HOLLY ENERGY PARTNERS LP - FORM 10-K

Attached files

file	filename
EX-12.1 - EXHIBIT 12.1 - HOLLY ENERGY PARTNERS LP	c12681exv12w1.htm
EX-10.2 - EXHIBIT 10.2 - HOLLY ENERGY PARTNERS LP	c12681exv10w2.htm
EX-10.29 - EXHIBIT 10.29 - HOLLY ENERGY PARTNERS LP	c12681exv10w29.htm
EX-10.28 - EXHIBIT 10.28 - HOLLY ENERGY PARTNERS LP	c12681exv10w28.htm
EX-10.24 - EXHIBIT 10.24 - HOLLY ENERGY PARTNERS LP	c12681exv10w24.htm
EX-10.23 - EXHIBIT 10.23 - HOLLY ENERGY PARTNERS LP	c12681exv10w23.htm
EX-10.40 - EXHIBIT 10.40 - HOLLY ENERGY PARTNERS LP	c12681exv10w40.htm
EX-10.45 - EXHIBIT 10.45 - HOLLY ENERGY PARTNERS LP	c12681exv10w45.htm
EX-31.2 - EXHIBIT 31.2 - HOLLY ENERGY PARTNERS LP	c12681exv31w2.htm
EX-21.1 - EXHIBIT 21.1 - HOLLY ENERGY PARTNERS LP	c12681exv21w1.htm
EX-32.2 - EXHIBIT 32.2 - HOLLY ENERGY PARTNERS LP	c12681exv32w2.htm
EX-32.1 - EXHIBIT 32.1 - HOLLY ENERGY PARTNERS LP	c12681exv32w1.htm
EX-31.1 - EXHIBIT 31.1 - HOLLY ENERGY PARTNERS LP	c12681exv31w1.htm
EX-23.1 - EXHIBIT 23.1 - HOLLY ENERGY PARTNERS LP	c12681exv23w1.htm
EX-10.34 - EXHIBIT 10.34 - HOLLY ENERGY PARTNERS LP	c12681exv10w34.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2010

Commission File Number 1-32225

HOLLY ENERGY PARTNERS, L.P.

Formed under the laws of the State of Delaware

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

100 Crescent Court, Suite 1600
Dallas, Texas 75201-6915
Telephone Number: (214) 871-3555

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

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

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No þ

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

Yes o No þ

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

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in part III of this Form 10-K or any amendments to this Form 10-K.

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


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

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

Yes o No þ

The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $640 million on June 30, 2010, 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 11, 2011 was 22,078,509.

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS


Item	Page

PART I

Forward-Looking Statements		3

1. Business		5

1A. Risk factors		14

1B. Unresolved staff comments		35

2. Properties		35

3. Legal proceedings		42

4. (Removed and reserved)		42

PART II

5. Market for the Registrant’s common units, related unitholder matters and issuer purchases of common units		43

6. Selected financial data		45

7. Management’s discussion and analysis of financial condition and results of operations		48

7A. Quantitative and qualitative disclosures about market risk		67

8. Financial statements and supplementary data		68

9. Changes in and disagreements with accountants on accounting and financial disclosure		97

9A. Controls and procedures		97

9B. Other information		97

PART III

10. Directors, executive officers and corporate governance		98

11. Executive compensation		105

12. Security ownership of certain beneficial owners and management and related unitholder matters		130

13. Certain relationships, related transactions and director independence		131

14. Principal accountant fees and services		136

PART IV

15. Exhibits and financial statement schedules		137

Signatures		138

Index to exhibits		139

Exhibit 10.2
Exhibit 10.23
Exhibit 10.24
Exhibit 10.28
Exhibit 10.29
Exhibit 10.34
Exhibit 10.40
Exhibit 10.45
Exhibit 12.1
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business”, “Risk Factors” and “Properties” in Items 1, 1A and 2 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner 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 and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

	•		risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;

	•		the economic viability of Holly Corporation, Alon USA, Inc. and our other customers;

	•		the demand for refined petroleum products in markets we serve;

	•		our ability to successfully purchase and integrate additional operations in the future;

	•		our ability to complete previously announced or contemplated acquisitions;

	•		the availability and cost of additional debt and equity financing;

	•		the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;

	•		the effects of current and future government regulations and policies;

	•		our operational efficiency in carrying out routine operations and capital construction projects;

	•		the possibility of terrorist attacks and the consequences of any such attacks;

	•		general economic conditions; and

	•		other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A. All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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INDEX TO DEFINED TERMS AND NAMES

The following terms and names that appear in this form 10-K are defined on the following pages:


6.25% Senior Notes			58
8.25% Senior Notes			58
Alon			5
Alon PTA			8
Amended Credit Agreement			11
Beeson Pipeline			7
Bpd			10
Bpsd			7
CFR			11
Credit Agreement			57
Distributable cash flow			46
DOT			11
EBITDA			46
Expansion capital expenditures			10
FERC			8
Fixed Rate Swap			66
GAAP			46
HEP			5
HLS			5
Holly			5
Holly ATA			7
Holly CPTA			8
Holly ETA			8
Holly IPA			8
Holly NPA			8
Holly PTA			8
Holly PTTA			6
Holly RPA			8
LIBOR			62
Long-Term Incentive Plan			83
LPG			6
Maintenance capital expenditures			47
mbbls			35
mbpd			54
Mid-America			36
NuStar			40
Omnibus Agreement			9
OSHA			21
Plains			7
PPI			8
Rio Grande			7
Roadrunner Pipeline			7
SEC			5
Senior Notes			16
Sinclair			6
Sinclair Transportation			41
SLC Pipeline			5
Variable Rate Swap			66

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

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Item 1. Business

OVERVIEW

Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership engaged principally in the business of operating a system of petroleum product and crude oil pipelines, storage tanks, distribution terminals and loading rack facilities in west Texas, New Mexico, Utah, Arizona, Oklahoma and Idaho. We were formed in Delaware in 2004 and maintain our principal corporate offices at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address is www.hollyenergy.com. The information contained on our website does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”) website is available on our website on the Investors page. Additionally available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person. “Holly” refers to Holly Corporation and its subsidiaries, other than HEP and its subsidiaries and other than Holly Logistic Services, L.L.C. (“HLS”), a subsidiary of Holly Corporation that is the general partner of the general partner of HEP and manages HEP.

We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that support Holly Corporation’s (“Holly”) refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. Holly currently owns a 34% interest in us including the 2% general partner interest. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.

Our assets include:

Pipelines:

	•		approximately 820 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel and jet fuel principally from Holly’s Navajo refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico;

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

	•		three 65-mile intermediate pipelines that transport intermediate feedstocks and crude oil from Holly’s Navajo refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery facilities in Artesia, New Mexico;

	•		approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to Holly’s Navajo refinery;

	•		approximately 10 miles of crude oil and refined product pipelines that support Holly’s Woods Cross refinery located near Salt Lake City, Utah; and

	•		gasoline and diesel connecting pipelines located at Holly’s Tulsa east refinery facility.

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	Refined Product Terminals and Refinery Tankage:

	•		four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 barrels, that are integrated with our refined product pipeline system that serves Holly’s Navajo refinery;

	•		three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000 barrels, that serve third-party common carrier pipelines;

	•		one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;

	•		two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with our refined product pipelines that serve Alon’s Big Spring refinery;

	•		a refined product truck loading rack facility at each of Holly’s Navajo and Woods Cross refineries, an asphalt truck loading rack facility at the Navajo refinery Lovington, New Mexico facility, refined product and lube oil rail loading racks and a lube oil truck loading rack at Holly’s Tulsa refinery west facility and a refined product, asphalt and liquefied petroleum gas (“LPG”) truck loading rack, a truck unloading rack and a rail loading rack at Holly’s Tulsa refinery east facility;

	•		a Roswell, New Mexico jet fuel terminal leased through September 2011;

	•		on-site crude oil tankage at Holly’s Navajo, Woods Cross and Tulsa refineries having an aggregate storage capacity of approximately 600,000 barrels; and

	•		on-site refined product and hydrocarbon tankage at Holly’s Tulsa refinery having an aggregate storage capacity of approximately 3,400,000 barrels.

We also own a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

We have a long-term strategic relationship with Holly. Our growth plan is to continue to pursue purchases of logistic assets at its existing refining locations in New Mexico, Utah and Oklahoma. We will also work with Holly on logistic asset acquisitions in conjunction with Holly’s refinery acquisition strategies. Furthermore, we will continue to pursue third-party logistic asset acquisitions which are accretive to our unitholders and increase the diversity of our revenues.

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from Holly certain storage assets for $88.6 million consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at Holly’s Tulsa refinery east facility.

In connection with this purchase, we amended our 15-year pipeline, tankage and loading rack throughput agreement with Holly (the “Holly PTTA”) that initially pertained to the logistics and storage assets acquired from an affiliate of Sinclair Oil Company (“Sinclair”) in December 2009. Under the amended Holly PTTA, Holly has agreed to transport, throughput and load volumes of product through our Tulsa east facility logistics and storage assets that will result in minimum annualized revenues to us of $27.2 million.

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Also, as part of this same transaction, we acquired Holly’s asphalt loading rack facility located at its Navajo refinery facility in Lovington, New Mexico for $4.4 million and entered into a 15-year asphalt facility throughput agreement (the “Holly ATA”). Under the Holly ATA, Holly has agreed to throughput a minimum volume of products via our Lovington asphalt loading rack facility that will result in minimum annualized revenues to us of $0.5 million.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, we acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes paid and 1,373,609 of our common units having a fair value of $53.5 million. Separately, Holly, also a party to the transaction, acquired Sinclair’s Tulsa refinery.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery Lovington facility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).

Tulsa West Loading Racks Transaction

On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.

Lovington-Artesia Pipeline Transaction

On June 1, 2009, we acquired from Holly a newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from the Navajo refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.

SLC Pipeline Joint Venture Interest

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate pipeline system that we jointly own with Plains All American Pipeline, L.P. (“Plains”). The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

Holly Capacity Expansion

Also in March 2009 Holly, our largest customer, completed a 15,000 barrels per stream day (“bpsd”) capacity expansion of its Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.

Rio Grande Pipeline Sale

On December 1, 2009, we sold our 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

2008 Acquisition

Crude Pipelines and Tankage Transaction

On February 29, 2008, we acquired from Holly certain crude pipelines and tankage assets for $180 million, consisting of crude oil trunk lines that support the Navajo refinery, crude oil and refined product pipelines that support the Woods Cross refinery, on-site crude tankage located at the Navajo and Woods Cross refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. The consideration paid consisted of $171 million in cash and 217,497 of our common units having a fair value of $9 million.

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Agreements with Holly and Alon

We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

	•		Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by Holly upon our initial public offering in 2004);

	•		Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from Holly in 2005 and 2009);

	•		Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);

	•		Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in March 2010);

	•		Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);

	•		Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from Holly in 2009);

	•		Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and

	•		Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from Holly in March 2010).

Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.

We also have a pipelines and terminals agreement with Alon expiring in 2020 (the “Alon PTA”) under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

If Holly or Alon fail to meet their minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment under the Holly PTA, Holly IPA and Alon PTA may be applied as a credit in the following four quarters after minimum obligations are met.

We also have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under this agreement expire beginning in 2012 through 2018.

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At December 31, 2010, contractual minimums under our long-term service agreements are as follows:


	Minimum Annualized
	Commitment		Year of
Agreement	(in millions)		Maturity	Contract Type

Holly PTA	$	43.7	2019	Minimum revenue commitment
Holly IPA		20.7	2024	Minimum revenue commitment
Holly CPTA		28.4	2023	Minimum revenue commitment
Holly PTTA		27.2	2024	Minimum revenue commitment
Holly RPA		9.2	2024	Minimum revenue commitment
Holly ETA		2.7	2024	Minimum revenue commitment
Holly ATA		0.5	2025	Minimum revenue commitment
Holly NPA		0.6	2024	Minimum revenue commitment
Alon PTA		22.7	2020	Minimum volume commitment
Alon capacity lease		6.6	Various	Capacity lease


Total	$	162.3

A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.

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

Omnibus Agreement

We entered into an omnibus agreement with Holly in 2004 that Holly and we have amended and restated several times in connection with our past acquisitions from Holly with the last amendment and restatement occurring on March 31, 2010 (the “Omnibus Agreement”). Under certain provisions of the Omnibus Agreement, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us, currently $2.3 million. This fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees.

Under the Omnibus Agreement, Holly agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The transfers that are covered by the agreement include the refined product pipelines, terminals and tanks transferred by Holly’s subsidiaries in connection with our initial public offering in July 2004, the intermediate pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental indemnification of up to $15 million for the assets transferred to us, other than the crude pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines acquired in July 2005. Except as described below, Holly’s indemnification obligations described above will remain in effect for an asset for ten years following the date it is transferred to us. The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage assets. Holly’s indemnification obligations described above do not apply to (i) the Tulsa west loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks acquired in March 2010.

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Under provisions of the Holly ETA and Holly PTTA, Holly will indemnify us for environmental liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities acquired from Holly in August 2009, the Tulsa logistics and storage assets acquired from Sinclair in December 2009 and the Tulsa east storage tanks and loading racks acquired from Holly in March 2010. Additionally, Holly agreed to indemnify us for any liabilities arising from Holly’s operation of the loading racks under the Holly ETA.

We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon will indemnify us through 2015, subject to a $100,000 deductible and a $20 million maximum liability cap.

CAPITAL REQUIREMENTS

Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2011 capital budget is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

We are currently constructing five interconnecting pipelines between Holly’s Tulsa east and west refining facilities. The project is expected to cost approximately $28 million with completion in the second quarter of 2011. We are currently negotiating terms for a long-term agreement with Holly to transfer intermediate products via these pipelines that will commence upon completion of the project. In the event that we are unable to obtain such an agreement, Holly will reimburse us for the cost of the pipelines.

We have an option agreement with Holly, granting us an option to purchase Holly’s 75% equity interest in the UNEV Pipeline, a joint venture pipeline currently under construction that will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. Under this agreement, we have an option to purchase Holly’s equity interest in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 barrels per day (“bpd’), with the capacity for further expansion to 120,000 bpd. The current total cost of the pipeline project including terminals is expected to be approximately $325 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. The pipeline is in the final construction phase and is expected to be mechanically complete in the second quarter of 2011.

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We expect that our currently planned expenditures for sustaining and maintenance capital as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline described above, will be funded with existing cash generated by operations, the sale of additional limited partner units, the issuance of debt securities and advances under our $275 million senior secured credit agreement (the “Amended Credit Agreement”), or a combination thereof. With volatility and uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under our Amended Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline. We are not obligated to purchase these assets nor are we subject to any fees or penalties if HLS’ board of directors decides not to proceed with any of these opportunities.

SAFETY AND MAINTENANCE

We perform preventive and normal maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by code or regulation. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems.

We monitor the structural integrity of selected segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs”, as well as hydrostatic testing that conforms to federal standards. We follow these inspections with a review of the data and we make repairs as necessary to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. We believe this approach will ensure that the pipelines that have the greatest risk potential receive the highest priority in being scheduled for inspections or pressure tests for integrity. Our inspection process complies with all Department of Transportation (“DOT”) and Code of Federal Regulations (“CFR”) 49 CFR Part 195 requirements.

Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws; 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, Woods Cross and Tulsa refineries, our contractual relationship with Holly under the Omnibus Agreement and the Holly pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of refined products transported from Holly’s refineries, particularly during the terms of our long-term transportation agreements with Holly expiring in 2019 — 2025. Additionally, with our contractual relationship with Alon under the Alon PTA expiring in 2020, we believe that we will not face significant competition for those barrels of refined products we transport from Alon’s Big Spring refinery.

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

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

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

Historically, the significant majority of the throughput at our terminal facilities has come from Holly, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso, and the Abilene and Wichita Falls terminals that serve Alon’s Big Springs refinery.

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

RATE REGULATION

Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to rates that are already on file and in effect by complaint. A successful challenge under a complaint may result in the complainant obtaining damages or reparations for up to two years prior to the date the complaint was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate by a protest. A successful challenge under a protest may result in the protestant obtaining refunds or reparations from the date the proposed new or changed rate become effective. In either challenge process, the third party must be able to show it has a substantial economic interest in those rates to proceed. The FERC generally has not investigated interstate rates on its own initiative but will likely become a party to any proceedings when the rates receive either a complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under investigation without a third-party intervention.

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

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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. Although these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements.

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There are environmental remediation projects that are currently in progress that relate to certain assets acquired from Holly. Certain of these projects were underway prior to our purchase and represent liabilities of Holly Corporation as the obligation for future remediation activities was retained by Holly. Additionally, as of December 31, 2010, we have an accrual of $0.3 million that relates to environmental clean-up projects for which we have assumed liability. The remaining projects, including assessment and monitoring activities, are covered under the Holly environmental indemnification discussed above and represent liabilities of Holly Corporation.

We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets, nevertheless, have the potential to substantially affect our business.

EMPLOYEES

To carry out our operations, HLS employs 148 people who provide direct support to our operations. HLS considers its employee relations to be good. Neither we nor our general partner have employees. We reimburse Holly for direct expenses that Holly or its affiliates incurs on our behalf for the employees of HLS.

Item 1A. Risk Factors

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

The headings provided in this Item 1A. are for convenience and reference purposes only and shall not affect or limit the extent or interpretation of the risk factors.

RISKS RELATED TO OUR BUSINESS

We depend upon Holly and particularly its Navajo refinery for a majority of our revenues; if those revenues were significantly reduced or if Holly’s financial condition materially deteriorated, there would be a material adverse effect on our results of operations.

For the year ended December 31, 2010, Holly accounted for 80% of the revenues of our petroleum product and crude pipelines and 83% 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 long-term pipeline and terminal, tankage and throughput agreements that it has with us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at the Navajo, Woods Cross or Tulsa refineries, our revenues and cash flow would decline.

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Any significant curtailing of production at the Navajo refinery could, by reducing throughput in our pipelines and terminals, result in our realizing materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2010, production from the Navajo refinery accounted for 86% of the throughput volumes transported by our refined product and crude oil pipelines. The Navajo refinery also received 100% of the petroleum products shipped on our intermediate pipelines. Operations at the Navajo, Woods Cross or Tulsa refineries could be partially or completely shut down, temporarily or permanently, as the result of:

	•		competition from other refineries and pipelines that may be able to supply the refinery’s end-user markets on a more cost-effective basis;

	•		operational problems such as catastrophic events at the refinery, labor difficulties or environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at the refinery;

	•		planned maintenance or capital projects;

	•		increasingly stringent environmental laws and regulations, such as the U.S. Environmental Protection Agency’s gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road usage as well as various state and federal emission requirements that may affect the refinery itself and potential future climate change regulations;

	•		an inability to obtain crude oil for the refinery at competitive prices; or

	•		a general reduction in demand for refined products in the area due to:

	•		a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel;

	•		higher gasoline prices due to higher crude oil costs, higher taxes or stricter environmental laws or regulations; or

	•		a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation either mandating or encouraging higher fuel economy or the use of alternative fuel or otherwise.

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

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

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

For the year ended December 31, 2010, Alon accounted for 12% of the combined revenues of our petroleum product and crude oil pipelines and of our terminals and truck loading racks, including revenues we received from Alon under a capacity lease agreement.

A decline in production at Alon’s Big Spring refinery would materially reduce the volume of refined products we transport and terminal for Alon and, as a result, our revenues would be materially adversely affected. The Big Spring refinery could partially or completely shut down its operations, temporarily or permanently, due to factors affecting its ability to produce refined products or for planned maintenance or capital projects. Such factors would include the factors discussed above under the discussion of risk factors for the Navajo refinery.

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The magnitude of the effect on us of any shutdown depends on the length of the shutdown and the extent of the refinery operations affected. We have no control over the factors that may lead to a shutdown or the measures Alon may take in response to a shutdown. Alon makes all decisions and is responsible for all costs at the Big Spring refinery concerning levels of production, regulatory compliance, refinery turnarounds, labor relations, environmental remediation and capital expenditures.

In addition, under the Alon PTA, if we are unable to transport or terminal refined products that Alon is prepared to ship, then Alon has the right to reduce its minimum volume commitment to us during the period of interruption. If a force majeure event occurs beyond the control of either of us, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.

Due to our lack of asset diversification, adverse developments in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.

We rely exclusively on the revenues generated from our business. Due to our lack of asset diversification, an adverse development in our business could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

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, 2010, the principal amount of our total outstanding debt was $494 million. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Various limitations in our Amended Credit Agreement and the indentures for our 6.25% senior notes maturing March 1, 2015 and the 8.25% senior notes maturing March 15, 2018 (collectively, the “Senior Notes”) may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage could have important consequences. We 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 the Amended Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain beneficial transactions. The agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Additionally, our purchase and contribution agreements with Holly with respect to the intermediate pipelines and the crude pipelines and tankage assets restrict us from selling pipelines and terminals acquired from Holly and from prepaying borrowings and long-term debt to outstanding balances below $35 million and $171 million prior to 2015 and 2018, respectively, in each case subject to certain limited exceptions. Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

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We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

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

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our strategy contemplates growth through the development and acquisition of crude, intermediate and refined products transportation and storage assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in our chosen businesses and increase our market position.

We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

In addition, we are experiencing increased competition for the types of assets and businesses we have historically purchased or acquired. Increased competition for a limited pool of assets could result in our losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher distributions in the future.

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We are exposed to the credit risks, and certain other risks, of our key customers and vendors.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion of our revenues from contracts with key customers, including Holly and Alon under their respective pipelines and terminals, tankage and throughput agreements. To the extent that these and other customers may be unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.

Mergers among our existing customers could provide strong economic incentives for the combined entities to utilize systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.

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. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.

Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.

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

We and our shippers could face increased competition if other pipelines are able to competitively supply our shippers’ end-user markets with refined products. The Longhorn Pipeline, owned by Magellan Midstream Partners, L.P., is an approximately 72,000 bpd common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the Arizona market. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from Holly and/or Alon. This could reduce our opportunity to earn revenues from Holly and Alon in excess of their minimum volume commitment obligations.

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

A material decrease in the supply, or a material increase in the price, of crude oil available to Holly’s and Alon’s refineries and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could materially reduce our revenues.

The volume of refined products we transport in our refined product pipelines depends on the level of production of refined products from Holly’s and Alon’s refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to offset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, the future growth of our shippers’ operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.

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Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, or producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital. Similarly, a material increase in the price of crude oil supplied to our shippers’ refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which caused a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our cash flow could be adversely affected.

Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve.

We may not be able to retain existing customers or acquire new customers.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve. Alon’s obligations to lease capacity on the Artesia-Orla-El Paso pipeline have remaining terms that expire beginning in 2012 through 2018. Our long-term pipeline and terminal, tankage and throughput agreements with Holly and Alon expire beginning in 2019 through 2024.

Meeting the requirements of evolving environmental, health and safety laws and regulations, including those related to climate change, could adversely affect our performance.

Environmental laws and regulations have raised operating costs for the oil and refined products industry and compliance with such laws and regulations may cause us, Holly and Alon to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities. We may also be required to address conditions discovered in the future that require environmental response actions or remediation. Future environmental, health and safety requirements or changed interpretations of existing requirements, may impose more stringent requirements on our assets and operations and require us to incur potentially material expenditures to ensure our continued compliance. Future developments in federal laws and regulations governing environmental, health and safety and energy matters are especially difficult to predict.

Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation. These include requirements effective January 2010 that require Holly’s and Alon’s refineries to report emissions of greenhouse gases to the EPA beginning in 2011, and proposed federal, state, and regional initiatives that require, or could require, us, Holly and Alon to reduce greenhouse gas emissions from our facilities. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances. These requirements may also adversely affect Holly’s and Alon’s refinery operations and have an indirect adverse effect on our business, financial condition and results of our operations.

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Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could also decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, in 2010, the EPA promulgated a rule establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks, and medium-duty passenger vehicles. Also in 2010, the EPA promulgated a rule establishing greenhouse gas emission thresholds for the permitting of certain stationary sources, which could require greenhouse emission controls for those sources. These requirements could have an indirect adverse effect on our business due to reduced demand for crude oil and refined products, and a direct adverse affect on our business from increased regulation of our facilities.

Changes in other forms of health and safety regulations are also being considered. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was recently passed by the U.S. House of Representatives. The Department of Transportation has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the Pipeline and Hazardous Materials Safety Administration’s announced intention to strengthen its rules. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include damage to our facilities from severe weather such as powerful winds or rising waters in low-lying areas, disruption of our operations, either because of climate-related damage to our facilities or scale-backs in our operations due to the threat of such effects, and higher operating costs and less efficient or non-routine operating practices necessitated by potential climatic effects or in the aftermath of such effects. Significant physical effects of climate change could also affect us indirectly by disrupting the operations of our customers or by disrupting services or supplies provided by service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the costs that may result from potential physical effects of climate change.

We may be subject to information technology system failures, network disruptions and breaches in data security.

Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, there can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and results of operations.

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Our operations are subject to federal, state, and local laws and regulations relating to product quality specifications, environmental protection and operational safety that could require us to make substantial expenditures.

Our pipelines and terminals, tankage and loading rack operations are subject to increasingly strict environmental and safety laws and regulations. Also, the transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us. We are also subject to the requirements of the Federal Occupational Safety and Health Administration (“OSHA”), and comparable state statutes. Any violation of OSHA could impose substantial costs on us.

Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.

We may have additional maintenance costs in the future.

Our pipeline and storage assets are generally long-lived assets, and some of those assets have been in service for many years. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions. However, we maintain continuing monitoring programs and maintenance expenditures in an attempt to address such issues.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life or destruction of property, injury, or extensive property damage, as well as a curtailment or interruption in our operations. In addition, third-party damage, mechanical malfunctions, undetected leaks in pipelines, faulty measurement or other errors may result in significant costs or lost revenues.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from coverage may limit our ability to recover the amount of the full loss in all situations. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. With our distribution policy, we do not have the same flexibility as other legal entities to accumulate cash to protect against underinsured or uninsured losses.

There can be no assurance that insurance will cover all damages and losses resulting from these types of hazards. We are not fully insured against all risks incident to our business. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. Our business interruption insurance covers only certain lost revenues arising from physical damage to our facilities and Holly and Alon facilities. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

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

Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products loaded at our loading racks. If our quality control measures were to fail, off specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the off specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.

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

Our growth strategy is dependent upon:

	•		the accuracy of our assumption that many of the markets that we currently serve or have plans to serve in the Southwestern, Rocky Mountain and Mid-Continent regions of the United States will experience population growth that is higher than the national average; and

	•		the willingness and ability of Holly to capture a share of this additional demand in its existing markets and to identify and penetrate new markets in the Southwestern, Rocky Mountain and Mid-Continent regions of the United States.

If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a growth strategy. If Holly chooses not to gain, or is unable to gain additional customers in new or existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide acquisition opportunities to us; or, if those opportunities arise, they may not be on terms attractive to us or on terms that allow us to obtain appropriate financing. Finally, Holly also will be subject to integration risks with respect to its Tulsa refining acquisitions and any new acquisitions it chooses to make.

Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.

One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. These projects may not be completed on schedule or at all or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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Rate regulation may not allow us to recover the full amount of increases in our costs.

The FERC regulates the tariff rates for interstate movements on our pipeline systems. The primary rate-making methodology of the FERC is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing would adversely affect our revenues and cash flow.

If our interstate or intrastate tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues.

If a party with an economic interest were to file either a protest of our proposal for increased rates or a complaint against our existing tariff rates, or the FERC were to initiate an investigation of our existing rates, then our rates could be subject to detailed review. If our proposed rate increases were found to be in excess of levels justified by our cost of service, the FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found to be in excess of our cost of services, we could be ordered to refund the excess we collected for as far back as two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. 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 may result in lower revenues and cash flows if additional volumes and / or capacity are unavailable to offset such rate reductions.

Holly and Alon have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements. These agreements do not prevent other current or future shippers from challenging our tariff rates.

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

The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services. If the FERC’s petroleum pipeline rate-making methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so.

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The fees we charge to third parties under transportation and storage agreements may not escalate sufficiently to cover increases in our costs, and the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil or refined products is curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions and mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would be negatively impacted.

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

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

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

Adverse changes in our credit ratings and risk profile, and that of our general partner, may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates, and could result in an increase in our borrowing costs, a reduced level of capital expenditures and an impact on future earnings and cash flows.

We are in compliance with all covenants or other requirements set forth in the Amended Credit Agreement. Further, we do not have any rating downgrade triggers that would automatically accelerate the maturity dates of any debt. However, a downgrade in our credit rating could adversely affect our ability to borrow on, renew existing, or obtain access to new financing arrangements and would increase the cost of such financing arrangements.

The credit and business risk profiles of our general partner, and of Holly as the indirect owner of our general partner, may be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and its indirect owner over our business activities, including our cash distribution acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

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Alternative financing strategies may not be successful.

Periodically, we will consider the use of alternative financing strategies such as joint venture arrangements and the sale of non-strategic assets. Joint venture agreements may not share the risks and rewards of ownership in proportion to the voting interests. Joint venture arrangements may require us to pay certain costs or to make certain capital investments and we may have little control over the amount or the timing of these payments and investments. We may not be able to negotiate terms that adequately reimburse us for our costs to fulfill service obligations for those joint ventures where we are the operator. In addition, our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone.

We may periodically sell assets or portions of our business. Separating the existing operations from our assets or operations of which we dispose may result in significant expense and accounting charges, disrupt our business or divert management’s time and attention. We may not achieve expected cost savings from these dispositions or the proceeds from sales of assets or portions of our business may be lower than the net book value of the assets sold. We may not be relieved of all of our obligations related to the assets or businesses sold. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on our common units.

Ongoing maintenance of effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.

We regularly document and test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time; we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could cause us to incur substantial expenditures of management time and financial resources to identify and correct any such failure.

We may be unsuccessful in integrating the operations of the assets we have acquired or of any future acquisitions with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. For example, in 2010 we completed the Tulsa east/Lovington storage assets acquisition. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, including the assets and businesses we acquired in 2010. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

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If we are unable to complete capital projects at their expected costs or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:

	•		denial or delay in issuing requisite regulatory approvals and/or permits;

	•		unplanned increases in the cost of construction materials or labor;

	•		disruptions in transportation of modular components and/or construction materials;

	•		severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;

	•		shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

	•		market-related increases in a project’s debt or equity financing costs; and/or

	•		nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

If we are unable to complete capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially and adversely affected.

We do not own all of the land on which our pipeline systems and facilities are located. Our operations could be disrupted if we were to lose or were unable to renew existing rights-of-way.

We do not own all of the land on which our pipeline systems and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the right to construct and operate pipelines on land owned by third parties and government agencies for specified periods of time. If we were to lose these rights through an inability to renew right-of-way contracts or otherwise, we may be required to relocate our pipelines and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

Our business may suffer due to a change in the composition of our Board of Directors, or if any of our key senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of our key senior executives and key senior employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks.

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In certain cases we have the right to be indemnified by third parties for environmental liabilities, and our results of operation and our ability to make distributions to our unitholders could be adversely affected if a third party fails to satisfy an indemnification obligation owed to us.

In connection with the pipelines, terminals and tanks transferred to us by Holly in connection with our initial public offering in 2004, the intermediate pipelines acquired in 2005, the crude pipelines and tankage assets acquired in 2008, the asphalt loading rack facility acquired in March 2010, and the refined product pipelines, tankage and terminals acquired from Alon in 2005, we have entered into environmental agreements with them pursuant to which they have agreed to indemnify us for certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition. These indemnities continue through 2014 for the assets contributed to us by Holly at our initial public offering, through 2015 for the intermediate pipelines acquired from Holly and the refined product pipelines, tankage and terminals acquired from Alon, and through 2023 for the crude pipelines and tankage assets acquired from Holly. Additionally, we have entered into agreements with Holly in connection with our acquisition of the Sinclair Logistics Assets and the Tulsa Loading Racks that provide that Holly will indemnify us for certain matters arising from the pre-closing ownership or operation of these assets, which indemnification obligations are not time limited. Other third parties are also obligated to indemnify us for ongoing remediation pursuant to separate indemnification obligations. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected in the future if Holly, Alon, or other third parties fail to satisfy an indemnification obligation owed to us.

Many of our executive officers face conflicts in the allocation of their time to our business.

Our general partner shares officers and administrative personnel with Holly to operate both our business and Holly’s business. Our general partners’ officers, several of whom are also officers of Holly, will allocate the time they and the other employees of Holly spend on our behalf and on behalf of Holly. These officers face conflicts regarding the allocation of their and other employees’ time, which may adversely affect our results of operations, cash flows and financial condition.

RISKS TO COMMON UNITHOLDERS

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

Currently, Holly indirectly owns the 2% general partner interest and a 32% limited partner interest in us and owns and controls the general partner of our general partner, HEP Logistics Holdings, L.P. Conflicts of interest may arise between Holly and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its other affiliates over our interests. These conflicts include, among others, the following situations:

	•		Holly, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm’s-length, third-party transactions;

	•		neither our partnership agreement nor any other agreement requires Holly to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Holly’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Holly;

	•		our general partner is allowed to take into account the interests of parties other than us, such as Holly, in resolving conflicts of interest;

	•		our general partner determines which costs incurred by Holly and its affiliates are reimbursable by us;

	•		our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

	•		our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and

	•		our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with Holly.

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

Under our Omnibus Agreement, we are currently obligated to pay Holly an administrative fee of $2.3 million per year for the provision by Holly or its affiliates of various general and administrative services for our benefit. We can provide no assurance that Holly will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If Holly fails to provide us with adequate personnel, our operations could be adversely impacted.

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

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

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

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner’s general partner, cannot vote on any matter; however, no such person currently exists. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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

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

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

In August 2009, all of the conditions necessary to end the subordination period for the 7,000,000 subordinated units owned by our general partner were met and the units were converted into our common units on a one-for-one basis. In addition, under our partnership agreement, because the subordination period for this class of subordinated units has expired, provided there is no significant decrease in our operating performance, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and the Partnership currently has a shelf registration on file with the SEC pursuant to which it may issue up to $860 million in additional common units.

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

	•		our unitholders’ proportionate ownership interest in us will decrease;

	•		the amount of cash available for distribution on each unit may decrease;

	•		because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•		the relative voting strength of each previously outstanding unit may be diminished; and

	•		the market price of the common units may decline.

Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

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

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

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

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

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

	•		any business or asset that Holly or any of it subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5 million; and

	•		any business or asset that Holly or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.

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

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

In some instances, our general partner may cause us to borrow funds from affiliates of Holly or from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make incentive distributions.

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

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

A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business or that we have not complied with state partnership law.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Further, we conduct business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership’s obligations as if they were a general partner if a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute.

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TAX RISKS TO COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the U.S. Internal Revenue Service (the “IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. As long as we qualify to be treated as a partnership for federal income tax purposes, we are not subject to federal income tax. Although a publicly-traded limited partnership is generally treated as a corporation for federal income tax purposes, a publicly-traded partnership such as us can qualify to be treated as a partnership for federal income tax purposes so long as for each taxable year at least 90% of its gross income is derived from specified investments and activities. We believe that we qualify to be treated as a partnership for federal income tax purposes because we believe that at least 90% of our gross income for each taxable year has been and is derived from such specified investments and activities. While we intend to meet this gross income requirement, regardless of our efforts we may not find it possible to meet, or may inadvertently fail to meet, this gross income requirement. If we do not meet this gross income requirement for any taxable year and the IRS does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

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

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation, possibly on a retroactive basis. At the federal level, members of Congress have recently considered substantive changes to existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. We are unable to predict whether any of these potential changes, or other proposals, will ultimately be enacted into law. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

Our partnership agreement allows remedial allocations of income, deduction, gain and loss by us to account for differences between the tax basis and fair market value of property at the time the property is contributed or deemed contributed to us and to account for differences between the fair market value and book basis of our assets existing at the time of issuance of any common units. If the IRS does not respect our remedial allocations, ratios of taxable income to cash distributions received by the holders of common units will be materially higher than previously estimated.

The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

Because our unitholders will generally be treated as partners to whom we allocate taxable income, which could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from that income.

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

If a unitholder disposes of common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. A unitholder’s amount realized will be measured by the sum of the cash and the fair market value of other property, if any, received by the unitholder, plus its share of our nonrecourse liabilities. Because the amount realized will include the unitholder’s share of our nonrecourse liabilities, the gain recognized by the unitholder on the sale of its units could result in a tax liability in excess of any cash it receives from the sale. Distributions in excess of a unitholder’s allocable share of our net taxable income (“excess distributions”) decrease the unitholder’s tax basis in its common units, which includes its share of nonrecourse liabilities. Such excess distributions with respect to the units sold become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. Moreover, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

An investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), Keogh Plans and other retirement plans, regulated investment companies and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax adviser before investing in our common units.

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

Because we cannot match transferors and transferees of common units and in order to maintain the uniformity of the economic and tax characteristics of our common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing treasury regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding common units. A subsequent holder of those common units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). However, because we cannot identify these common units once they are traded by the initial holder, we do not give any subsequent holder of a common unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those common units and may result in those unitholders reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied treasury regulations relating to these depreciation or amortization adjustments. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied those treasury regulations.

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The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Internal Revenue Code Section 743(b). If so, because neither we nor a unitholder can identify the common units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling common units within the period under audit as if all unitholders owned common units with respect to which allowable deductions were not taken. Any position we take that is inconsistent with applicable treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing treasury regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The reporting of partnership tax information is complicated and subject to audits.

We furnish each unitholder with a Schedule K-1 that sets forth the unitholder’s share of our income, gains, losses and deductions. We cannot guarantee that these schedules will be prepared in a manner that conforms in all respects to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, which could result in an audit of a unitholder’s individual tax return and increased liabilities for taxes because of adjustments resulting from the audit.

There are limits on the deductibility of our losses that may adversely affect our unitholders.

There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases when our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units.

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

We will be considered to have terminated our partnership for federal income tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders may receive two Schedules K-1) for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership for federal tax purposes, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma and Washington. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder’s responsibility to file all federal, state, local and foreign tax returns.

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Unitholders may have negative tax consequences if we default on our debt or sell assets.

If we default on any of our debt, our lenders will have the right to sue us for non-payment. Such an action could cause an investment loss and cause negative tax consequences for unitholders through the realization of taxable income by unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, unitholders could have increased taxable income without a corresponding cash distribution.

Item 1B. Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

Item 2. Properties

PIPELINES

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

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

Our crude pipelines consist of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to the Navajo refinery and crude oil and refined product pipelines that support Holly’s Woods Cross refinery.

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

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


	Years Ended December 31,
	2010		2009		2008		2007		2006
Volumes transported for (bpd):
Holly		324,382		295,039		253,484		142,447		126,929
Third parties⁽¹⁾		38,910		43,709		22,756		46,511		47,551

Total		363,292		338,748		276,240		188,958		174,480

Total barrels in thousands (“mbbls”)⁽¹⁾		132,602		123,643		101,104		68,970		63,685


(1)		We sold our 70% interest in Rio Grande on December 1, 2009. Rio Grande volumes are excluded.

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The following table sets forth certain operating data for each of our crude oil and petroleum 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 17,500 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of drag reducing agents.


	Diameter		Approximate Length		Capacity
Origin and Destination	(inches)		(miles)		(bpd)

Refined Product Pipelines:
Artesia, NM to El Paso, TX		6		156		24,000
Artesia, NM to Orla, TX to El Paso, TX		8/12/8		214		70,000	⁽¹⁾
Artesia, NM to Moriarty, NM⁽²⁾		12/8		215		45,000	⁽³⁾
Moriarty, NM to Bloomfield, NM⁽²⁾		8		191			⁽³⁾
Big Spring, TX to Abilene, TX		6/8		105		20,000
Big Spring, TX to Wichita Falls, TX		6/8		227		23,000
Wichita Falls, TX to Duncan, OK		6		47		21,000
Midland, TX to Orla, TX		8/10		135		25,000
Artesia, NM to Roswell, NM		4		36		5,300
Woods Cross, UT		10/8		8		70,000
Tulsa, OK⁽⁴⁾
Intermediate Product Pipelines:
Lovington, NM to Artesia, NM		8		65		48,000
Lovington, NM to Artesia, NM		10		65		72,000
Lovington, NM to Artesia, NM		16		65		96,000
Crude Pipelines:
Lovington / Artesia, New Mexico		Various		861		31,000
Roadrunner Pipeline		16		65		80,000
Beeson Pipeline		8		37		35,000
Woods Cross, Utah		12		4		40,000


(1)		Includes 17,500 bpd of capacity on the Orla to El Paso segment of this pipeline that is leased to Alon under capacity lease agreements.

(2)		The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC (“Mid-America”) under a long-term lease agreement.

(3)		Capacity for this pipeline is reflected in the information for the Artesia to Moriarty pipeline.

(4)		Tulsa gasoline and diesel fuel connections to Magellan’s pipeline of less than one mile.

Holly shipped an aggregate of 71% of the petroleum products transported on our refined product pipelines and 100% of the petroleum products transported on our intermediate pipelines and crude oil pipelines in 2010. These pipelines transported 93% of the light refined products produced by Holly’s Navajo refinery in 2010.

Artesia, New Mexico to El Paso, Texas

The Artesia to El Paso refined product pipeline is regulated by the FERC. It was constructed in 1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used primarily for the shipment of refined products produced at the Navajo refinery to our El Paso terminal, where we deliver to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s tank farm for truck rack loading for local delivery by tanker truck. Refined products produced at the Navajo refinery destined for El Paso are transported on either this pipeline or our Artesia to Orla to El Paso pipeline.

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Artesia, New Mexico to Orla, Texas to El Paso, Texas

The Artesia to Orla to El Paso refined product pipeline is a common-carrier pipeline regulated by the FERC and consists of three segments:

	•		an 8-inch, 10-mile and a 12-inch, 72-mile segment from the Navajo refinery to Orla, Texas;

	•		a 12-inch, 124-mile segment from Orla to outside El Paso, Texas; and

	•		an 8-inch, 8-mile segment from outside El Paso to our El Paso terminal.

There are two shippers on this pipeline, Holly and Alon. As mentioned above, refined products destined to our El Paso terminal are delivered to common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s truck rack for local delivery by tanker truck.

Artesia, New Mexico to Moriarty, New Mexico

The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from the Navajo refinery Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area, including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). Holly is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to adjustments based on changes in the PPI) of $520,000 to Mid-America to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.

Moriarty, New Mexico to Bloomfield, New Mexico

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

Big Spring, Texas to Abilene, Texas

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

Big Spring, Texas to Wichita Falls, Texas

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

Wichita Falls, Texas to Duncan, Oklahoma

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

Midland, Texas to Orla, Texas

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

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Artesia, New Mexico to Roswell, New Mexico

The 36-mile, 4-inch diameter Artesia to Roswell refined product pipeline delivers jet fuel only to tanks located at our jet fuel terminal in Roswell. Holly is the only shipper on this pipeline.

Woods Cross, Utah refined product pipelines

The Woods Cross refined product pipelines consist of three pipeline segments. The Woods Cross to Pioneer terminal segment consists of 2 miles of 8-inch pipeline which is used for product shipments to and through the Pioneer terminal. The Woods Cross to Pioneer segment represents 2 miles of 10-inch pipeline that is also used for product shipments to and through the Pioneer terminal. The Woods Cross to Chevron Pipeline’s Salt Lake Products Pipeline segment consists of 4 miles of 8-inch pipeline and is used for product shipments from Holly’s Woods Cross refinery to Chevron’s North Salt Lake pumping station. Holly is the only shipper on these pipelines.

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

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

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

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

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

The 65-mile, 16-inch diameter pipeline was constructed in 2009. This pipeline is used for the shipment of intermediate feedstocks and crude oil from the Navajo refinery Lovington facility to its Artesia facility. Holly is the only shipper on this pipeline.

Lovington / Artesia, New Mexico crude oil pipelines

The crude oil gathering and trunk pipelines deliver crude oil to Holly’s Navajo refinery and consist of 850 miles of 4-inch, 6-inch and 8-inch diameter pipeline. The crude oil trunk pipelines consist of five pipeline segments that deliver crude oil to the Navajo refinery Lovington facility and seven pipeline segments that deliver crude oil to the Navajo refinery Artesia facility.

The Lovington system crude oil mainlines include five pipeline segments consisting of a 23-mile, 12-inch pipeline from Russell to Lovington, a 20-mile, 8-inch pipeline from Russell to Hobbs, an 11-mile, 6-inch and 8-inch pipeline from Crouch to Lovington, a 20-mile, 8-inch pipeline from Hobbs to Lovington and a 6-mile, 6-inch pipeline from Gaines to Hobbs.

The Artesia system crude oil mainlines include seven pipeline segments consisting of an 11-mile, 6-inch pipeline from Beeson to North Artesia, a 7-mile, 4-inch and 6-inch pipeline from Barnsdall to North Artesia, a 2-mile, 8-inch pipeline from the Barnsdall jumper line to Lovington, a 4-mile, 4-inch pipeline from the Artesia Station to North Artesia, a 6-mile, 8-inch pipeline from North Artesia to Evans Junction and a 1-mile, 6-inch pipeline from Abo to Evans Junction.

We operate a 12-mile, 8-inch pipeline from Evans Junction to Artesia, New Mexico that supplies natural gas to the Navajo refinery Artesia facility.

Roadrunner Pipeline

The Roadrunner crude oil pipeline connects the Navajo refinery Lovington facility to a west Texas terminal of the Centurion Pipeline that extends to Cushing, Oklahoma. It was constructed in 2009 and consists of 65 miles of 16-inch pipeline. This pipeline is used for the shipment of crude oil from Cushing to the Navajo refinery Lovington facility.

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Beeson Pipeline

The Beeson crude oil pipeline delivers crude oil to the Navajo refinery Lovington facility. It was constructed in 2009 and consists of 37 miles of 8-inch pipeline. This pipeline ships crude oil from our crude oil gathering system to the Navajo refinery Lovington facility for processing.

Woods Cross, Utah crude oil pipeline

This 4-mile, 12-inch pipeline is used for the shipment of crude oil from Chevron Pipeline’s North Salt Lake City station to the Woods Cross refinery.

REFINED PRODUCT TERMINALS, LOADING RACKS AND REFINERY TANKAGE

Refined Product Terminals and Loading Racks

Our refined product terminals receive products from pipelines connected to Holly’s Navajo and Woods Cross refineries and Alon’s Big Spring refinery. We then distribute them to Holly and third parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally complementary to our pipeline assets and serve Holly’s and Alon’s marketing activities. Terminals play a key role in moving product to the end-user market by providing the following services:

	•		distribution;

	•		blending to achieve specified grades of gasoline;

	•		other ancillary services that include the injection of additives and filtering of jet fuel; and

	•		storage and inventory management.

Typically, our refined product terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that operates 24 hours a day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by our customers. In addition, nearly all of our terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.

Our refined product terminals derive most of their revenues from terminalling fees paid by customers. We charge a fee for transferring refined products from the terminal to trucks or to pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by charging our customers fees for blending, injecting additives, and filtering jet fuel. Holly currently accounts for the substantial majority of our refined product terminal revenues.

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


	Years Ended December 31,
	2010		2009		2008		2007		2006

Refined products terminalled for (bpd):
Holly		178,903		114,431		109,539		119,910		118,202
Third parties		39,568		42,206		32,737		45,457		43,285

Total		218,471		156,637		142,276		165,367		161,487

Total (mbbls)		79,742		57,173		52,073		60,344		58,943

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


	Storage		Number
	Capacity		of	Supply
Terminal Location	(barrels)		Tanks	Source	Mode of Delivery
El Paso, TX		747,000	20	Pipeline/ rail	Truck/Pipeline
Moriarty, NM		189,000	9	Pipeline	Truck
Bloomfield, NM		193,000	7	Pipeline	Truck
Tucson, AZ⁽¹⁾		176,000	9	Pipeline	Truck
Mountain Home, ID⁽²⁾		120,000	3	Pipeline	Pipeline
Boise, ID⁽³⁾		111,000	9	Pipeline	Pipeline
Burley, ID⁽³⁾		70,000	7	Pipeline	Truck
Spokane, WA		333,000	32	Pipeline/Rail	Truck
Abilene, TX		127,000	5	Pipeline	Truck/Pipeline
Wichita Falls, TX		220,000	11	Pipeline	Truck/Pipeline
Roswell, NM ⁽²⁾		25,000	1	Pipeline	Truck
Orla tank farm		135,000	5	Pipeline	Pipeline
Artesia facility truck rack		N/A	N/A	Refinery	Truck
Lovington facility asphalt truck rack		N/A	N/A	Refinery	Truck
Woods Cross facility truck rack		N/A	N/A	Refinery	Truck/Pipeline
Tulsa west facility truck and rail rack		N/A	N/A	Refinery	Truck/Rail/Pipeline
Tulsa east facility truck and rail racks		25,000	N/A	Refinery	Truck/Rail/Pipeline

Total		2,471,000


(1)		The underlying ground at the Tucson terminal is leased.

(2)		Handles only jet fuel.

(3)		We have a 50% ownership interest in these terminals. The capacity and throughput information represents the proportionate share of capacity and throughput attributable to our ownership interest.

El Paso Terminal

We receive light refined products at this terminal from the Navajo refinery Artesia facility through our Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for 93% of the volumes at this terminal. We also receive product from the Big Spring refinery that accounted for 7% of the volumes at this terminal in 2010. Refined products received at this terminal are sold locally via the truck rack or transported to our Tucson terminal and other terminals in Phoenix on Kinder Morgan’s East System pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, Inc., a joint venture pipeline and terminal owned by ConocoPhillips and NuStar Energy, L.P. (“NuStar”) and a terminal connected to the Longhorn Pipeline.

Moriarty Terminal

We receive light refined products at this terminal from the Navajo refinery 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

Tucson Terminal

We own 100% of the improvements and lease the underlying ground at this terminal. The Tucson terminal receives light refined products from Kinder Morgan’s East System pipeline, which transports refined products from the Navajo refinery 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.

Mountain Home Terminal

We receive jet fuel from third parties at this terminal that is transported on Chevron’s Salt Lake City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal through our 13-mile, 4-inch pipeline to the United States Air Force base outside of Mountain Home. Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing, testing and transporting jet fuel at this terminal.

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Boise Terminal

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

Burley Terminal

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

Spokane Terminal

This terminal is connected to the Woods Cross refinery via a Chevron common carrier pipeline. The Spokane terminal also is supplied by Chevron and Yellowstone pipelines and by rail and truck. Refined products received at this terminal are sold locally, via the truck rack. We have several major customers at this terminal. Other terminals in the Spokane area include terminals owned by ExxonMobil and ConocoPhillips.

Abilene Terminal

This terminal receives refined products from the Big Spring refinery, which accounted for all of its volumes in 2010. Refined products received at this terminal are sold locally via a truck rack or pumped over a 2-mile pipeline to Dyess Air Force Base. Alon is the only customer at this terminal.

Wichita Falls Terminal

This terminal receives refined products from the Big Spring refinery, which accounted for all of its volumes in 2010. Refined products received at this terminal are sold via a truck rack or shipped via pipeline connections to Alon’s terminal in Duncan, Oklahoma and also to NuStar’s Southlake Pipeline. Alon is the only customer at this terminal.

Roswell Terminal

This terminal receives jet fuel from the Navajo refinery, which accounted for all of its volumes in 2010, for further transport to Cannon Air Force Base and to Albuquerque, New Mexico. We lease this terminal under an agreement that expires in September 2011.

Orla Tank Farm

The Orla tank farm was constructed in 1998. It receives refined products from the Big Spring refinery that accounted for all of its volumes in 2010. Refined products received at the tank farm are delivered into our Orla to El Paso pipeline. Alon is the only customer at this tank farm.

Artesia Facility Truck Rack

The truck rack at the Navajo refinery 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.

Lovington Facility Asphalt Truck Rack

The asphalt loading rack facility at the Lovington Refinery loads asphalt produced at the Lovington facility onto tanker trucks. Holly is the only customer of this truck rack.

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Woods Cross Facility Truck Rack

The truck rack at the Woods Cross facility loads light refined products produced at the 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.

Tulsa Facilities Truck and Rail Racks

The Tulsa truck and rail loading rack facilities consist of loading racks located at Holly’s Tulsa refinery west and east facilities. Loading racks at the Tulsa refinery west facility consist of rail racks that load refined products and lube oil produced at the refinery onto rail car and a truck rack that loads lube oil onto tanker trucks. Loading racks at the Tulsa refinery east facility consist of truck and rail racks at which we load refined products and off load crude. The truck racks also load asphalt and LPG.

Refinery Tankage

Our refinery tankage consists of on-site tankage at Holly’s Navajo, Woods Cross and Tulsa refineries. Our refinery tankage derives its revenues from fixed fees or throughput charges in providing Holly’s refining facilities with approximately 4,000,000 barrels of storage.

The following table outlines the locations of our refinery tankage, storage capacity, tankage type and number of tanks:


	Storage			Number
	Capacity			of
Refinery Location	(barrels)		Tankage Type	Tanks
Artesia, NM		166,000	Crude oil		2
Lovington, NM		267,000	Crude oil		2
Woods Cross, UT		180,000	Crude oil		3
Tulsa, OK		3,485,000	Crude oil and refined product		59

Total		4,098,000

TRUCK FLEET

We have a truck fleet consisting of 7 trucks and 13 trailers that transport crude oil to Holly’s Wood Cross refinery. Our trucking operations are conducted in Utah only, and Holly is our only customer.

PIPELINE AND TERMINAL CONTROL OPERATIONS

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

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

Item 3. Legal Proceedings

We are a party to various legal and regulatory proceedings, which we believe will not have a material adverse impact on our financial condition, results of operations or cash flows.

Item 4. (Removed and Reserved)

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PART II


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

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


					Cash		Trading
Years Ended December 31,	High		Low		Distributions⁽¹⁾		Volume
2010
Fourth quarter	$	53.74	$	49.16	$	0.845		2,530,800
Third quarter	$	52.16	$	42.17	$	0.835		4,120,000
Second quarter	$	48.17	$	38.41	$	0.825		4,945,100
First quarter	$	44.95	$	38.21	$	0.815		4,583,200

2009
Fourth quarter	$	41.65	$	35.21	$	0.805		5,548,600
Third quarter	$	40.05	$	31.30	$	0.795		2,296,400
Second quarter	$	33.29	$	23.19	$	0.785		5,544,700
First quarter	$	30.43	$	20.96	$	0.775		2,632,700


(1)		Represents cash distributions attributable to each of the quarters in the years ended December 31, 2010 and 2009. Distributions are declared and paid within 45 days following the close of each quarter.

The cash distribution for the fourth quarter of 2010 was declared on January 26, 2011 and is payable on February 14, 2011 to all unitholders of record on February 7, 2011.

As of February 8, 2011, we had approximately 10,300 common unitholders, including beneficial owners of common units held in street name.

We consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our revolving credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our Amended Credit Agreement, occurs or would result from the cash distribution. The indenture relating to our 6.25% and 8.25% Senior Notes prohibits us from making cash distributions under certain circumstances.

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

We make distributions of available cash from operating surplus for any quarter in the following manner: 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; and 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, thereafter. Cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

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


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

In May 2010, all of the conditions necessary to end the subordination period for the 937,500 Class B subordinated units originally issued to Alon were met and the units were converted into our common units on a one-for-one basis.

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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.


	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands, except per unit data)
Statement Of Income Data:

Revenues	$	182,097		$	146,561		$	108,822		$	96,190		$	80,794
Operating costs and expenses
Operations		52,947			44,003			38,920			30,467			26,966
Depreciation and amortization		30,682			26,714			21,937			12,920			12,833
General and administrative		7,719			7,586			6,380			4,914			4,849

		91,348			78,303			67,237			48,301			44,648


Operating income		90,749			68,258			41,585			47,889			36,146

Equity in earnings of SLC Pipeline		2,393			1,919			—			—			—
SLC Pipeline acquisition costs		—			(2,500	)		—			—			—
Interest income		7			11			118			454			899
Interest expense		(34,001	)		(21,501	)		(21,763	)		(13,289	)		(13,056	)
Gain on sale of assets		—			—			36			298			—
Other income		17			67			990			—			—

		(31,584	)		(22,004	)		(20,619	)		(12,537	)		(12,157	)


Income from continuing operations before income taxes		59,165			46,254			20,966			35,352			23,989

State income tax		(296	)		(20	)		(270	)		(200	)		—


Income from continuing operations		58,869			46,234			20,696			35,152			23,989
Income from discontinued operations, net of noncontrolling interest⁽¹⁾		—			19,780			4,671			4,119			3,554

Net income		58,869			66,014			25,367			39,271			27,543
Less general partner interest in net income, including incentive distributions⁽²⁾		12,152			7,947			3,913			3,166			1,858

Limited partners’ interest in net income	$	46,717		$	58,067		$	21,454		$	36,105		$	25,685

Limited partners’ per unit interest in net income — basic and diluted⁽²⁾	$	2.12		$	3.18		$	1.32		$	2.24		$	1.59

Distributions per limited partner unit	$	3.32		$	3.16		$	3.00		$	2.835		$	2.635


Other Financial Data:
EBITDA⁽³⁾	$	123,841		$	100,707		$	70,195		$	66,684		$	55,030
Distributable cash flow⁽⁴⁾	$	91,054		$	72,213		$	60,365		$	51,012		$	47,219
Cash flows from operating activities	$	103,168		$	68,195		$	63,651		$	59,056		$	45,853
Cash flows from investing activities	$	(60,629	)	$	(147,379	)	$	(213,267	)	$	(9,632	)	$	(9,107	)
Cash flows from financing activities	$	(44,644	)	$	76,423		$	144,564		$	(50,658	)	$	(45,774	)
Maintenance capital expenditures⁽⁴⁾	$	4,487		$	3,595		$	3,133		$	1,863		$	1,095
Expansion capital expenditures		56,142			150,149			210,170			8,094			8,012

Total capital expenditures	$	60,629		$	153,744		$	213,303		$	9,957		$	9,107


Balance Sheet Data (at period end):
Net property, plant and equipment	$	434,950		$	398,044		$	257,886		$	125,384		$	127,357
Total assets	$	643,273		$	616,845		$	439,688		$	238,904		$	245,771
Long-term debt⁽⁵⁾	$	491,648		$	390,827		$	355,793		$	181,435		$	180,660
Total liabilities	$	533,901		$	422,981		$	431,568		$	200,348		$	198,582
Total equity⁽⁶⁾	$	109,372		$	193,864		$	8,120		$	38,556		$	47,189


(1)		On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

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(2)		Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.

(3)		Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income plus (i) interest expense net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon U.S. generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants.

Set forth below is our calculation of EBITDA.


	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)

Income from continuing operations	$	58,869		$	46,234		$	20,696		$	35,152		$	23,989

Add (subtract):
Interest expense		30,453			20,620			18,479			12,281			12,088
Amortization of discount and deferred debt issuance costs		1,008			706			1,002			1,008			968
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs		2,540			175			2,282			—			—
Interest income		(7	)		(11	)		(118	)		(454	)		(899	)
State income tax		296			20			270			200			—
Depreciation and amortization		30,682			26,714			21,937			12,920			12,833
EBITDA from discontinued operations (excludes gain on sale of Rio Grande in 2009)		—			6,249			5,647			5,577			6,051


EBITDA	$	123,841		$	100,707		$	70,195		$	66,684		$	55,030


(4)		Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from discontinued operations. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It also is used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

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Set forth below is our calculation of distributable cash flow.


	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)

Income from continuing operations	$	58,869		$	46,234		$	20,696		$	35,152		$	23,989

Add (subtract):
Depreciation and amortization		30,682			26,714			21,937			12,920			12,833
Amortization of discount and deferred debt issuance costs		1,008			706			1,002			1,008			968
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs		2,540			175			2,282			—			—
Equity in excess cash flows over earnings of SLC Pipeline		407			552			—			—			—
Increase (decrease) in deferred revenue		2,035			(7,256	)		11,958			(1,786	)		4,473
SLC Pipeline acquisition costs*		—			2,500			—			—			—
Maintenance capital expenditures**		(4,487	)		(3,595	)		(3,133	)		(1,863	)		(1,095	)
Distributable cash flow from discontinued operations (excludes gain on sale of Rio Grande in 2009)		—			6,183			5,623			5,581			6,051


Distributable cash flow	$	91,054		$	72,213		$	60,365		$	51,012		$	47,219


*		Under accounting standards effective January 1, 2009, we were required to expense rather than capitalize certain acquisition costs of $2.5 million associated with our joint venture agreement with Plains that closed in March 2009. These costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures; accordingly, we have added back these costs to arrive at distributable cash flow.

**		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.

(5)		Includes $159 million, $206 million and $171 million in credit agreement advances that were classified as long-term debt at December 31, 2010, 2009 and 2008, respectively.

(6)		As a master limited partnership, we distribute our available cash, which historically has exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets contributed and acquired from Holly while under common control of Holly had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to partners’ equity.

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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. is a Delaware limited partnership. We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. Holly currently owns a 34% interest in us. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon’s Big Spring refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from Holly certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at Holly’s Tulsa refinery east facility and an asphalt loading rack facility located at Holly’s Navajo refinery facility in Lovington, New Mexico.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, we acquired certain logistics and storage assets for $79.2 million from an affiliate of Sinclair consisting of storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of the Roadrunner Pipeline, a 65-mile, 16-inch crude oil pipeline that connects the Navajo refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma, and the Beeson Pipeline, a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility.

Tulsa West Loading Racks Transaction

On August 1, 2009, we acquired from Holly for $17.5 million certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.

Lovington-Artesia Pipeline Transaction

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SLC Pipeline Joint Venture Interest Transaction

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system that we jointly own with Plains. The SLC Pipeline commenced operations effective March 2009 and allows various refiners in the Salt Lake City area, including Holly’s Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

Holly Capacity Expansion

Also in March 2009 Holly, our largest customer, completed a 15,000 bpsd capacity expansion of its Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.

Rio Grande Pipeline Sale

On December 1, 2009, we sold our 70% interest in Rio Grande to a subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations.

2008 Acquisition

Crude Pipelines and Tankage Transaction

In February 2008, we acquired from Holly certain crude pipelines and tankage assets for $180 million that consist of crude oil trunk lines and gathering lines, product and crude oil pipelines and tankage that service Holly’s Navajo and Woods Cross refineries and a leased jet fuel terminal.

Agreements with Holly and Alon

We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

	•		Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by Holly upon our initial public offering in 2004);

	•		Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from Holly in 2005 and 2009);

	•		Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);

	•		Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in March 2010);

	•		Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);

	•		Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from Holly in 2009);

	•		Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and

	•		Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from Holly in March 2010).

Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at a percentage change based upon the change in the PPI but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or FERC index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.

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We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

At December 31, 2010, contractual minimums under our long-term service agreements are as follows:


	Minimum Annualized
	Commitment
Agreement	(In millions)		Year of Maturity	Contract Type

Holly PTA	$	43.7	2019	Minimum revenue commitment
Holly IPA		20.7	2024	Minimum revenue commitment
Holly CPTA		28.4	2023	Minimum revenue commitment
Holly PTTA		27.2	2024	Minimum revenue commitment
Holly RPA		9.2	2024	Minimum revenue commitment
Holly ETA		2.7	2024	Minimum revenue commitment
Holly ATA		0.5	2025	Minimum revenue commitment
Holly NPA		0.6	2024	Minimum revenue commitment
Alon PTA		22.7	2020	Minimum volume commitment
Alon capacity lease		6.6	Various	Capacity lease


Total	$	162.3

A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.

Under certain provisions of the Omnibus Agreement that we have with Holly, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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

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RESULTS OF OPERATIONS

The following tables present income, distributable cash flow and volume information for the years ended December 31, 2010, 2009 and 2008.


	Years Ended
	December 31,						Change from
	2010			2009			2009
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	48,482		$	43,206		$	5,276
Affiliates — intermediate pipelines		20,998			16,362			4,636
Affiliates — crude pipelines		38,932			29,266			9,666

		108,412			88,834			19,578
Third parties — refined product pipelines		27,954			37,930			(9,976	)

		136,366			126,764			9,602

Terminals and loading racks:
Affiliates		37,964			12,561			25,403
Third parties		7,767			7,236			531

		45,731			19,797			25,934


Total revenues		182,097			146,561			35,536

Operating costs and expenses
Operations		52,947			44,003			8,944
Depreciation and amortization		30,682			26,714			3,968
General and administrative		7,719			7,586			133

		91,348			78,303			13,045


Operating income		90,749			68,258			22,491

Equity in earnings of SLC Pipeline		2,393			1,919			474
SLC Pipeline acquisition costs		—			(2,500	)		2,500
Interest income		7			11			(4	)
Interest expense, including amortization		(34,001	)		(21,501	)		(12,500	)
Other		17			67			(50	)

		(31,584	)		(22,004	)		(9,580	)


Income from continuing operations before income taxes		59,165			46,254			12,911

State income tax		(296	)		(20	)		(276	)


Income from continuing operations		58,869			46,234			12,635

Discontinued operations⁽¹⁾
Income from discontinued operations, net of noncontrolling interest of $1,579		—			5,301			(5,301	)
Gain on sale of interest in Rio Grande		—			14,479			(14,479	)


Income from discontinued operations		—			19,780			(19,780	)

Net income		58,869			66,014			(7,145	)

Less general partner interest in net income, including incentive distributions⁽²⁾		12,152			7,947			4,205


Limited partners’ interest in net income	$	46,717		$	58,067		$	(11,350	)


Limited partners’ earnings per unit — basic and diluted⁽²⁾
Income from continuing operations	$	2.12		$	2.12		$	—
Income from discontinued operations		—			0.28			(0.28	)
Gain on sale of discontinued operations		—			0.78			(0.78	)

Net income	$	2.12		$	3.18		$	(1.06	)


Weighted average limited partners’ units outstanding		22,079			18,268			3,811


EBITDA⁽³⁾	$	123,841		$	100,707		$	23,134


Distributable cash flow⁽⁴⁾	$	91,054		$	72,213		$	18,841


Volumes from continuing operations (bpd)⁽¹⁾
Pipelines:
Affiliates — refined product pipelines		96,094			88,001			8,093
Affiliates — intermediate pipelines		84,277			69,794			14,483
Affiliates — crude pipelines		144,011			137,244			6,767

		324,382			295,039			29,343
Third parties — refined product pipelines		38,910			43,709			(4,799	)

		363,292			338,748			24,544
Terminals and loading racks:
Affiliates		178,903			114,431			64,472
Third parties		39,568			42,206			(2,638	)

		218,471			156,637			61,834

Total for pipelines and terminal assets (bpd)		581,763			495,385			86,378

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	Years Ended
	December 31,						Change from
	2009			2008			2008
	(In thousands, except per unit data)
Revenues
Pipelines:
Affiliates — refined product pipelines	$	43,206		$	40,446		$	2,760
Affiliates — intermediate pipelines		16,362			11,917			4,445
Affiliates — crude pipelines		29,266			22,380			6,886

		88,834			74,743			14,091
Third parties — refined product pipelines		37,930			19,314			18,616

		126,764			94,057			32,707

Terminals and loading racks:
Affiliates		12,561			10,297			2,264
Third parties		7,236			4,468			2,768

		19,797			14,765			5,032


Total revenues		146,561			108,822			37,739

Operating costs and expenses
Operations		44,003			38,920			5,083
Depreciation and amortization		26,714			21,937			4,777
General and administrative		7,586			6,380			1,206

		78,303			67,237			11,066


Operating income		68,258			41,585			26,673

Equity in earnings of SLC Pipeline		1,919			—			1,919
SLC Pipeline acquisition costs		(2,500	)		—			(2,500	)
Interest income		11			118			(107	)
Interest expense, including amortization		(21,501	)		(21,763	)		262
Gain on sale of assets		—			36			(36	)
Other		67			990			(923	)

		(22,004	)		(20,619	)		(1,385	)


Income from continuing operations before income taxes		46,254			20,966			25,288

State income tax		(20	)		(270	)		250


Income from continuing operations		46,234			20,696			25,538

Discontinued operations⁽¹⁾
Income from discontinued operations, net of noncontrolling interest of $1,579 and $1,278 for the years ended December 31, 2009 and 2008, respectively		5,301			4,671			630
Gain on sale of interest in Rio Grande		14,479			—			14,479


Income from discontinued operations		19,780			4,671			15,109


Net income		66,014			25,367			40,647

Less general partner interest in net income, including incentive distributions⁽²⁾		7,947			3,913			4,034


Limited partners’ interest in net income	$	58,067		$	21,454		$	36,613


Limited partners’ earnings per unit — basic and diluted⁽²⁾
Income from continuing operations	$	2.12		$	1.04		$	1.08
Income from discontinued operations		0.28			0.28			—
Gain on sale of discontinued operations		0.78			—			0.78

Net income	$	3.18		$	1.32		$	1.86


Weighted average limited partners’ units outstanding		18,268			16,291			1,977


EBITDA⁽³⁾	$	100,707		$	70,195		$	30,512


Distributable cash flow⁽⁴⁾	$	72,213		$	60,365		$	11,848


Volumes from continuing operations (bpd)⁽¹⁾
Pipelines:
Affiliates — refined product pipelines		88,001			83,203			4,798
Affiliates — intermediate pipelines		69,794			58,855			10,939
Affiliates — crude pipelines		137,244			111,426			25,818

		295,039			253,484			41,555
Third parties — refined product pipelines		43,709			22,756			20,953

		338,748			276,240			62,508

Terminals and loading racks:
Affiliates		114,431			109,539			4,892
Third parties		42,206			32,737			9,469

		156,637			142,276			14,361

Total for pipelines and terminal assets (bpd)		495,385			418,516			76,869

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(1)		On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations. Pipeline volume information excludes volumes attributable to Rio Grande.

(2)		Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.

(3)		EBITDA is calculated as net income plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. See our calculation of EBITDA under Item 6, “Selected Financial Data.”

(4)		Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from discontinued operations. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. See our calculation of distributable cash flow under Item 6, “Selected Financial Data.”

Results of Operations — Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Summary

Income from continuing operations for the year ended December 31, 2010 was $58.9 million, a $12.6 million increase compared to the year ended December 31, 2009. This increase in overall earnings was due principally to earnings attributable to our 2009 and March 2010 asset acquisitions and overall increased shipments on our pipeline systems. These factors were partially offset by a decrease in previously deferred revenue realized and increased operating costs and expenses and interest expense.

Revenues for the year ended December 31, 2010 include the recognition of $8.4 million of prior shortfalls billed to shippers in 2009 as they did not meet their minimum volume commitments in any of the subsequent four quarters. Revenues of $10.4 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the year ended December 31, 2010. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels or in 2011 when shipping rights expire unused after a twelve-month period.

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Revenues

Total revenues from continuing operations for the year ended December 31, 2010 were $182.1 million, a $35.5 million increase compared to the year ended December 31, 2009. This increase is due principally to revenues attributable to our recent asset acquisitions and higher tariffs on affiliate shipments, partially offset by a $7.3 million decrease in previously deferred revenue realized. For 2010, overall pipeline shipments were up 7%, reflecting increased affiliate volumes attributable to Holly’s first quarter of 2009 Navajo refinery expansion, including volumes shipped on our new 16-inch intermediate and Beeson pipelines, partially offset by a decrease in third-party shipments. Additionally, prior year affiliate shipments reflect lower volumes as a result of production downtime during a major maintenance turnaround of the Navajo refinery during the first quarter of 2009. Overall terminal and loading rack volumes were also up in 2010, increasing 39% over 2009 levels due principally to volumes transferred and stored at our Tulsa storage and rack facilities.

Revenues from our refined product pipelines were $76.4 million, a decrease of $4.7 million compared to the year ended December 31, 2009. This decrease was due principally to an $8.5 million decrease in previously realized deferred revenue that was partially offset by an overall increase in refined product pipeline shipments. Volumes shipped on our refined product pipeline system averaged 135 thousand barrels per day (“mbpd”) compared to 131.7 mbpd for the year ended December 31, 2009, reflecting an increase in affiliate shipments, partially offset by a decline in third-party shipments.

Revenues from our intermediate pipelines were $21 million, an increase of $4.6 million compared to the year ended December 31, 2009. This increase was due principally to increased shipments on our intermediate pipeline system combined with a $1.2 million increase in previously deferred revenue realized. Volumes shipped on our intermediate product pipeline system increased to an average of 84.3 mbpd compared to 69.8 mbpd for 2009.

Revenues from our crude pipelines were $38.9 million, an increase of $9.7 million compared to the year ended December 31, 2009. This increase was due principally to an $8.4 million year-over-year increase in revenues attributable to our Roadrunner Pipeline agreement. Volumes shipped on our crude pipeline system increased to an average of 144 mbpd compared to 137.2 mbpd for 2009.

Revenues from terminal, tankage and loading rack fees were $45.7 million, an increase of $25.9 million compared to the year ended December 31, 2009. This includes a $24.7 million year-over-year increase in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities. Refined products terminalled in our facilities increased to an average of 218.5 mbpd compared to 156.6 mbpd for 2009.

Operations Expense

Operations expense for the year ended December 31, 2010 increased by $8.9 million compared to the year ended December 31, 2009. This increase was due principally to costs attributable to overall higher throughput volumes, including those from our recent asset acquisitions, and higher maintenance and payroll costs.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2010 increased by $4 million compared to the year ended December 31, 2009. This increase is attributable to our 2009 and March 2010 asset acquisitions and capital projects. Additionally, effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years resulting in a $3 million reduction in depreciation expense for the year ended December 31, 2010.

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General and Administrative

General and administrative costs for the year ended December 31, 2010 of $7.7 million was relatively flat compared to $7.6 million for the year ended December 31, 2009.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $2.4 million and $1.9 million for the years ended December 31, 2010 and December 31, 2009, respectively.

SLC Pipeline Acquisition Costs

We incurred a $2.5 million finder’s fee in connection with the acquisition our SLC Pipeline joint venture interest in March 2009. As a result of accounting requirements effective January 1, 2009, we were required to expense rather than capitalize these direct acquisition costs.

Interest Expense

Interest expense for the year ended December 31, 2010 totaled $34 million, an increase of $12.5 million compared to the year ended December 31, 2009. This increase reflects interest on our 8.25% senior notes and costs of $1.1 million from a partial settlement of an interest rate swap. For the years ended December 31, 2010 and 2009, fair value adjustments to our interest rate swaps resulted in $1.5 million and $0.2 million, respectively, in non-cash interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 6.8% for the year ended December 31, 2010 compared to 5.3% for 2009.

State Income Tax

We recorded state income taxes of $296,000 and $20,000 for the years ended December 31, 2010 and 2009, respectively, which are solely attributable to the Texas margin tax. State income taxes for the year ended December 31, 2009 are presented net of a $167,000 tax refund resulting from over-estimates of prior year margin taxes.

Discontinued Operations

We sold our interest in Rio Grande on December 1, 2009. Income from discontinued operations for the year ended December 31, 2009 includes a gain from the sale of our 70% interest in Rio Grande of $14.5 million. Rio Grande operations generated earnings of $6.9 million for the year ended December 31, 2009, presented net of earnings attributable to noncontrolling interest holders of $1.6 million.

Results of Operations — Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Summary

Income from continuing operations for the year ended December 31, 2009 was $46.2 million, a $25.5 million increase compared to the year ended December 31, 2008. This increase in overall earnings was due principally to overall increased shipments on our pipeline systems, earnings attributable to our 2009 asset acquisitions, the effect of the annual tariff increase on affiliate pipeline shipments and an increase in previously deferred revenue realized.

Revenues for the year ended December 31, 2009 include the recognition of $15.7 million of prior shortfalls billed to shippers in 2008 as they did not meet their minimum volume commitments in any of the subsequent four quarters. Revenues of $8.4 million relating to deficiency payments associated with certain guaranteed shipping contracts was deferred during the year ended December 31, 2009 and was recognized in 2010 when shipping rights expired unused after a twelve-month period.

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Revenues

Total revenues from continuing operations for the year ended December 31, 2009 were $146.6 million, a $37.7 million increase compared to the year ended December 31, 2008. This increase was due principally to overall increased shipments on our pipeline systems, increased revenues attributable to our crude pipeline assets acquired in the first quarter of 2008, the effect of annual tariff increases on affiliate pipeline shipments, an increase in previously deferred revenue realized and revenues attributable to our Tulsa facilities acquired in 2009. Increased volumes attributable to Holly’s Navajo refinery expansion in the first quarter of 2009, including volumes shipped on our new 16-inch intermediate and Beeson pipelines acquired in 2009 contributed to an increase in affiliate pipeline shipments. Affiliate shipments for the year ended December 31, 2009 were also impacted by the effects of reduced production during Holly’s planned maintenance turnaround of its Navajo refinery in the first quarter of 2009. Additionally, third-party refined product shipments were up for 2009 compared to 2008, which had been down as a result of limited production resulting from an explosion and fire at Alon’s Big Spring refinery in the first quarter of 2008.

On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that resulted in the shutdown of production. In early April 2008, Alon reopened its Big Spring refinery and resumed production at approximately one-half of refining capacity until production was restored in late September and later increased to full capacity during the fourth quarter of 2008. Lost production and reduced operations attributable to this incident resulted in a decrease in third-party shipments on our refined product pipelines during the first nine months of 2008.

Revenues from our refined product pipelines were $81.1 million, an increase of $21.4 million compared to the year ended December 31, 2008. This increase was due principally to increased shipments on our refined product pipeline system, the effect of the annual tariff increase on affiliate refined product shipments and a $10.7 million increase in previously deferred revenue realized. Volumes shipped on our refined product pipeline system increased to an average of 131.7 mbpd compared to 106 mbpd for 2008.

Revenues from our intermediate pipelines were $16.4 million, an increase of $4.4 million compared to the year ended December 31, 2008. This increase was due principally to increased shipments on our intermediate pipeline system including volumes shipped on our 16-inch pipeline acquired in 2009, the effect of the annual tariff increase on intermediate pipeline shipments and a $1.1 million increase in previously deferred revenue realized. Volumes shipped on our intermediate product pipeline system increased to an average of 69.8 mbpd compared to 58.9 mbpd for 2008.

Revenues from our crude pipelines were $29.3 million, an increase of $6.9 million compared to the year ended December 31, 2008. This increase was due principally to the realization of revenues from crude oil shipments for a full twelve-month period during the year ended December 31, 2009 compared to ten months of shipments during 2008 due to the commencement of operations on March 1, 2008, increased shipments on our crude pipeline system and the effect of the annual tariff increase. Additionally, this increase includes $0.8 million in revenues attributable to our Roadrunner Pipeline transportation agreement with Holly. Volumes shipped on our crude pipeline system increased to an average of 137.2 mbpd compared to 111.4 mbpd for 2008.

Revenues from terminal, tankage and loading rack fees were $19.8 million, an increase of $5 million compared to the year ended December 31, 2008. This increase includes $2.5 million in revenues attributable to volumes transferred via our Tulsa facilities acquired in 2009. Refined products terminalled in our facilities increased to an average of 156.6 mbpd compared to 142.3 mbpd for 2008.

Operations Expense

Operations expense for the year ended December 31, 2009 increased by $5.1 million compared to the year ended December 31, 2008. This increase was due principally to costs attributable to higher throughput volumes, including those from our 2009 asset acquisitions, and higher maintenance and payroll expense.

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Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2009 increased by $4.8 million compared to the year ended December 31, 2008. This increase was attributable to our 2009 and 2008 asset acquisitions and capital projects.

General and Administrative

General and administrative costs for the year ended December 31, 2009 increased by $1.2 million compared to the year ended December 31, 2008, due principally to increased professional fees related to our 2009 asset acquisitions.

Equity in Earnings of SLC Pipeline

The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $1.9 million for the year ended December 31, 2009.

SLC Pipeline Acquisition Costs

We incurred a $2.5 million finder’s fee in connection with the acquisition our SLC Pipeline joint venture interest in March 2009.

Interest Expense

Interest expense for the year ended December 31, 2009 totaled $21.5 million, a decrease of $0.3 million compared to the year ended December 31, 2008. For the years ended December 31, 2009 and 2008, fair value adjustments to our interest rate swaps resulted in $0.2 million and $2.3 million, respectively, in non-cash interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 5.3% for the year ended December 31, 2009 compared to 5.4% for 2008.

State Income Tax

We recorded state income taxes of $20,000 and $270,000 for the years ended December 31, 2009 and 2008, respectively, which are solely attributable to the Texas margin tax. State income taxes for the year ended December 31, 2009 are presented net of a $167,000 tax refund resulting from over-estimates of prior year margin taxes.

Discontinued Operations

Income from discontinued operations for the year ended December 31, 2009 includes a gain from the sale of our 70% interest in Rio Grande of $14.5 million in December 2009. Rio Grande operations generated earnings of $6.9 million and $5.9 million for the years ended December 31, 2009 and 2008, respectively. Rio Grande earnings for the years ended December 31, 2009 and 2008 are presented net of earnings attributable to noncontrolling interest holders of $1.6 million and $1.3 million, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Overview

At December 31, 2010, we had a $300 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”). During the year ended December 31, 2010, we received advances totaling $66 million and repaid $113 million, resulting in the net repayment of $47 million in advances under the Credit Agreement and an outstanding balance of $159 million at December 31, 2010. These advances were used to finance acquisitions and capital projects. As of December 31, 2010, we had no working capital borrowings.

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On February 14, 2011 we amended the Credit Agreement, slightly reducing the size from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The Amended Credit Agreement expires in February 2016 and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Amended Credit Agreement is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit.

If any particular lender under the Amended Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Amended Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

In March 2010, we issued $150 million in aggregate principal amount of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”). A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

Our 6.25% senior notes having an aggregate principal amount outstanding of $185 million mature March 1, 2015 and are registered with the SEC (the “6.25% Senior Notes”). The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and have certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise $860 million through security offerings, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

We believe our current cash balances, future internally generated funds and funds available under the Amended Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

In February, May, August and November 2010, we paid regular quarterly cash distributions of $0.805, $0.815, $0.825 and $0.835, respectively, on all units, an aggregate amount of $84.4 million. Included in these distributions was $10.3 million paid to the general partner as incentive distributions.

Cash flows from continuing and discontinued operations have been combined for presentation purposes in the Consolidated Statements of Cash Flows. For the years ended December 31, 2009 and 2008, net cash flows from our discontinued Rio Grande operations were $37.6 million and $3.5 million, respectively. Net cash flows from discontinued operations for 2009 include $35 million in proceeds received upon the sale of our Rio Grande interest.

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Cash and cash equivalents decreased by $2.1 million during the year ended December 31, 2010. The combined cash flows used for investing and financing activities of $60.6 million and $44.6 million, respectively, exceeded cash flows provided by operating activities of $103.2 million. Working capital decreased by $12.2 million to $(7.8) million during the year ended December 31, 2010.

Cash Flows — Operating Activities

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Cash flows from operating activities increased by $35 million from $68.2 million for the year ended December 31, 2009 to $103.2 million for the year ended December 31, 2010. This increase is due principally to $38 million in additional cash collections from our major customers, resulting from increased revenues, partially offset by year-over-year changes in payments attributable to costs of increased operations and interest.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. For the year ended December 31, 2010, we received cash payments of $11.7 million under these commitments. We billed $8.4 million during the year ended December 31, 2009 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2010. Another $1.4 million is included in our accounts receivable at December 31, 2010 related to shortfalls that occurred in the fourth quarter of 2010.

Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Cash flows from operating activities increased by $4.5 million from $63.7 million for the year ended December 31, 2008 to $68.2 million for the year ended December 31, 2009. This increase is due principally to $12.4 million in additional cash collections from our major customers, resulting principally from increased revenues, partially offset by year-over-year changes in payments attributable to increased operations.

For the year ended December 31, 2009, we received cash payments of $8.6 million under minimum volume shipping commitments. We billed $15.7 million during the year ended December 31, 2008 related to shortfalls that subsequently expired without recapture and was recognized as revenue during the year ended December 31, 2009. Another $2.7 million is included in our accounts receivable at December 31, 2009 related to shortfalls that occurred in the fourth quarter of 2009.

Cash Flows — Investing Activities

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Cash flows used for investing activities decreased by $86.8 million from $147.4 million for the year ended December 31, 2009 to $60.6 million for the year ended December 31, 2010. During the year ended December 31, 2010, we acquired storage assets from Holly for $35.5 million and invested $25.1 million in additions to properties and equipment. During the year ended December 31, 2009, we paid $95.1 million with respect to our asset acquisitions from Holly, consisting of a 16-inch intermediate pipeline, loading rack facilities in Tulsa, Oklahoma and the Roadrunner and Beeson Pipelines. We also paid $25.7 million in cash upon our purchase of the logistics and storage assets from Sinclair and purchased our 25% joint venture interest in the SLC Pipeline for $25.5 million. Additionally, we invested $33 million in additions to properties and equipment for the year ended December 31, 2009. These additions relate principally to the expansion of our pipeline system between Artesia, New Mexico and El Paso, Texas, the South System. On December 1, 2009, we sold our 70% interest in Rio Grande for $35 million. Proceeds received are presented net of Rio Grande’s cash balance of $3.1 million

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Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Cash flows used for investing activities decreased by $65.9 million from $213.3 million for the year ended December 31, 2008 to $147.4 million for the year ended December 31, 2009. During the year ended December 31, 2009, we paid $95.1 million with respect to our asset acquisitions from Holly, consisting of a 16-inch intermediate pipeline, loading rack facilities in Tulsa, Oklahoma and the Roadrunner and Beeson Pipelines. We also paid $25.7 million in cash upon our purchase of the logistics and storage assets from Sinclair and purchased our 25% joint venture interest in the SLC Pipeline for $25.5 million. Additionally, we invested $33 million in additions to properties and equipment for the year ended December 31, 2009 compared to $42.3 million for the year ended December 31, 2008. These additions relate principally to the expansion of our pipeline system between Artesia, New Mexico and El Paso, Texas, the South System. On December 1, 2009, we sold our 70% interest in Rio Grande for $35 million. Proceeds received are presented net of Rio Grande’s cash balance of $3.1 million. During the year ended December 31, 2008, we paid $171 million in connection with our purchase of the crude pipelines and tankage assets from Holly in February 2008.

Cash Flows — Financing Activities

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Cash flows used for financing activities were $44.6 million for the year ended December 31, 2010, a decrease of $121 million compared to cash flows provided by financing activities of $76.4 million for the year ended December 31, 2009. During the year ended December 31, 2010, we received $66 million and repaid $113 million in advances under the Credit Agreement. Also, we received $147.5 million in net proceeds and incurred $0.5 million in financing costs upon the issuance of the 8.25% Senior Notes. During the year ended December 31, 2010, we paid $84.4 million in regular quarterly cash distributions to our general and limited partners, paid $57.6 million in excess of Holly’s transferred basis in the storage assets acquired in March 2010 and paid $2.7 million for the purchase of common units for recipients of our restricted unit incentive grants. During the year ended December 31, 2009, we received $239 million and repaid $233 million in advances under the Credit Agreement. Also, we received $133.3 million in proceeds and incurred $0.3 million in costs with respect to our November and May 2009 equity offerings. During the year ended December 31, 2009, we paid $61.2 million in regular quarterly cash distributions to our general and limited partners, paid $3.1 million in excess of Holly’s transferred basis in the assets acquired from Holly in 2009 and paid $1.5 million in distributions to noncontrolling interest holders in Rio Grande. Additionally during 2009, we received $3.8 million in capital contributions from our general partner and paid $0.6 million for the purchase of common units for recipients of our restricted unit incentive grants.

Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Cash flows provided by financing activities decreased by $68.2 million from $144.6 million for the year ended December 31, 2008 to $76.4 million for the ended December 31, 2009. During the year ended December 31, 2009, we received $239 million and repaid $233 million in advances under the Credit Agreement. Also, we received $133.3 million in proceeds and incurred $0.3 million in costs with respect to our November and May 2009 equity offerings. During the year ended December 31, 2009, we paid $61.2 million in regular quarterly cash distributions to our general and limited partners, paid $3.1 million in excess of Holly’s transferred basis in the assets acquired from Holly in 2009 and paid $1.5 million in distributions to noncontrolling interest holders in Rio Grande. Additionally during 2009, we received $3.8 million in capital contributions from our general partner and paid $0.6 million for the purchase of common units for recipients of our restricted unit incentive grants. During the year ended December 31, 2008, we received net advances of $200 million under the Credit Agreement of which $171 million were used to finance the cash portion of the consideration paid to acquire the crude pipelines and tankage assets. During the year ended December 31, 2008, we paid $52.4 million in distributions on all units including the general partner interest and paid $1.8 million in distributions to noncontrolling interest holders in Rio Grande. Additionally in 2008, we paid $0.8 million for the purchase of our common units for restricted unit grants and paid $0.7 million in deferred financing costs that were attributable to the amendment to our Credit Agreement.

Capital Requirements

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We have an option agreement with Holly, granting us an option to purchase Holly’s 75% equity interest in the UNEV Pipeline, a joint venture pipeline currently under construction that will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. Under this agreement, we have an option to purchase Holly’s equity interest in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The current total cost of the pipeline project including terminals is expected to be approximately $325 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. The pipeline is in the final construction phase and is expected to be mechanically complete in the second quarter of 2011.

We expect that our currently planned sustaining and maintenance capital expenditures as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline described above, will be funded with existing cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our Amended Credit Agreement, or a combination thereof. With volatility and uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Amended Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline. We are not obligated to purchase the UNEV Pipeline nor are we subject to any fees or penalties if HLS’ board of directors decides not to proceed with this opportunity.

Credit Agreement

Our $275 million Amended Credit Agreement expires in February 2016; provided that the Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% Senior Notes have not been repurchased, refinanced, extended or repaid. The Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes.

Our obligations under the Amended Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Amended Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our material, wholly-owned subsidiaries. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

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Indebtedness under the Amended Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 1.00% to 2.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 2.00% to 3.00%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Amended Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Amended Credit Agreement). We incur a commitment fee on the unused portion of the Amended Credit Agreement at a rate ranging from 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

The Amended Credit Agreement imposes certain requirements on us including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes

The 6.25% Senior Notes and 8.25% Senior Notes are unsecured and impose certain restrictive covenants which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

Our purchase and contribution agreements with Holly with respect to the intermediate pipelines and the crude pipelines and tankage assets restrict us from selling pipelines and terminals acquired from Holly and from prepaying borrowings and long-term debt to outstanding balances below $35 million and $171 million prior to 2015 and 2018, respectively, in each case subject to certain limited exceptions.

Long-term Debt

The carrying amounts of our long-term debt are as follows:


	December 31,
	2010			2009
	(In thousands)

Credit Agreement	$	159,000		$	206,000

6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(1,584	)		(1,964	)
Unamortized premium — dedesignated fair value hedge		1,444			1,791

		184,860			184,827


8.25% Senior Notes
Principal		150,000			—
Unamortized discount		(2,212	)		—

		147,788			—


Total long-term debt	$	491,648		$	390,827

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Our interest rate swap contracts are discussed under “Risk Management.”

Long-term Contractual Obligations

The following table presents our long-term contractual obligations as of December 31, 2010.


			Payments Due by Period
			Less than						Over 5
	Total		1 Year		1-3 Years		3-5 Years		Years
	(In thousands)

Long-term debt — principal	$	494,000	$	—	$	—	$	185,000	$	309,000
Long-term debt — interest		161,228		27,134		54,269		48,488		31,337
Pipeline operating lease		40,619		6,249		12,498		12,498		9,374
Right-of-way leases		1,805		296		456		341		712
Other		9,814		1,135		2,120		2,120		4,439


Total	$	707,466	$	34,814	$	69,343	$	248,447	$	354,862

Our long-term debt consists of $185 million, $150 million and $159 million in outstanding principal under the 6.25% Senior Notes, the 8.25% Senior Notes and the Credit Agreement, respectively. The Credit Agreement was amended on February 14, 2011; the Amended Credit Agreement expires in 2016.

The pipeline operating lease amounts above reflect the exercise of the first of three 10-year extensions, expiring in 2017, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico. However, these amounts exclude the second and third 10-year lease extensions, which based on the current outlook, are likely to be exercised.

Most of our right-of-way agreements are renewable on an annual basis, and the right-of-way lease payments above include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2010. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right-of-way expenses in addition to the payments listed.

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, 2010, 2009 and 2008.

A substantial majority of our revenues are generated under long-term contracts that provide for increases in our rates and minimum revenue guarantees annually for increases in the PPI. Historically, the PPI has increased an average of 3% annually over the past 5 calendar years. This is no indication of PPI increases to be realized in the future. Furthermore, certain of our long-term contracts have provisions that limit the level of annual PPI percentage rate increases.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil 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.

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There are environmental remediation projects that are currently in progress that relate to certain assets acquired from Holly. Certain of these projects were underway prior to our purchase and represent liabilities of Holly Corporation as the obligation for future remediation activities was retained by Holly. At December 31, 2010, we have an accrual of $0.3 million that relates to environmental clean-up projects for which we have assumed liability. The remaining projects, including assessment and monitoring activities, are covered under the Holly environmental indemnification discussed above and represent liabilities of Holly Corporation.

CRITICAL ACCOUNTING POLICIES

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

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals. Additional pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in the capacity of one of our pipelines.

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Billings to customers for obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

•

the customer receives the future services provided by these billings,

•

the period in which the customer is contractually allowed to receive the services expires, or

•

we determine a high likelihood that we will not be required to provide services within the allowed period.

We will recognize shortfall billings as revenue prior to the expiration of the contractual term period to provide services only when we determine with a high likelihood that we will not be required to provide services within the allowed period. We determine this when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period or the customer acknowledges that its anticipated shipment levels will not permit it to utilize such a shortfall credit within the respective contractual make-up period. To date, we have not recognized any shortfall billings as revenue prior to the expiration of the contractual term period.

Long-Lived Assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results, and actual results could differ from those estimates.

We have evaluated our transportation agreements for impairment as of December 31, 2010 and determined that projected cash flows to be received under these agreements substantially exceed our carrying balances. Furthermore, there were no impairments of our long-lived assets during the years ended December 31, 2010, 2009 and 2008.

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.

RISK MANAGEMENT

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of December 31, 2010, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This interest rate swap effectively converts $155 million of our LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin of 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2010. This swap contract matures in February 2013.

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We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on $155 million of our variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive loss. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swap against the expected future interest payments on $155 million of our variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive loss to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.

Additional information on our interest rate swaps are as follows:


	Balance Sheet			Location of Offsetting	Offsetting
Derivative Instrument	Location	Fair Value		Balance	Amount
	(In thousands)
December 31, 2010

*Interest rate swap designated as cash flow hedging instrument:*

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026


December 31, 2009

*Interest rate swap designated as cash flow hedging instrument:*

Variable-to-fixed interest rate swap contract ($171 million of LIBOR based debt interest)	Other long-term liabilities	$	9,141	Accumulated other comprehensive loss	$	9,141


*Interest rate swaps not designated as hedging instruments:*

Fixed-to-variable interest rate swap contract ($60 million of 6.25% Senior Notes interest)	Other assets	$	2,294	Long-term debt	$	1,791	⁽¹⁾

				Equity		503	⁽²⁾

		$	2,294		$	2,294


Variable-to-fixed interest rate swap contract ($60 million of 6.25% Senior Notes interest)	Other long-term liabilities	$	2,555	Equity	$	2,555	⁽²⁾


(1)		Represents unamortized balance of deferred hedge premium.

(2)		Represents prior year charges to interest expense.

In May 2010, we repaid $16 million of our Credit Agreement debt and also settled a corresponding portion of our interest rate swap agreement having a notional amount of $16 million for $1.1 million. Upon payment, we reduced our swap liability and reclassified a $1.1 million charge from accumulated other comprehensive loss to interest expense, representing the application of hedge accounting prior to settlement.

In the first quarter of 2010, we settled two interest rate swaps. We had an interest rate swap contract that effectively converted interest expense associated with $60 million of our 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). We had an additional interest rate swap contract that effectively unwound the effects of the Variable Rate Swap, converting $60 million of the previously hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”), effectively fixing interest at a 4.75% rate. Upon settlement of the Variable Rate and Fixed Rate Swaps, we received $1.9 million and paid $3.6 million, respectively.

For the years ended December 31, 2010, 2009 and 2008, we recognized $1.5 million, $0.2 million and $2.3 million, respectively, in non-cash charges to interest expense as a result of fair value adjustments to our interest rate swaps.

We review publicly available information on our counterparty in order to review and monitor its financial stability and assess its ongoing ability to honor its commitments under the interest rate swap contract. This counterparty is a large financial institution. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparty honoring its respective commitments.

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

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At December 31, 2010, we had an outstanding principal balance on our 6.25% Senior Notes and 8.25% Senior Notes of $185 million and $150 million, respectively. A change in interest rates would generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At December 31, 2010, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $183.2 million and $156.8 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.25% Senior Notes and 8.25% Senior Notes at December 31, 2010 would result in a change of approximately $4.3 million and $6.3 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2010, borrowings outstanding under the Credit Agreement were $159 million. By means of our cash flow hedge, we have effectively converted the variable rate on $155 million of outstanding borrowings to a fixed rate of 5.49%.

At December 31, 2010, our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from our senior management. This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.


Item 7A.		Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” above for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”

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

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Item 8.		Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE PARTNERSHIP’S INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Holly Energy Partners, L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the Partnership’s internal control over financial reporting as of December 31, 2010 using the criteria for effective control over financial reporting established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concludes that, as of December 31, 2010, the Partnership maintained effective internal control over financial reporting.

The Partnership’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010. That report appears on page 69.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Holly Energy Partners, L.P.’s (the “Partnership”) internal control over financial reporting as of December 31 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Partnership’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report. Our responsibility is to express an opinion on the effectiveness of the partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Holly Energy Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Holly Energy Partners, L.P. as of December 31, 2010 and 2009, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2010, our report dated February 16, 2011, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 16, 2011

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Index to Consolidated Financial Statements


	Page
	Reference

Report of Independent Registered Public Accounting Firm		71

Consolidated Balance Sheets at December 31, 2010 and 2009		72

Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		73

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		74

Consolidated Statements of Partners’ Equity for the years ended December 31, 2010, 2009 and 2008		75

Notes to Consolidated Financial Statements		76

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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, 2010 and 2009, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Energy Partners, L.P. at December 31, 2010 and 2009, and the related consolidated results of its operations and its cash flows, for each of the three years in the period ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 16, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 16, 2011

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Holly Energy Partners, L.P.

Consolidated Balance Sheets


	December 31,
	2010			2009
	(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	403		$	2,508
Accounts receivable:
Trade		3,544			4,693
Affiliates		18,964			14,074

		22,508			18,767

Prepaid and other current assets		775			739
Current assets of discontinued operations		—			2,195

Total current assets		23,686			24,209

Properties and equipment, net		434,950			398,044
Transportation agreements, net		108,489			115,436
Goodwill		49,109			49,109
Investment in SLC Pipeline		25,437			25,919
Other assets		1,602			4,128


Total assets	$	643,273		$	616,845


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	6,347		$	3,860
Affiliates		3,891			2,351

		10,238			6,211
Accrued interest		7,517			2,863
Deferred revenue		10,437			8,402
Accrued property taxes		1,990			1,072
Other current liabilities		1,262			1,257

Total current liabilities		31,444			19,805

Long-term debt		491,648			390,827
Other long-term liabilities		10,809			12,349

Partners’ Equity:
Common unitholders (22,078,509 and 21,141,009 units issued and outstanding at December 31, 2010 and 2009, respectively)		261,317			275,553
Class B subordinated unitholders (937,500 units issued and outstanding at December 31, 2009)		—			21,426
General partner interest (2% interest)		(141,919	)		(93,974	)
Accumulated other comprehensive loss		(10,026	)		(9,141	)

Total partners’ equity		109,372			193,864


Total liabilities and partners’ equity	$	643,273		$	616,845

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Income


	Years Ended December 31,
	2010			2009			2008
	(In thousands, except per unit data)
Revenues:
Affiliates	$	146,376		$	101,395		$	85,040
Third parties		35,721			45,166			23,782

		182,097			146,561			108,822


Operating costs and expenses:
Operations		52,947			44,003			38,920
Depreciation and amortization		30,682			26,714			21,937
General and administrative		7,719			7,586			6,380

		91,348			78,303			67,237


Operating income		90,749			68,258			41,585

Other income (expense):
Equity in earnings of SLC Pipeline		2,393			1,919			—
SLC Pipeline acquisition costs		—			(2,500	)		—
Interest income		7			11			118
Interest expense		(34,001	)		(21,501	)		(21,763	)
Gain on sale of assets		—			—			36
Other		17			67			990

		(31,584	)		(22,004	)		(20,619	)


Income from continuing operations before income taxes		59,165			46,254			20,966

State income tax		(296	)		(20	)		(270	)


Income from continuing operations		58,869			46,234			20,696

Discontinued operations
Income from discontinued operations, net of noncontrolling interest of $1,579 and $1,278 for the years ended December 31, 2009 and 2008, respectively		—			5,301			4,671
Gain on sale of interest in Rio Grande Pipeline Company		—			14,479			—

Income from discontinued operations		—			19,780			4,671


Net income		58,869			66,014			25,367

Less general partner interest in net income, including incentive distributions		12,152			7,947			3,913


Limited partners’ interest in net income	$	46,717		$	58,067		$	21,454


Limited partners’ per unit interest in earnings — basic and diluted:
Income from continuing operations	$	2.12		$	2.12		$	1.04
Income from discontinued operations		—			0.28			0.28
Gain on sale of discontinued operations		—			0.78			—

Net income	$	2.12		$	3.18		$	1.32


Weighted average limited partners’ units outstanding		22,079			18,268			16,291

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows


	Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾
	(In thousands)
Cash flows from operating activities
Net Income	$	58,869		$	66,014		$	25,367
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		30,682			27,597			22,889
Equity in earnings of SLC Pipeline, net of distributions		482			(419	)		—
Change in fair value — interest rate swaps		1,464			175			2,282
Noncontrolling interest in earnings of Rio Grande Pipeline Company		—			1,579			1,278
Amortization of restricted and performance units		2,214			699			1,688
Gain on sale of interest in Rio Grande Pipeline Company		—			(14,479	)		—
Gain on sale of assets		—			—			(36	)
(Increase) decrease in current assets:
Accounts receivable — trade		1,149			388			1,529
Accounts receivable — affiliates		(4,890	)		(4,679	)		(3,695	)
Prepaid and other current assets		(36	)		(146	)		(47	)
Current assets of discontinued operations		2,195			—			—
Increase (decrease) in current liabilities:
Accounts payable — trade		2,487			(1,956	)		2,805
Accounts payable — affiliates		1,540			149			(3,819	)
Accrued interest		4,654			18			(151	)
Deferred revenue		2,035			(7,256	)		11,958
Accrued property taxes		918			(74	)		(32	)
Other current liabilities		5			(248	)		678
Other, net		(600	)		833			957

Net cash provided by operating activities		103,168			68,195			63,651


Cash flows from investing activities
Additions to properties and equipment		(25,103	)		(32,999	)		(42,303	)
Acquisitions of assets from Holly Corporation		(35,526	)		(95,080	)		(171,000	)
Acquisition of logistics assets from Sinclair Oil Company		—			(25,665	)		—
Investment in SLC Pipeline		—			(25,500	)		—
Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash		—			31,865			—
Proceeds from sale of assets		—			—			36

Net cash used for investing activities		(60,629	)		(147,379	)		(213,267	)


Cash flows from financing activities
Borrowings under credit agreement		66,000			239,000			285,000
Repayments of credit agreement borrowings		(113,000	)		(233,000	)		(85,000	)
Proceeds from issuance of senior notes		147,540			—			—
Proceeds from issuance of common units		—			133,301			104
Contribution from general partner		—			3,812			186
Distributions to HEP unitholders		(84,426	)		(61,188	)		(52,426	)
Distributions to noncontrolling interest		—			(1,500	)		(1,800	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation		(57,560	)		(3,120	)		—
Purchase of units for restricted grants		(2,704	)		(616	)		(795	)
Deferred financing costs		(494	)		—			(705	)
Cost of issuing common units		—			(266	)		—

Net cash provided by (used for) financing activities		(44,644	)		76,423			144,564


Cash and cash equivalents
Decrease for the year		(2,105	)		(2,761	)		(5,052	)
Beginning of year		2,508			5,269			10,321


End of year	$	403		$	2,508		$	5,269


⁽¹⁾		Includes cash flows attributable to discontinued operations.

See accompanying notes.

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Holly Energy Partners, L.P.

Consolidated Statements of Partners’ Equity


	Holly Energy Partners, L.P. Partners’ Equity (Deficit):
													Accumulated
							Class B			General			Other			Non-
	Common			Subordinated			Subordinated			Partner			Comprehensive			controlling
	Units			Units			Units			Interest			Loss			Interest			Total
	(In thousands)

Balance December 31, 2007	$	172,807		$	(73,725	)	$	22,973		$	(94,239	)	$	—		$	10,740		$	38,556

Issuance of common units		9,104			—			—			—			—			—			9,104
Cost of issuing common units		(71	)		—			—			—			—			—			(71	)
Capital contribution		—			—			—			186			—			—			186
Distributions to HEP unitholders		(24,788	)		(20,720	)		(2,775	)		(4,143	)		—			—			(52,426	)
Distributions to noncontrolling interest		—			—			—			—			—			(1,800	)		(1,800	)
Purchase of units for restricted grants		(795	)		—			—			—			—			—			(795	)
Amortization of restricted and performance units		1,688			—			—			—			—			—			1,688
Comprehensive income:
Net income		11,181			9,386			1,257			3,543			—			1,278			26,645
Other comprehensive loss		—			—			—			—			(12,967	)		—			(12,967	)

Comprehensive income		11,181			9,386			1,257			3,543			(12,967	)		1,278			13,678


Balance December 31, 2008		169,126			(85,059	)		21,455			(94,653	)		(12,967	)		10,218			8,120

Issuance of common units		186,801			—			—			—			—			—			186,801
Cost of issuing common units		(266	)		—			—			—			—			—			(266	)
Conversion of subordinated units		(90,824	)		90,824			—			—			—			—			—
Capital contribution		—			—			—			3,812			—			—			3,812
Distributions to HEP unitholders		(35,245	)		(16,275	)		(2,925	)		(6,743	)		—			—			(61,188	)
Distributions to noncontrolling interest		—			—			—			—			—			(1,500	)		(1,500	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation		—			—			—			(3,120	)		—			—			(3,120	)
Purchase of units for restricted grants		(616	)		—			—			—			—			—			(616	)
Amortization of restricted and performance units		699			—			—			—			—			—			699
Elimination of noncontrolling interest upon sale of Rio Grande		—			—			—			—			—			(10,297	)		(10,297	)
Comprehensive income:
Net income		45,878			10,510			2,896			6,730			—			1,579			67,593
Other comprehensive income		—			—			—			—			3,826			—			3,826

Comprehensive income		45,878			10,510			2,896			6,730			3,826			1,579			71,419


Balance December 31, 2009		275,553			—			21,426			(93,974	)		(9,141	)		—			193,864

Conversion of Class B subordinated units		20,588			—			(20,588	)		—			—			—			—
Distributions to HEP unitholders		(81,218	)		—			(1,519	)		(1,689	)		—			—			(84,426	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation		—			—			—			(57,560	)		—			—			(57,560	)
Purchase of units for restricted grants		(2,704	)		—			—			—			—			—			(2,704	)
Amortization of restricted and performance units		2,214			—			—			—			—			—			2,214
Comprehensive income:
Net income		46,884			—			681			11,304			—			—			58,869
Other comprehensive loss		—			—			—			—			(885	)		—			(885	)

Comprehensive income		46,884			—			681			11,304			(885	)		—			57,984


Balance December 31, 2010	$	261,317		$	—		$	—		$	(141,919	)	$	(10,026	)	$	—		$	109,372

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010

Note 1: Description of Business and Summary of Significant Accounting Policies

Description of Business

Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 34% owned by Holly Corporation (“Holly”). We commenced operations on July 13, 2004 upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.

We operate in one business segment — the operation of petroleum product and crude oil pipelines and terminals, tankage and loading rack facilities.

We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.

Principles of Consolidation and Common Control Transactions

The consolidated financial statements include our accounts and those of our subsidiaries. All significant inter-company transactions and balances have been eliminated.

The pipeline and terminal assets that Holly contributed to us concurrently with the completion of our initial public offering in 2004, the intermediate pipeline assets purchased from Holly in July 2005 and the various pipeline and logistic asset purchases from Holly in 2009 and 2010 (see Note 3) occurred while we were a consolidated variable interest entity of Holly. Therefore, as an entity under common control with Holly, we recorded these assets on our balance sheets at Holly’s historical basis instead of our purchase price or fair value.

If these assets had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $218 million would have been recorded as increases to our properties and equipment and intangible assets instead of reductions to our partners’ equity.

Use of Estimates

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

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid investments with maturity of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheet approximate fair value due to the short-term maturity of these instruments.

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Accounts Receivable

The majority of the accounts receivable are due from affiliates of Holly, Alon or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and, in certain circumstances, collateral such as letters of credit or guarantees, may be required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal.

Inventories

Inventories consisting of materials and supplies used for operations are stated at the lower of cost, using the average cost method, or market and are shown under “Prepaid and other current assets” in our consolidated balance sheets.

Properties and Equipment

Properties and equipment are stated at cost. Properties and equipment acquired from Holly while under common control of Holly are stated at Holly’s historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets; primarily 25 years for terminal facilities, 25 to 32 years for pipelines and 5 to 10 years for corporate and other assets. Maintenance, repairs and major replacements are generally expensed as incurred. Costs of replacements constituting improvements are capitalized.

Transportation Agreements

The transportation agreement assets are stated at acquisition date fair value and are being amortized over the periods of the agreements using the straight-line method. See Note 6 for additional information on our transportation agreements.

Goodwill

Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. See “Sinclair Logistics and Storage Assets Transaction” under Note 3 for information on our goodwill acquired in 2009.

Long-Lived Assets

We evaluate long-lived assets, including intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value.

There were no impairments of our long-lived assets, including goodwill, during the years ended December 31, 2010, 2009 and 2008.

Investment in SLC Pipeline

We account for our 25% SLC Pipeline joint venture interest using the equity method of accounting, whereby we record our pro-rata share of earnings of the SLC Pipeline, and contributions to and distributions from the SLC Pipeline as adjustments to our investment balance. As of December 31, 2010, our underlying equity in the SLC Pipeline was $61.2 million compared to our recorded investment balance of $25.4 million, a difference of $35.8 million. This is attributable to the difference between our contributed capital and our allocated equity at formation of the SLC Pipeline. We are amortizing this difference as an adjustment to our pro-rata share of earnings.

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Asset Retirement Obligations

We record legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.

We have asset retirement obligations with respect to certain of our assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2010, an asset retirement obligation of $0.7 million is included in “Other long-term liabilities” in our consolidated balance sheets.

Revenue Recognition

Revenues are recognized as products are shipped through our pipelines and terminals. Billings to customers for obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

•

the customer receives the future services provided by these billings,

•

the period in which the customer is contractually allowed to receive the services expires, or

•

We determine a high likelihood that we will not be required to provide services within the allowed period.

We have additional pipeline transportation revenues under an operating lease to a third party of an interest in the capacity of one of our pipelines.

Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.

Environmental Costs

Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Environmental costs recoverable through insurance or other sources are included in other assets to the extent such recoveries are considered probable. At December 31, 2010 and 2009, we had accruals for environmental remediation obligations of $0.3 million and $0.2 million, respectively.

Income Tax

We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.

We are organized as a pass-through for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of taxable income.

- 78 -

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us.

Net Income per Limited Partners’ Unit

We have identified the general partner interest and our previously outstanding subordinated units as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the year. Net income per unit applicable to limited partners (including subordinated unit holders) is computed by dividing limited partners’ interest in net income, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of outstanding common and subordinated units.

Note 2: Discontinued Operations

In accounting for the sale, we recorded a gain of $14.5 million and a receivable of $2.2 million that represented our final distribution from Rio Grande. Our recorded net asset balance of Rio Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.

Cash flows from discontinued operations have been combined with cash flows from continuing operations for presentation purposes in the Consolidated Statements of Cash Flows. For the years ended December 31, 2009 and 2008, net cash flows from our discontinued Rio Grande operations were $37.6 million and $3.5 million, respectively. Net cash flows from discontinued operations for 2009 include $35 million in proceeds received upon the sale of our Rio Grande interest.

Note 3: Acquisitions

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

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See Note 11 for additional information on our long-term transportation agreements with Holly.

In accounting for these acquisitions from Holly, we recorded total property and equipment at Holly’s historical basis of $35.5 million and the purchase price in excess of Holly’s basis in the assets of $57.6 million as a decrease to our partners’ equity.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, we acquired from an affiliate of Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of our common units having a fair value of $53.5 million. Separately, Holly, also a party to the transaction acquired Sinclair’s Tulsa refinery.

With respect to this purchase, we recorded $30.2 million in properties and equipment, $49.1 million in goodwill and $0.2 million in other long-term liabilities. The value of the acquired assets, which does not include goodwill, is based on fair value using a cost approach methodology.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).

Tulsa West Loading Racks Transaction

Lovington-Artesia Pipeline Transaction

On June 1, 2009, we acquired from Holly a newly constructed 16-inch intermediate pipeline for $34.2 million. The pipeline runs 65 miles from the Navajo refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.

In accounting for our 2009 acquisitions from Holly, consisting of the Roadrunner and Beeson Pipelines, the Tulsa west loading rack facilities and 16-inch intermediate pipeline as discussed above, we recorded total property and equipment of $95.1 million representing Holly’s historical basis in the transferred assets. The $3.1 million aggregate purchase price in excess of Holly’s historical basis in the assets was recorded as a decrease to our partners’ equity.

SLC Pipeline Joint Venture Interest

On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system that we jointly own with All American Pipeline, L.P. (“Plains”). The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.

2008 Acquisition

Crude Pipelines and Tankage Transaction

On February 29, 2008, we acquired from Holly certain crude pipeline and tankage assets for $180 million, consisting of crude oil trunk lines that support the Navajo refinery, crude oil and product pipelines that support the Woods Cross refinery, on-site crude tankage located at the Navajo and Woods Cross refinery complexes, a jet fuel products pipeline running between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. The consideration paid consisted of $171 million in cash and 217,497 of our common units having a fair value of $9 million.

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At the time of this transaction, we were not a consolidated variable interest entity of Holly. Since we were not under common control with Holly, we recorded the acquired assets at fair value. We recorded property and equipment of $105.8 million and a long-term transportation agreement of $74.2 million based on values derived using cost and income approach methodologies.

Note 4: Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-tem maturity of these instruments.

Our debt consists of outstanding principal under our $300 million revolving credit agreement (the “Credit Agreement”), our 6.25% senior notes due 2015 (the “6.25% Senior Notes”) and our 8.25% senior notes due 2018 (the “8.25% Senior Notes”). The $159 million carrying amount of outstanding debt under the Credit Agreement approximates fair value as interest rates are reset frequently using current rates. The estimated fair value of our 6.25% Senior Notes and 8.25% Senior Notes was $183.2 million and $156.8 million, respectively, at December 31, 2010. These fair value estimates are based on market quotes provided from a third-party bank. See Note 8 for additional information on these instruments.

Fair Value Measurements

Fair value measurements are derived using inputs, (assumptions that market participants would use in pricing an asset or liability), including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

•

(Level 1) Quoted prices in active markets for identical assets or liabilities.

•

(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

•

(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

We have an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs that as of December 31, 2010, represented a liability having a fair value of $10 million. With respect to this instrument, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreement. Our measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 8 for additional information on our interest rate swap.

Note 5: Properties and Equipment


	December 31,
	2010		2009
	(In thousands)

Pipelines and terminals ⁽¹⁾	$	507,260	$	455,075
Land and right of way		25,264		25,230
Other		14,591		12,528
Construction in progress		16,601		10,484

		563,716		503,317
Less accumulated depreciation		128,766		105,273

	$	434,950	$	398,044


(1)		We periodically evaluate estimated useful lives of our properties and equipment. Effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years. This change in estimated useful lives resulted in a $3 million reduction in depreciation expense for the year ended December 31, 2010.

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During the years ended December 31, 2010 and 2009 we capitalized $0.5 million and $1 million, respectively, in interest related to major construction projects.

Depreciation expense was $23.7 million, $19.7 million and $15.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Note 6: Transportation Agreements

Our transportation agreements consist of the following:

•

The Alon pipelines and terminals agreement (the “Alon PTA”) represents a portion of the total purchase price of the Alon assets acquired in 2005 that was allocated based on an estimated fair value derived under an income approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term of the Alon PTA plus the expected 15-year extension period.

•

The Holly crude pipelines and tankage agreement (the “Holly CPTA”) represents a portion of the total purchase price of certain crude pipelines and tankage assets acquired from Holly in 2008 that was allocated using a fair value based on the agreement’s expected contribution to our future earnings under an income approach. This asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA.

The carrying amounts of the transportation agreements are as follows:


	December 31,
	2010		2009
	(In thousands)

Alon transportation agreement	$	59,933	$	59,933
Holly crude pipelines and tankage agreement		74,231		74,231

		134,164		134,164
Less accumulated amortization		25,675		18,728

	$	108,489	$	115,436

Amortization expense was $6.9 million, $7 million and $6.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

We have additional transportation agreements with Holly that relate to pipeline, terminal and tankage assets contributed to us or acquired from Holly. These transfers occurred while we were a consolidated variable interest entity of Holly, therefore, our basis in these assets reflect Holly’s historical cost and does not reflect a step-up in basis to fair value.

In addition, we have an agreement to provide transportation and storage services to Holly via our Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with Holly and not between Sinclair and us, there is no purchase price allocation attributable to this agreement.

Note 7: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs are charged to us monthly in accordance with an omnibus agreement that we have with Holly. These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $2.9 million, $2.8 million and $2.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts include retirement costs of $1.5 million, $1.6 million and $1.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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We have adopted an incentive plan (“Long-Term Incentive Plan”) for employees, consultants and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted units, performance units, unit options and unit appreciation rights.

As of December 31, 2010, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $2.2 million, $1.2 million and $1.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. We currently purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At December 31, 2010, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 169,939 had not yet been granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The fair value of each restricted unit award is measured at the market price as of the date of grant and is being amortized over the vesting period.

A summary of restricted unit activity and changes during the year ended December 31, 2010 is presented below:


						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Grant-Date		Contractual	Value
Restricted Units	Grants			Fair Value		Term	($000)

Outstanding at January 1, 2010 (not vested)		53,271		$	34.31
Granted		36,755			43.13
Vesting and transfer of full ownership to recipients		(41,505	)		38.53
Forfeited		(1,226	)		34.28

Outstanding at December 31, 2010 (not vested)		47,295		$	37.47	0.8 year	$	2,408

The fair value of restricted units that were vested and transferred to recipients during the years ended December 31, 2010, 2009 and 2008 was $1.6 million, $1.2 million and $0.8 million, respectively. As of December 31, 2010, there was $0.5 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 0.8 year.

During the year ended December 31, 2010, we paid $2.7 million for the purchase of 62,352 of our common units in the open market for the recipients of our restricted unit grants.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted in 2010 are payable based upon the growth in distributable cash flow per common unit over the performance period, and vest over a period of three years. Performance units granted in 2009 and 2008 are payable based upon the growth in distributions on our common units during the requisite period, and vest over a period of three years. As of December 31, 2010, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.

We granted 16,965 performance units to certain officers in March 2010. These units will vest over a three-year performance period ending December 31, 2012 and are payable in HEP common units. The number of units actually earned will be based on the growth of distributable cash flow per common unit over the performance period, and can range from 50% to 150% of the number of performance units granted. The fair value of these performance units is based on the grant date closing unit price of $42.59 and will apply to the number of units ultimately awarded.

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A summary of performance unit activity and changes during the year ended December 31, 2010 is presented below:


	Payable
Performance Units	In Units

Outstanding at January 1, 2010 (not vested)		54,771
Granted		16,965
Vesting and payment of units to recipients		(12,321	)
Forfeited		—

Outstanding at December 31, 2010 (not vested)		59,415

The fair value of performance units vested and transferred to recipients during the years ended December 31, 2010, 2009 and 2008 was $0.6 million, $0.4 million and $0.1 million, respectively. Based on the weighted average fair value at December 31, 2010 of $32.97, there was $0.8 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1 year.

Note 8: Debt

Credit Agreement

At December 31, 2010, the Credit Agreement consisted of a $300 million senior secured revolving credit facility expiring in August 2011. During the year ended December 31, 2010, we received advances totaling $66 million and repaid $113 million, resulting in the net repayment of $47 million in advances under the Credit Agreement and an outstanding balance of $159 million at December 31, 2010. These advances were used to finance acquisitions and capital projects. As of December 31, 2010, we had no working capital borrowings.

On February 14, 2011 we amended the Credit Agreement, slightly reducing the size of the credit facility from $300 million to $275 million (the “Amended Credit Agreement”). The size was reduced based on management’s review of past and forecasted utilization of the facility. The Amended Credit Agreement expires in February 2016; provided that the Amended Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the 6.25% Senior Notes have not been repurchased, refinanced, extended or repaid. The Amended Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Amended Credit Agreement is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit.

We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

Indebtedness under the Amended Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 1.00% to 2.00%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 2.00% to 3.00%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Amended Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Amended Credit Agreement). We incur a commitment fee on the unused portion of the Amended Credit Agreement at a rate ranging from 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

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The Amended Credit Agreement imposes certain requirements on us which we are subject to and currently in compliance with, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Amended Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes

In March 2010, we issued $150 million in aggregate principal amount outstanding of 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

Our 6.25% Senior Notes having an aggregate principal amount outstanding of $185 million mature March 1, 2015 and are registered with the SEC. The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

Long-term Debt

The carrying amounts of our long-term debt are as follows:


	December 31,
	2010			2009
	(In thousands)

Credit Agreement	$	159,000		$	206,000

6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(1,584	)		(1,964	)
Unamortized premium — dedesignated fair value hedge		1,444			1,791

		184,860			184,827


8.25% Senior Notes
Principal		150,000			—
Unamortized discount		(2,212	)		—

		147,788			—


Total long-term debt	$	491,648		$	390,827

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Interest Rate Risk Management

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

Additional information on our interest rate swaps are as follows:

Balance Sheet

Location of Offsetting

Offsetting

Derivative Instrument

Location

Fair Value

Balance

Amount

(In thousands)

December 31, 2010

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract
($155 million of LIBOR based debt interest)

Other long-term liabilities

10,026

Accumulated other comprehensive loss

10,026

Balance Sheet

Fair

Location of Offsetting

Offsetting

Derivative Instrument

Location

Value

Balance

Amount

(In thousands)

December 31, 2009

Interest rate swap designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract
($171 million of LIBOR based debt interest)

Other long-term liabilities

9,141

Accumulated other comprehensive loss

9,141

Interest rate swaps not designated as hedging instruments:

Fixed-to-variable interest rate swap contract
($60 million of 6.25% Senior Notes interest)

Other assets

2,294

Long-term debt

1,791

⁽¹⁾

Equity

503

⁽²⁾

2,294

Variable-to-fixed interest rate swap contract
($60 million of 6.25% Senior Notes interest)

Other long-term liabilities

2,555

Equity

2,555

⁽²⁾


(1)		Represents unamortized balance of deferred hedge premium.

(2)		Represents prior year charges to interest expense.

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We have a deferred hedge premium that relates to the application of hedge accounting to the Variable Rate Swap prior to its hedge dedesignation in 2008. This deferred hedge premium having a balance of $1.4 million at December 31, 2010, is being amortized as a reduction to interest expense over the remaining term of the 6.25% Senior Notes.

Interest Expense and Other Debt Information

Interest expense consists of the following components:


	Years Ended December 31,
	2010		2009		2008
	(In thousands)
Interest on outstanding debt:
Credit Agreement, net of interest on interest rate swap	$	9,109	$	10,657	$	8,705
6.25% Senior Notes, net of interest on interest rate swaps		11,404		10,703		10,454
8.25% Senior Notes		10,298		—		—
Partial settlement of interest rate swap — cash flow hedge		1,076		—		—
Net fair value adjustments to interest rate swaps		1,464		175		2,282
Net amortization of discount and deferred debt issuance costs		713		706		1,002
Commitment fees		392		268		327


Total interest incurred		34,456		22,509		22,770

Less capitalized interest		455		1,008		1,007


Net interest expense	$	34,001	$	21,501	$	21,763


Cash paid for interest ⁽¹⁾	$	31,305	$	21,721	$	19,482


(1)		Net of cash received under our interest rate swap agreements of $1.9 million, $3.8 million and $3.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Note 9: Commitments and Contingencies

We lease certain facilities, pipelines and rights of way under operating leases, most of which contain renewal options. The right of way agreements have various termination dates through 2053.

As of December 31, 2010, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:


Year Ending
December 31,	$000’s
2011		6,545
2012		6,478
2013		6,476
2014		6,420
2015		6,419
Thereafter		10,086


Total	$	42,424

Rental expense charged to operations was $7.1 million, $7.1 million and $6.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

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Note 10: Significant Customers

All revenues are domestic revenues, of which 92% are currently generated from our two largest customers: Holly and Alon. The vast majority of our revenues are derived from activities conducted in the southwest United States.

The following table presents the percentage of total revenues from continuing operations generated by each of these customers:


	Years Ended December 31,
	2010			2009			2008
Holly		80	%		69	%		78	%
Alon		12	%		26	%		17	%

Note 11: Related Party Transactions

We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

•

Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by Holly upon our initial public offering in 2004);

•

Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from Holly in 2005 and 2009);

•

Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);

•

Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in March 2010);

•

Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);

•

Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from Holly in 2009);

•

Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and

•

Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from Holly in March 2010).

Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or the Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following our July 1, 2010 PPI rate adjustment, these agreements with Holly will result in minimum annualized payments to us of $133 million.

If Holly fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment under the Holly PTA and Holly IPA may be applied as a credit in the following four quarters after minimum obligations are met.

We entered into an omnibus agreement with Holly in 2004 that Holly and we amended and restated several times in connection with our past acquisitions from Holly with the last amendment and restatement occurring on March 31, 2010 (the “Omnibus Agreement”). Under certain provisions of the Omnibus Agreement, we pay Holly an annual administrative fee for the provision by Holly or its affiliates of various general and administrative services to us, currently $2.3 million. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. Also, we reimburse Holly and its affiliates for direct expenses they incur on our behalf.

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Related party transactions with Holly are as follows:

•

Revenues received from Holly were $146.4 million, $101.4 million and $85 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

Holly charged general and administrative services under the Omnibus Agreement of $2.3 million, $2.3 million and $2.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

We reimbursed Holly for costs of employees supporting our operations of $18.6 million, $17 million and $13.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

Holly reimbursed us $3.7 million and $1.7 million for certain costs paid on their behalf for the years ended December 31, 2010 and December 31, 2009, respectively.

•

We paid Holly a $2.5 million finder’s fee in connection the acquisition of our 25% joint venture interest in the SLC Pipeline in the first quarter of 2009.

•

We distributed $35.9 million, $29.5 million and $25.6 million for the years ended December 31, 2010, 2009 and 2008, respectively, to Holly as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions.

•

Accounts receivable from Holly were $19 million and $14.1 million at December 31, 2010 and 2009, respectively.

•

Accounts payable to Holly were $3.9 million and $2.4 million at December 31, 2010 and 2009, respectively.

•

Revenues for the years ended December 31, 2010, 2009 and 2008 include $3.6 million, $2.4 million and $1.2 million, of shortfalls billed under the Holly IPA in 2009, 2008 and 2007, respectively, as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters in 2010, 2009 and 2008. Deferred revenue in the consolidated balance sheets at December 31, 2010 and 2009 includes $3.3 million and $3.6 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $3.3 million deferred at December 31, 2010.

•

We acquired various pipeline, terminal and tankage assets from Holly in 2010, 2009 and 2008. See Note 3 for a description of these transactions.

Note 12: Partners’ Equity, Income Allocations and Cash Distributions

Holly currently holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 34% ownership interest in us.

Issuances of units

We issued 1,373,609 of our common units having a value of $53.5 million to Sinclair as partial consideration of our total $79.2 million purchase of Sinclair’s Tulsa logistics assets in December 2009.

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We issued in a public offering 2,185,000 of our common units priced at $35.78 per unit in November 2009. Aggregate net proceeds of $74.9 million were used to fund the cash portion of our December 2009 asset acquisitions, to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.

Additionally, we issued in a public offering 2,192,400 of our common units priced at $27.80 per unit in May 2009. Net proceeds of $58.4 million were used to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.

We received aggregate capital contributions of $3.8 million from our general partner to maintain its 2% general partner interest concurrent with the 2009 common unit issuances described above.

Allocations of Net Income

Net income attributable to Holly Energy Partners, L.P. is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted average ownership percentage during the period.

The following table presents the allocation of the general partner interest in net income:


	Years Ended December 31,
	2010		2009		2008
	(In thousands)
General partner interest in net income	$	971	$	1,210	$	445
General partner incentive distribution		11,181		6,737		3,468


Total general partner interest in net income attributable to HEP	$	12,152	$	7,947	$	3,913

Cash Distributions

We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. The Amended Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the Amended Credit Agreement, occurs or would result from the cash distribution.

Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, 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 the Amended Credit Agreement and in all cases are used solely for working capital purposes or to pay distributions to partners.

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We make distributions of available cash from operating surplus for any quarter, in the following manner: 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; and 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, thereafter. Cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

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


		Marginal Percentage Interest in
	Total Quarterly Distribution	Distributions
	Target Amount	Unitholders			General Partner

Minimum quarterly distribution	$0.50		98	%		2	%
First target distribution	Up to $0.55		98	%		2	%
Second target distribution	above $0.55 up to $0.625		85	%		15	%
Third target distribution	above $0.625 up to $0.75		75	%		25	%
Thereafter	Above $0.75		50	%		50	%

On January 26, 2011, we announced our cash distribution for the fourth quarter of 2010 of $0.845 per unit. The distribution is payable on all common and general partner units and will be paid February 14, 2011 to all unitholders of record on February 7, 2011.

The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.


	Years Ended December 31,
	2010		2009		2008
	(in thousands, except per unit data)

General partner interest	$	1,724	$	1,356	$	1,069
General partner incentive distribution		11,181		6,737		3,468


Total general partner distribution		12,905		8,093		4,537
Limited partner distribution		73,223		59,725		49,085


Total regular quarterly cash distribution	$	86,128	$	67,818	$	53,622

Cash distribution per unit applicable to limited partners	$	3.32	$	3.16	$	3.00

As a master limited partnership, we distribute our available cash, which has historically exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets contributed and acquired from Holly had occurred while we were not a consolidated variable interest entity of Holly, our acquisition cost in excess of Holly’s historical basis in the transferred assets of $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

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Note 13: Comprehensive Income (Loss)

We have other comprehensive income (loss) resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:


	Years Ended December 31,
	2010			2009		2008
	(In thousands)

Net income	$	58,869		$	67,593	$	26,645
Other comprehensive income (loss):
Change in fair value of cash flow hedge		(1,961	)		3,826		(12,967	)
Reclassification adjustment to net income on partial settlement of cash flow hedge		1,076			—		—


Other comprehensive income (loss)		(885	)		3,826		(12,967	)


Comprehensive income		57,984			71,419		13,678

Less noncontrolling interest in comprehensive income		—			1,579		1,278


Comprehensive income attributable to HEP unitholders	$	57,984		$	69,840	$	12,400

Note 14: Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:


	First		Second		Third		Fourth		Total
	(In thousands, except per unit data)
Year ended December 31, 2010
Revenues	$	40,696	$	45,483	$	46,549	$	49,369	$	182,097
Operating income	$	17,863	$	22,484	$	24,172	$	26,230	$	90,749
Income from continuing operations before income taxes	$	10,796	$	13,481	$	16,335	$	18,553	$	59,165
Net income	$	10,702	$	13,435	$	16,259	$	18,473	$	58,869
Limited partners’ interest in net income	$	8,056	$	10,526	$	13,087	$	15,048	$	46,717
Limited partners’ per unit interest in net income — basic and diluted	$	0.36	$	0.48	$	0.59	$	0.68	$	2.12
Distributions per limited partner unit	$	0.815	$	0.825	$	0.835	$	0.845	$	3.32

Year ended December 31, 2009
Revenues	$	29,332	$	37,999	$	40,805	$	38,425	$	146,561
Operating income	$	11,640	$	18,958	$	21,274	$	16,386	$	68,258
Income from continuing operations before income taxes	$	3,918	$	15,044	$	15,569	$	11,723	$	46,254
Income from discontinued operations	$	1,594	$	1,441	$	1,070	$	15,675	$	19,780
Net income	$	5,439	$	16,392	$	16,539	$	27,644	$	66,014
Limited partners’ interest in net income	$	4,146	$	14,543	$	14,517	$	24,861	$	58,067
Limited partners’ per unit interest in net income — basic and diluted	$	0.25	$	0.82	$	0.78	$	1.22	$	3.18
Distributions per limited partner unit	$	0.775	$	0.785	$	0.795	$	0.805	$	3.16

Note 15: Supplemental Guarantor / Non-Guarantor Financial Information

Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes and 8.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional.

We sold our 70% interest in Rio Grande on December 1, 2009; therefore, Rio Grande is no longer a subsidiary of HEP. Rio Grande (“Non-Guarantor”) was the only subsidiary that did not guarantee these obligations. Amounts attributable to Rio Grande prior to our sale are presented in discontinued operations.

- 92 -

The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Subsidiaries accounted for the ownership of the Non-Guarantor, using the equity method of accounting.

Condensed Consolidating Balance Sheet


				Guarantor
December 31, 2010	Parent			Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	401	$	—		$	403
Accounts receivable		—			22,508		—			22,508
Intercompany accounts receivable (payable)		(92,230	)		92,230		—			—
Prepaid and other current assets		235			540		—			775

Total current assets		(91,993	)		115,679		—			23,686

Properties and equipment, net		—			434,950		—			434,950
Investment in subsidiaries		541,262			—		(541,262	)		—
Transportation agreements, net		—			108,489		—			108,489
Goodwill		—			49,109		—			49,109
Investment in SLC Pipeline		—			25,437		—			25,437
Other assets		1,261			341		—			1,602

Total assets	$	450,530		$	734,005	$	(541,262	)	$	643,273


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	10,238	$	—		$	10,238
Accrued interest		7,498			19		—			7,517
Deferred revenue		—			10,437		—			10,437
Accrued property taxes		—			1,990		—			1,990
Other current liabilities		1,011			251		—			1,262

Total current liabilities		8,509			22,935		—			31,444

Long-term debt		332,649			158,999		—			491,648
Other long-term liabilities		—			10,809		—			10,809
Partners’ equity		109,372			541,262		(541,262	)		109,372

Total liabilities and partners’ equity	$	450,530		$	734,005	$	(541,262	)	$	643,273

Condensed Consolidating Balance Sheet


				Guarantor
December 31, 2009	Parent			Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	2,506	$	—		$	2,508
Accounts receivable		—			18,767		—			18,767
Intercompany accounts receivable (payable)		(76,855	)		76,855		—			—
Prepaid and other current assets		261			478		—			739
Current assets of discontinued operations		—			2,195		—			2,195

Total current assets		(76,592	)		100,801		—			24,209

Properties and equipment, net		—			398,044		—			398,044
Investment in subsidiaries		458,381			—		(458,381	)		—
Transportation agreements, net		—			115,436		—			115,436
Goodwill		—			49,109		—			49,109
Investment in SLC Pipeline		—			25,919		—			25,919
Other assets		3,267			861		—			4,128

Total assets	$	385,056		$	690,170	$	(458,381	)	$	616,845


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	6,211	$	—		$	6,211
Accrued interest		2,849			14		—			2,863
Deferred revenue		—			8,402		—			8,402
Accrued property taxes		—			1,072		—			1,072
Other current liabilities		961			296		—			1,257

Total current liabilities		3,810			15,995		—			19,805

Long-term debt		184,827			206,000		—			390,827
Other long-term liabilities		2,555			9,794		—			12,349
Partners’ equity		193,864			458,381		(458,381	)		193,864

Total liabilities and partners’ equity	$	385,056		$	690,170	$	(458,381	)	$	616,845

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Condensed Consolidating Statement of Income


				Guarantor
Year ended December 31, 2010	Parent			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	146,376		$	—		$	146,376
Third parties		—			35,721			—			35,721


		—			182,097			—			182,097

Operating costs and expenses:
Operations		—			52,947			—			52,947
Depreciation and amortization		—			30,682			—			30,682
General and administrative		5,053			2,666			—			7,719

		5,053			86,295			—			91,348

Operating income (loss)		(5,053	)		95,802			—			90,749

Equity in earnings of subsidiaries		87,280			—			(87,280	)		—
Equity in earnings of SLC Pipeline		—			2,393			—			2,393
Interest income (expense)		(23,358	)		(10,636	)		—			(33,994	)
Other		—			17			—			17


		63,922			(8,226	)		(87,280	)		(31,584	)


Income before income taxes		58,869			87,576			(87,280	)		59,165

State income tax		—			(296	)		—			(296	)


Net income	$	58,869		$	87,280		$	(87,280	)	$	58,869

Condensed Consolidating Statement of Income


				Guarantor			Non-
Year ended December 31, 2009	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	101,395		$	—	$	—		$	101,395
Third parties		—			45,166			—		—			45,166

		—			146,561			—		—			146,561
Operating costs and expenses:
Operations		—			44,003			—		—			44,003
Depreciation and amortization		—			26,714			—		—			26,714
General and administrative		4,697			2,889			—		—			7,586

		4,697			73,606			—		—			78,303

Operating income (loss)		(4,697	)		72,955			—		—			68,258

Equity in earnings of subsidiaries		81,773			3,686			—		(85,459	)		—
Equity in earnings of SLC Pipeline		—			1,919			—		—			1,919
SLC Pipeline acquisition costs		—			(2,500	)		—		—			(2,500	)
Interest income (expense)		(11,062	)		(10,428	)		—		—			(21,490	)
Other		—			67			—		—			67

		70,711			(7,256	)		—		(85,459	)		(22,004	)

Income from continuing operations before income taxes		66,014			65,699			—		(85,459	)		46,254


State income tax		—			(20	)		—		—			(20	)


Income from continuing operations		66,014			65,679			—		(85,459	)		46,234

Income from discontinued operations		—			16,094			5,265		(1,579	)		19,780


Net income	$	66,014		$	81,773		$	5,265	$	(87,038	)	$	66,014

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Condensed Consolidating Statement of Income


				Guarantor			Non-
Year ended December 31, 2008	Parent			Subsidiaries			Guarantor		Eliminations			Consolidated
	(In thousands)
Revenues:
Affiliates	$	—		$	85,040		$	—	$	—		$	85,040
Third parties		—			23,782			—		—			23,782

		—			108,822			—		—			108,822
Operating costs and expenses:
Operations		—			38,920			—		—			38,920
Depreciation and amortization		—			21,937			—		—			21,937
General and administrative		3,819			2,561			—		—			6,380

		3,819			63,418			—		—			67,237

Operating income (loss)		(3,819	)		45,404			—		—			41,585

Equity in earnings of subsidiaries		38,215			2,983			—		(41,198	)		—
Interest income (expense)		(9,029	)		(12,616	)		—		—			(21,645	)
Gain on sale of assets		—			36			—		—			36
Other		—			990			—		—			990

		29,186			(8,607	)		—		(41,198	)		(20,619	)

Income from continuing operations before income taxes		25,367			36,797			—		(41,198	)		20,966


State income tax		—			(270	)		—		—			(270	)


Income from continuing operations		25,367			36,527			—		(41,198	)		20,696

Income from discontinued operations		—			1,688			4,261		(1,278	)		4,671


Net income	$	25,367		$	38,215		$	4,261	$	(42,476	)	$	25,367

Condensed Consolidating Statement of Cash Flows


				Guarantor
Year Ended December 31, 2010	Parent			Subsidiaries			Eliminations		Consolidated
	(In thousands)

Cash flows from operating activities	$	(59,916	)	$	163,084		$	—	$	103,168

Cash flows from investing activities
Additions to properties and equipment		—			(25,103	)		—		(25,103	)
Acquisition of assets from Holly Corporation		—			(35,526	)		—		(35,526	)


		—			(60,629	)		—		(60,629	)

Cash flows from financing activities
Net repayments under credit agreement		—			(47,000	)		—		(47,000	)
Net proceeds from issuance of senior notes		147,540			—			—		147,540
Distributions to HEP unitholders		(84,426	)		—			—		(84,426	)
Purchase price in excess of transferred basis in assets acquired from Holly Corporation		—			(57,560	)		—		(57,560	)
Purchase of units for restricted grants		(2,704	)		—			—		(2,704	)
Deferred financing costs		(494	)		—			—		(494	)


		59,916			(104,560	)		—		(44,644	)


Cash and cash equivalents
Increase (decrease) for the year		—			(2,105	)		—		(2,105	)
Beginning of year		2			2,506			—		2,508


End of year	$	2		$	401		$	—	$	403

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Condensed Consolidating Statement of Cash Flows


				Guarantor			Non-
Year Ended December 31, 2009	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)

Cash flows from operating activities	$	(131,123	)	$	196,205		$	6,613		$	(3,500	)	$	68,195

Cash flows from investing activities
Additions to properties and equipment		—			(32,999	)		—			—			(32,999	)
Acquisitions of assets from Holly Corporation		—			(95,080	)		—			—			(95,080	)
Acquisition of assets from Sinclair Oil Company		—			(25,665	)		—			—			(25,665	)
Investment in SLC Pipeline		—			(25,500	)		—			—			(25,500	)
Proceeds from sale of interest in Rio Grande Pipeline Company, net of transferred cash		—			31,865			—			—			31,865
Other		—			3,174			(3,174	)		—			—


		—			(144,205	)		(3,174	)		—			(147,379	)

Cash flows from financing activities
Net borrowings under credit agreement		—			6,000			—			—			6,000
Proceeds from issuance of common units		186,801			(53,500	)		—			—			133,301
Contribution from general partner		3,812			—			—			—			3,812
Distributions to HEP unitholders		(61,188	)		—			(5,000	)		5,000			(61,188	)
Distributions to noncontrolling interest		—			—			—			(1,500	)		(1,500	)
Net purchase price in excess of transferred basis in assets acquired from Holly Corporation		2,580			(5,700	)		—			—			(3,120	)
Purchase of units for restricted grants		(616	)		—			—			—			(616	)
Cost of issuing common units		(266	)		—			—			—			(266	)


		131,123			(53,200	)		(5,000	)		3,500			76,423

Cash and cash equivalents
Decrease for the year		—			(1,200	)		(1,561	)		—			(2,761	)
Beginning of year		2			3,706			1,561			—			5,269


End of year	$	2		$	2,506		$	—		$	—		$	2,508

Condensed Consolidating Statement of Cash Flows


				Guarantor			Non-
Year Ended December 31, 2008	Parent			Subsidiaries			Guarantor			Eliminations			Consolidated
	(In thousands)

Cash flows from operating activities	$	44,035		$	17,973		$	5,843		$	(4,200	)	$	63,651

Cash flows from investing activities
Additions to properties and equipment		—			(41,762	)		(541	)		—			(42,303	)
Acquisition of assets from Holly Corporation		—			(171,000	)		—			—			(171,000	)
Proceeds from sale of assets		—			36			—			—			36


		—			(212,726	)		(541	)		—			(213,267	)

Cash flows from financing activities
Net borrowings under credit agreement		9,000			191,000			—			—			200,000
Proceeds from issuance of common units		—			104			—			—			104
Contribution from general partner		186			—			—			—			186
Distributions to HEP unitholders		(52,426	)		—			(6,000	)		6,000			(52,426	)
Distributions to noncontrolling interest		—			—			—			(1,800	)		(1,800	)
Purchase of units for restricted grants		(795	)		—			—			—			(795	)
Deferred financing costs		—			(705	)		—			—			(705	)


		(44,035	)		190,399			(6,000	)		4,200			144,564

Cash and cash equivalents
Decrease for the year		—			(4,354	)		(698	)		—			(5,052	)
Beginning of year		2			8,060			2,259			—			10,321


End of year	$	2		$	3,706		$	1,561		$	—		$	5,269

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

We have had no change in, or disagreement with, our independent registered public accounting firm on matters involving accounting and financial disclosure.

Item 9A. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2010 at a reasonable level of assurance.

(b) Changes in internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

See Item 8 for “Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”

Item 9B. Other Information

There have been no events that occurred in the fourth quarter of 2010 that would need to be reported on Form 8-K that have not been previously reported.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Holly Logistic Services, L.L.C., as the general partner of HEP Logistics Holdings, L.P., our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders. Unitholders are not entitled to elect the directors of HLS or directly or indirectly participate in our management or operation. The sole member of HLS, which is a subsidiary of Holly, elects our directors to serve until their death, resignation or removal. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.

Board Leadership Structure

The Board believes that the Company’s Chief Executive Officer is best situated to serve as Chairman of the Board because he is the director most familiar with the Company’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Independent directors and management have different perspectives and roles in strategy development. The Company’s independent directors bring experience, oversight and expertise from outside the Company and industry, while the Chief Executive Officer brings Company-specific experience and expertise. The Board believes that the combined role of Chairman of the Board and Chief Executive Officer promotes strategy development and execution and facilitates information flow between management and the Board, which are essential to effective governance of the Company.

One of the key responsibilities of the Board is to develop strategic direction and hold management accountable for the execution of strategy once it is developed. The Board believes the combined role of Chairman of the Board and Chief Executive Officer, together with a lead independent director (the “Presiding Director”) having the duties described below, is in the best interest of unitholders because it provides the appropriate balance between strategy development and independent oversight of management.

Presiding Director

Charles M. Darling, IV, an independent director who serves as Chairman of the compensation committee, was appointed by the non-management directors of HLS to serve as the Presiding Director of the Board for all meetings of the non-management directors held in executive session. The Presiding Director has the responsibility of presiding at all executive sessions of the non-management directors of the Board, consulting with management on Board and committee meeting agendas, acting as a liaison in appropriate instances between management and the non-management directors, including advising the Chairman of the Board and Chief Executive Officer on the efficiency of the board meetings, and facilitating teamwork and communication between the non-management directors and management.

Persons wishing to communicate with the non-management directors are invited to email the Presiding Director at presiding.director@hollyenergypartners.com or write to: Charles M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., Suite 1600, Dallas, Texas 75201-6915. Although the Company has not to date developed formal processes by which unitholders may otherwise communicate directly with directors, the Company believes that its process with regard to communicating with non-management directors, and its informal process under which any communication sent to the Board in care of the Chief Executive Officer or Secretary of the Company is forwarded to the Board for consideration, serves the Board’s and the unitholders’ needs. There is no screening process, and all unitholder communications that are received by officers for the Board’s attention are forwarded to the Board.

- 98 -

Risk Management

The Board has an active role, as a whole and also at the committee level, in overseeing management of the Company’s risks. The Board regularly reviews information regarding the Company’s credit, liquidity and operations, as well as the risks associated with each. The compensation committee is responsible for overseeing the management of risks relating to the Company’s executive compensation plans and arrangements. The audit committee oversees management of financial risks. The sole member of HLS manages risks associated with the independence of the Board and potential conflicts of interest. While each committee is responsible for evaluating certain risks and overseeing the management of such risks, the entire Board is regularly informed through committee reports about such risks.

The audit committee and the Board also receive input from the Company’s risk management oversight committee (the “Risk Committee”), made up of management personnel with a range of different backgrounds, skills and experiences with regard to the operational, financial and strategic risk profile of the Company. The Risk Committee monitors the risk environment for the Company as a whole, and reviews the activities that mitigate to an achievable and acceptable level the risks that may adversely affect the Company’s ability to achieve its goals. The Risk Committee also supports the audit committee’s efforts to monitor and evaluate guidelines and policies to govern the process by which risk assessment and management is undertaken.

Four members of the board of directors of HLS serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of HLS or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Exchange Act to serve on the audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we have an audit committee of three independent directors that reviews our external financial reporting, selects our independent registered public accounting firm, and reviews procedures for internal auditing and the adequacy of our internal accounting controls. We also have a compensation committee consisting of three independent directors, which oversees compensation decisions for certain officers of HLS whose time is fully committed to us and a portion of the long-term incentive compensation of other officers who only devote part of their time to the matters of HEP and who receive long-term incentive compensation with respect to their services. The compensation committee also oversees the compensation plans described below. In addition, we have an executive committee of the board consisting of two independent directors and one director employed by Holly.

The board of directors of HLS has determined that Messrs. Darling, Gray, Pinkerton and Stengel meet the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange and under the Exchange Act. These directors serve as the only members of our audit, conflicts and compensation committees.

We are managed and operated by the directors and officers of HLS on behalf of our general partner. Most of our operational personnel are employees of HLS.

Mr. Clifton spends approximately 25% of his time overseeing the management of our business and affairs. Messrs. Blair and Cunningham spend all of their time in the management of our business. The rest of our officers devote approximately one-quarter of their time to us. Our non-management directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

- 99 -

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


Name	Age		Position with HLS
Matthew P. Clifton		59	Chairman of the Board and Chief Executive Officer
Charles M. Darling, IV		62	Director
William J. Gray		70	Director
Jerry W. Pinkerton		70	Director
P. Dean Ridenour		69	Director
William P. Stengel		62	Director
Bruce R. Shaw		43	Senior Vice President and Chief Financial Officer
David G. Blair		52	President
Mark T. Cunningham		51	Vice President, Operations⁽¹⁾
Denise C. McWatters		51	Vice President, General Counsel and Secretary


(1)		Effective January 27, 2010, Mr. Cunningham was designated an executive officer. Previously, Mr. Cunningham was not an executive officer and was not required to file reports under Section 16 of the Securities Exchange Act of 1934, nor did he have significant policy-making responsibilities with us, but he was the next highest compensated officer. In an effort to provide complete disclosure, we began providing information on Mr. Cunningham in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Committee memberships as of the date of this Form 10-K Annual Report are set forth below:

Name

Executive

Audit

Compensation

Conflicts

Matthew P. Clifton

Charles M. Darling, IV

William J. Gray

Jerry W. Pinkerton

William P. Stengel


A “C” indicates that the director serves as the chair of the committee.

An “X” indicates membership on the committee.

The board of directors of HLS held ten meetings during 2010, with the audit committee, conflicts committee and compensation committee holding five, eleven, and eight meetings, respectively. During 2010, each director attended at least 75% of the total number of meetings of the Board.

The Board believes that it is necessary for each of the Company’s directors to possess many qualities and skills. When searching for new candidates, the sole member of HLS considers the evolving needs of the Board and searches for candidates that fill any current or anticipated future needs. The Board also believes that all directors must possess a considerable amount of business management, business leadership and educational experience. When considering director candidates, the sole member of HLS first considers a candidate’s management experience and then considers issues of judgment, background, stature, conflicts of interest, integrity, ethics and commitment to the goal of maximizing unitholder value. The sole member of HLS also focuses on issues of diversity, such as diversity of education, professional experience and differences in viewpoints and skills. The sole member of HLS does not have a formal policy with respect to diversity; however, the Board and the sole member of HLS believe that it is essential that the Board members represent diverse viewpoints. In considering candidates for the Board, the sole member of HLS considers the entirety of each candidate’s credentials in the context of these standards. With respect to the nomination of continuing directors for re-election, the individual’s contributions to the Board are also considered.

All our directors bring to the Board executive leadership experience derived from their service in the many areas detailed below for each director. Certain individual qualifications and skills of our directors that contribute to the Board’s effectiveness as a whole are described in the following paragraphs.

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The names of the current directors, along with biographical information, are set forth below.

Matthew P. Clifton was elected Chairman of our Board, and Chief Executive Officer in March 2004. He has been employed by Holly for over 30 years. Mr. Clifton served as Holly’s Vice President of Economics, Engineering and Legal Affairs from 1988 to 1991, Senior Vice President of Holly from 1991 to 1995, President of Navajo Pipeline Company, a wholly owned subsidiary of Holly, since its inception in 1981, President of Holly from 1995 to 2005 and has served as Chief Executive Officer of Holly since January 1, 2006. Mr. Clifton has also served as a director of Holly since 1995. The Board elected Mr. Clifton to Chairman of the Board because he has extensive knowledge of operations of the Company, the refining industry and macro-economic conditions, as well as valuable industry relationships throughout the country. Mr. Clifton brings a unique and valuable perspective as well as an understanding of the Company’s history, culture, vision and strategy to the Board. Mr. Clifton received his B.S. degree in Accounting and Finance from St. Joseph’s University.

Charles M. Darling, IV was appointed to our Board of Directors in July 2004. Mr. Darling has served as President of DQ Holdings, L.L.C., a venture capital investment and consulting firm focused primarily on opportunities in the energy industry, since August 1998. In addition, Mr. Darling was the General Manager of Desert Power, LP and of its General Partner, Desert Power, LLC, which was an indirect affiliate of DQ Holdings, LLC. In late 2006, Desert Power, LLC and Desert Power, LP, along with certain of their subsidiaries, filed for bankruptcy in Nevada. In late 2007, the bankruptcy court approved the plan of reorganization, which became final in accordance with its terms in early 2008. From 1997 to 1998, Mr. Darling was the President and General Counsel, and was a Director from 1993 to 1998, of DeepTech International, which was acquired by El Paso Energy Corp. in August 1998. Mr. Darling was also a Director at Leviathan Gas Pipeline Company from 1993 through 1998. Prior to joining DeepTech in 1997, Mr. Darling practiced law at the law firm of Baker Botts, L.L.P., for over 20 years. The sole member of HLS appointed Mr. Darling to serve as a director due to his director and executive managerial experience in public companies, his extensive financial experience, and his experience in dealing with legal, regulatory and risk matters affecting the Company due to his 20-year legal practice at a large, national law firm, his service as President and General Counsel of a publicly traded energy company with a publicly traded pipelines MLP, and his subsequent endeavors in the energy industry. Mr. Darling’s leadership skills, management and legal experience make him particularly well suited to be our Presiding Director. Mr. Darling received his B.A. degree in from Columbia University and his J.D. from the University of Pennsylvania.

William J. Gray was appointed to our Board of Directors in April 2008. Mr. Gray is a private consultant, a member of the New Mexico House of Representatives (since November 2006), and served as a director of Holly Corporation from September 1996 until May 2008. He has also served as a governmental affairs consultant for Holly Corporation since January 2003 and as a consultant to Holly from October 1999 through September 2001. Mr. Gray was employed by Holly Corporation for over 30 years and retired in October 1999 at which time Mr. Gray was Senior Vice President, Marketing and Supply. The sole member of HLS appointed Mr. Gray to serve as a director due to his forty years of experience in pipeline, refining, and marketing and supply, for his business and management expertise, and for his regulatory and governmental experience and perspective. Mr. Gray received his BSIE degree from Texas Tech University.

Jerry W. Pinkerton was appointed to our Board of Directors in July 2004. Since December 2003, Mr. Pinkerton has been retired. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp and from August 1997 to December 2000, Mr. Pinkerton served as Controller of TXU and its U.S. subsidiaries. From August 1988 until its merger with TXU in August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior to joining ENSERCH, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. Mr. Pinkerton also sits on the board of directors of Animal Health International, Inc. where he serves as chairman of its audit committee. The sole member of HLS appointed Mr. Pinkerton to serve as a director due to his audit, accounting and financial reporting expertise and a level of financial sophistication that qualifies him as a financial expert for his role as the chairman of the audit committee. Due to his executive managerial experience with public companies and public accounting firms and his service on each of the Company’s four committees, Mr. Pinkerton possesses business and management expertise, a broad range of expertise and knowledge of Board committee functions, providing an invaluable insight into the Company’s business. Mr. Pinkerton received his B.B.A. degree in Accounting from The University of North Texas.

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P. Dean Ridenour was appointed to our Board of Directors in August 2004 and served as Vice President and Chief Accounting Officer from January 2005 to January 2008. Mr. Ridenour served as Vice President, Special Projects of Holly Corporation from August 2004 to December 2004 and prior to becoming a full-time employee, provided full-time consulting services to Holly Corporation beginning in October 2002. From April 2001 until October 2002, Mr. Ridenour temporarily retired. From July 1999 through April 2001, Mr. Ridenour served as Chief Financial Officer and director of GeoUtilities, Inc., an internet-based superstore for energy, telecom and other utility services, which was purchased by AES Corporation in March 2000. Mr. Ridenour was employed for 34 years by Ernst & Young LLP, including 20 years as an audit partner, retiring in 1997. Mr. Ridenour is no longer an officer of HEP. The sole member of HLS appointed Mr. Ridenour to serve as a director due to his management experience, accounting and financial reporting expertise. Mr. Ridenour received his B.B.A. in Accounting and his M.A. in Finance from the University of Iowa.

William P. Stengel was appointed to our Board of Directors in July 2004. Mr. Stengel has been retired since May 2003. From 1997 to May 2003, Mr. Stengel served as Managing Director of the global energy and mining group at Citigroup/Citibank, N.A. From 1973 to 1997, Mr. Stengel served in various other capacities with Citigroup/Citibank, N.A. The sole member of HLS appointed Mr. Stengel to serve as a director due to his executive management experience in public companies, banking and financial expertise, and general business and management expertise. Due to his service on each of the Company’s four committees, Mr. Stengel possesses a broad range of expertise and knowledge of Board committee functions, providing an invaluable insight into the Company’s business. Mr. Stengel received his B.A. degree in Biology from Princeton University, and his MBA in Finance from Columbia University.

None of our directors reported any litigation for the period from 2001 to 2011 that is required to be reported in this Form 10-K Annual Report.

The names of the current executive officers, along with biographical information, are set forth below, except for that of Mr. Clifton which is included above.

Bruce R. Shaw was elected Senior Vice President, Chief Financial Officer in January 2008. Mr. Shaw served on our Board of Directors from April 2007 to April 2008 and as Vice President, Special Projects for Holly from September 2007 to December 2007. Prior to September 2007, Mr. Shaw briefly left Holly in June 2007 and served as President of Standard Supply and Distributing Company, Inc. and Bartos Industries, Ltd., two companies that are affiliated with each other in the heating, ventilation, and air conditioning industry. Mr. Shaw previously served Holly in various positions including Vice President of Corporate Development from February 2006 to May 2007, Vice President of Crude Purchasing and Corporate Development from February 2005 to February 2006, Vice President of Corporate Development from March 2004 to February 2005, Vice President of Marketing and Corporate Development from November 2003 to March 2004, Vice President of Corporate Development from October 2001 to November 2003 and Director of Corporate Development from June 1997 to January 2000. Mr. Shaw also served as Vice President, Corporate Development for HLS from August 2004 to January 2007. Mr. Shaw received his undergraduate degree in Mechanical Engineering from Texas A&M University and his MBA from Dartmouth College.

David G. Blair was elected President in January 2010. He has been employed by Holly for over 29 years. Mr. Blair served as our Senior Vice President from January 2007 to December 2009. Prior to January 2007, Mr. Blair served as Holly’s Vice President responsible for Holly Asphalt Company from February 2005 to December 2006. Mr. Blair was General Manager of the NK Asphalt Partnership between Koch Materials Company and Navajo Refining Company from July 2000 to February 2005. Mr. Blair was named Vice President, Marketing, Asphalt & Specialty Products in October 1994. Mr. Blair served in various positions within Holly in crude oil supply, wholesale product marketing, and supply and trading from 1981 to 1991. Mr. Blair received his B.B.A. degree in Finance from Texas Tech University.

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Mark T. Cunningham was elected Vice President of Operations in July of 2007. He has served Holly as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of Integrity Management and EH&S from July 2004 through December 2006. Prior to joining Holly, Mr. Cunningham served Diamond Shamrock/Ultramar Diamond Shamrock for 20 years in several engineering and pipeline operations capacities. He began his time with Diamond Shamrock in 1983 and served in various positions, including Senior Design Engineer, Superintendent of Special Projects, Regional Manager and General Manager of Operations and Director of Operations through April 2003. Mr. Cunningham provided consulting engineering services from May 2003 to June 2004. Mr. Cunningham received his B.S. degree in Electrical Engineering from Texas Tech University and his MBA from West Texas State University.

Denise C. McWatters was elected Vice President, General Counsel and Secretary in April 2008. Ms. McWatters also serves in a similar capacity for Holly. She joined Holly in October 2007 as Deputy General Counsel with more than 20 years of legal experience. Ms. McWatters served as the General Counsel of The Beck Group from 2005 through 2007. From 2002 through May 2005, Ms. McWatters practiced law in the Law Offices of Denise McWatters. Prior to such practice, Ms. McWatters was a shareholder in the predecessor firm to Locke Lord Bissell & Liddell LLP, served as Counsel in the legal department at Citigroup, N.A. and was a shareholder in the law firm of Cox Smith Matthews Incorporated. Ms. McWatters received her B.S. and M.A. in Psychology from Southern Methodist University and her J.D. from The University of Texas School of Law.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10% of HEP’s units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of HEP’s equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required all such reports concerning beneficial ownership were filed in a timely manner by reporting persons during the year ended December 31, 2010, except for one Form 4 filed on February 11, 2010 with respect to the surrender of HEP common units held by P. Dean Ridenour, a director of HLS, to satisfy tax withholding obligations with respect to the vesting of certain restricted units on January 1, 2010. In addition, two Forms 4/A were filed on January 4, 2011 to correct errors in Forms 4 that were timely filed on January 5, 2010 by David G. Blair and Bruce R. Shaw, the President and the Senior Vice President and Chief Financial Officer, respectively, of HLS. The Forms 4 that were timely filed by Mr. Blair and Mr. Shaw on January 5, 2010 each contained an error in the reported number of common units surrendered to satisfy tax withholding obligations with respect to the vesting of certain restricted units on January 1, 2010. The Forms 4/A filed by Mr. Blair and Mr. Shaw on January 4, 2011 corrected those reporting errors.

Audit Committee

The audit committee of HLS is composed of three directors who are not officers or employees of HEP or any of its subsidiaries or Holly Corporation or any of its subsidiaries. The board of directors of HLS has adopted a written charter for the audit committee. The board of directors of HLS has determined that a member of the audit committee, namely Jerry W. Pinkerton, is an audit committee financial expert (as defined by the SEC) and has designated Mr. Pinkerton as the audit committee financial expert. As indicated above, the board of directors of HLS has determined that Mr. Pinkerton meets the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange and under the Exchange Act.

The audit committee selects our independent registered public accounting firm and reviews the professional services they provide. It reviews the scope of the audit performed by the independent registered public accounting firm, the audit report issued by the independent auditor, HEP’s annual and quarterly financial statements, any material comments contained in the auditor’s letters to management, HEP’s internal accounting controls and such other matters relating to accounting, auditing and financial reporting as it deems appropriate. In addition, the audit committee reviews the type and extent of any non-audit work to be performed by the independent registered public accounting firm and its compatibility with their continued objectivity and independence.

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Report of the Audit Committee for the Year Ended December 31, 2010

Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s internal controls and the financial reporting process. The audit committee selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of Holly Energy Partners, L.P. for the year ended December 31, 2010. Ernst & Young LLP is responsible for performing an independent audit of Holly Energy Partners, L.P.’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and to issue a report thereon as well as to issue a report on the effectiveness of Holly Energy Partners, L.P.’s internal control over financial reporting. The audit committee monitors and oversees these processes.

The audit committee has reviewed and discussed Holly Energy Partners, L.P.’s audited consolidated financial statements with management and Ernst & Young LLP. The audit committee has discussed with Ernst & Young LLP the matters required to be discussed by Statement on Auditing Standards No. 114, “The Auditor’s Communication With Those Charged With Governance.” The audit committee has received the written disclosures and the letter from Ernst & Young LLP pursuant to Rule 3526 of the Public Company Accounting Oversight Board, “Communication With Audit Committees Governing Independence,” and has discussed with Ernst & Young LLP that firm’s independence.

The board of directors of our general partner, upon recommendation by the audit committee, has adopted an audit committee charter, which is available on our website at www.hollyenergy.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All fees for audit, audit-related and tax services as well as all other fees presented under Item 14 “Principal Accountant Fees and Services” were approved by the audit committee in accordance with the charter.

Based on the foregoing review and discussions and such other matters the audit committee deemed relevant and appropriate, the audit committee recommended to the board of directors that the audited consolidated financial statements of Holly Energy Partners, L.P. be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2010.

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

Code of Ethics

HEP has adopted a Code of Business Conduct and Ethics that applies to all officers, directors and employees, including the company’s principal executive officer, principal financial officer, and principal accounting officer.

Available on our website at www.hollyenergy.com are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which also will be provided in print without charge upon written request to the Vice President, Investor Relations at: Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600, Dallas, TX, 75201-6915. HEP intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding any amendment to, or any waiver of, a provision of its Code of Business Conduct and Ethics with respect to its principal financial officers by posting such information on this website.

New York Stock Exchange Certification

In 2010, Mr. Clifton, as the Chief Executive Officer of HEP, provided to the New York Stock Exchange the annual CEO certification regarding HEP’s compliance with the New York Stock Exchange’s corporate governance listing standards.

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Item 11. Executive Compensation

DIRECTOR COMPENSATION

Members of the Board of Directors of HLS who also serve as officers or employees of HLS or Holly do not receive additional compensation in their capacity as directors. The only officer of HLS or Holly who also served as a director during 2010 was Mr. Clifton.

For the year ended December 31, 2010, directors who are not employees of HLS or its subsidiaries were compensated as follows:


Annual cash retainer (payable in four quarterly installments)	$	50,000
Each attended board meeting or committee meeting (also paid to non-members of committees who are invited to attend by such committee’s chairman) (1)	$	1,500
Telephonic special board or committee meetings (under 30 minutes)	$	0
Telephonic special board or committee meetings (over 30 minutes)	$	1,000
Each attended strategy meeting with HLS management	$	1,500
Annual grant of restricted units under the Long-Term Incentive Plan (2)	$	50,000
Special cash retainer for Chairpersons of committees (payable in four quarterly installments)	$	10,000

Each director is fully indemnified by HLS for actions associated with being a director to the extent permitted under Delaware law.


(1)		Upon submission of appropriate receipts, directors are also reimbursed for reasonable out-of-pocket expenses in connection with attending board or committee meetings.

(2)		Directors receive an annual grant under the Holly Energy Partners, L.P. Long-Term Incentive Plan (“Long-Term Incentive Plan”) of restricted HEP units equal in value to $50,000 on the date of grant, with 100% vesting one year after the date of grant.

		Restricted unit grants are based upon the market closing price of our common units on the day of the grant (or the last business day prior, if August 1 occurs on a non-business day). With respect to the restricted units, the units fully vest one year following the date of grant if the Director continues serving on the Board until the end of the one-year vesting period. Accelerated vesting will occur on a pro-rata basis upon a change in control, the Director’s total and permanent disability or death, or the Director’s retirement.

		Vesting of the restricted units will occur upon the earlier of: (a) the Director’s death, (b) the Director’s total and permanent disability, as determined by the Committee in its sole discretion, (c) the Director’s retirement, in accordance with any retirement policy of the Company regarding Board members (of which there is currently none), (d) a change in control, or (e) on the first anniversary of the date of the grant. Until such time as the restricted units are vested, the Director shall be entitled to receive all distributions paid with respect to such units and any right to vote with respect to such units (vesting pursuant to (a), (b) and (c) are prorated).

		For purposes of director restricted units, a change in control means, subject to certain specific exceptions set forth in the restricted unit agreements: (i) a person or group of persons (other than Holly, HLS, HEP, or any employee benefit plan of any of the three entities or its affiliates) becomes the beneficial owner of more than 40% of the combined voting power of the then outstanding securities of Holly, HLS or HEP or of the then outstanding common stock or membership interests, as applicable, of Holly or HLS, (ii) a majority of the members of Holly’s board of directors is replaced during a 12 month period by directors who were not elected or nominated by two-thirds of the board members prior to their appointment, (iii) the consummation of a merger of consolidation of Holly, HLS, HEP or any subsidiary of any of the foregoing other than (A) a merger or consolidation resulting in the voting securities of Holly, HLS, or HEP, as applicable, outstanding immediately prior to the transaction continuing to represent at least 60% of the combined voting power of the voting securities of Holly, HLS, HEP or the surviving entity, as applicable, outstanding immediately after the transaction, or (B) a merger of consolidation effected to implement a recapitalization of Holly, HLS, or HEP in which no person or group becomes the beneficial owner of securities of Holly, HLS, or HEP representing more than 50% of the combined voting power of the then outstanding securities of Holly, HLS or HEP, or (iv) the stockholders or unit holders, as applicable, of Holly or HEP approve a plan of complete liquidation or dissolution of Holly or HEP or an agreement for the sale or disposition of all or substantially all of the assets of Holly or HEP.

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During the calendar year ending December 31, 2010, compensation was made to directors of HLS as set forth below:


	Fees Earned or				All Other
	Paid in Cash (1)		Stock Awards (2)		Compensation (3)		Total
Charles M. Darling, IV	$	104,015	$	49,993		0	$	154,008
William Gray	$	92,015	$	49,993	$	32,119	$	142,008
Jerry W. Pinkerton	$	104,015	$	49,993		0	$	154,008
P. Dean Ridenour	$	85,015	$	49,993		0	$	135,008
William P. Stengel	$	104,015	$	49,993		0	$	154,008


(1)		The total amounts under fees earned or paid in cash includes amounts earned by directors for attending meetings during the 2010 calendar year that will be paid in 2011.

(2)		Reflects the aggregate grant date fair value of all awards computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, determined without regard to forfeitures. See note 6 to our consolidated financial statements for the fiscal year ended December 31, 2010, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards. Each of the 2010 directors received an award of 1,080 restricted HEP units under the Long-Term Incentive Plan on August 1, 2010 with a grant date fair value of $49,993 (computed using the closing price of $46.29 on July 30, 2010 (the last business day before the date of grant) that will vest on August 1, 2011. The fair market value of each restricted unit grant is amortized over the one year vesting period. As of December 31, 2010, Messrs. Darling, Gray, Pinkerton, Ridenour and Stengel each held 1,080 unvested restricted units.

(3)		In addition to the $92,015 of director fees reflected in this table, Mr. Gray received $32,119 for consulting services provided by Mr. Gray to Holly during 2010. None of the consulting fees were paid by HEP.

COMPENSATION DISCUSSION AND ANALYSIS

This compensation discussion and analysis (“CD&A”) provides information about our compensation objectives and policies for the HLS officers that also act as our principal executive officer, our principal financial officer and our three other most highly compensated executive officers and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. We provide a general description of our compensation program and specific information about its various components. Additionally, we describe our policies relating to reimbursement to Holly for compensation expenses. Immediately following this CD&A is our Compensation Committee Report (the “Committee Report”).

Overview

HEP is managed by HLS, the general partner of HEP’s general partner. HLS is a subsidiary of Holly. The employees providing services to HEP are employed by HLS, as HEP itself has no employees. As of December 31, 2010, HLS had 148 employees that provided general, administrative and operational services to HEP. Throughout this discussion, the following HLS officers are referred to as our “Named Executive Officers” and are included in the Summary Compensation Table:

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

Bruce R. Shaw, Senior Vice President and Chief Financial Officer;

David G. Blair, President;

Mark T. Cunningham, Vice President; and

Denise C. McWatters, Vice President, General Counsel and Secretary.

Of the five HEP Named Executive Officers, only Messrs. Blair and Cunningham are allocated 100% to HLS.

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Under the terms of the Omnibus Agreement, we currently pay an annual administrative fee to Holly of $2,300,000 for the provision of general and administrative services for our benefit, which may be increased or decreased as permitted under the Omnibus Agreement. Additionally, we reimburse Holly for expenses incurred on our behalf. The administrative services covered by the Omnibus Agreement include, without limitation, the costs of corporate services provided to HEP by Holly such as accounting, information technology, human resources, in-house legal support and limited outside legal support for general corporate and tax matters; office space, furnishings and equipment; and limited transportation of HEP executive officers and employees on Holly airplanes for business purposes. The partnership agreement provides that our general partner will determine the expenses that are allocable to HEP. See Item 13, “Certain Relationships, Related Transactions and Director Independence” of this Form 10-K Annual Report for additional discussion of our relationships and transactions with Holly. None of the services covered by the administrative fee are assigned any particular value individually. Although certain Named Executive Officers provide services to both Holly and HEP, no portion of the administrative fee is specifically allocated to services provided by the Named Executive Officers to HEP; rather, the administrative fee covers services provided to HEP by Holly and, except as described below, there is no reimbursement by HEP for the cost of such services. With respect to equity compensation paid by HEP to the Named Executive Officers, HLS purchases the units, and HEP reimburses HLS for the purchase price of the units.

With respect to Messrs. Blair and Cunningham, we reimbursed Holly for 100% of the compensation expenses incurred by Holly for salary, bonus, retirement and other benefits provided to the officers for 2010. We reimbursed HLS for 100% of the expenses incurred in providing Messrs. Blair and Cunningham with long-term equity incentive compensation. All compensation paid to them is fully disclosed in the tabular disclosure following this CD&A.

Messrs. Clifton and Shaw and Ms. McWatters were compensated by HLS for the services they perform for HLS through awards of equity-based compensation granted pursuant to the Long-Term Incentive Plan. None of the cash compensation paid, or other benefits made available to, Messrs. Clifton and Shaw and Ms. McWatters by Holly was allocated to the services they provide to HLS and, therefore, only the Long-Term Incentive Plan awards granted to them are disclosed herein.

Objectives of Compensation Program

Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance the long-term value of HEP for the benefit of its unitholders. Our objective is to be competitive with our industry and encourage high levels of performance from our executives.

The HLS compensation committee (the “Committee”), comprised entirely of independent directors, administers the Long-Term Incentive Plan for certain HLS employees. The Committee determined and approved the long-term equity incentive compensation to be paid to each of the Named Executive Officers and the other elements of compensation (in addition to the long-term equity incentive compensation) to be paid to Messrs. Blair and Cunningham.

As to Messrs. Blair and Cunningham, the Committee has not adopted any formal policies for allocating compensation among salaries, bonuses and long-term equity incentive compensation. Instead, the Committee attempts to balance the use of both cash and equity compensation in the total compensation package provided to Messrs. Blair and Cunningham and as to our other Named Executive Officers, attempts to utilize long-term equity incentive compensation to build value to both HEP and its unitholders. The Committee considers both recommendations by management and other factors in determining the final compensation factors that are appropriate for both HEP and each Named Executive Officer for which it is responsible. The Committee does not review or approve pension benefits for Named Executive Officers, and all pension and retirement benefits provided to the executives are the same pension benefits that are provided to Holly employees.

In January and February 2010, the Committee, with the assistance of management (other than Messrs. Blair and Cunningham as to Mr. Blair, and other than Mr. Cunningham as to Mr. Cunningham), reviewed the mix and level of cash and long-term equity incentive compensation for Messrs. Blair and Cunningham with a goal of providing sufficient current compensation to retain them, while at the same time providing incentives to maximize long-term value for HEP and its unitholders. The Committee, with the assistance of the Chairman (other than as to the Chairman), and Mr. Blair (other than as to the Chairman and Mr. Blair), annually performs an internal review of each of the Named Executive Officers’ long-term incentive compensation to determine whether the executives are being provided with equity awards that are effective in motivating the Named Executive Officers to create long-term value for HEP. These long-term equity incentives are designed to retain the executives during the period of time during which their performance is expected to impact our business and reward them in accordance with the success of those long-term goals and policies.

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Role of the Compensation Committee Consultant and the Committee in the Compensation Setting Process

The Committee has engaged Frederic W. Cook & Co. (the “Compensation Consultant”), an outside consulting firm specializing in executive compensation, to advise the Committee on matters related to executive, long-term equity incentives, and non-employee director compensation. The Compensation Consultant provides the Committee with relevant market data, updates on related trends and developments, advice on program design, and input on compensation decisions for executive officers and non-employee directors. The Compensation Consultant is independent, retained directly by the Committee, and provides no other services to us.

The Compensation Consultant does not have authority to determine the ultimate compensation that is provided to employees, and the Committee is under no obligation to utilize the information provided by the Compensation Consultant when making compensation decisions. Instead, the Compensation Consultant provides recommendations to the Committee by identifying areas that do not appear to be consistent with the general practice of our peers (without setting specific benchmarks). The Compensation Consultant provides recommendations to the Committee prior to the Committee meetings at which salaries are approved, bonuses are awarded and equity compensation is established for the upcoming year.

Review of Market Data

Market pay levels are one of many factors considered by the Committee in setting compensation for the Named Executive Officers, and we regularly review comparison data provided by our Compensation Consultant in regard to salary and annual incentive levels. This review provides a frame of reference as a starting point in evaluating the reasonableness and competitiveness of compensation within the sector of the energy industry with which we compete for executive talent, and to ensure that our compensation reflects practices of reasonably comparable companies of similar size and scope of operations. Our Compensation Consultant obtains market information from various sources, including published compensation surveys (including, but not limited to, the Liquid Pipeline Roundtable Compensation Survey) and information taken from the SEC filings for groups of publicly traded organizations, as compiled by our Compensation Consultant, that we and our Compensation Consultant consider appropriate peer organizations. The purpose of the peer groups is to provide a frame of reference for our consideration of what compensation is appropriate for our executives and to ensure that our compensation is generally comparable to companies of similar size and scope of operations rather than to set specific benchmarks for the compensation provided to the Named Executive Officers and other executive officers. We look at multiple peer groups because we believe it is beneficial to reference several relevant data points.

The first peer group used by our Compensation Consultant includes publicly traded master limited partnerships (“MLPs”) that are representative of the types of companies with which we compete for executives. The composition of our peer group was reviewed by the Committee in 2010 in light of merger & acquisition activity, availability of relevant pay data, geographic location, organization size, and other considerations that the Committee felt were appropriate factors in ensuring the relevance of the peer group to us, as a result of which the Committee, in October 2010, adjusted the peer group it utilized.

Our 2010 peer group before and after the October 2010 adjustment is as follows:


Company Name	Before Adjustment		After Adjustment
Atlas Pipeline Partners, L.P.		X		X
Buckeye Energy Partners, L.P.		X		X
Copano Energy, L.L.C.				X
Crosstex Energy, L.P.		X		X
DCP Midstream Partners L.P.				X
Enbridge Energy Partners, L.P.		X
Genesis Energy, L.P.				X
Hiland Partners, LP.		X
Inergy L.P.		X		X
Kinder Morgan Energy Partners, L.P.		X
Magellan Midstream Partners, L.P.		X		X
MarkWest Energy Partners, L.P.		X		X
NuStar Energy L.P.		X		X
Regency Energy Partners, L.P.				X
Sunoco Logistics Partners L.P.		X		X
Targa Resources Partners, L.P.				X
TC Pipelines, L.P.		X
TEPPCO Partners, L.P.		X

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In addition, there is a second peer group that is used by Holly for long-term incentive compensation (which program we utilize as one reference point in our long-term incentive compensation decisions). In 2010, this peer group consisted of the following broader group of energy companies:

Company Name

BJ Services Company
Cameron International Corporation
Crosstex Energy, Inc.,
CVR Energy, Inc.,
El Paso Corporation
Exterran Energy Corp.
FMC Technologies, Inc.
Frontier Oil Corporation
Murphy Oil Corporation
Spectra Energy Corp.
Tesoro Corporation
The Williams Companies, Inc.
Western Refining, Inc.

Holly modified this second peer group in late 2010 in order to update the group of companies that Holly would use as a relevant peer group when comparing executive compensation levels for the 2011 year. The 2010 update did not impact any compensation decisions for the 2010 year at HEP.

Our objective generally is to position pay at levels approximately in the middle range of market practice, taking into account median levels derived from our peer group analyses. We consider our salary and non-salary compensation components in comparison to the median compensation levels within these peer groups rather than to an exact percentile above or below the median. If compensation is generally within plus or minus 15% to 20% of the market median, it is considered to be in the middle range of the market.

For each of the Named Executive Officers committing more than half their time to HEP in 2010 (Messrs. Blair and Cunningham), total compensation (including cash and equity components of total compensation) was in the middle range of the market. As noted, however, this market analysis is just one of many factors considered when making overall compensation decisions for our executives. The range of various compensation elements for Messrs. Clifton and Shaw and Ms. McWatters is discussed in further detail within the “Compensation Discussion and Analysis” section of Holly’s most recent proxy statement.

Role of Named Executive Officers in Determining Executive Compensation

In making executive compensation decisions, the Committee solicited the recommendations of our Chief Executive Officer, except with respect to his own compensation. In addition to the Compensation Consultant’s information and various peer group trends, the Committee considered the Chief Executive Officer’s recommendations in making its determinations of compensation. The Committee also reviewed the total compensation provided in the previous year in determining compensation to be paid in 2010 and established compensation for 2010 that was consistent with the compensation paid in 2009 after considering overall performance and the other specific factors discussed in this CD&A.

Various members of management facilitate the Committee’s consideration of compensation for Named Executive Officers by providing data for the Committee’s review. This data includes, but is not limited to, performance evaluations, performance compensation provided to the Named Executive Officers in previous years, tax-related considerations and accounting-related considerations. Management provides the Committee with guidance as to how such data impacts pre-determined performance goals set by the Committee during the previous year. When management considers a discretionary bonus to be appropriate, it will suggest an amount and provide the Committee with management’s rationale for such bonus. Given the day-to-day familiarity that management has with the work performed, the Committee values management’s recommendations, although no Named Executive Officer will have any authority to determine or comment on compensation decisions directly related to him or herself. The Committee makes the final decision as to the compensation as described in this CD&A.

Overview of 2010 Executive Compensation Components

After reviewing the internal evaluations, the input by management, and the market data provided by the Compensation Consultant, the Committee believes that the 2010 compensation for Messrs. Blair and Cunningham reflects an appropriate allocation of compensation between salary, bonuses and equity compensation.

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For Messrs. Blair and Cunningham, the components of compensation in 2010 were:

•

base salary;

•

annual performance-based cash incentive compensation;

•

long-term equity incentive compensation;

•

retirement and other post-employment benefits; and

•

health and welfare benefits.

In 2010, the only component of compensation we provided for Messrs. Clifton and Shaw and Ms. McWatters (the other Named Executive Officers) was long-term equity incentive compensation. Because Messrs. Clifton and Shaw and Ms. McWatters were committing less than half of their business time to HEP, during which time they were primarily involved in determining the long-term business goals and policies of HEP, the Committee believed that it was appropriate to compensate them only through long-term equity incentives. All Named Executive Officers receiving equity awards received HEP restricted units with the exception of Mr. Clifton, who only received an award of HEP performance units, and Mr. Blair, who received an award of both HEP restricted units and HEP performance units. The nature of each of these types of awards is more fully described below.

Base Salary

Base salaries for Messrs. Blair and Cunningham for 2010 were reviewed by the Committee based on each executive’s position, level of responsibility and individual performance, HLS’s salary range for individuals at each such executive’s level, and market practices. The Committee also reviewed competitive market data relevant to each position provided by the Compensation Consultant. Following a review of these various factors, the Committee determined that increases in the base salaries for Messrs. Blair and Cunningham were warranted for the 2010 year. The base salaries for Messrs. Blair and Cunningham were increased over ten percent in 2010 in recognition of both increased responsibilities and excellent performance, so that their respective base salaries more closely reflected the median range for their respective peers with similar responsibilities. The salary amounts for 2008, 2009 and 2010 for each of Messrs. Blair and Cunningham are set forth below in the Summary Compensation Table.

Annual Incentive Cash Bonus Compensation

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

The total bonus pool for all non-hourly personnel of HLS is established by the Committee after the end of each calendar year, giving consideration to amounts budgeted for the pool, operating results and employee performance. The awards to executives for a given year are paid in cash in the first quarter of the following year.

Payment with respect to cash bonuses to Messrs. Blair and Cunningham is contingent upon the satisfaction of pre-established performance criteria as they apply to each of them, all of which are evaluated by management and incorporated into the recommendations made to the Committee. The amounts paid for 2010 are disclosed in the Summary Compensation Table and the bonuses are more fully described, including percentages of the bonuses that could be attributable to each performance criteria, in greater detail in the narrative following the “2010 Grants of Plan-Based Awards” table. Generally, payment with respect to any 2010 cash bonus is contingent upon the satisfaction of the following criteria:

•

A portion of the bonus is equal to a pre-established percentage of the employee’s base salary and is earned based upon HEP’s distributable cash flow compared to the 2010 operating budget adjusted for differences in estimated and actual PPI adjustments and differences in the timing of known acquisitions. The performance metric of distributable cash flow is used because it is a widely accepted financial indicator used to compare partnership performance. We believe that this measure provides an enhanced perspective of the operating performance of our assets and the cash our business is generating, and is therefore a useful criteria in evaluating management’s performance and linking the payment of their bonus to our performance.

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•

A portion of the bonus is equal to a pre-established percentage of the employee’s base salary, based on the employee’s individual performance over the year. The employee’s individual performance for 2010 is evaluated through an annual performance review completed in February 2011, which is a subjective and discretionary review of each applicable individual. The review includes a written assessment provided by the employee’s immediate supervisor. The assessment reviews how well the employee displays each of the following competencies:

	•		Individual Performance

	•		Integrity

	•		Interpersonal Effectiveness

Each one of these performance dimensions has a variety of sub-categories that are separately reviewed. The assessment also evaluates how well the employee performed their individual goals for 2010.

•

When the Committee established the 2010 performance criteria, the Committee determined that it could award a total of up to 200% of the total target bonus based on performance in excess of the targets, and the Committee communicated these maximum amounts and performance measures that would be potentially applicable to each executive officer.

In addition to the pre-defined performance criteria, the Committee has discretion to approve an increase or a decrease in Messrs. Blair and Cunningham’s bonus. Increases and decreases are determined using the same factors that are used to establish bonuses, and poor results on the indicated factors could, in the discretion of the Committee, result in a decrease in a bonus. The Committee may consider other factors as well including, for example, environmental, health and safety. The Committee also considers whether conditions outside the control of the executives affected the factors. In cases where the performance objectives described above are achieved, yet the Committee believes additional compensation is warranted to reward an executive for outstanding performance, the Committee may award additional bonuses in its discretion. In making the determination as to whether such discretion should be applied (either to decrease a bonus or award additional bonuses), the Committee reviews recommendations from management. The Committee awarded Mr. Blair’s and Mr. Cunningham’s bonuses in recognition of the achievement of their performance targets and their impact on our improved financial results in 2010 and their efforts toward integration of several recent asset acquisitions. All 2010 bonuses will be paid in March 2011.

The Committee also utilized the analysis of the Compensation Consultant to determine how the compensation of Messrs. Blair and Cunningham, including bonus payments, compared to our peers and a market average. The annual incentive targets were assessed on the basis of total cash compensation, including base salary and annual incentive payments. The Committee believes this analysis verifies that total cash compensation to Messrs. Blair and Cunningham is appropriate for the level of responsibility that each of these officers hold as well as in comparison to cash compensation levels of comparable executives at our peer companies. The salary and non-salary components of total cash compensation for Messrs. Blair and Cunningham approximated the middle range and median levels of the benchmark MLP group.

The target and actual annual incentive cash bonus compensation awarded (and subsequently earned and payable) is described in the narrative to the section titled “2010 Grants of Plan-Based Awards”.

The Committee has established 2011 performance goals for existing salary grades. Performance goals for all salary grades will remain the same in 2011 as those set for 2010.

Long-Term Incentive Equity Compensation

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

The Long-Term Incentive Plan contemplates four potential types of awards: restricted units (including fully vested bonus units), performance units, unit options and unit appreciation rights. Since the inception of HEP, we have made only restricted unit (including fully vested bonus units) and performance unit awards.

With respect to the Named Executive Officers, in determining the appropriate amount and type of long-term equity incentive awards to be made, the Committee considers the amount of time devoted by each executive to our business, the executive’s position and scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies. The awards are granted annually during the first quarter of the year. Our goal is to reward the creation of value and high performance with variable compensation dependent on that performance. The total compensation may then be adjusted, including if the Committee observes a material variation from the market data (however, no specific formula is used to benchmark this data). The Committee believes this analysis verifies that total equity compensation to Messrs. Clifton, Shaw, Blair and Cunningham and Ms. McWatters is appropriate for the level of responsibility that each of these officers hold.

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Restricted Unit Awards

A restricted unit award is an award of common units that is subject to forfeiture upon termination of employment prior to the vesting of the award. The Committee may approve grants on terms that it determines appropriate, including the period during which the award will vest. Under the Long-Term Incentive Plan, the Committee may condition vesting upon the achievement of specified financial objectives. The restricted units will vest upon a change of control of HEP, our general partner, HLS or Holly, unless provided otherwise by the Committee in the agreement governing the award. The individual award agreements governing the restricted units granted to our Named Executive Officers to date have included an additional requirement that the vesting upon a change in control of HEP, HLS or Holly, as applicable, will be subject to the individual being terminated by us without cause or due to an adverse change in his or her employment relationship (the terms of which are described in greater detail in the “Potential Payments Upon Termination or Change in Control” below), meaning that the restricted units are subject to a “double-trigger” vesting event rather than a “single-trigger” event as provided in the Long-Term Incentive Plan document. However, the Long-Term Incentive Plan does allow us to provide for single-trigger change in control benefits in the event that the Committee has determined that the situation would be appropriate for any particular grant, and such grants may occur in the future. Restricted unit holders have all the rights of a unitholder with respect to such restricted units, including the right to receive all distributions paid with respect to such restricted units and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period.

In 2010, the Named Executive Officers who were granted awards of restricted units were Messrs. Blair, Cunningham and Shaw and Ms. McWatters. All of the restricted units granted in 2010 vest in thirds over three annual periods and will be fully vested and nonforfeitable after December 31, 2012, as described in greater detail in the narrative in the section titled “2010 Grants of Plan-Based Awards.” In addition, Mr. Clifton was granted an award of 6,000 fully vested bonus units in recognition of his leadership and efforts in connection with (a) our improved financial results in 2009, and (b) our various asset acquisitions in 2009.

Performance Units

A performance unit is a notational phantom unit that entitles the grantee to receive a common unit upon the vesting of the unit or, as may be provided in the applicable agreement between the grantee and HLS, the cash equivalent to the value of a common unit. The grants made during the 2010 year are governed by award agreements that provide solely for settlement in units. Performance units will only be settled upon the attainment of pre-established performance targets. The Committee may approve grants on such terms as the Committee shall determine. The Committee approves the period over which performance units will vest, and the Committee may base its determination upon the achievement of specified financial objectives. As with restricted units, performance units may vest upon a change of control of HEP, our general partner, HLS or Holly, unless provided otherwise by the Committee; to date, the individual performance unit agreements do provide for the “double-trigger” vesting provisions described above for the restricted units. Performance units are also subject to forfeiture in the event that the executive’s employment or service relationship terminates for any reason, unless and to the extent that the Committee provides otherwise.

In 2010, performance units were awarded to Messrs. Clifton and Blair given their responsibilities to HEP with respect to long-term strategy. The performance period for such award is from January 1, 2010 through December 31, 2012. Messrs. Clifton and Blair may earn no less than 50% and no more than 150% of the performance units subject to their awards over the course of the performance period as described more fully in the narrative in the section below titled “2010 Grant of Plan-Based Awards.” The performance units currently outstanding may be settled only in common units of HEP. Prior to vesting, distributions are paid on each performance unit at the same rate as distributions paid on our common units.

Acquisition of Common Units for Long-Term Incentive Equity Awards

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

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Tax and Accounting Implications

We account for the equity compensation expense for our employees and executive officers, including our Named Executive Officers, under the rules of FASB ASC Topic 718, which requires us to estimate and record an expense for each award of equity compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued. Because we are a partnership, Section 162(m) of the Code does not apply to compensation paid to our Named Executive Officers; accordingly, the Committee did not consider its impact in determining compensation levels for the 2010 year. The Committee has taken into account the tax implications to the partnership in its decision to grant long-term incentive compensation awards of restricted and performance units as opposed to options or unit appreciation rights.

Retirement and Benefit Plans

The cost of retirement and welfare benefits for employees of HLS are charged monthly to us by Holly in accordance with the terms of the Omnibus Agreement. These employees participate in the health and welfare benefit plans available to our full-time employees, generally. Employees of HLS also participate in Holly’s Retirement Plan (a tax qualified defined benefit plan) and Holly’s Thrift Plan (a tax qualified defined contribution plan). Holly’s Retirement Plan is described below in the narrative accompanying the Pension Benefits Table.

The Thrift Plan is offered to all employees of HLS. Employees may, at their election, contribute to the Thrift Plan amounts from 0% up to a maximum of 75% of their eligible compensation. In 2006, employees had the option to participate in both the Retirement Plan and the Thrift Plan. Effective January 1, 2007, the Retirement Plan was frozen for new employees not covered by collective bargaining agreements with labor unions, and these new employees were required to participate in the new Automatic Thrift Plan Contribution feature under the Thrift Plan (the amounts attributable to employer contributions are shown in the Summary Compensation Table below). To the extent an employee was hired prior to January 1, 2007, and elected to begin receiving the Automatic Thrift Plan Contribution under the Thrift Plan, their participation in future benefits under the Retirement Plan was frozen. The Automatic Thrift Plan Contribution is up to 5% of eligible compensation, subject to applicable IRS limits, and it is paid in addition to employee deferrals and employer matching contributions under the Thrift Plan.

For employees not covered by collective bargaining agreements with labor unions, Holly provided (a) a 100% match of employee contributions to the Thrift Plan up to 6% of their eligible compensation from January 1, 2010 through May 31, 2010, and (b) a 50% match of employee contributions to the Thrift Plan up to 6% of their eligible compensation from June 1, 2010 through December 31, 2010. Effective January 1, 2011, Holly reinstated the 100% match of employee contributions to the Thrift Plan up to 6% of their eligible compensation. Employee contributions that were made on a tax-deferred basis were generally limited to $16,500 per year, with employees 50 years of age or over able to make additional tax-deferred contributions of $5,500. Prior to 2007, Holly’s contributions in the Thrift Plan did not vest until the earlier of three years of credited service or termination of employment due to retirement, disability or death. On and after January 1, 2007, company matching contributions for employees not covered by collective bargaining agreements with labor unions are immediately vested with no waiting period. Automatic Thrift Plan Contributions are still subject to a three year cliff vesting period.

Neither Messrs. Blair nor Cunningham elected to receive the Automatic Thrift Plan Contribution under the Thrift Plan, and both remained in the Holly Retirement Plan that is discussed below in the section entitled “Pension Benefits Table.” Messrs. Blair and Cunningham are the only Named Executive Officers whose Retirement Plan and Thrift Plan benefits are charged to us by Holly.

Change in Control Agreements

As of the date of this Form 10-K Annual Report, neither we nor HLS has entered into any employment agreements or severance agreements with any of the Named Executive Officers. Holly has entered into Change in Control Agreements with Messrs. Blair and Cunningham. The material terms of, and the quantification of, the potential amounts payable under the Change in Control Agreements are described below in the section titled “Potential Payments upon Termination or Change in Control.” As described above with respect to the restricted unit and performance unit awards, the Change in Control Agreements contain “double-trigger” payment provisions that will not only require a change in control, but a qualifying termination of the executive prior to the individual becoming entitled to benefits pursuant to these agreements. Holly has historically provided these agreements to Messrs. Blair and Cunningham to provide for management continuity in the event of a change of control and to provide competitive benefits for the recruitment and retention of executives. On February 14, 2011, the HLS Board of Directors adopted the Holly Energy Partners, L.P. Change in Control Policy and the related form of Change in Control Agreement to be entered into between HEP and certain officers of HLS. As of the date of this Form 10-K Annual Report, it is anticipated that the Change in Control Agreements between Holly and each of Messrs. Blair and Cunningham will be terminated and, upon such termination, that each of Messrs. Blair and Cunningham will enter into a Change in Control Agreement with HEP in accordance with the Holly Energy Partners, L.P. Change in Control Policy recently adopted by the HLS Board of Directors. HEP will bear all costs and expenses associated with these agreements.

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Compensation Committee Report

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

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

Summary Compensation Table

The table below summarizes the total compensation paid or earned by each of the Named Executive Officers in 2010, 2009 and 2008. As previously noted, the cash compensation and benefits for Named Executive Officers other than Messrs. Blair and Cunningham were not paid by us, but rather by Holly, and were not allocated to the services those Named Executive Officers performed for us in 2010. Information regarding the compensation paid to Messrs. Clifton and Shaw and Ms. McWatters as consideration for the services they perform for Holly will be reported in Holly’s annual proxy statement.

Summary Compensation Table(1)


											Non-Equity
											Incentive
											Plan		Change in		All Other
Name and Principal								Stock			Compen-		Pension		Compen-
Position	Year		Salary			Bonus⁽²⁾		Awards ⁽³⁾			sation⁽⁴⁾		Value⁽⁵⁾		sation ⁽⁶⁾		Total
Matthew P. Clifton, Chairman of the Board and Chief Executive Officer		2010		n/a			n/a	$	844,057			n/a		n/a		n/a	$	844,057
		2009		n/a			n/a	$	500,018			n/a		n/a		n/a	$	500,018
		2008		n/a			n/a	$	427,509			n/a		n/a		n/a	$	427,509
Bruce R. Shaw, Senior Vice President and Chief Financial Officer		2010		n/a			n/a	$	93,783			n/a		n/a		n/a	$	93,783
		2009		n/a			n/a	$	77,519			n/a		n/a		n/a	$	77,519
		2008		n/a			n/a	$	194,582	⁽⁷⁾		n/a		n/a		n/a	$	194,582
David G. Blair, President		2010	$	312,000	⁽⁸⁾	$	44,000	$	393,800		$	156,000	$	153,366	$	13,253	$	1,072,419
		2009	$	274,851			n/a	$	310,030		$	210,000	$	100,105	$	14,700	$	909,686
		2008	$	267,609		$	40,500	$	310,006		$	94,500	$	63,876	$	13,800	$	790,291
Mark T. Cunningham, Vice President — Operations		2010	$	201,780	⁽⁹⁾	$	20,500	$	150,002		$	82,000	$	39,620	$	8,491	$	502,393
		2009	$	181,380			n/a	$	70,017		$	85,000	$	27,907	$	10,863	$	375,167
		2008	$	172,760		$	23,345	$	75,003		$	41,655	$	16,195	$	9,891	$	338,849
Denise C. McWatters, Vice President, General Counsel and Secretary		2010		n/a			n/a	$	45,018			n/a		n/a		n/a	$	45,018
		2009		n/a			n/a	$	37,513			n/a		n/a		n/a	$	37,513
		2008		n/a			n/a	$	0			n/a		n/a		n/a	$	0


(1)		Previously, Mr. Cunningham was not an executive officer and was not required to file reports under Section 16 of the Securities Exchange Act of 1934, nor did he have significant policy-making responsibilities with us, but he was the next highest compensated officer. In an effort to provide complete disclosure, we began providing information on Mr. Cunningham in the Annual Report on Form 10-K for the fiscal year ending December 31, 2007. Effective January 27, 2010, Mr. Cunningham has been designated an executive officer. The value of compensation received by Ms. McWatters from us does not exceed $100,000. Nevertheless, the value of the equity award granted to her by us has been included to provide investors with an understanding of the compensation provided to Ms. McWatters by us in consideration for her services to HEP. The inclusion of Ms. McWatters in our tabular disclosures has not resulted in the exclusion of any other executive officer from our executive compensation disclosures.

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(2)		Annual bonuses for services performed in 2010 will be paid in March 2011. Amounts in this column reflect the discretionary bonus, if any, payable pursuant to our annual incentive bonus arrangement reported in the Non-Equity Incentive Plan Compensation column.

(3)		Amounts reported for stock awards in each of the 2010, 2009 and 2008 years represent the aggregate grant date fair value computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures. See notes 5, 7 and 6 to our consolidated financial statements for the fiscal years ended December 31, 2008, 2009, and 2010, respectively, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards. With respect to performance units, the amounts in the table above were based on an estimated payment of 125%, 110%, and 110% of the award in 2008, 2009 and 2010, respectively, as this is the “probable” payout percentage for the performance units in such year and is consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures; however, assuming that the performance units granted in 2010 will be paid out at the maximum payout level of 150%, each of the Named Executive Officers who received a grant of performance units in 2010 would receive the following amounts: Mr. Clifton, $802,523; and Mr. Blair, $281,286. The terms of the 2010 performance unit awards and the 2010 restricted stock awards are provided below in the narrative following the “2010 Grants of Plan-Based Awards” table. For additional information on restricted stock and performance unit awards, see below under “2010 Outstanding Equity Awards at Fiscal Year End.” No forfeitures of equity awards to the Named Executive Officers occurred in 2010.

(4)		The annual bonus amounts for services performed in 2010 (paid in March 2011) reflect the actual bonuses payable to Messrs. Blair and Cunningham pursuant to the pre-defined target percentages that were allocated to the components which are described below in greater detail in the narrative following the “2010 Grants of Plan-Based Awards” table.

(5)		The amounts shown in this column reflect the following assumptions:


	December 31, 2008	December 31, 2009	December 31, 2010

Discount Rate:	6.5%	6.2%	5.65%

Mortality Table:	RP2000 White Collar Projected to 2020	RP2000 White Collar Projected to 2020	RP2000 White Collar Projected to 2020

Reserving Table:	(50% Male/ 50% Female)	(50% Male/ 50% Female)	(50% Male/ 50% Female)

Retirement Age:	the later of current age	the later of current age	the later of current age
	or age 62	or age 62	or age 62


(6)		This reflects matching contributions made to the Thrift Plan by HLS, which were reimbursed by HEP (only applicable to Messrs. Blair and Cunningham). Since Messrs. Blair and Cunningham elected to remain in the Holly Retirement Plan, as discussed in greater detail below in the section titled “Pension Benefits Table,” the only contributions are employer matching of employee contributions, subject to the limits described above in the section titled “Retirement and Benefit Plans.”

(7)		This reflects awards Mr. Shaw received as a director and an officer during the fiscal year ended December 31, 2008, as follows: $77,522 for 2008 restricted HEP units (director compensation) and $117,060 for 2008 restricted HEP units (officer compensation).

(8)		As of January 1, 2010, Mr. Blair’s annual salary was $312,000. His actual payroll payments in 2010 were $310,887 due to our bi-weekly payroll system (the December 13, 2010, through December 26, 2010, payroll payment was made on January 5, 2011 and the December 27, 2010, through December 31, 2010, payroll payment was made on January 19, 2011). Similar adjustments were made for other mid-period pay adjustments in prior periods.

(9)		As of January 1, 2010, Mr. Cunningham’s annual salary was $182,400. His annual salary was increased to $205,000 effective February 22, 2010. His actual payroll payments in 2010 were $200,654 due to our bi-weekly payroll system (the December 13, 2010, through December 26, 2010, payroll payment was made on January 5, 2011, and the December 27, 2010, through December 31, 2010, payroll payment was made on January 19, 2011). Similar adjustments were made for other mid-period pay adjustments in prior periods.

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2010 Grants of Plan-Based Awards

The following table sets forth, for each Named Executive Officer, information about awards under our equity and non-equity incentive plans made during the year ending December 31, 2010.


			Estimated Future Payouts						Estimated Future Payouts
			Under Non-Equity Incentive						Under Equity Incentive Plan						(i)
			Plan Awards (1)						Awards (2)						All other		(k)
	(b)		(c)						(f)				(h)		Equity		Grant
(a)	Grant		Thresh-		(d)		(e)		Thresh-		(g)		Maximum		Awards		Date Fair
Name	Date		old		Target		Maximum		old		Target		(#)		((3)		Value (4)

Matthew P. Clifton Performance Units		3/1/10		—		—		—		6,281		12,562		18,843			$	588,517
Unrestricted Units		3/1/10														6,000	$	255,540

Bruce R. Shaw Restricted Units		3/1/10		—		—		—								2,202	$	93,783

David G. Blair Performance Units		3/1/10		—		—		—		2,202		4,403		6,605		—	$	206,276
Restricted Units		3/1/10		—		—		—								4,403	$	187,524
Cash Incentives		—		—		156,000		312,000		—		—		—				—

Mark T. Cunningham Restricted Units		3/1/10		—		—		—		—		—		—		3,522	$	150,002
Cash Incentives		—		—		82,000		164,000		—		—		—		—		—

Denise C. McWatters Restricted Units		3/1/10														1,057		45,018


(1)		The amounts in columns (d) and (e) reflect the “Target” and “Maximum” bonus award amounts for Mr. Blair and Mr. Cunningham with respect to cash bonuses awarded pursuant to our Annual Incentive Plan in 2010 based on the percentages set forth below in the section titled “Annual Incentive Cash Bonus Compensation.” No “Threshold” is reported because our Annual Incentive Plan does not specify a “Threshold” amount. The “Target” amount represents 50% and 40% of the base salaries of Messrs. Blair and Cunningham, respectively. The “Maximum” represents 200% of the respective employee’s “Target” amount.

(2)		The amounts in columns (f), (g) and (h) represent the “Threshold” (50%), “Target” (100%) and “Maximum” (150%) payment levels with respect to grants of performance units in 2010. The Committee approved a grant of 12,562 performance units to Mr. Clifton and 4,403 performance units to Mr. Blair, the vesting schedules of which are described in the narrative below.

(3)		The Committee approved a grant of 6,000 unrestricted shares to Mr. Clifton which vested immediately upon grant. The Committee approved a grant of 4,403 restricted units to Mr. Blair, 3,522 restricted units to Mr. Cunningham, 2,202 restricted units to Mr. Shaw and 1,057 restricted units to Ms. McWatters, the vesting schedules of which are described in the narrative below.

(4)		This reflects the price of $42.59, the closing price at the close of business on February 26, 2010, the last business day immediately preceding the date of grant. The value of performance units was calculated using the $42.59 price and using the “Target” payout level, which is the “probable” payout percentage for the performance units and is consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date under FASB ASC Topic 718, determined without regard to forfeitures. The assumptions used in calculating the assumed payout of performance units is discussed in footnote 3 to the Summary Compensation Table.

The 2010 awards of performance units and restricted units were issued under our Long-Term Incentive Plan. The material terms of these awards are described below.

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2010 Performance Units

Under the terms of the performance units granted to Messrs. Clifton and Blair in 2010, each employee may earn from 50% to 150% of the performance units, based on the total increase in our distributable cash flow per common unit. The performance period for the awards began on January 1, 2010 and ends on December 31, 2012. Following the completion of the performance period, Messrs. Clifton and Blair shall be entitled to a payment of a number of common units equal to the result of multiplying their respective original grant amounts by the performance percentage set forth below:


3-Year Total Increase in
Distributable Cash Flow per		Performance Percentage (%) to be
Common Unit above $12.492		Multiplied by Performance Units
$0.00		50%
$1.026		100%
$2.107 or more		150%

In order to receive 100% of the units subject to this award, the distributable cash flow per common unit in the three years ended December 31, 2012 must total $13.52 per unit. In order to receive 150%, the distributable cash flow per common unit for the three years ended December 31, 2012 must total $14.60 per unit. The percentages are interpolated between points.

In the event that the employment of either Mr. Clifton or Mr. Blair terminates prior to January 1, 2013, other than due to a special involuntary termination associated with a defined change-in-control event, an involuntary termination, death, disability or retirement, the employee will forfeit his award. In the event of the involuntary termination, death or total and permanent disability of either Mr. Clifton or Mr. Blair, as determined by the Committee in its sole discretion, or upon either of the employee’s retirement after attaining age 62 or an earlier retirement age approved by the Committee in its sole discretion, the applicable employee shall forfeit a number of units equal to the percentage that the number of full months following the date of involuntary separation, death, disability or retirement to the end of the performance period bears to 36. Any remaining units that are not forfeited will become vested and payable based upon the performance actually achieved by us as of the end of the specified performance period. In its sole discretion, the Committee may make a payment assuming a performance percentage of up to 150% instead of the prorated number. As shown in the table above, the amount shown in column (f) reflects the minimum payment amount of 50%, the amount shown in column (g) reflects the target payment amount of 100% and the amount shown in column (h) reflects the maximum payment amount of 150%.

Prior to vesting, distributions are paid on each performance unit at the same rate as distributions paid on our common units. The termination and change-in-control provisions of this award are described below under the section titled “Potential Payments upon Termination or Change in Control.” Additional information regarding the performance unit awards can be found above under “Compensation Discussion and Analysis — Long-Term Incentive Equity Compensation — Performance Units.”

2010 Restricted Units

Under the terms of the restricted units granted in 2010, except in the case of early termination, the restricted units become vested in accordance with the following schedule:


	Cumulative Amount of
Vesting Date	Restricted Units Vested
Immediately following December 31, 2010		1/3
Immediately following December 31, 2011		2/3
Immediately following December 31, 2012		All

Other than due to a special involuntary termination associated with a defined change-in-control event, death, disability or retirement, if an employee’s employment is terminated prior to one of the vesting dates specified above, all unvested restricted units will be forfeited. In the event of the employee’s death, total and permanent disability as determined by the Committee in its sole discretion, or upon either of the employee’s retirement after attaining age 62 or an earlier retirement age approved by the Committee in its sole discretion, the employee shall forfeit a number of units equal to (i) the total number of units initially subject to the award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2012 bears to 36. Any remaining units that are not forfeited will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Each listed employee is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units. The termination and change-in-control provisions of this award are described below in the section titled “Potential Payments upon Termination or Change in Control.”

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Annual Incentive Cash Bonus Compensation

The cash bonuses that are available to our Named Executive Officers under the Annual Incentive Plan are based upon pre-set percentages of salary, achieved by reaching certain performance levels. A more detailed description of the pre-established performance criteria utilized in 2010 can be found above in the CD&A under the section titled “Annual Incentive Cash Bonus Compensation.” The following chart reflects the target percentages that were set for Messrs. Blair and Cunningham for 2010 (Messrs. Clifton and Shaw and Ms. McWatters do not receive cash bonuses under our Annual Incentive Plan).


	Actual						Target
Name and	Distributable						Incentive
Principal	Cash Flow vs.			Individual			Compensation
Position	Budget			Performance			⁽¹⁾
David G. Blair, President		35	%		15	%		50	%
Mark T. Cunningham, Vice President — Operations		20	%		20	%		40	%


(1)		Pursuant to our Annual Incentive Plan, the percentages with respect to the performance criteria identified in the first two columns actually achieved for each individual are added together and then multiplied by the base salary for each individual. The “Target” and “Maximum” awards are reflected above in the chart in the “2010 Grants of Plan Based Awards” section. Neither of the listed employees received the “Maximum” awards. When the Committee established the 2010 performance criteria, the Committee determined that it could award a total of up to 200% of the total target bonus based on performance in excess of the targets (or 100% and 80% of the base salaries of Messrs. Blair and Cunningham, respectively). The Committee awarded Mr. Blair $200,000 and awarded Mr. Cunningham $102,500 in recognition of the achievement of their performance targets.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth, for each of our Named Executive Officers, information regarding restricted and performance units that were held as of December 31, 2010, including awards that were granted prior to 2010:

Equity Awards(1)(2)

Equity Incentive

Plan Awards:

Number of

Market or Payout

Number of

Market Value

Unearned Units,

Value of Unearned

Units That

of Units That

Units or Other

Units, Units or

Have Not

Rights That

Other Rights That

Name

Vested

Have Not Vested

Matthew P. Clifton

n/a

74,618

(3)

3,798,802

Bruce R. Shaw

6,056

308,311

n/a

David G. Blair

10,109

514,649

22,307

(4)

1,135,649

Mark T. Cunningham

6,141

312,638

n/a

Denise C. McWatters

2,130

108,438

n/a


(1)		The values are based upon the closing market price of $50.91 on December 31, 2010.

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(2)		All awards are more particularly described in the text that immediately follows this chart.

(3)		These 74,618 units include (a) 7,802 unvested restricted units which will vest at 100% only after a performance standard is achieved and (b) 44,544 performance units which were multiplied by 1.5 because these performance units are subject to a maximum threshold of 150%.

(4)		These 22,307 units reflect 14,871 performance units which were multiplied by 1.5 because these performance units are subject to a maximum of 150%.

The following chart sets forth by year of grant the number of restricted and performance units awarded to our Named Executive Officers that remained outstanding as of December 31, 2010, and that are reflected in the immediately preceding chart:


	2005		2008		2008		2009		2009		2010		2010
	Performance		Restricted		Performance		Restricted		Performance		Restricted		Performance
	Units		Units		Units		Units		Units		Units		Units
Name	(1)		(2)		(3)		(4)		(5)		(6)		(7)		Total
Matthew P. Clifton		7,802		0		10,522		0		21,460		0		12,562		52,346
Bruce R. Shaw		0		1,636		0		2,218		0		2,202		0		6,056
David G. Blair		0		1,271		3,815		4,435		6,653		4,403		4,403		24,980
Mark T. Cunningham		0		616		0		2,003		0		3,522		0		6,141
Denise C. McWatters		0		0		0		1,073		0		1,057		0		2,130


(1)		Mr. Clifton received an award of 7,802 restricted HEP units with a performance standard in February 2005. Except in the case of early termination, immediately following December 31, 2007, the performance units become vested in accordance with the following schedule:


Vesting Trigger:
Attainment of Quarterly Adjusted Net Income	Cumulative Amount of
Per Diluted Unit of at Least $0.56	Performance Units Vested
For any quarter between October 1, 2007 and December 31, 2010		1/3
For any quarter between October 1, 2008 and December 31, 2010		2/3
For any quarter between October 1, 2009 and December 31, 2010		All

All units may vest as late as immediately following December 31, 2010, but the indicated number of units may vest sooner if the required adjusted net income per diluted unit is obtained sooner. In addition, other than due to a special involuntary terminated associated with a defined change-in-control event, death, disability or retirement, if Mr. Clifton’s employment is terminated prior to one of the vesting dates, all then unvested units will be forfeited.

In its sole discretion, the Committee may decide to vest all of the units. Mr. Clifton is a unitholder with respect to all of the units and has the right to receive all distributions paid with respect to such units. The termination and change-in-control provisions of this award are described below in the section titled “Potential Payments upon Termination or Change in Control.”

As of December 31, 2010, the standards for vesting of the units had not been reached. After action by the Committee on January 25, 2011, these units were forfeited.

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(2)

Under the terms of the March 2008 restricted unit grants, except in the case of early termination, the restricted units become vested in accordance with the following schedule:


	Cumulative Amount of
Vesting Date	Restricted Units Vested
Immediately following December 31, 2008		1/3
Immediately following December 31, 2009		2/3
Immediately following December 31, 2010		All

Other than due to a special involuntary termination associated with a defined change-in-control event, death, disability or retirement, if an employee’s employment is terminated prior to one of the vesting dates specified above, all unvested restricted units will be forfeited. In the event of the employee’s death, total and permanent disability as determined by the Committee in its sole discretion, or upon either of the employee’s retirement after attaining age 62 or an earlier retirement age approved by the Committee in its sole discretion, the employee shall forfeit a number of units equal to (i) the total number of units initially subject to the award times (ii) the percentage that the period of full months beginning on the first calendar month following the date of death, disability or retirement and ending on December 31, 2010, bears to 36. Any remaining units that are not forfeited will become vested. In its sole discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Each listed employee is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units. The termination and change-in-control provisions of this award are described below under the section titled “Potential Payments upon Termination or Change in Control.” Effective January 1, 2011, these restricted units vested with respect to all of the Named Executive Officers who received March 2008 restricted unit grants.

(3)

Mr. Clifton and Mr. Blair received awards of 10,522 and 3,815 performance units, respectively, in March 2008. Under the terms of the grant, the employees may earn from 50% to 150% of the performance units, based on the total increase in our cash distributions on our common units. The performance period for the award began on January 1, 2008 and ends on December 31, 2010. Following the completion of the performance period, the employees shall be entitled to payment of a number of common units equal to the result of multiplying the original grant amounts by the performance percentage set forth below:


3-Year Total Increase in Cash
Distributions Per Common Unit		Performance Percentage (%) to be
above $8.70^**		Multiplied by Performance Units
$0.00 or less		50%
$0.308		75%
$0.623		100%
$0.946		125%
$1.276 or more		150%


**		$8.70 represents a 3-year cumulative distribution of $2.90 per annum, $2.90 being the annual distribution rate in effect at the start of the performance period.

		In order to receive 75% of the units subject to this award, the cash distributions per unit declared and paid in the three years ended December 31, 2010 must total $9.01 per unit. In order to receive 100%, the distributions per unit declared and paid for the three years ended December 31, 2010 must total $9.32 per unit. In order to receive 125%, the distributions per unit declared and paid for the three years ended December 31, 2010 must total $9.65 per unit. In order to receive 150%, the distributions per unit declared and paid in the three years ended December 31, 2010 must total $9.98 per unit. The percentages are interpolated between points.

		In its sole discretion, the Committee may make a payment assuming a performance percentage of up to 150%. Prior to vesting, distributions are paid on each performance unit at the same rate as distributions paid on our common units. The termination and change-in-control provisions of this award are described below under the section titled “Potential Payments upon Termination or Change in Control.” On January 25, 2011, the Committee determined that the performance percentage applicable to these performance units was 112%, and Mr. Clifton and Mr. Blair were paid 11,785 common units and 4,273 common units, respectively, in accordance with such determination.

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(4)

Under the terms of the March 2009 restricted unit grants, except in the case of early termination, the restricted units become vested in accordance with the following schedule:


	Cumulative Amount of
	Restricted Units
Vesting Date	Vested
Immediately following December 31, 2009		1/3
Immediately following December 31, 2010		2/3
Immediately following December 31, 2011		All

In its sole discretion, the Committee may decide to vest all of the units. Each listed employee is a unitholder with respect to all of the restricted units and has the right to receive all distributions paid with respect to such restricted units. The termination and change-in-control provisions of this award are described below under the section titled “Potential Payments upon Termination or Change in Control.”

(5)

Mr. Clifton and Mr. Blair received awards of 21,460 and 6,653 performance units, respectively, in March 2009. Under the terms of the grant, the employees may earn from 50% to 150% of the performance units, based on the total increase in our cash distributions on our common units. The performance period for the award began on January 1, 2009 and ends on December 31, 2011. Following the completion of the performance period, the employees shall be entitled to payment of a number of common units equal to the result of multiplying the original grant amounts by the performance percentage set forth below:


3-Year Total Increase in Cash
Distributions Per Common Unit		Performance Percentage (%) to be
above $9.18^**		Multiplied by Performance Units
$0.00		50%
$0.658		100%
$1.346 or more		150%


**		$9.18 represents a 3-year cumulative distribution of $3.06 per annum, $3.06 being the annual distribution rate in effect at the start of the performance period.

In order to receive 50% of the units subject to this award, the cash distributions per unit declared and paid in the three years ended December 31, 2011 must total $9.18 per unit. In order to receive 100%, the distributions per unit declared and paid for the three years ended December 31, 2011 must total $9.84 per unit. In order to receive 150%, the distributions per unit declared and paid in the three years ended December 31, 2011 must total $10.53 per unit. The percentages are interpolated between points.

In its sole discretion, the Committee may make a payment assuming a performance percentage of up to 150%. Prior to vesting, distributions are paid on each performance unit at the same rate as distributions paid on our common units. The termination and change-in-control provisions of this award are described below under the section titled “Potential Payments upon Termination or Change in Control.”

(6)		The vesting dates for the restricted units granted in March 2010 are described in the narrative disclosures in the section titled “2010 Grants of Plan-Based Awards” under the heading “Restricted Units.”

(7)		Messrs. Clifton and Blair received an award of performance units in March 2010. The vesting dates for this award are described in the narrative disclosures in the section titled “2010 Grants of Plan-Based Awards” under the heading “Performance Units.”

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2010 Unit Awards Vested

The following table presents unit awards vested for our Named Executive Officers during 2010:


	Unit Awards
	Number of
	Units		Value
	Acquired on		Realized on
Named Executive Officer	Vesting		Vesting (6)
Matthew P. Clifton ⁽¹⁾		16,221	$	683,538
Bruce R. Shaw ⁽²⁾		2,745	$	109,361
David G. Blair ⁽³⁾		8,074	$	329,302
Mark T. Cunningham ⁽⁴⁾		1,870	$	74,501
Denise C. McWatters ⁽⁵⁾		537	$	21,394

(1)

This amount includes:

	(a)		10,221 performance units which became payable to Mr. Clifton on January 27, 2010, upon the Committee’s determination that the performance percentage applicable to 8,736 performance units granted to Mr. Clifton in February 2007 was 117%.

	(b)		6,000 unrestricted units which were granted to Mr. Clifton on March 1, 2010, and which vested immediately upon the grant.

(2)		The following restricted units previously granted to Mr. Shaw vested on January 1, 2010: (a) 636 restricted units granted in March 2008 and (b) 1,000 restricted units granted in April 2008; and (c) 1,109 restricted units granted in March 2009.

(3)		This amount includes:

	(a)		restricted units previously granted to Mr. Blair which vested on January 1, 2010: (a) 1,017 restricted units granted in February, 2007;

	(b)		1,272 restricted units granted in March 2008, and (c) 2,218 restricted units granted in March, 2009. (b) 3,567 units which became payable to Mr. Blair on January 27, 2010, upon the Committee’s determination that the performance percentage applicable to 3,049 performance units granted to Mr. Blair in February 2007 was 117%.

(4)		The following restricted units previously granted to Mr. Cunningham vested on January 1, 2010: (a) 70 restricted units granted in February 2005; (b) 183 restricted units granted in February 2007; (c) 615 restricted units granted in March 2008; and (d) 1,002 restricted units granted in March 2009.

(5)		537 restricted units previously granted to Ms. McWatters in March 2009 vested on January 1, 2010.

(6)		Calculated as the aggregate market value of the shares as of the respective vesting dates, based on the closing price of our common units on December 31, 2009, which was $39.84 and on January 27, 2010, which was $41.98 and on March 1, 2010, which was $42.41.

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Pension Benefits Table

Our Named Executive Officers participate in Holly’s Retirement Plan, which generally provides a defined benefit to participants following their retirement. The table below sets forth an estimate of the retirement benefits payable to Messrs. Blair and Cunningham at normal retirement age under Holly’s Retirement Plan. Messrs. Clifton and Shaw and Ms. McWatters also participate in Holly’s Retirement Plan; however, since we do not reimburse HLS for their pension benefits, which are instead paid for by Holly, we have not provided any disclosure with respect to their potential retirement benefits. The costs of the pension benefits for Messrs. Blair and Cunningham are reimbursed on a current basis.

Pension Benefits

Number of Years

Present Value of

Payments During

Name

Plan Name

Credited Service

Accumulated Benefit

Last Fiscal Year

(a)

(b)

(c)

(d)

(e)

Matthew P. Clifton

n/a

Bruce R. Shaw

n/a

David G. Blair

Retirement Plan

29.8

763,680

Mark T. Cunningham⁽¹⁾

Retirement Plan

6.5

113,285

Denise C. McWatters

n/a


(1)		Mr. Cunningham is not eligible to commence receiving any benefit under the Retirement Plan as of December 31, 2010.

Since Mr. Blair is over age 50 and has more than 10 years of service, he is eligible for early retirement under the Holly Retirement Plan as of December 31, 2010. His early retirement benefit that would be payable had he elected to receive such a benefit beginning January 1, 2011 is estimated to be $8,622 per month payable for his lifetime or $927,998 payable as a lump sum.

The actuarial present value of the accumulated benefits reflected in the above chart was determined using the same assumptions as used for financial reporting purposes (which are discussed further in note 17 to Holly’s consolidated financial statements for the fiscal year ended December 31, 2010 except the payment date was assumed to be age 62 for Holly’s Retirement Plan rather than age 65. Age 62 is the earliest date a benefit can be paid with no benefit reduction under Holly’s Retirement Plan. In addition, the material assumptions used for these calculations include the following:


Discount Rate		5.65%

Mortality Table		RP2000 White Collar Projected to 2020 (50% male/ 50% female)

The amount of benefits accrued under the Retirement Plan is based upon a participant’s compensation, age and length of service. The compensation taken into account under the Retirement Plan is a participant’s average monthly compensation, which is based on an individual’s base salary or base pay and any quarterly bonuses during the highest consecutive 36-month period of employment. No quarterly bonuses were provided to executives in 2010, but quarterly bonuses were paid to some non-executive union employees.

Holly’s Retirement Plan provides for benefits upon normal retirement, early retirement, and late retirement, as well as providing accelerated deferred vested benefits, disability benefits, and death benefits. The normal retirement benefit under the plan may commence after an employee retires following his or her attainment of age 65. The normal form of payment is a monthly pension for the participant’s life in an amount equal to (a) 1.6% of the participant’s average monthly compensation multiplied by his or her total years of credited benefit service, minus (b) 1.5% of the participant’s primary social security benefit multiplied by his or her total years of credited benefit service, such amount not to exceed 45% of the participant’s primary social security benefit. In addition, a participant who (i) has attained age 50 and completed at least 10 years of service, or (ii) has attained age 55 and completed at least 3 years of service may elect to terminate employment and begin receiving benefits under Holly’s Retirement Plan. If such a participant begins receiving benefits under Holly’s Retirement Plan on or after the date the participant attains age 60 but before he reaches age 62, such benefits will be reduced by 1/12thof 21/2% for each full month that such benefits begin before age 62. If benefits begin before age 60, the participant’s Retirement Plan benefits will be reduced by 1/12th of 5% for each full month that such benefits begin before age 60.

An employee’s benefit service is not deemed interrupted if the employee performed services for Holly and is later transitioned to work as an HLS employee. Instead of the normal form of payment, participants may also elect to receive their accrued benefits in the form of a life annuity with a period certain, a contingent annuity, or a lump sum. Participants in the cash balance feature of the Retirement Plan were allowed to make a one-time irrevocable election during the 2009 year to freeze their benefit accruals under the Retirement Plan and elect to participate in the automatic contribution feature under the defined contribution plan effective as of January 1, 2010, and participation under the cash balance feature was frozen to new employees; however, as previously noted, neither Messrs. Blair nor Cunningham elected to participate in such an option.

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Benefits up to limits set by the Code are funded by Holly’s contributions to the Retirement Plan, with the amounts determined on an actuarial basis. In 2010, the Code limited benefits that could be covered by the Retirement Plan’s assets to $195,000 per year (subject to increases for future years based on price level changes) and limited the compensation that could be taken into account in computing such benefits to $245,000 per year (subject to certain upward adjustments for future years).

Nonqualified Deferred Compensation Table

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

Potential Payments Upon Termination or Change in Control

There are no employment agreements currently in effect between us and any Named Executive Officer, and the Named Executive Officers are not covered under any general severance plan of Holly, HLS or HEP. In 2007, Holly entered into Change in Control Agreements with Messrs. Blair and Cunningham, and those agreements were in effect as of December 31, 2010. The expenses associated with those Change in Control Agreements are borne by Holly and are not reimbursable by us. Holly also entered into similar agreements with Messrs. Clifton and Shaw and Ms. McWatters, the costs of which also are borne by Holly. Because Messrs. Clifton and Shaw and Ms. McWatters do not perform services solely on behalf of HEP, a quantification of their potential benefits under their respective Change in Control Agreements is not provided below but will be disclosed in Holly’s annual proxy statement. Further, the Change in Control Agreements with Messrs. Clifton and Shaw and Ms. McWatters trigger only upon a change in control of Holly. On February 14, 2011, the HLS Board of Directors adopted the Holly Energy Partners, L.P. Change in Control Policy and the related form of Change in Control Agreement to be entered into between HEP and certain officers of HLS. As of the date of this Form 10-K Annual Report, it is anticipated that the Change in Control Agreements between Holly and each of Messrs. Blair and Cunningham will be terminated and, upon such termination, that each of Messrs. Blair and Cunningham will enter into a Change in Control Agreement with HEP in accordance with the Holly Energy Partners, L.P. Change in Control Policy recently adopted by the HLS Board of Directors. The discussion below describes the Change in Control Agreements in effect between Holly and Messrs. Blair and Cunningham as of December 31, 2010.

The Change in Control Agreements are subject to an initial three year term, with an automatic one year extension on the second anniversary of the effective date (and on each anniversary date thereafter) unless a cancellation notice is given 60 days prior to the second anniversary of the effective date (or any anniversary date thereafter, as applicable). The Change in Control Agreements provide that if, in connection with or within two years after a “Change in Control” of Holly, HLS or HEP (1) the executive is terminated without “Cause,” leaves voluntarily for “Good Reason,” or is terminated as a condition of the occurrence of the transaction constituting the “Change in Control,” and (2) the executive is not offered employment with Holly or its related entities on substantially the same terms as his previous employment with HLS within 30 days after the termination, then the executive will receive the following cash severance amounts paid by Holly as outlined in the table below: (i) a cash payment, paid within 10 days following the executive’s termination, equal to his accrued and unpaid salary, unreimbursed expenses and accrued vacation pay, and (ii) a lump sum amount, paid within 15 days following the executive’s termination, equal to the multiple specified in the table below for such executive times (A) his annual base salary as of his date of termination or the date immediately prior to the “Change in Control,” whichever is greater, and (B) his annual bonus amount, calculated as the average annual bonus paid to him for the prior three years. In addition, the executive (and his dependents, as applicable) will receive a continuation of their medical and dental benefits for the number of years indicated in the table below for such executive.


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

For purposes of the Change in Control Agreements, the following terms have been given the meanings set forth below:

(a)

“Cause” means an executive’s (i) engagement in any act of willful gross negligence or willful misconduct on a matter that is not inconsequential, as reasonably determined by Holly’s board of directors in good faith, or (ii) conviction of a felony.

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(b)

“Change in Control” means, subject to certain specific exceptions set forth in the Change in Control Agreements: (i) a person or group of persons (other than Holly, HLS, HEP, or any employee benefit plan of any of the three entities or its affiliates) becomes the beneficial owner of more than 50% of the combined voting power of the then outstanding securities of Holly, HLS or HEP or of the then outstanding common stock or membership interests, as applicable, of Holly or HLS, (ii) a majority of the members of Holly’s board of directors is replaced during a 12 month period by directors who were not endorsed by a majority of the board members prior to their appointment, (iii) the consummation of a merger of consolidation of Holly, HLS, HEP or any subsidiary of any of the foregoing other than (A) a merger or consolidation resulting in the voting securities of Holly, HLS, or HEP, as applicable, outstanding immediately prior to the transaction continuing to represent at least 50% of the combined voting power of the voting securities of Holly, HLS, HEP or the surviving entity, as applicable, outstanding immediately after the transaction, or (B) a merger of consolidation effected to implement a recapitalization of Holly, HLS, or HEP in which no person or group becomes the beneficial owner of securities of Holly, HLS, or HEP representing more than 50% of the combined voting power of the then outstanding securities of Holly, HLS or HEP, or (iv) the stockholders or unit holders, as applicable, of Holly or HEP approve a plan of complete liquidation or dissolution of Holly or HEP or an agreement for the sale or disposition of all or substantially all of the assets of Holly or HEP.

(c)

“Good Reason” means, without the express written consent of the executive: (i) a material reduction in the executive’s (or his supervisor’s) authority, duties or responsibilities, (ii) a material reduction in the executive’s base compensation, or (iii) the relocation of the executive to an office or location more than 50 miles from the location at which the executive normally performed the executive’s services, except for travel reasonably required in the performance of the executive’s responsibilities. The executive must provide notice to Holly of the alleged Good Reason event within 90 days of its occurrence and Holly, HLS and HEP will be have an opportunity to remedy the alleged Good Reason event within 30 days from receipt of the notice of the allegation.

All payments and benefits due under the Change in Control Agreements will be conditioned on the execution and non-revocation by the executive of a release of claims for the benefit of Holly, HLS and HEP and their related entities and agents. The Change in Control Agreements also contain confidentiality provisions pursuant to which each executive agrees not to disclose or otherwise use the confidential information of Holly, HLS or HEP. Violation of the confidentiality provisions entitles Holly, HLS or HEP to complete relief, including injunctive relief. Further, in the event of a breach of the confidentiality covenants, the executive could be terminated for Cause (provided the breach constituted willful gross negligence or misconduct on the executive’s part that is not inconsequential). The agreements do not prohibit the waiver of a breach of these covenants.

If amounts payable to an executive under a Change in Control Agreement (together with any other amounts that are payable by Holly, HLS or HEP as a result of a change in ownership or control) (collectively, the “Payments”) exceed the amount allowed under section 280G of the Code for such executive (thereby subjecting the executive to an excise tax as described in further detail below) by 10% or more, Holly will pay the executive a tax gross up (a “Gross Up”) in an amount necessary to allow the executive to retain (after all regular income and Code Section 280G taxes) a net amount equal to the total present value of the Payments on the date they are to be paid (after all regular income taxes but without reduction for Code Section 280G taxes). Conversely, the Payments will be reduced to the level at which no excise tax applies if they exceed the Code Section 280G limit for the executive by less than 10% (a “Cut Back”).

In addition, under the terms of the long-term incentive equity awards described above in the section entitled “Compensation Discussion and Analysis—Long-Term Incentive Equity Compensation” and in the narrative following the “Grants of Plan Based Awards Table,” if, in the event of a “Change in Control”, either sixty (60) days prior to the “Change in Control” event or at any time following such event, (i) a Named Executive Officer’s employment is terminated, other than for “cause,” or (ii) he resigns within ninety (90) days following an “Adverse Change” (any such termination, a “Special Involuntary Termination”) then all restrictions on the award will lapse, the units will become vested and the vested units will be delivered to the Named Executive Officer as soon as practicable, though in no event following two and one-half months following the end of the year in which the Special Involuntary Termination occurs. All outstanding performance units will vest at 150% in the event of a Special Involuntary Termination.

Other than upon a Special Involuntary Termination, restricted units and performance units have slightly different accelerated vesting and forfeiture provisions upon certain terminations of employment. With regard to restricted units, if an executive dies, becomes totally and permanently disabled (as determined by the Committee in its sole discretion), or retires after attaining age 62 (or an earlier retirement age approved by the Committee), the executive will forfeit a number of restricted units equal to the total number of restricted units subject to an award, multiplied by a fraction, the numerator of which is the number of full months following the date of death, disability or retirement until the last day of the vesting period, and the denominator of which is 36, and any remaining unvested restricted units will become vested. With regard to performance units, if an executive dies, becomes totally and permanently disabled (as determined by the Committee in its sole discretion), retires after attaining age 62 (or an earlier retirement age approved by the Committee), or separates from employment for any other reason other than a voluntary separation or for “Cause,” then the executive will forfeit a number of performance units equal to 100% of the performance units subject to an award, multiplied by a fraction, the numerator of which is the number of full months following the date of death, disability, retirement or separation until the end of the applicable performance period, and the denominator of which is 36. The Committee will determine the number of remaining performance units earned and the amount to be paid to the executive as soon as administratively possible after the end of the performance period based upon the performance actually attained for the entire performance period.

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For purposes of the long-term equity incentive awards, the following terms have been given the meanings set forth below:

(a)

“Adverse Change” means without the consent of the executive, (i) a change in the executive’s principal office of employment of more than 25 miles from the executive’s work address at the time of a grant of the equity award, (ii) a material increase (without adequate consideration) or material reduction in the duties to be performed by the executive, or (iii) a material reduction in the executive’s base compensation (other than bonuses and other discretionary items of compensation or a general reduction applicable generally to executives).

(b)

“Cause” means (i) an act of dishonesty constituting a felony or serious misdemeanor and resulting (or intended to result in) personal gain or enrichment to the executive at the expense of HLS, (ii) gross or willful and wanton negligence in the performance of the executive’s material duties, or (ii) conviction of a felony involving moral turpitude. The existence of Cause is determined by the Committee in its sole discretion.

(c)

“Change in Control” means, subject to certain specific exceptions set forth in the long-term equity incentive awards: (i) a person or group of persons becomes the beneficial owner of more than 40% of the combined voting power of the then outstanding securities of Holly, HLS, HEP or HEP Logistics Holdings, L.P. (“HLH”), (ii) a majority of the members of Holly’s board of directors is replaced by directors who were not endorsed by two-thirds of the board members prior to their appointment, (iii) the consummation of a merger or consolidation of Holly, HLS, HEP or any subsidiary of any of the foregoing other than (A) a merger or consolidation resulting in the voting securities of Holly, HLS, HLH or HEP, as applicable, outstanding immediately prior to the transaction continuing to represent at least 60% of the combined voting power of the voting securities of Holly, HLS, HLH, HEP or the surviving entity, as applicable, outstanding immediately after the transaction, or (B) a merger of consolidation effected to implement a recapitalization of Holly, HLS, HLH or HEP in which no person or group becomes the beneficial owner of securities of Holly, HLS, HLH or HEP representing more than 40% of the combined voting power of the then outstanding securities of Holly, HLS, HLH or HEP, or (iv) the stockholders or unit holders, as applicable, of Holly, HLS, HLH or HEP approve a plan of complete liquidation or dissolution of Holly, HLS, HLH or HEP or an agreement for the sale or disposition of all or substantially all of the assets of Holly, HLS, HLH or HEP.

The following table reflects the estimated payments due pursuant to the Change in Control Agreements and the accelerated vesting of equity awards of each Named Executive Officer as of December 31, 2010, assuming, as applicable, that a Change in Control occurred (under both the Change in Control Agreements and the equity awards) and/or such executives were terminated effective December 31, 2010. For these purposes, our common unit price was assumed to be $50.91, which is the closing price per unit on December 31, 2010. The amounts below have been calculated using numerous assumptions that we believe are reasonable, such as the assumption that all reimbursable expenses were current as of December 31, 2010. Accrued vacation is not allowed to be carried over to a subsequent year, so we assumed all accrued vacation for the 2010 year was taken prior to December 31, 2010. Employees accrue vacation in 2010 for use in 2011, so we included the value of the 2011 accrued but unused vacation. However, any actual payments that may be made pursuant to the agreements described above are dependent on various factors, which may or may not exist at the time a Change in Control actually occurs and the Named Executive Officer is actually terminated. Therefore, such amounts and disclosures should be considered “forward looking statements.” Because vesting of the performance units upon a termination due to death, disability, retirement, or other separation (other than a voluntary separation, a for “Cause” separation or a Special Involuntary Termination) remains contingent upon the attainment of performance goals at the end of the applicable performance periods, no amounts associated with accelerated vesting of performance units under those circumstances have been included in the table below.

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			Value of					280G Excise
	Cash		Welfare		Accelerated Vesting			Tax Gross Up
	Payments⁽¹⁾		Benefits⁽²⁾		of Equity Awards			or Cut Back⁽³⁾		Total⁽⁴⁾
Matthew P. Clifton
Termination in connection with or following a Change in Control		n/a		n/a	$	3,798,803	⁽⁵⁾⁽⁸⁾		n/a	$	3,798,803	⁽⁸⁾
Termination due to Death, Disability or Retirement		n/a		n/a	$	397,200	⁽⁸⁾⁽⁹⁾		n/a	$	397,200	⁽⁸⁾

Bruce R. Shaw
Termination in connection with or following a Change in Control		n/a		n/a	$	308,311	⁽⁶⁾		n/a	$	308,311
Termination due to Death, Disability or Retirement		n/a		n/a	$	177,116	⁽⁹⁾		n/a	$	177,116

David G. Blair
Termination in connection with or following a Change in Control	$	1,106,666	$	23,111	$	1,650,298	⁽⁷⁾		n/a	$	2,780,075
Termination due to Death, Disability or Retirement		n/a		n/a	$	252,362	⁽⁹⁾		n/a	$	252,362

Mark T. Cunningham
Termination in connection with or following a Change in Control	$	318,436	$	17,625	$	312,638	⁽⁶⁾		n/a	$	648,699
Termination due to Death, Disability or Retirement		n/a		n/a	$	142,141	⁽⁹⁾		n/a	$	142,141

Denise C. McWatters
Termination in connection with or following a Change in Control		n/a		n/a	$	108,438	⁽⁶⁾		n/a	$	108,438
Termination due to Death, Disability or Retirement		n/a		n/a	$	45,259	⁽⁹⁾		n/a	$	45,259


(1)		Represents cash payments equal to the sum of (a) accrued vacation ($36,000 for Mr. Blair and $15,769 for Mr. Cunningham), plus (b) the executive’s base salary as of December 31, 2010, and the average of the annual cash bonus paid for 2007, 2008 and 2009 times the multiplier identified above. The total for Mr. Blair was calculated by multiplying two (2) times the sum of his base salary ($312,000) and average bonus ($223,333). The total for Mr. Cunningham was calculated by multiplying one (1) times the sum of his base salary ($205,000) and average bonus ($97,667).

(2)		Represents the value of the continuation of medical and dental benefits for each executive (and, as applicable, his spouse and dependents) for the length of one year multiplied by the applicable multiplier identified above. The amount was determined based upon the applicable COBRA rates for the employee’s benefits. The value of the benefits was determined by using the current monthly premium amount for a similarly situated employee electing COBRA continuation coverage.

(3)		As applicable, reflects the amount of the Tax Code Section 280G Gross Up payment or the amount subject to the Section 280G Cut Back. To determine whether any Gross Up or Cut Back applies, the “base amount” for each Named Executive Officer was calculated using the five-year average of each officer’s compensation for the years 2005-2009. In the case of Ms. McWatters, the amount is calculated using her annualized compensation for 2007, since her employment with Holly commenced in October 2007. In the case of Mr. Shaw, the amount is calculated using

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		his annualized compensation for 2007 because he left employment in May 2007 and returned in September 2007. Payments received in connection with a change in control in excess of a Named Executive Officer’s “base amount” are considered “excess parachute payments” as provided by Section 280G of the Tax Code, if the total of all “parachute payments” received by the Named Executive Officer is equal to or greater than three times his or her base amount. Excess parachute payments will be subject to the excise tax. In making the calculation, the following assumptions were used: (a) the change in control occurred on December 31, 2010, (b) the closing price of our common units was $50.91 per unit on such date, (c) the excise tax rate under Section 4999 of the Tax Code is 20%, the federal income tax rate is 35%, the Medicare rate is 1.45%, the adjustment to reflect the phase-out of itemized deductions is 1.05%, and there are no state or local income taxes, (d) no amounts will be discounted as attributable to reasonable compensation, (e) all cash severance payments are contingent upon a change in control, and (f) the presumption required under applicable regulations that the equity awards granted in 2010 were contingent upon a change in control could be rebutted.

(4)		These payments reflect the application of any potential Gross Up or Cut Back. No Gross Up or Cut Back was applicable for any Named Executive Officer.

(5)		Mr. Clifton held 7,802 unvested restricted units on December 31, 2010. Vesting of these restricted units is at 100% and is contingent upon the satisfaction of a performance standard (unless certain termination events occur prior to December 31, 2010), and the performance standard has not been satisfied to date. See “Outstanding Equity Awards at Fiscal Year End.” Mr. Clifton also held 44,544 performance units on December 31, 2010. The amount in the table was reached by (a) multiplying his 7,802 shares of restricted units by the closing price of HEP units on December 31, 2010 of $50.91, to equal $397,200; and (b) because Mr. Clifton is eligible to receive 150% of the performance units under the terms of the long-term incentive plan in the event of a Special Involuntary Termination, his 44,544 performance units were first multiplied by 1.5, and then again by $50.91, to equal $3,401,603. These two amounts, $397,200 and $3,401,603, were added together to reach the total amount of $3,798,803 that is disclosed in the table above.

(6)		Based upon a payment of the HEP restricted units as provided for under the terms of the long-term incentive equity agreements governing the awards of the units and based upon the closing price of HEP units on December 31, 2010 of $50.91. As of December 31, 2010, Mr. Shaw held 6,056 outstanding restricted units, Mr. Cunningham held 6,141 outstanding restricted units, and Ms. McWatters held 2,130 outstanding restricted units.

(7)		Mr. Blair held 10,109 shares of restricted units, and 14,871 performance units on December 31, 2010. The amount in the table was reached by (a) multiplying his 10,109 restricted units (or applicable pro rata portion thereof) by the closing price of HEP units on December 31, 2010 of $50.91; and (b) because Mr. Blair is eligible to receive 150% of the performance units under the terms of the long-term incentive plan in the event of a Special Involuntary Termination, his 14,871 performance units were first multiplied by 1.5, and then again by $50.91, to equal $1,135,649. These two amounts, $514,649 and $1,135,649, were added together to reach the total amount of $1,650,298 that is disclosed in the table above with respect to a Special Involuntary Termination.

(8)		Includes the 7,802 unvested restricted units which were forfeited effective January 25, 2011. If such forfeited units were not included, (a) Mr. Clifton’s Accelerated Vesting of Equity Awards (for termination in connection with or following a change in control) would be $3,401,.603, making his total $3,401,603, and (b) Mr. Clifton’s Accelerated Vesting of Equity Awards (for termination due to death, disability or retirement) would be $0, making his total $0.

(9)		As described above, restricted units are subject to pro rata vesting upon death, disability or retirement after age 62 (or an earlier retirement age approved by the Committee). Amounts are calculated based on the closing price of HEP units on December 31, 2010 of $50.91 and reflect the vesting of the following number of units: Mr. Clifton, 7,802; Mr. Shaw, 3,479; Mr. Blair, 4,957; Mr. Cunningham, 2,792; and Ms. McWatters, 889.

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Compensation Practices as They Related to Risk Management

Although a significant portion of the compensation provided to the Named Executive Officers is performance-based, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees) because these programs are designed to encourage employees to remain focused on both our short- and long-term operational and financial goals.

While annual cash-based incentive bonus awards play an appropriate role in the executive compensation program, the Committee believes that payment should be determined based on an evaluation of HEP performance on a wide variety of measures, as compared to our past performance and the performance of our peers, which mitigates excessive risk-taking that could produce unsustainable gains in one area of performance at the expense of our overall long-term interests. In addition, we set performance goals that we believe are reasonable in light of our past performance and market conditions. For Named Executive Officers performing a majority of their services to HEP, an appropriate part of total compensation is fixed, while another portion is variable and linked to performance. A portion of the variable compensation we provide is comprised of long-term incentives. A portion of the long-term incentives we provide is in the form of restricted units subject to time-based vesting conditions, which retains value even in a depressed market, so executives are less likely to take unreasonable risks. With respect to our performance-based equity incentives, assuming achievement of at least a minimum level of performance, payouts result in some compensation at levels below full target achievement, in lieu of an “all or nothing” approach. Further, our unit ownership guidelines require certain of our executives to hold certain levels of units (in addition to unvested and unsettled equity-based awards), which aligns an appropriate portion of their personal wealth to our long-term performance and the interests of our unitholders.

Guidelines for Unit Ownership for Outside Directors

Pursuant to the unit ownership guidelines approved by the Board in 2009, each director is expected to maintain an ownership level of Common Units with a market value of $125,000. To the extent a director does not meet these guidelines he will be expected to retain 25% of the units received upon settlement of restricted units awarded to him, until such time as the unit ownership requirement is met. Currently all of our directors are in compliance with the unit ownership guidelines.

Guidelines for Unit Ownership for Executives

Under our unit ownership guidelines approved by the Board in 2009, each Named Executive Officer specified below is expected to retain twenty-five percent of the after-tax units received from restricted unit and performance unit awards made in 2006 and subsequent years until his ownership equals the following levels:


Executive	Value of Units

Matthew P. Clifton	$	500,000

David G. Blair	$	250,000

Bruce R. Shaw	$	250,000

Units owned from any source count toward meeting the guideline, but units relating to unvested restricted units and/or performance units do not count. Currently all of our Named Executive Officers have satisfied the stock ownership guidelines.

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

The following table sets forth as of February 11, 2011 the beneficial ownership of units of HEP held by beneficial owners of 5% or more of the units, by directors of HLS, the general partner of our general partner, by each executive officer and by all directors and executive officers of HLS as a group. Unless otherwise indicated, the address for each unitholder shall be c/o Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915.


			Percentage of
	Common		Common
	Units		Units
	Beneficially		Beneficially
Name of Beneficial Owner	Owned		Owned

Holly Corporation ⁽¹⁾		7,290,000		34.4
Tortoise Capital Advisors LLC ⁽²⁾		2,629,211		11.9
Goldman, Sachs Group, Inc. ⁽³⁾		1,659,142		7.5
Kayne Anderson Capital Advisors, L.P. ⁽⁴⁾		1,102,207		5.0
Matthew P. Clifton ⁽⁵⁾		85,263		*
Bruce R. Shaw ⁽⁵⁾		9,134		*
David G. Blair ⁽⁵⁾		16,064		*
Mark T. Cunningham ⁽⁵⁾		9,878		*
Denise C. McWatters ⁽⁵⁾⁽⁶⁾		4,255
P. Dean Ridenour ⁽⁵⁾		30,570		*
Charles M. Darling, IV ⁽⁵⁾⁽⁷⁾		19,586		*
William J. Gray ⁽⁵⁾		6,785		*
Jerry W. Pinkerton ⁽⁵⁾		8,386		*
William P. Stengel ⁽⁵⁾⁽⁸⁾		7,816		*
All directors and executive officers as group (10 persons)⁽⁵⁾		197,737		*


*		Less than 1%

(1)		Holly Corporation directly holds 72,503 common units. 7,217,497 common units are held by affiliates of Holly Corporation. Holly Logistics Limited LLC directly holds 7,000,000 common units; Navajo Pipeline Co., L.P. directly holds 127,440 common units; and other wholly-owned subsidiaries of Holly Corporation directly own 90,057 common units. Holly Corporation is the ultimate parent company of each such entity and may, therefore, be deemed to beneficially own the units held by each such entity. Holly Corporation files information with or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Exchange Act. The percentage of total units beneficially owned includes a 2% general partner interest held by HEP Logistics Holdings, L.P. which is HEP’s general partner and an indirect wholly-owned subsidiary of Holly Corporation.

(2)		Tortoise Capital Advisors LLC has filed with the SEC a Schedule 13G, dated February 11, 2011. Based on this Schedule 13G, Tortoise Capital Advisors LLC has sole voting power and sole dispositive power with respect to zero units, shared voting power with respect to 2,449,949 units and shared dispositive power with respect to 2,629,211 units. The address of Tortoise Capital Advisors LLC is 11550 Ash St., Suite 300, Leawood, KS 66211.

(3)		The Goldman Sachs Group, Inc. has filed with the SEC a Schedule 13G, dated February 8, 2011. The Goldman Sachs Group, Inc. has sole voting power and sole dispositive power with respect to zero units, shared voting power with respect to 3,751 units and shared dispositive power with respect to 1,659,142 units. The address of The Goldman Sachs Group, Inc. is 200 West Street, New York, NY 10282.

(4)		Kayne Anderson Capital Advisors, L.P. has filed with the SEC a Schedule 13G, dated February 9, 2011. Based on this Schedule 13G, Kayne Anderson Capital Advisors, L.P. has sole voting power and sole dispositive power with respect to zero units, and shared voting power and shared dispositive power with respect to 1,102,207 units. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067.

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(5)		The number of units beneficially owned includes restricted common units granted as follows: 1,080 units each to Mr. Darling, Mr. Gray, Mr. Pinkerton, Mr. Ridenour and Mr. Stengel, 5,152 units to Mr. Blair, 2,577 units to Mr. Shaw, 3,349 units to Mr. Cunningham, and 1,241 units to Ms. McWatters, for a combined total of 17,719 units.

(6)		This number includes 2,000 common units owned by Ms. McWatters’ spouse. Ms. McWatters disclaims beneficial ownership as to the common units owned by her spouse.

(7)		This number includes 11,200 common units owned by DQ Holdings, L.L.C. Mr. Darling is an owner and general manager of DQ Holdings, L.L.C. and, as such, has shared voting and dispositive power with respect to the 11,200 common units owned by DQ Holdings, L.L.C. Mr. Darling disclaims beneficial ownership as to the common units held by DQ Holdings, L.L.C. except to the extent of his pecuniary interest therein.

(8)		This number includes 500 common units owned by Mr. Stengel’s spouse. Mr. Stengel disclaims beneficial ownership as to the common units owned by his spouse.

Equity Compensation Plan Table

The following table summarizes information about our equity compensation plans as of December 31, 2010:

Number of

Number of securities

Securities to be

remaining available for

issued upon

Weighted average

future issuance under

exercise of

exercise price of

equity compensation

outstanding options,

plans (excluding

warrants and rights

securities reflected)

Equity compensation plans approved by security holders

—

Equity compensation plans not approved by security holders

—

169,939

Total

—

169,939

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

Item 13. Certain Relationships, Related Transactions and Director Independence

Our general partner and its affiliates own 7,290,000 of our common units representing a 32% limited partner interest in us. In addition, the general partner owns a 2% general partner interest in us. Transactions with the general partner are discussed below.

Transactions with our general partner are discussed later in this section.

DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES

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

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Operational stage


Distributions of available cash to our general partner and its affiliates		We generally make cash distributions 98% to the unitholders, including our general partner and its affiliates as the holders of an aggregate of 7,290,000 of the common units and 2% to the general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner is entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.

Payments to our general partner and its affiliates		We pay Holly or its affiliates an administrative fee, currently $2.3 million per year, for the provision of various general and administrative services for our benefit. The administrative fee may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from Holly or its affiliates. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of HLS who provide services to us. Please read “Omnibus Agreement” below. Our general partner determines the amount of these expenses.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

*Liquidation stage*

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

OMNIBUS AGREEMENT

Our Omnibus Agreement with Holly and our general partner that addresses the following matters:

•

our obligation to pay Holly an annual administrative fee, currently in the amount of $2.3 million, for the provision by Holly of certain general and administrative services;

•

Holly’s and its affiliates’ agreement not to compete with us under certain circumstances and our right to notice of, and right of first offer to purchase, certain logistics assets constructed by Holly and acquired as part of an acquisition by Holly of refining assets;

•

an indemnity by Holly for certain potential environmental liabilities;

•

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

•

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

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Payment of general and administrative services fee

Under the Omnibus Agreement we pay Holly an annual administrative fee, currently in the amount of $2.3 million, for the provision of various general and administrative services for our benefit. Our general partner may agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses.

The $2.3 million fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. The fee does not include salaries of pipeline and terminal personnel or other employees of HLS or the cost of their employee benefits, such as 401(k), pension, and health insurance benefits, which are separately charged to us by Holly. We also reimburse Holly and its affiliates for direct general and administrative expenses they incur on our behalf.

Noncompetition

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

•

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

•

any business conducted by Holly with the approval of our general partner;

•

any business or asset that Holly or any of its affiliates acquires or constructs that has a fair market value or construction cost of less than $5 million; and

•

any business or asset that Holly or any of its affiliates acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.

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

Indemnification

Under the Omnibus Agreement, Holly agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The transfers that are covered by the agreement include the refined product pipelines, terminals and tanks transferred by Holly’s subsidiaries in connection with our initial public offering in July 2004, the intermediate pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008 and the asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental indemnification of up to $15 million for the assets transferred to us, other than the crude pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines acquired in July 2005. Except as described below, Holly’s indemnification obligations described above will remain in effect for an asset for ten years following the date it is transferred to us. The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage assets acquired in 2008. Holly’s indemnification obligations described above do not apply to (i) the Tulsa west loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks acquired in March 2010.

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Under provisions of the Holly ETA and Holly PTTA, Holly agreed to indemnify us for environmental liabilities arising from our pre-ownership operations of the Tulsa loading racks acquired from Holly in August 2009 and the Tulsa logistics and storage assets acquired from Sinclair in December 2009. Additionally, Holly agreed to indemnify us for any liabilities arising from Holly’s operation of the loading racks under the Holly ETA.

We indemnified Holly and its affiliates against environmental liabilities related to our assets that occur after the date we acquired such asset.

Right of first refusal to purchase our assets

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

PIPELINE AND TERMINAL, TANKAGE AND THROUGHPUT AGREEMENTS

We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

•

Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by Holly upon our initial public offering in 2004);

•

Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from Holly in 2005 and 2009);

•

Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);

•

Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in March 2010);

•

Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);

•

Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from Holly in 2009);

•

Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and

•

Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from Holly in March 2010).

Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at a percentage change based upon the change in the Producer Price Index but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or the Federal Energy Regulatory Commission index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following our July 1, 2010 PPI rate adjustment, these agreements with Holly, will result in minimum annualized payments to us of $133 million.

Under certain circumstances, certain of Holly’s minimum revenue commitments under these agreements may be temporarily suspended or terminated.

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

SUMMARY OF TRANSACTIONS WITH HOLLY

•

Tulsa East / Lovington Storage Asset Transaction — On March 31, 2010, we acquired from Holly certain storage assets for $93 million located at Holly’s Tulsa refinery east facility and an asphalt loading rack facility located at Holly’s Navajo refinery Lovington facility.

•

Roadrunner / Beeson Pipelines Transaction — On December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million.

•

Tulsa West Loading Racks Transaction — On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility for $17.5 million.

•

Lovington-Artesia Pipeline Transaction — On June 1, 2009, we acquired a newly constructed 16-inch intermediate pipeline from Holly for $34.2 million.

•

Crude Pipelines and Tankage Transaction — On February 29, 2008, we acquired certain crude pipelines and tankage assets from Holly for $180 million.

•

See “2010 Acquisitions”, “2009 Acquisition” and “2008 Acquisition” under Item 1, “Business” of this Annual Report on Form 10-K for additional information on these acquisitions from Holly.

•

Revenues received from Holly were $146.4 million, $101.4 million and $85 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

Holly charged general and administrative services under the Omnibus Agreement of $2.3 million, $2.3 million and $2.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

We reimbursed Holly for costs of employees supporting our operations of $18.6 million, $17 million and $13.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

•

Holly reimbursed us $3.7 million and $1.7 million for certain costs paid on their behalf for the years ended December 31, 2010 and December 31, 2009, respectively.

•

We paid Holly a $2.5 million finder’s fee in connection the acquisition of our 25% joint venture interest in the SLC Pipeline in the first quarter of 2009.

•

REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

The disclosure, review and approval of any transactions with related persons is governed by our Code of Business Conduct and Ethics, which provides guidelines for disclosure, review and approval of any transaction that creates a conflict of interest between us and our employees, officers or directors and members of their immediate family. Conflict of interest transactions may be authorized if they are found to be in the best interest of the Partnership based on all relevant facts. Pursuant to the Code of Business Conduct and Ethics, conflicts of interest are to be disclosed to and reviewed by a superior employee to the related person who does not have a conflict of interest, and additionally, if more than trivial size, by the superior of the reviewing person. Conflicts of interest involving directors or senior executive officers are reviewed by the full Board of Directors or by a committee of the Board of Directors on which the related person does not serve. Related party transactions required to be disclosed in our SEC reports are reported through our disclosure controls and procedures.

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There are no transactions disclosed in this Item 13 entered into since January 1, 2010 that were not required to be reviewed, ratified or approved pursuant to our Code of Business Conduct and Ethics or with respect to which our policies and procedures with respect to conflicts of interest were not followed.

See Item 10 for a discussion of “Director Independence.”

Item 14. Principal Accountant Fees and Services

The audit committee of the board of directors of HLS selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the HEP for the 2010 calendar year.

Fees paid to Ernst & Young LLP for 2010 and 2009 are as follows:


	2010		2009
Audit Fees ⁽¹⁾	$	551,000	$	692,000
Audit Related Fees		—		—
Tax Fees ⁽²⁾		204,000		—
All Other Fees		—		—

Total	$	755,000	$	692,000


(1)		Represents fees for professional services provided in connection with the audit of our annual financial statements and internal controls over financial reporting, review of our quarterly financial statements, and procedures performed as part of our securities filings.

(2)		In 2009, Holly paid $12,400 in fees on our behalf to Ernst & Young LLP, representing one-half of fees related to tax services. Effective January 1, 2010, we pay all fees related to tax services provided by Ernst & Young LLP.

The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website at www.hollyenergy.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fee categories above were approved by the audit committee in advance.

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Part IV

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

(a) Documents filed as part of this report

(1) Index to Consolidated Financial Statements


	Page in
	Form 10-K

Report of Independent Registered Public Accounting Firm		71

Consolidated Balance Sheets at December 31, 2010 and 2009		72

Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		73

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		74

Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 2008		75

Notes to Consolidated Financial Statements		76

(2) Index to Consolidated Financial Statement Schedules

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

(3) Exhibits

See Index to Exhibits on pages 140 to 148.

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

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


	HOLLY ENERGY PARTNERS, L.P. (Registrant)

	By:	HEP LOGISTICS HOLDINGS, L.P. its General Partner

	By:	HOLLY LOGISTIC SERVICES, L.L.C. its General Partner

Date: February 16, 2011		/s/ Matthew P. Clifton Matthew P. Clifton
		Chairman of the Board of Directors and Chief Executive Officer

		/s/ Bruce R, Shaw

		Bruce R. Shaw
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

		/s/ Scott C. Surplus

		Scott C. Surplus
		Vice President and Controller
		(Principal Accounting Officer)

		/s/ Charles M. Darling, IV

		Charles M. Darling, IV
		Director

		/s/ William J. Gray

		William J. Gray
		Director

		/s/ Jerry W. Pinkerton

		Jerry W. Pinkerton
		Director

		/s/ P. Dean Ridenour

		P. Dean Ridenour
		Director

		/s/ William P. Stengel

		William P. Stengel
		Director

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Exhibit Index


Exhibit Number		Description

	2.1	Purchase and Sale Agreement, dated February 25, 2008 between Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C., Woods Cross Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K Current Report dated February 27, 2008, File No. 1-32225).

	2.2	Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing — Tulsa LLC, HEP Tulsa LLC, and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K Current Report dated October 21, 2009, File No. 1-32225).

	3.1	First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	3.2	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated February 28, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., as amended, dated July 6, 2005 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).

	3.4	Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners, L.P., dated April 11, 2008 (incorporated by reference to Exhibit 4.1 of Registrant’s Current Report on Form 8-K filed April 15, 2008, File No. 1-32225).

	3.5	First Amended and Restated Agreement of Limited Partnership of Holly Energy Partners — Operating Company, L.P. (incorporated by reference to Exhibit 3.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	3.6	First Amended and Restated Agreement of Limited Partnership of HEP Logistics Holdings, L.P. (incorporated by reference to Exhibit 3.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	3.7	First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C. (incorporated by reference to Exhibit 3.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	3.8	First Amended and Restated Limited Liability Company Agreement of HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 3.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	4.1	Indenture, dated February 28, 2005, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

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Exhibit Number		Description

	4.2	Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.2 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	4.3	Form of Notation of Guarantee (included as Exhibit E to the Indenture filed as Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	4.4	First Supplemental Indenture, dated March 10, 2005, among HEP Fin-Tex/Trust-River, L.P., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2005, File No. 1-32225).

	4.5	Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended March 31, 2005, File No. 1-32225).

	4.6	Third Supplemental Indenture, dated as of June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2009, File No. 1-32225).

	4.7	Fourth Supplemental Indenture, dated as of June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2009, File No. 1-32225).

	4.8	Fifth Supplemental Indenture, dated as of July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2009, File No. 1-32225).

	4.9	Sixth Supplemental Indenture, dated as of December 15, 2009, among Roadrunner Pipeline, L.L.C., Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-32225).

	4.10	Seventh Supplemental Indenture, dated as of April 14, 2010, among Holly Energy Storage- Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

	4.11	Eighth Supplemental Indenture, dated as of June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

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Exhibit Number			Description

	4.12		Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp. and each of the guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated March 11, 2010, File No. 1-32225).

	4.13		First Supplemental Indenture, dated as of April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association
			(incorporated by reference to Exhibit 4.3 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

	4.14		Second Supplemental Indenture, dated as of June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

	10.1		Option Agreement, dated January 31, 2008, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 5, 2008, File No. 1-32225).

	10.2	*	First Amendment to Option Agreement, dated February 11, 2010, by and among Holly Corporation, Holly UNEV Pipeline Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P.

	10.3		Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

	10.4		Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

	10.5		Mortgage, Line of Credit Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

	10.6		Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.5 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

	10.7		Mortgage and Deed of Trust, dated February 29, 2008, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.6 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

	10.8		Fee and Leasehold Deed of Trust, dated February 29, 2008, by HEP Woods Cross, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.7 of Registrant’s Form 8-K Current Report dated March 6, 2008, File No. 1-32225).

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Exhibit Number		Description

	10.9	Amended and Restated Credit Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger, Bank of America, N.A., as syndication agent, Guaranty Bank, as documentation agent and certain other lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated October 31, 2007, File No. 1-32225).

	10.10	Agreement and Amendment No. 1 to Amended and Restated Credit Agreement, dated February 25, 2008, between Holly Energy Partners — Operating, L.P., Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 27, 2008, File No. 1-32225).

	10.11	Amendment No. 2 to Amended and Restated Credit Agreement, dated September 8, 2008, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries acting as guarantors, Union Bank of California, N.A., as administrative agent, issuing bank and sole lead arranger and certain other lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2008, File No. 1-32225).

	10.12	Amended and Restated Pledge Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.12 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.13	Amended and Restated Guaranty Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.13 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.14	Amended and Restated Security Agreement, dated August 27, 2007, between Holly Energy Partners — Operating, L.P., certain of its subsidiaries, and Union Bank of California, N.A., as administrative agent (entered into in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.14 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.15	Form of Mortgage, Deed of Trust, Security Agreement, Assignment of Rents and Leases, Fixture Filing and Financing Statement (for purposes of granting security interests in real property in connection with the Amended and Restated Credit Agreement) (incorporated by reference to Exhibit 10.15 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.16	Form of Mortgage and Deed of Trust (Oklahoma) (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	10.17	Form of Mortgage and Deed of Trust (Texas) (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	10.18	Mortgage and Deed of Trust, dated July 8, 2005, by HEP Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated July 6, 2005, File No. 1-32225).

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Exhibit Number			Description

	10.19		Pipelines and Terminals Agreement, dated February 28, 2005, among the Partnership and Alon USA, LP2005 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 28, 2005, File No. 1-32225).

	10.20		Corrected Version Dated October 10, 2007 of Amendment and Supplement to Pipeline Lease Agreement effective as of August 31, 2007 between HEP Pipeline Assets, Limited Partnership and Alon USA, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated October 16, 2007, File No. 1-32225).

	10.21		LLC Interest Purchase Agreement, dated as of June 1, 2009, among Holly Corporation, Navajo Pipeline Co., L.P., and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).

	10.22		Amended and Restated Intermediate Pipelines Agreement, dated as of June 1, 2009, among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).

	10.23	*	Amendment to Amended and Restated Intermediate Pipelines Agreement, dated as of December 9, 2010, among Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C., and HEP Logistics GP, L.L.C.

	10.24	*	Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective as of January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC.

	10.25		Mortgage, Line of Credit Mortgage and Deed of Trust, dated as of June 1, 2009, by Lovington-Artesia, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-32225).

	10.26		Asset Purchase Agreement, dated as of August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225).

	10.27		Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225).

	10.28	*	Amendment to Tulsa Equipment and Throughput Agreement, dated as of December 9, 2010, among Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC.

	10.29	*	Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective as of January 1, 2011, between Holly Refining & Marketing — Tulsa, LLC and Holly Refining & Marketing Company LLC.

	10.30		Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing — Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated August 6, 2009, File No. 1-32225).

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Exhibit Number			Description

	10.31		LLC Interest Purchase Agreement, dated as of December 1, 2009, among Holly Corporation, Navajo Pipeline Co., L.P., and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.32		Asset Purchase Agreement, dated as of December 1, 2009, between Holly Corporation, Navajo Pipeline Co., L.P. and HEP Pipeline, L.L.C. (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.33		Pipeline Throughput Agreement, dated as of December 1, 2009, between Navajo Refining Company, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.34	*	Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective as of January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC.

	10.35		Form of Mortgage, Line of Credit Mortgage and Deed of Trust, to be entered into by HEP Pipeline L.L.C. and Holly Energy Partners, L.P. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.5 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.36		Form of Mortgage and Deed of Trust, to be entered into by Roadrunner Pipeline, L.L.C for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.6 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.37		Form of Mortgage, Line of Credit Mortgage and Deed of Trust, to be entered into by Roadrunner Pipeline, L.L.C. for the benefit of Holly Corporation (incorporated by reference to Exhibit 10.7 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.38		Amended and Restated Crude Pipelines and Tankage Agreement, entered into on December 1, 2009, to be effective as of January 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners — Operating, L.P., HEP Pipeline, LLC, and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.8 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.39		Amended and Restated Refined Product Pipelines and Terminals Agreement, entered into on December 1, 2009, to be effective as of January 1, 2009, among Navajo Refining Company, L.L.C., Holly Refining & Marketing Company — Woods Cross, Holly Refining & Marketing Company, Holly Energy Partners — Operating, L.P., HEP Pipeline, LLC, HEP Refining Assets, L.P., HEP Refining, L.L.C., HEP Mountain Home, L.L.C., and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

	10.40	*	Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective as of January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and Holly Refining & Marketing Company LLC.

	10.41		Indemnification Proceeds and Payments Allocation Agreement, dated as of December 1, 2009, between Holly Refining & Marketing — Tulsa, LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated December 7, 2009, File No. 1-32225).

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Exhibit Number			Description

	10.42		LLC Interest Purchase Agreement, dated as of March 31, 2010, by and among Holly Corporation, Holly Refining & Marketing-Tulsa, LLC, Lea Refining Company, HEP Tulsa LLC and HEP Refining, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.43		First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated as of March 31, 2010, by and between Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.44		Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated as of June 11, 2010, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.1 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

	10.45	*	Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective as of January 1, 2011, between Holly Refining & Marketing-Tulsa, LLC and Holly Refining & Marketing Company LLC.

	10.46		Loading Rack Throughput Agreement (Lovington), dated as of March 31, 2010, by and between Navajo Refining Company, L.L.C. and Holly Energy Storage-Lovington LLC (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.47		Fourth Amended and Restated Omnibus Agreement, dated as of March 31, 2010, by and among Holly Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.4 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.48		First Amended and Restated Lease and Access Agreement (East Tulsa), dated as of March 31, 2010, by and between Holly Refining & Marketing-Tulsa, LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.5 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.49		Pipeline Systems Operating Agreement, dated as of February 8, 2010, by and among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing — Tulsa LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated February 9, 2010, File No. 1-32225).

	10.50		First Amendment to Pipeline Systems Operating Agreement, dated as of March 31, 2010, by and among Navajo Refining Company, L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing-Tulsa, LLC and Holly Energy Partners-Operating, L.P. (incorporated by reference to Exhibit 10.6 of Registrant’s Form 8-K Current Report dated April 6, 2010, File No. 1-32225).

	10.51		Tulsa Refinery Interconnects Term Sheet dated August 9, 2010 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 11, 2010, File No. 1-32225).

	10.52		Amendment to Tulsa Refinery Interconnects Term Sheet dated December 31, 2010 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated January 6, 2011, File No. 1-32225).

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Exhibit Number		Description

	10.53+	Holly Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	10.54+	First Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan effective January 1, 2005 (incorporated by reference to Exhibit 10.4 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended September 30, 2005, File No. 1-32225).

	10.55+	Second Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan, effective January 1, 2005 (incorporated by reference to Exhibit 10.27 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.56+	Third Amendment to the Holly Energy Partners, L.P. Long-Term Incentive Plan effective March 3, 2009 (incorporated by reference to Exhibit 10.41 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-32225).

	10.57+	Holly Logistic Services, L.L.C. Annual Incentive Plan (incorporated by reference to Exhibit 10.10 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2004, File No. 1-32225).

	10.58+	First Amendment to the Holly Logistic Services, L.L.C. Annual Incentive Plan effective January 1, 2005 (incorporated by reference to Exhibit 10.26 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-32225).

	10.59+	Form of Director Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 of Registrant’s Current Report on Form 8-K dated November 15, 2004, File No. 1-32225).

	10.60+	Form of Employee Restricted Unit Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Current Report on Form 8-K dated November 15, 2004, File No. 1-32225).

	10.61+	Form of Restricted Unit Agreement (with Performance Vesting) (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 4, 2005, File No. 1-32225).

	10.62+	Form of Restricted Unit Agreement (without Performance Vesting) (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated August 4, 2005, File No. 1-32225).

	10.63+	Holly Energy Partners, L.P. Employee Form of Change in Control Agreement (incorporated by reference to Exhibit 10.3 of Registrant’s Form 8-K Current Report dated February 20, 2008, File No. 1-32225).

	10.64+	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.49 of Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-32225).

	10.65+	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.2 of Registrant’s Quarterly Report on Form 10-Q for its quarterly period ended June 30, 2010, File No. 1-32225).

	12.1*	Statement of Computation of Ratio of Earnings to Fixed Charges.

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Exhibit Number		Description

	21.1*	Subsidiaries of Registrant.

	23.1*	Consent of Independent Registered Public Accounting Firm.

	31.1*	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2*	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1*	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2*	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith.

+		Constitutes management contracts or compensatory plans or arrangements.

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HOLLY ENERGY PARTNERS LP - FORM 10-K - February 16, 2011

Attached files