8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): June 2, 2009 (June 2, 2009)

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation) 001-03876
(Commission File Number) 75-1056913
(I.R.S. Employer
Identification Number)

100 Crescent Court,
Suite 1600
Dallas, Texas
(Address of principal
executive offices)

75201-6915
(Zip code)

Registrant’s telephone number, including area code: (214) 871-3555

Not applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o     Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o     Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o     Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o     Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

	Item 7.01 Regulation FD Disclosure.
	Item 8.01 Other Events.
	Item 9.01 Financial Statements and Exhibits.
SIGNATURES
EXHIBIT INDEX
EX-23.1
EX-99.1
EX-99.2
EX-99.3
EX-99.4
EX-99.5
EX-99.6

Item 7.01 Regulation FD Disclosure.

     Furnished as Exhibit 99.1 and incorporated herein by reference in its entirety is a copy of a press release issued by Holly Corporation (the “Company”) on June 2, 2009 announcing that it intends to commence an offering of $200 million principal amount of senior notes due 2017.

     A copy of certain information contained in the preliminary offering memorandum dated June 2, 2009 relating to the proposed private offering of the notes under the captions “Risk factors,” “Our recent acquisition of the Tulsa Refinery,” “Management’s discussion and analysis of financial condition and results of operations,” and “Business” is attached as Exhibits 99.2, 99.3, 99.4 and 99.5 , respectively, to this report and is incorporated herein by reference.

     In accordance with General Instruction B.2 of Form 8-K, the information furnished in this report on Form 8-K pursuant to Item 7.01, including Exhibits 99.1, 99.2, 99.3, 99.4 and 99.5, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 (“Exchange Act”), or otherwise subject to the liabilities of that section, unless the Company specifically incorporates it by reference in a document filed under the Exchange Act or the Securities Act of 1933 (“Securities Act"). By filing this report on Form 8-K pursuant to Item 7.01 and furnishing this information, the Company makes no admission as to the materiality of any information in this report, including Exhibits 99.1, 99.2, 99.3, 99.4 and 99.5, or that any such information includes material investor information that is not otherwise publicly available.

     The information furnished in this report on Form 8-K pursuant to Item 7.01, including the information contained in Exhibits 99.1, 99.2, 99.3, 99.4 and 99.5, is summary information that is intended to be considered in the context of the Company’s Securities and Exchange Commission (“SEC”) filings and other public announcements that the Company may make, by press release or otherwise, from time to time. The Company disclaims any current intention to revise or update the information furnished in this report on Form 8-K pursuant to Item 7.01, including the information contained in Exhibits 99.1, 99.2, 99.3, 99.4 and 99.5, although the Company may do so from time to time as its management believes is warranted. Any such updating may be made through the furnishing or filing of other reports or documents with the SEC, through press releases or through other public disclosure.

     The information furnished in this report on Form 8-K pursuant to Item 7.01, including the information contained in Exhibits 99.1, 99.2, 99.3, 99.4 and 99.5, is neither an offer to sell nor a solicitation of an offer to buy any of the notes. The notes that the Company intends to offer will not be registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act.

Item 8.01 Other Events.

     In December 2007, the Financial Accounting Standard Board issued Statement of Financial Accounting Standards (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51.” SFAS No. 160 changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. This standard was effective for all fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption was not permitted.

     The Company adopted this standard effective January 1, 2009. The Company is filing as Exhibit 99.6 to this report the Consolidated Financial Statements of Holly Corporation as of December 31, 2008 and 2007, and for each of the three years ended December 31, 2008, which have been updated from the

financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, to reflect our retrospective application of this standard. As a result, all previous references to “minority interest” have been replaced with “noncontrolling interest.” Additionally, net income attributable to the non-controlling interest in the Company’s subsidiary Holly Energy Partners, L.P. is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in the Company’s Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interests in earnings of Holly Energy Partners,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in the Company’s Consolidated Financial Statements. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

Item 9.01 Financial Statements and Exhibits.

23.1	—	Consent of Ernst & Young LLP
99.1	—	Press Release of Holly Corporation issued June 2, 2009.*
99.2	—	Information contained under the caption “Risk factors” in the preliminary offering memorandum.*
99.3	—	Information contained under the caption “Our recent acquisition of the Tulsa Refinery” in the preliminary offering memorandum.*
99.4	—	Information contained under the caption “Management’s discussion and analysis of financial condition and results of operations” in the preliminary offering memorandum.*
99.5	—	Information contained under the caption “Business” in the preliminary offering memorandum.*
99.6	—	Consolidated Financial Statements of Holly Corporation as of December 31, 2007 and 2008 and for each of the three years ended December 31, 2008 (adjusted to reflect to the retrospective application of SFAS No. 160 and certain other items as described in Note 21).

* Furnished pursuant to Regulation FD.

SIGNATURES

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

HOLLY CORPORATION
By:	/s/ Scott C. Surplus
	Scott C. Surplus
	Vice President and Controller

Date: June 2, 2009

EXHIBIT INDEX

Exhibit
Number		Exhibit Title
23.1	—	Consent of Ernst & Young LLP
99.1	—	Press Release of Holly Corporation issued June 2, 2009.*
99.2	—	Information contained under the caption “Risk factors” in the preliminary offering memorandum.*
99.3	—	Information contained under the caption “Our recent acquisition of the Tulsa Refinery” in the preliminary offering memorandum.*
99.4	—	Information contained under the caption “Management’s discussion and analysis of financial condition and results of operations” in the preliminary offering memorandum.*
99.5	—	Information contained under the caption “Business” in the preliminary offering memorandum.*
99.6	—	Consolidated Financial Statements of Holly Corporation as of December 31, 2007 and 2008 and for each of the three years ended December 31, 2008 (adjusted to reflect to the retrospective application of SFAS No. 160 and certain other items as described in Note 21).

* Furnished pursuant to Regulation FD.

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

     We consent to the incorporation by reference in the Registration Statements (Form S-8 Nos. 2-74856 and 333-54612) pertaining to the Holly Corporation Stock Option Plan and the Holly Corporation Long-Term Incentive Compensation Plan and in the related Prospectuses of our report dated February 27, 2009 (except for changes as described in Notes 1 and 21, as to which the date is May 29, 2009) with respect to the consolidated financial statements of Holly Corporation for the year ended December 31, 2008, included in the Current Report on Form 8-K of Holly Corporation dated June 2, 2009, filed with the Securities and Exchange Commission.

/s/ ERNST & YOUNG LLP

Dallas, Texas
May 29, 2009

EX-99.1

Exhibit 99.1

Holly Corporation Announces Proposed Offering of Senior Notes

DALLAS, TX, June 2, 2009 — Holly Corporation (NYSE-HOC) (“Holly” or the “Company”) announced today that it intends to commence an offering of $200 million principal amount of senior unsecured notes due 2017. Holly intends to use the net proceeds from the offering (i) to make post-closing inventory payments expected to be between $90 and $100 million in connection with its acquisition of the Tulsa Refinery on June 1, 2009 from Sunoco, Inc. (R&M) and (ii) for general corporate purposes, including planned capital expenditures.

This press release shall not constitute an offer to sell, or the solicitation of an offer to buy, any of the securities described herein, nor shall there be any sale of these securities in any state in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of such state. The securities to be offered have not been registered under the Securities Act of 1933 or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The securities will be offered only to qualified institutional buyers under Rule 144A and to persons outside the United States under Regulation S. This notice is being issued pursuant to and in accordance with Rule 135c under the Securities Act.

Holly, headquartered in Dallas, Texas, is an independent petroleum refiner and marketer that produces high value light products such as gasoline, diesel fuel and jet fuel and high value specialty lubricants. Holly operates through its subsidiaries a 100,000 BPSD refinery located in Artesia, New Mexico, a 31,000 BPSD refinery in Woods Cross, Utah and an 85,000 BPSD refinery located in Tulsa, Oklahoma. Also, a subsidiary of Holly owns an approximate 41% interest (which includes a 2% general partner interest) in Holly Energy Partners, L.P., which through subsidiaries owns or leases approximately 2,600 miles of petroleum product and crude oil pipelines in Texas, New Mexico, Utah and Oklahoma and tankage and refined product terminals in several Southwest and Rocky Mountain states.

The following is a “safe harbor” statement under the Private Securities Litigation Reform Act of 1995: The statements in this press release relating to matters that are not historical facts are “forward-looking statements” based on management’s beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties, including those contained in our filings with the Securities and Exchange Commission. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

EX-99.2

Exhibit 99.2

Risk factors

This offering involves a high 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 offering memorandum, including the financial statements and related notes, before deciding to invest in the notes offered hereby. The risks described below are not the only risks facing us, our industry or our business. 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 actually occurs, our business, financial condition or results of operations could be materially and adversely affected. In such case, you may lose all or part of your original investment.

RISKS RELATING TO OUR BUSINESS

The prices of crude oil and refined products materially affect our profitability and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors and governmental regulations and policies.

Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles) or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.

We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely upon the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year. In general, prices for refined products are influenced by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on operating results therefore depends in part upon how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings and cash flows. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between

16

Risk factors

purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial results.

In addition, we currently process volumes of lower cost crude oils, such as regional sour, heavy Western Canadian and Black Wax. As part of our current capital initiatives, we plan on providing additional flexibility to both our Navajo and Woods Cross Refineries that will allow us to process a greater degree of these lower cost crude oils. In recent years, the spread, or differential, between these lower cost heavy/sour crude oils and higher priced light sweet crude oils has widened. A substantial or prolonged decrease in these crude oil differentials could negatively impact our earnings and cash flows.

Volatile prices for natural gas and electrical power used by our refineries and other operations affect manufacturing and operating costs, as well. Natural gas and electricity prices have been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets.

We may not be able to execute our business strategies successfully to grow our business.

One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets, such as our UNEV Pipeline joint venture, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada that is currently under construction and in which our subsidiary owns a 75% interest. The construction process involves numerous regulatory, environmental, political and legal uncertainties, most of which are not fully within our control, including: denial or delay in issuing requisite regulatory approvals and/or permits; compliance with or liability under environmental regulations; 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 or spills) affecting our facilities or those of vendors and suppliers; shortages of sufficiently skilled labor or labor disagreements resulting in unplanned work stoppages; and/or nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project. These projects may not be completed on schedule, at all or at the budgeted cost. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, 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 capital investments may not achieve our expected investment return, which could adversely affect our business, financial condition and results of operations. Our forecasted internal rates of return are also based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, available alternative supply and customer demand.

In addition, a component of our growth strategy is to acquire complementary assets selectively for our refining operations in order to increase earnings and cash flow, such as our recent Tulsa Refinery acquisition discussed under “Our recent acquisition of the Tulsa Refinery.” Our ability to do so will be dependent upon a number of factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets, obtain financing to

17

Risk factors

fund acquisitions and to support our growth and other factors beyond our control. Risks associated with acquisitions include those relating to:

Ø	diversion of management time and attention from our existing business;
Ø	challenges in managing the increased scope, geographic diversity and complexity of operations;
Ø	difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
Ø	liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
Ø	greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
Ø	difficulties in achieving anticipated operational improvements;
Ø	incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
Ø	issuance of additional equity, which could result in further dilution of the ownership interests of existing stockholders.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits for, or may have adverse effects on, our business, financial conditions and results of operations. In particular, with respect to our recent acquisition of the Tulsa Refinery, prior to this acquisition we have not historically operated a specialty lubricants business, the specialty lubricants business may not produce the anticipated benefits and if we are not successful in operating the specialty lubricants business it could have adverse effects on our business, financial condition and results of operations.

To operate our petroleum refining facilities successfully, we are required to expend significant amounts for capital outlays and operating expenditures.

The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent upon the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent upon our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures. Our future capital expenditures are based on our best estimates of labor and equipment required to complete these projects. There may exist risks of cost overruns or delays in project completion, some of which may be factors outside of our control.

Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity, and plan to do so in connection with our acquisition of the Tulsa Refinery. See “Management’s discussion and analysis of financial condition and results of operations—Liquidity and Capital Resources—Planned capital expenditures.” The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; the yield and product quality of new equipment may differ from design and/or specifications, and redesign or modification of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment

18

Risk factors

or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future results of operations and financial condition. In addition, we expect to execute turnarounds at our refineries every three to five years, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen capital costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.

We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and we may face potential exposure for environmental matters.

Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, characteristics and composition of gasoline and diesel fuels and other matters otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition or results of operations. Over the years, there have been, and continue to be, ongoing communications, including notices of violations and discussions about environmental matters between us and federal and state authorities, some of which have resulted, or will result, in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. There are several environmental matters pending with respect to the Tulsa Refinery that we will be responsible for. See “Our recent acquisition of the Tulsa Refinery—Regulatory and Environmental Matters.”

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include, but are not limited to, soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed.

We are, and have been, the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including, but not limited to, expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures.

We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, could require us to make additional unforeseen expenditures. There is growing consensus

19

Risk factors

that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides). Also, new federal or state legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our products.

The costs of environmental and safety regulations are already significant, and compliance with more stringent laws or regulations, or adverse changes in the interpretation of existing regulations, by government agencies could have an adverse effect on our business, financial condition and results of operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.

From time to time, new federal energy policy legislation is enacted by the United States Congress. For example, in December 2007, the United States Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels, such as ethanol, commencing in 2008 and escalating for 15 years and also increases energy efficiency goals, including mandating higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products, particularly gasoline, in certain markets. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that we cannot predict.

Insufficient ethanol supplies or disruption in ethanol supply may disrupt our ability to market ethanol blended fuels.

If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended, which could result in lower profits.

Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of refining and marketing companies, including certain multinational integrated oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.

We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and, therefore, are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations. These competitors may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be material adverse effects on our business, financial condition and results of operations.

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Risk factors

In recent years, there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.

Portions of our operations may be impacted by competitors’ plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.

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

The renewal or replacement of existing sales agreements with our customers depends on a number of factors outside of our control, including competition from other refiners and the demand for refined products in the markets that we serve. Loss of or reduction in amounts purchased by our major customers could have an adverse effect on us to the extent that, because of market limitations or transportation constraints, we are not able to correspondingly increase sales to other purchasers.

A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.

In order to maintain or increase production levels at our refineries, we must continually contract for new crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries and/or materially increase the cost of crude oil for Holly. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and, therefore, a corresponding reduction in our cash flow. The recently announced reversal of the Guernsey to Wamsutter section of the Rocky Mountain Pipeline System could potentially cause a decline in the volumes of local crude oils. This could require us to source alternative crude oils at a higher price or, depending on refining economics, could reduce refinery production runs. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries’ production capacities.

The potential operation of new refined product transportation pipelines, or disruption or proration of existing pipelines, could impact the supply of refined products to our existing markets.

If one of the major refined products pipelines becomes inoperative, we would be required to keep refined products in inventory, or supply refined products to our customers through an alternative pipeline or by additional tanker trucks from our refineries, which could increase our costs and result in a decline in profitability. The Longhorn Pipeline 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. Longhorn Partners Pipeline L.P., owner of the Longhorn Pipeline, is a wholly-owned subsidiary of Flying J Inc. On December 22, 2008, both Longhorn Partners Pipeline and Flying J filed voluntary petitions for

21

Risk factors

reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The status of current shipping levels is currently unknown. The future ownership and operation of the Longhorn Pipeline is uncertain pending resolution of the bankruptcy proceedings. 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, Arizona and related markets.

An additional factor that could affect some of our markets is the presence of pipeline capacity from the West Coast into our Arizona markets. Additional increases in shipments of refined products from the West Coast into the Arizona markets could result in additional downward pressure on refined product prices in these markets.

In addition to the projects described above, other projects have been explored from time to time by refiners and other entities that, if completed, could result in further increases in the supply of products to our markets. For example, competitors may rely on alternate methods of transportation, such as trucking, to increase the volume of refined products entering our markets. Such alternatives may decrease the price of refined products or decrease our ability to market our refined products in those markets.

The common carrier pipeline we use to serve the Albuquerque market out of El Paso currently operates at near capacity. However, through our relationship with HEP, our Navajo Refinery has pipeline access to the Albuquerque vicinity and to Bloomfield, New Mexico that will permit us to deliver a total of up to 45,000 BPD of light products to these locations, thereby eliminating the risk of future pipeline constraints on shipments to Albuquerque. If needed, additional pump stations could further increase HEP’s pipeline capabilities. Any future pipeline constraints or disruptions affecting our ability to transport refined products to Arizona or Albuquerque could, if sustained, adversely affect our business, financial condition and results of operations.

The Tulsa Refinery relies in part on pipelines owned by Magellan Midstream Partners, L.P. for the transportation of refined products to market, and on pipelines owned by Sunoco Logistics Partners L.P. for the transportation of gas oil to Cushing, Oklahoma for offtake pursuant to our Gas Oil Offtake and Net Out Agreement with Sunoco, Inc. (R&M). See “Our recent acquisition of the Tulsa Refinery—Other Agreements.” Any disruption to the service provided by these pipelines could significantly impair our ability to transport these intermediate and refined products and therefore could materially affect our revenues for the Tulsa Refinery.

We depend upon HEP for a substantial portion of the crude supply and distribution network that serves our Navajo Refinery, and we own a significant equity interest in HEP.

We currently own an approximate 41% interest in HEP, including a 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariff rates for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon USA, Inc., by charging fees for terminalling refined products and other hydrocarbons and for storing and providing other services at its terminals. HEP serves our refineries in New Mexico and Utah under three pipelines and terminals and tankage agreements expiring in 2019 through 2024. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and regulatory risks, including, but not limited to:

Ø	its reliance upon its significant customers, including us;
Ø	competition from other pipelines;
Ø	environmental regulations affecting pipeline operations;
Ø	operational hazards and risks;

22

Risk factors

Ø	pipeline tariff regulations affecting the rates HEP can charge;
Ø	limitations on additional borrowings and other restrictions due to HEP’s debt covenants; and
Ø	other financial, operational and legal risks.

The occurrence of any of these risks could directly or indirectly affect HEP’s as well as our business, financial condition and results of operations, as HEP is a consolidated subsidiary. Additionally, these risks could affect HEP’s ability to continue operations, which could affect their ability to serve our supply and distribution network needs.

Additionally, the tariffs that we pay to HEP to transport and store refined products and other hydrocarbons to and from our Navajo and Woods Cross Refineries adjust annually based on the Producer Price Index. In a severe inflationary economic environment, our transportation costs per barrel of hydrocarbons transported by HEP could increase significantly and materially increase our operating expenses.

For additional information about HEP, see “Business—Holly Energy Partners, L.P.”

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 material releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage or an interruption in our operations and may affect our ability to meet marketing commitments. Alternative supply arrangements could require additional capital expenditures, hurt our business and profitability and cause us to operate the affected refinery at less than full capacity until pipeline access was restored or crude oil transportation was fully replaced. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.

We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities. Furthermore, our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In

23

Risk factors

addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel, including technical personnel for the lubricants business at the Tulsa Refinery that we recently acquired from Sunoco. We do not currently maintain key man life insurance, non-compete agreements or employment agreements with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel become unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.

Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our business, financial condition and results of operations.

We may not be able to renegotiate our collective bargaining agreements on satisfactory terms when they expire, or at all.

As of December 31, 2008, approximately 35% of our employees were represented by labor unions under collective bargaining agreements expiring in 2009 through 2010. We may not be able to renegotiate our collective bargaining agreements on satisfactory terms when they expire, or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our business, financial condition and results of operations.

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

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. 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.

Difficult conditions in the global capital markets and the economy generally may materially and adversely affect our business and results of operations.

Our results of operations are materially affected by conditions in the domestic capital markets and the economy generally. The stress experienced by domestic capital markets that began in the second half of 2007 continued and substantially increased during 2008. While the domestic capital markets have shown signs of improvement in 2009, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States continue to contribute to increased volatility and diminished expectations of the economy and the markets going forward. These factors, combined with volatile oil and gas prices,

24

Risk factors

declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown. In addition, the fixed-income markets have experienced periods of extreme volatility which negatively impacted market liquidity conditions.

The capital markets have experienced decreased liquidity, increased price volatility, credit downgrade events, and increased probabilities of default. These events and the continuing market upheavals may have an adverse effect on us because our liquidity and ability to fund our capital expenditures is dependent in part upon our bank borrowings and access to the public capital markets. Our revenues are likely to decline in such circumstances. In addition, in the event of extreme prolonged market events, such as a worsening of the global credit crisis, we could incur significant losses.

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 business, financial condition and results of operations.

The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the refining industry in general, and on us in particular, are 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. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. 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. In addition, disruptions or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Our financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.

Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel fuel, which in the Southwest region of the United States is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes. However, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products could reduce demand for gasoline and diesel fuel, which could result in lower prices and reduce operating margins.

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

25

Risk factors

substantial expenditures of management time and financial resources to identify and correct any such failure.

Additionally, the failure to comply with Section 404 or the report by us of a “material weakness” may cause investors to lose confidence in our financial statements, and our stock price may be adversely affected. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may decline.

Product liability claims and litigation could adversely affect our business, financial condition and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against petroleum fuel manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. The lubricants business that is part of the Tulsa Refinery that we recently acquired from Sunoco may have additional exposure to products liability claims due to the use of lubricant products in applications other than for fuel. There is no assurance that product liability claims against us would not have a material adverse effect on our business, financial condition or results of operations. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels.

If the market value of our inventory declined to an amount less than our LIFO basis, we would record a write-down of inventory and a non-cash charge to cost of sales, which would adversely affect our earnings.

The nature of our business requires us to maintain substantial quantities of crude oil, refined petroleum product and blendstock inventories. Because crude oil and refined petroleum products are commodities, we have no control over the changing market value of these inventories. Because certain of our refining inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology, we would record a write-down of inventory and a non-cash charge to cost of sales if the market value of our inventory were to decline to an amount less than our LIFO basis. A material write-down could affect our operating income and profitability.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are not able to obtain the necessary funds from financing activities.

We have significant short-term cash needs to satisfy working capital requirements such as crude oil purchases, which fluctuate with the pricing and sourcing of crude oil.

We generally purchase crude oil for our refineries with cash generated from our operations. If the price of crude oil increases significantly, we may not have sufficient cash flow or borrowing capacity, and may not be able to sufficiently increase borrowing capacity, under our existing credit facilities to purchase enough crude oil to operate our refineries at full capacity. Our failure to operate our refineries at full capacity could have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including those to support our expansion and upgrade plans, as well as for regulatory compliance. If credit markets tighten even further, it may become more difficult to obtain cash from third party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case

26

Risk factors

our operations may not perform as well as we currently expect and we could be subject to regulatory action.

Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and limit our ability to purchase enough crude oil to operate our refineries at full capacity.

An unfavorable credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flow.

We may need to use current cash flow to fund our pension and postretirement health care obligations, which could have a significant adverse effect on our financial position.

We have benefit obligations in connection with our noncontributory defined benefit pension plans that provided retirement benefits for substantially all of our employees. However, effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements. To the extent an employee not covered by a collective bargaining agreement was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen. We expect to contribute between $5.0 million to $15.0 million to the retirement plan in 2009. Future adverse changes in the financial markets could result in significant charges to stockholders’ equity and additional significant increases in future pension expense and funding requirements.

We also have benefit obligations in connection with our unfunded postretirement health care plans, which provide health care benefits as part of the voluntary early retirement program offered to eligible employees. As part of the early retirement program, we allow qualified retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. As of December 31, 2008, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7 million. Increased participation in this program and/or increasing medical costs may affect our ability to pay required health care benefits, causing us to have to divert funds away from other areas of the business to pay their costs.

RISKS RELATING TO THE NOTES

Your right to receive payments on these notes is effectively subordinated to the rights of our existing and future secured creditors. Further, the guarantees of these notes will be effectively subordinated to all of the guarantors’ existing and future secured indebtedness.

Holders of our existing or future secured indebtedness and holders of existing or any future secured indebtedness of the guarantors will have claims that are prior to your claims as holders of the notes to the extent of the value of the assets securing that other indebtedness. The notes will be effectively subordinated to all of that secured indebtedness, including indebtedness under our credit agreement. In the event of any distribution or payment of our assets in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of secured indebtedness will have a prior claim to those assets that constitute their collateral. Holders of the notes will participate in the distribution or payment of our remaining assets ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all of our other general

27

Risk factors

creditors, based upon the respective amounts owed to each holder or creditor. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of notes may receive less, ratably, than holders of secured indebtedness.

Not all of our subsidiaries will guarantee the notes. Your right to receive payments on the notes will be effectively subordinated to the rights of creditors of our subsidiaries that do not guarantee the notes or whose guarantees are invalidated.

HEP, in which we own an approximate 39% limited partner interest and a 2% general partner interest, and its subsidiaries, as well as some of our other subsidiaries, will not guarantee the notes. These subsidiaries are consolidated with us for the purposes of our financial statements. Creditors of our subsidiaries that do not guarantee the notes will have claims, with respect to the assets of those subsidiaries, that rank effectively senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors must be satisfied prior to making any such distribution or payment to us in respect of our direct or indirect equity interests in such subsidiaries. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. In addition, as described below, there are federal and state laws that could invalidate the guarantees of our subsidiaries that guarantee the notes. If that were to occur, the claims of creditors of those subsidiaries would also rank effectively senior to the notes, to the extent of the assets of those subsidiaries.

You generally will be required to accrue income before you receive cash attributable to original issue discount on the notes. Additionally, in the event we enter into bankruptcy, you may not have a claim for all or a portion of any unamortized amount of the original issue discount on the notes.

We intend to issue the notes with original issue discount (“OID”) for United States federal income tax purposes. Accordingly, if you are a United States Holder (as defined below), you generally will be required to accrue OID on a current basis for United States federal income tax purposes, even before you receive cash attributable to such OID income and regardless of your method of accounting. For further discussion of the computation and reporting of OID, see “Certain United States federal tax considerations—United States Holders—Stated interest and OID.”

Additionally, a bankruptcy court may not allow a claim for all or a portion of any unamortized amount of the OID on the notes.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, including these notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our subsidiaries conduct substantially all of our consolidated operations and own substantially all of our consolidated assets. Consequently, our cash flow and our ability to meet our debt service obligations, including these notes, depend upon the cash flow of our subsidiaries, including HEP, and the payment of funds by our subsidiaries to us in the form of dividends, distributions, tax sharing payments or otherwise. Their ability to make any payments will depend on their earnings, distributions, the terms of their indebtedness, tax considerations and legal restrictions. Current provisions in HEP’s credit agreement and notes place restrictions on HEP’s ability to pay dividends to us. We have no special purpose entities.

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Risk factors

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit agreement or otherwise in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including these notes, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our credit agreement and these notes, on commercially reasonable terms or at all.

Our credit agreement includes certain financial covenant requirements, including the maintenance of ratios relating to our leverage and our interest coverage. If we do not meet these requirements, an event of default occurs under our credit agreement. Accordingly, the existence of outstanding borrowings or a default or event of default under our credit agreement could adversely affect our ability to have sufficient cash to pay our obligations, including these notes.

We and our subsidiaries may be able to incur substantial additional debt. This could further exacerbate the risks associated with our current debt levels.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture governing the notes will not fully prohibit us or our subsidiaries from doing so. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify and our ability to satisfy our obligations with respect to the notes could be adversely affected.

Our indebtedness could adversely affect our ability to operate our business and prevent us from fulfilling our obligations under the notes.

On March 31, 2009, as adjusted to give effect to this offering and the application of the net proceeds therefrom, we would have had total indebtedness of $200.0 million, excluding letters of credit outstanding under our credit agreement aggregating $9.8 million and indebtedness of HEP.

Our indebtedness could have important consequences to you. For example, it could:

Ø	make it more difficult for us to satisfy our obligations with respect to the notes;
Ø	limit our ability to obtain additional financing to fund our working capital, expenditures, debt service requirements or for other purposes;
Ø	limit our ability to use operating cash flow in other areas of our business because we must dedicate a portion of these funds to service debt;
Ø	limit our ability to compete with other companies who are not as highly leveraged; and
Ø	limit our ability to react to changing market conditions in our industry and in our customers’ industries and to economic downturns.

In addition, the indenture governing the notes will contain, and our credit agreement does contain, financial or other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debt, including the notes. Our ability to satisfy our debt obligations, including the notes, will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. If we cannot generate sufficient cash from operations to meet our other obligations, we may need to refinance or sell assets. Our business may not generate sufficient cash flow, or we may not be able to obtain sufficient funding, to make the payments required by all of our debt, including the notes.

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Risk factors

We may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture.

Upon the occurrence of certain specific kinds of “change of control” events, as defined in the indenture, we will be required to offer to repurchase all outstanding notes at 101% of the principal amount thereof plus accrued and unpaid interest and liquidated damages, if any, to the date of repurchase. However, it is possible that we will not have sufficient funds at the time of the change of control to make the required repurchase of notes. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “change of control” under the indenture. A change of control would also constitute a default under our credit agreement. See “Description of notes—Repurchase at the Option of Holders—Change of control.”

Federal and state statutes allow courts, under specific circumstances, to void the notes and the guarantees and require noteholders to return payments received from us or the guarantors.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, the notes and the guarantees could be voided, or claims in respect of the notes or the guarantees could be subordinated to all other debts of ours or any guarantor, if, among other things, we or the guarantor, at the time the indebtedness evidenced by the notes or the guarantees was incurred:

Ø	received less than reasonably equivalent value or fair consideration for the incurrence of the indebtedness; and
Ø	were insolvent or rendered insolvent by reason of the incurrence of the indebtedness; or
Ø	were engaged, or about to engage, in a business or transaction for which our or the guarantor’s remaining assets constituted unreasonably small capital; or
Ø	intended to incur, or believed that we would incur, debts beyond our ability to pay such debts as they matured.

In addition, any payment by us or a guarantor pursuant to its guarantee could be voided and required to be returned to us or the guarantor, or to a fund for the benefit of our creditors or the creditors of the guarantor. In any such case, your right to receive payments in respect of the notes from us or such guarantor would be effectively subordinated to all of our or its indebtedness and other liabilities.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, we or a guarantor would be considered insolvent if:

Ø	the sum of our or its debts, including contingent liabilities, was greater than the fair saleable value of all of our or its assets; or
Ø	if the present fair saleable value of our or its assets were less than the amount that would be required to pay our or its probable liability on our or its total existing debts and liabilities, including contingent liabilities, as they become absolute and mature; or
Ø	we or it could not pay our or its debts as they become due.

Based upon information currently available to us, we believe that the notes and the guarantees are being incurred for proper purposes and in good faith and that we and each of the guarantors:

Ø	are solvent and will continue to be solvent after giving effect to the issuance of the notes and the guarantees, as the case may be;
Ø	will have enough capital for carrying on our business and the business of each of the guarantors after the issuance of the notes and the guarantees, as the case may be; and
Ø	will be able to pay our debts as they become due.

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Risk factors

If an active trading market does not develop for these notes, you may not be able to resell them.

These notes have not been registered under the Securities Act or under any state securities law. Accordingly, the notes may only be offered or sold pursuant to an exception from the registration requirements of the Securities Act or pursuant to an effective registration statement. We are required to exchange the notes for a new issue of our debt securities registered under the Securities Act, with terms substantially identical to the notes offered hereby, however, in general we will not be required to consummate the exchange offer with respect to any notes that are freely tradable under Rule 144 under the Securities Act before the required date for the consummation of such exchange offer. For additional information see “Description of notes—Registration Rights; Release of Restricted Legends; Special Interest.” Prior to this offering, there was no public market for the notes, and we cannot assure you that an active trading market will develop for the notes. If no active trading market develops, you may not be able to resell your notes at their fair market value or at all. Future trading prices of the notes will depend on many factors, including, among other things, prevailing interest rates, our operating results and the market for similar securities. Historically, the market for non-investment grade debt has been subject to disruptions that have caused volatility in prices. It is possible that the market for the notes will be subject to disruptions.

Any disruptions may have a negative effect on noteholders, regardless of our prospects and financial performance. The liquidity of, and trading market for, the notes may also be hurt by general declines in the market for similar securities. Such a decline may adversely affect any liquidity and trading of the notes independent of our financial performance and prospects. We have been informed by the initial purchasers that they currently intend to make a market in the notes after this offering is completed. However, the initial purchasers may cease their market-making activities at any time. We do not intend to apply for listing of the notes on any securities exchange.

Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.

The restrictive covenants in the indenture governing the notes to be issued pursuant to this offering, our credit agreement, and any future financing agreements, could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, the indenture governing the notes and our credit agreement contain financial and other restrictive covenants that will limit our ability, and the ability of certain of our subsidiaries, to, among other things:

Ø	pay dividends or make other distributions;
Ø	purchase equity interests or redeem subordinated indebtedness early;
Ø	enter into certain lease obligations and make certain investments or capital expenditures;
Ø	create or incur certain liens; and
Ø	sell assets or merge or consolidate with another company or engage in change of control transactions.

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Risk factors

Any default under our credit agreement or indenture could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. If we fail to satisfy the covenants set forth in the credit agreement or another event of default occurs under the credit agreement, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. Should we desire to undertake a transaction that is prohibited by the covenants in the indenture governing the notes or our credit agreement, we will need to obtain consent under the indenture and our credit agreement. Such refinancing may not be possible or may not be available on commercially acceptable terms, or at all. In addition, our obligations under our credit agreement are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit agreement when due, the lenders could seek to foreclose on these assets. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

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EX-99.3

Exhibit 99.3

Our recent acquisition of the Tulsa Refinery

Substantially all the information presented below regarding the Tulsa Refinery and related assets to be acquired from Sunoco is based on information provided to us by Sunoco in connection with our recent acquisition.

On June 1, 2009, through a wholly-owned subsidiary, we acquired the Tulsa Refinery from Sunoco for $65 million, plus an amount to be paid within 30 days of closing for the market value of crude oil, refined product and other inventories valued as of the closing date. Our current estimate is that the amount to be paid for these inventories will be between $90 and $100 million. We intend to use a portion of the net proceeds from this offering to make these post-closing inventory payments, among other things. See “Use of proceeds.”

DESCRIPTION OF THE TULSA REFINERY

Facilities

The Tulsa Refinery is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The refinery has a total crude oil throughput capacity of approximately 85,000 BPSD. The refinery has a Nelson Complexity Index of 10.4. Most of the operating units at the Tulsa Refinery currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. The refinery completed a major maintenance turnaround in July 2007.

The following table provides information about the main process units of the Tulsa Refinery:

Tulsa Refinery process units

	Current design
Unit	capacity BPSD
Crude (w/LERU)(1)		85,000
MEROX		12,000
Unifiner		25,000
Fixed-Bed Platformer		22,500
Propane De-asphalting		11,500
Lube Extraction Unit		19,500
MEK Dewaxing		12,500
Delayed Coker		9,300
Butane Splitter		3,400

(1) LERU—Light Ends Recovery Unit.

The refinery’s supporting infrastructure includes approximately 3.2 million barrels of feedstock and product tankage and an additional 1.2 million barrels of tank capacity that are currently out of service and could be made available for future use. There are also nine truck racks and six rail racks that support product distribution at the Tulsa Refinery.

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Our recent acquisition of the Tulsa Refinery

Operations

The following table provides information about the Tulsa Refinery’s operations:

	Year ended									Three months
	December 31,									ended March 31,
	(unaudited)									(unaudited)
	2008			2007			2006			2009(1)			2008
	(in thousands)
Tulsa Refinery
Crude charge (BPD)(2)		76,800			67,300			77,700			42,100			79,300
Refinery production (BPD)(3)		74,500			65,300			75,600			40,800			77,000
Refinery utilization(4)		90.4	%		79.2	%		91.4	%		49.5	%		93.3	%

(1)	Reduced rates during the first quarter of 2009 are primarily due to regeneration work on the fixed-bed platformer in February 2009 and Sunoco’s objective to minimize inventory.
(2)	Crude charge represents the barrels per day of crude oil processed at the crude units at the Tulsa Refinery.
(3)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
(4)	Represents crude charge divided by total crude capacity measured in BPSD.

Markets and competition

The Tulsa Refinery primarily serves the Mid-Continent region of the United States.

Distillates and gasolines are primarily delivered from the Tulsa Refinery to market via two pipelines owned and operated by Magellan Midstream Partners, L.P. These pipelines connect the refinery to distribution channels throughout Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, the Tulsa Refinery has a proprietary diesel transfer line to the local Burlington Northern Santa Fe Railroad depot, and the refinery’s truck and rail rack capability facilitates access to local refined product markets.

The refinery also produces specialty lubricant products including agricultural oils, base oils, process oils and waxes that are sold throughout the United States and to customers with operations in Central America and South America.

Refined product demand in the Mid-Continent region has generally historically resulted in higher refined product margins for its regional refineries as compared to some other regions in the United States. This shortage of refining capacity in the region is compensated by imports of petroleum products into the region from the Gulf Coast and other regions via pipeline, which generally supports the margins of local refineries such as the Tulsa Refinery due to the increased cost to import petroleum products. Additionally, Mid-Continent refining margins may benefit from increasing Canadian crude oil production and supply into the region.

In support of the growth of the Canadian crude market in the region, Enbridge and TransCanada have completed or announced plans to expand their respective systems to the refining hub at Cushing, Oklahoma, which will significantly improve access to the region. Enbridge completed the expansion of its Spearhead Pipeline from the Chicago area to Cushing in May 2009. TransCanada’s Keystone pipeline runs from Hardisty, Alberta to the Nebraska/Kansas border, and TransCanada has announced plans to extend the pipeline to Cushing by late 2010 or early 2011.

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Our recent acquisition of the Tulsa Refinery

Crude oil and feedstock supplies

The Tulsa Refinery is located approximately 45 miles from Cushing, Oklahoma, a significant crude oil pipeline crossroad and storage hub. Local pipelines provide access to regional crude production as well as many United States onshore, Gulf of Mexico, Canadian and other foreign crudes. The proximity of the refinery to this pipeline and storage hub allows the refinery the flexibility to optimize its crude slate and maintain lower crude inventories than a typical refinery.

Crude oil is received at the refinery through three pipeline systems owned and operated by subsidiaries of Sunoco Logistics Partners L.P. We will purchase crude oil from subsidiaries of Sunoco Logistics Partners L.P. pursuant to crude supply contracts with a term of up to five years entered into at the closing of our acquisition of the refinery. Please see “—Other Agreements—Crude Supply Agreements.”

The refinery also purchases other feedstocks on an opportunistic basis. From time to time, the refinery purchases naphtha, gasoline components, transmix, light cycle oil, lube blend stocks or residuals from other refineries. These feedstocks are delivered by truck, rail car or pipeline, depending on product and logistical requirements.

Principal products and customers

The Tulsa Refinery primarily processes light sweet crudes into high value light products, such as gasoline, diesel and jet fuel and LPG products. It also produces specialty lubricant products such as agricultural oils, base oils, process oils and waxes.

The table below provides information regarding the principal products produced at the Tulsa Refinery:

	Year ended December 31,									Three months ended March 31,
	(unaudited)									(unaudited)
	2008			2007			2006			2009			2008
	(in thousands)
Tulsa Refinery
Production of refined products:
Gasolines		21	%		22	%		23	%		18	%		22	%
Diesel fuels		29	%		30	%		29	%		30	%		29	%
Jet fuels		12	%		11	%		11	%		10	%		12	%
Lubricants		15	%		18	%		18	%		17	%		16	%
Gas oil/intermediates		17	%		15	%		14	%		20	%		15	%
LPG and other		6	%		4	%		5	%		5	%		6	%
Total		100	%		100	%		100	%		100	%		100	%

Light products are shipped by product pipelines and are also made available to customers through truck and rail loading facilities.

The Tulsa Refinery’s principal customers for conventional gasoline include other refiners, convenience store chains, independent marketers and retailers. The composition of gasoline differs, because of regulatory requirements, depending on the area in which gasoline is to be sold. Railroads are the primary diesel customers. Jet fuel is sold primarily for commercial use. LPGs are sold to LPG wholesalers and retailers.

The specialty lubricant products produced at the Tulsa Refinery are high value products that provide a disproportionately high margin contribution to the refinery. Specialty lubricant products are sold in both commercial and specialty markets. Base oil customers include blender-compounders who prepare

37

Our recent acquisition of the Tulsa Refinery

the various finished lubricant and grease products sold to end users. Agricultural oils, primarily formulated as supplemental carriers for herbicides, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the adhesive or candle-making businesses.

Capital improvement projects

We plan to construct a new diesel hydrotreater and to expand sulfur recovery capacity, which, once complete, will allow all diesel produced at the Tulsa Refinery to be produced as ultra low sulfur diesel (“ULSD”). Additionally, this project will allow the Tulsa Refinery to upgrade coker distillate and extracts to ULSD. The project is expected to be mechanically complete in mid-2011 with an expected cost of approximately $150.0 million.

Employees

The refinery employs approximately 400 workers and is not unionized. Substantially all of the refinery employees, as well as the specialty lubricant products management team, have elected to continue employment with us following the acquisition. Our existing senior management, marketing and business development personnel will perform the same functions with respect to the Tulsa Refinery.

REGULATORY AND ENVIRONMENTAL MATTERS

In March 2006, Sunoco entered into a consent decree with the EPA, environmental agencies in Ohio, Oklahoma and Pennsylvania and the Air Management Services for the city of Philadelphia. The 2006 consent decree addresses various alleged air compliance issues at the Tulsa Refinery and other refineries owned by Sunoco. In connection with our acquisition of the refinery, we have assumed, pursuant to a modified consent decree, all of the liabilities and obligations of the consent decree that apply to the Tulsa Refinery. These obligations include requirements for NOx reductions from the refinery’s heaters and boilers and reduced sulfur levels in the refinery’s fuel gas loop. We estimate the capital expenditures to address the remaining consent decree requirements to be approximately $23.0 million, which is expected to be expended through 2013.

Beginning in 2006, the Clean Air Act phased in limits on the sulfur content of diesel fuel. Effective in June 2006, diesel fuel for on-road uses was required to contain no more than 15 PPM of sulfur. Effective in June 2012, the same requirement will apply to diesel for locomotive and marine operations. We refer to these requirements as the ULSD requirements. Sunoco operated the refinery under a hardship waiver from the EPA that excepted the refinery from these requirements until April 1, 2010, but required Sunoco to generate or purchase diesel sulfur credits to offset non-ULSD production at the Tulsa Refinery. In connection with our acquisition of the refinery, we requested from the EPA, and received, a hardship waiver that waives the ULSD requirements with respect to our operation of the Tulsa Refinery until November 1, 2011, subject to an obligation to offset production of non-ULSD diesel with diesel sulfur credits. We expect our diesel hydrotreater and sulfur recovery project planned for the refinery to allow the refinery to fully satisfy the ULSD requirements in 2011. Under our purchase agreement with Sunoco, Sunoco will retain liability for any failure to generate sufficient diesel sulfur credits for its operations prior to our purchase of the refinery. Additionally, we have extended a contract with the Burlington Northern Santa Fe Corporation through May 2012 for the purchase of diesel fuel from the refinery. To the extent we cannot fully offset our non-ULSD diesel production by generating diesel sulfur credits, we will be obligated to buy diesel sulfur credits to satisfy the balance of any remaining deficit.

Due to soil and groundwater contamination at the Tulsa Refinery, the refinery has been remediating areas of the Tulsa Refinery under a consent order from the Oklahoma Department of Environmental Quality, or ODEQ, and Sunoco had been negotiating a RCRA corrective action permit with the ODEQ

38

Our recent acquisition of the Tulsa Refinery

with respect to the contamination. The remediation includes riverbank containment and the removal of light non-aqueous phase liquids. In connection with our acquisition of the refinery, we will become the permittee under the RCRA permit and will assume all obligations under the final RCRA corrective action permit relating to the Tulsa Refinery. Prior to our acquisition of the refinery, Sunoco spent approximately $9.7 million on remediation projects relating to soil and groundwater contamination. We expect to spend approximately $5.0 million on remediation projects through 2014.

OTHER AGREEMENTS

In connection with the acquisition of the Tulsa Refinery, we have entered into a number of other ancillary agreements with Sunoco or affiliates of Sunoco, including those described below.

Crude Supply Agreements.  A subsidiary of Sunoco Logistics Partners L.P., an affiliate of Sunoco that owns the pipeline systems that supply the refinery with crude oil, will supply the majority of the refinery’s crude charge requirements at market-related prices after the closing.

Gas Oil Exchange and Net-Out Agreement; LEF Line Agreement.  At Holly’s option, Sunoco will take up to 15,000 BPD of gas oil produced at the refinery for a period of five years after the closing at monthly average NYMEX pricing for light sweet crude oil less $0.50 per barrel. For purposes of settlement, amounts owed by Sunoco for gas oil off-take will be netted against amounts owed by us for crude purchases under our crude supply agreements with Sunoco Logistics Partners L.P. discussed above. Additionally, to transport the gas oil from the refinery during the term of Sunoco’s off-take agreement, a subsidiary of Sunoco Logistics Partners L.P. will continue to operate its LEF pipeline that transports gas oil from the refinery to Cushing, Oklahoma for a period of five years after the closing, or any earlier termination of the crude supply agreements discussed above.

Trademark Assignment; Trademark License Agreement.  Sunoco will transfer to us its North America specialty lubricant products trademarks, and will grant us a perpetual, royalty-free license to use certain marks and trademarks in Central America and South America.

Transition Services Agreement.  Sunoco will provide us with certain back office services to assist with our integration of the refinery from the date of closing for terms ranging from 30 to 180 days after the closing, depending on the type of service and subject to our electing to terminate any service with prior notice. Sunoco is providing these services at no additional cost, except for our reimbursement of certain out-of-pocket expenses.

39

EX-99.4

Exhibit 99.4

Management’s discussion and analysis of financial condition and results of operations

OVERVIEW

We are principally an independent petroleum refiner operating three refineries in Artesia and Lovington, New Mexico (operated as one refinery) and Woods Cross, Utah and, as of June 1, 2009, our recently acquired refinery in Tulsa, Oklahoma. See “Our recent acquisition of the Tulsa Refinery.” As of March 31, 2009, prior to our acquisition of the Tulsa Refinery, our refineries had a combined crude capacity of 131,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At March 31, 2009, we also owned a 46% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande Pipeline Company and a 25% interest in the joint venture that owns the 95-mile crude oil SLC Pipeline (the “SLC Pipeline”). On May 8, 2009 and May 21, 2009, HEP sold 2,000,000 and 192,400 common units, respectively, to the public, reducing our interest in HEP to approximately 41%, including our 2% general partner interest.

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States and, as of our June 1, 2009, acquisition of the Tulsa Refinery, high value specialty lubricant products. Our principal expenses are costs of products sold and operating expenses.

On February 29, 2008, we sold certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. We received consideration of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million for the assets.

In connection with the 2008 transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP (“HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”), but they will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the FERC Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a Federal Energy Regulatory Commission (“FERC”) adjustment factor. Additionally, we amended our Omnibus Agreement with HEP (“Omnibus Agreement”) to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.

HEP is a VIE as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

On March 31, 2006, we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale amounted to $48.9 million, net of transaction fees and expenses. Additionally, we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. We have

42

Management’s discussion and analysis of financial condition and results of operations

presented the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale in discontinued operations.

Under our common stock repurchase program, repurchases are made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million, or an average of $42.48 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million, or an average of $39.10 per share.

The following management’s discussion and analysis of financial condition and results of operations does not include information relating to the Tulsa Refinery, which we acquired on June 1, 2009.

RESULTS OF OPERATIONS

Statement of income data

										Three months ended March 31,
	Year ended December 31,									(unaudited)
	2008			2007			2006			2009			2008
	(in thousands)
Sales and other revenues	$	5,867,668		$	4,791,742		$	4,023,217		$	650,823		$	1,479,984
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		5,280,699			4,003,488			3,349,404			511,654			1,383,437
Operating expenses (exclusive of depreciation and amortization)		267,570			209,281			208,460			67,202			60,708
General and administrative expenses (exclusive of depreciation and amortization)		54,906			68,773			63,255			11,747			12,832
Depreciation and amortization		63,789			43,456			39,721			20,321			13,309
Exploration expenses, including dry holes		372			412			486			—			105
Total operating costs and expenses		5,667,336			4,325,410			3,661,326			610,924			1,470,391
Income from operations		200,332			466,332			361,891			39,899			9,593
Other income (expense):
Equity in earnings of Holly Energy Partners		2,990			19,109			12,929			—			2,990
Equity in earnings of SLC Pipeline		—			—			—			175			—
Impairment of equity securities		(3,724	)		—			—			—			—
Gain on sale of HPI		5,958			—			—			—			—
Interest income		10,824			15,089			9,757			2,196			3,555
Interest expense		(23,955	)		(1,086	)		(1,076	)		(6,239	)		(1,992	)
		(7,907	)		33,112			21,610			(3,868	)		4,553

43

Management’s discussion and analysis of financial condition and results of operations

							Three months ended March 31,
	Year ended December 31,						(unaudited)
	2008		2007		2006		2009		2008
	(in thousands)
Income from continuing operations before income taxes		192,425		499,444		383,501		36,031		14,146
Income tax provision		64,826		165,316		136,603		12,131		4,695
Income from continuing operations		127,599		334,128		246,898		23,900		9,451
Income from discontinued operations, net of taxes		—		—		19,668		—		—
Net income(1)		127,599		334,128		266,566		23,900		9,451
Less net income attributable to noncontrolling interest(1)		7,041		—		—		1,955		802
Net income attributable to Holly Corporation stockholders(1)	$	120,558	$	334,128	$	266,566	$	21,945	$	8,649
Earnings per share attributable to Holly Corporation stockholders—basic:
Continuing operations	$	2.40	$	6.09	$	4.33	$	0.44	$	0.17
Discontinued operations		—		—		0.35		—		—
Net income	$	2.40	$	6.09	$	4.68	$	0.44	$	0.17
Earnings per share attributable to Holly Corporation stockholders—diluted:
Continuing operations	$	2.38	$	5.98	$	4.24	$	0.44	$	0.17
Discontinued operations		—		—		0.34		—		—
Net income	$	2.38	$	5.98	$	4.58	$	0.44	$	0.17
Cash dividends declared per common share	$	0.60	$	0.46	$	0.29	$	0.15	$	0.15
Average number of common shares outstanding:
Basic		50,202		54,852		56,976		50,042		51,165
Diluted		50,549		55,850		58,210		50,171		51,515

44

Management’s discussion and analysis of financial condition and results of operations

Balance sheet data

					Three months ended
					March 31,
	Year ended December 31,				(unaudited)
	2008		2007		2009		2008
	(in thousands)
Cash, cash equivalents and investments in marketable securities	$	96,008	$	329,784	$	54,465	$	437,771
Working capital	$	68,465	$	216,541	$	32,619	$	255,259
Total assets	$	1,874,225	$	1,663,945	$	2,013,867	$	2,276,722
Long-term debt—Holly Energy Partners	$	341,914	$	—	$	411,485	$	341,416
Total equity(1)	$	936,332	$	602,127	$	951,084	$	898,049

(1) During the first quarter of 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” As a result, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retroactive basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

Cash flow data

										Three months ended March 31,
	Year ended December 31,									(unaudited)
	2008			2007			2006			2009			2008
	(in thousands)
Net cash provided by (used for) operating activities	$	155,490		$	422,737		$	245,183		$	(2,315	)	$	98,850
Net cash provided by (used for) investing activities	$	(57,777	)	$	(293,057	)	$	35,805		$	(70,339	)	$	83,459
Net cash provided by (used for) financing activities	$	(151,277	)	$	(189,428	)	$	(175,935	)	$	85,727		$	(96,127	)
Capital expenditures	$	418,059		$	161,258		$	120,429		$	99,228		$	72,761

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Eliminations.

45

Management’s discussion and analysis of financial condition and results of operations

										Three months ended March 31,
	Year ended December 31,									(unaudited)
	2008			2007			2006			2009			2008
	(in thousands)
Sales and other revenues
Refining(1)	$	5,837,449		$	4,790,164		$	4,021,974		$	636,910		$	1,477,376
HEP(2)		101,750			—			—			32,125			9,942
Corporate and other		2,641			1,578			1,752			99			401
Consolidations and eliminations		(74,172	)		—			(509	)		(18,311	)		(7,735	)
Consolidated	$	5,867,668		$	4,791,742		$	4,023,217		$	650,823		$	1,479,984
Operating income (loss)
Refining(1)	$	210,252		$	537,118		$	425,474		$	38,705		$	18,884
HEP(2)		41,734			—			—			12,830			3,734
Corporate and other		(51,654	)		(70,786	)		(63,583	)		(11,636	)		(13,025	)
Consolidated	$	200,332		$	466,332		$	361,891		$	39,899		$	9,593

(1)

The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. Although we previously included the Montana Refinery in the Refining segment prior to its sale in March 2006, the results of the Montana Refinery are now included in discontinued operations and are not included in the above tables. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

(2)

The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at their storage tanks and terminals. The HEP segment also includes a 25% interest in SLC Pipeline, a crude oil pipeline and a 70% interest in Rio Grande, which also provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

Refining operating data

Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following tables set forth information, including non-GAAP performance measures, about our consolidated refinery operations. The cost of products and refinery gross margin do not include the effect of

46

Management’s discussion and analysis of financial condition and results of operations

depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”

	Year ended December 31,									Three months ended March 31,
	(unaudited)									(unaudited)
	2008			2007			2006			2009			2008
Consolidated(1)
Crude charge (BPD)(2)		100,680			103,490			96,570			80,994			108,160
Refinery production (BPD)(3)		110,850			113,270			105,730			86,347			120,080
Sales of produced refined products (BPD)		111,950			115,050			105,090			89,171			119,350
Sales of refined products (BPD)(4)		120,750			126,800			119,870			98,802			132,940
Refinery utilization(5)		89.7	%		94.1	%		92.4	%		69.8	%		97.4	%
Average per produced barrel(6)
Net sales	$	108.83		$	89.77		$	80.21		$	55.23		$	103.20
Cost of products(7)		97.87			73.03			64.43			43.30			95.48
Refinery gross margin		10.96			16.74			15.78			11.93			7.72
Refinery operating expenses(8)		5.14			4.43			4.83			6.40			4.78
Net operating margin	$	5.82		$	12.31		$	10.95		$	5.53		$	2.94

(1)	The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.
(2)	Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
(3)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
(4)	Includes refined products purchased for resale.
(5)	Represents crude charge divided by total crude capacity measured in BPSD. Our consolidated crude capacity was increased from 101,000 BPSD to 109,000 BPSD during 2006, from 109,000 BPSD to 111,000 BPSD in mid-year 2007 and by an additional 5,000 BPSD in the fourth quarter of 2008, increasing our consolidated crude capacity to 116,000 BPSD. During the first quarter of 2009, we completed a 15,000 BPSD expansion at our Navajo Refinery, increasing our consolidated crude capacity to 131,000 BPSD effective April 1, 2009.
(6)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”
(7)	Transportation costs billed from HEP are included in cost of products.
(8)	Represents operating expenses of the refineries, exclusive of depreciation and amortization.

Results of operations—three months ended March 31, 2009 compared to three months ended March 31, 2008.

Summary

Net income attributable to Holly Corporation stockholders for the three months ended March 31, 2009 was $21.9 million ($0.44 per basic and diluted share), a $13.3 million increase compared to $8.6 million ($0.17 per basic and diluted share) for the three months ended March 31, 2008. Income increased due principally to higher year-over-year refined product margins for the first quarter, partially offset by the effects of an overall decrease in refining production during the three months ended

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March 31, 2009 due to planned downtime. Overall refinery gross margins for the three months ended March 31, 2009 were $11.93 per produced barrel compared to $7.72 for the three months ended March 31, 2008. Additionally contributing to the increase in net income for the first quarter of 2009 were improved results from our asphalt marketing business and an increase in sulfur credit sales.

Overall production levels for the three months ended March 31, 2009 decreased by 28% due principally to reduced production attributable to our planned major maintenance turnaround at the Navajo Refinery during the first quarter of 2009. We timed this turnaround with the completion of phase I of our major capital projects initiative at the Navajo Refinery, increasing the refinery’s production capacity from 85,000 BPSD to 100,000 BPSD effective April 1, 2009.

Sales and other revenues

Sales and other revenues from continuing operations decreased 56% from $1,480.0 million for the three months ended March 31, 2008 to $650.8 million for the three months ended March 31, 2009, due principally to significantly lower refined product sales prices combined with the effects of a 26% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold decreased 46% from $103.20 for the first quarter of 2008 to $55.23 for the first quarter of 2009. The total volume of refined products sold for the three months ended March 31, 2009 decreased due to the effects of reduced production resulting from our Navajo Refinery’s planned major maintenance turnaround during the first quarter of 2009. Sales and other revenues for the three months ended March 31, 2009 and 2008, includes $13.8 million and $2.2 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties. Additionally, revenues for the three months ended March 31, 2009 include sulfur credit sales of $4.5 million compared to $0.9 million for the three months ended March 31, 2008.

Cost of products sold

Cost of products sold decreased 63% from $1,383.4 million for the three months ended March 31, 2008 to $511.7 million for the three months ended March 31, 2009, due principally to significantly lower crude oil costs. The average price we paid per produced barrel sold for crude oil and feedstocks and the transportation costs of moving the finished products to the market place decreased 55% from $95.48 for the first quarter of 2008 to $43.30 for the first quarter of 2009. Also contributing to this decrease was the effects of a 26% decrease in first quarter year-over-year volumes of refined products sold.

Gross refinery margins

Gross refining margin per produced barrel increased 55% from $7.72 for the three months ended March 31, 2008 to $11.93 for the three months ended March 31, 2009 due to the effects of a decrease in the average price we paid per barrel of crude oil and feedstocks partially offset by a decrease in the average sales price we received per produced barrel sold. Gross refinery margin does not include the effects of depreciation and amortization. See “Annex A—Reconciliations to amounts reported under generally accepted accounting principles” for a reconciliation to the income statement of prices of refined products sold and costs of products purchased.

Operating expenses

Operating expenses, exclusive of depreciation and amortization, increased 11% from $60.7 million for the three months ended March 31, 2008 to $67.2 million for the three months ended March 31, 2009, due principally to the inclusion of HEP costs for a full three month period during the first quarter of 2009 compared to one month during the first quarter of 2008. For the three months ended March 31, 2009 and 2008, operating expenses included $10.8 million and $3.5 million, respectively, in costs

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Management’s discussion and analysis of financial condition and results of operations

attributable to HEP operations. Excluding HEP, operating expenses decreased by $0.8 million due principally to lower utility costs, partially offset by higher maintenance costs.

General and administrative expenses

General and administrative expenses decreased 9% from $12.9 million for the three months ended March 31, 2008 to $11.7 million for the three months ended March 31, 2009, due principally to a decrease in professional fees and services. For the three months ended March 31, 2009 and 2008, general and administrative expenses included $0.7 million and $0.5 million, respectively, in costs attributable to HEP operations.

Depreciation and amortization expenses

Depreciation and amortization increased 53% from $13.3 million for the three months ended March 31, 2008 to $20.3 million for the three months ended March 31, 2009. The increase was due principally to depreciation attributable to capitalized refinery improvement projects in 2008 and the inclusion of HEP depreciation expense. For the three months ended March 31, 2009 and 2008, depreciation and amortization expenses included $7.2 million and $2.0 million, respectively, in costs attributable to HEP operations.

Equity in earnings of HEP

Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Equity in earnings of HEP for the three months ended March 31, 2008 was $3.0 million, representing our pro-rata share of earnings in HEP from January 1 through February 29, 2008.

Interest expense

Interest expense was $6.2 million for the three months ended March 31, 2009 compared to $2.0 million for the three months ended March 31, 2008. The increase was due principally to the inclusion of HEP interest expense. For the three months ended March 31, 2009 and 2008, interest expense included $6.0 million and $1.7 million, respectively, in costs attributable to HEP operations.

Income taxes

Income taxes for the three months ended March 31, 2009 were $12.1 million compared to $4.7 million for the three months ended March 31, 2008. Our effective tax rate for the first quarter of 2009 and 2008 was 33.7% and 33.2%, respectively.

Results of operations—year ended December 31, 2008 compared to year ended December 31, 2007

Summary

Net Income attributable to Holly Corporation stockholders for the year ended December 31, 2008 was $120.6 million ($2.40 per basic and $2.38 per diluted share) compared to $334.1 million ($6.09 per basic and $5.98 per diluted share) for the year ended December 31, 2007. Income for the year ended December 31, 2008 decreased $213.5 million compared to the year ended December 31, 2007 due principally to reduced refined product margins during the first half of 2008. Overall refinery gross margins from continuing operations for the year ended December 31, 2008 were $10.96 per produced barrel compared to $16.74 for the year ended December 31, 2007.

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Sales and other revenues

Sales and other revenues from continuing operations increased 23% from $4,791.7 million for the year ended December 31, 2007 to $5,867.7 million for the year ended December 31, 2008 due principally to higher refined product sales prices, partially offset by a 5% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold increased 21% from $89.77 for the year ended December 31, 2007 to $108.83 for the year ended December 31, 2008. The decrease in volumes of refined products sold was principally due to the effects of downtime at our refineries during the second quarter and a scheduled major maintenance turnaround at our Woods Cross Refinery during the third quarter of 2008. Additionally, sales and other revenues for the year ended December 31, 2008 include $27.6 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. Sales and other revenues for 2007 include $23.0 million in sulfur credit sales.

Cost of products sold

Cost of products sold increased 32% from $4,003.5 million in 2007 to $5,280.7 million in 2008 due principally to significantly higher crude oil costs in the first half of 2008. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 34% from $73.03 in 2007 to $97.87 in 2008. This increase was partially offset by the effects of a 5% decrease in year-over-year volumes of refined products sold.

Gross refinery margins

Gross refining margin per produced barrel decreased 35% from $16.74 in 2007 to $10.96 in 2008 due to an increase in the average we paid per produced barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross refining margin does not include the effects of depreciation or amortization. See “Annex A—Reconciliations to amounts reported under generally accepted accounting principles” for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.

Operating expenses

Operating expenses, exclusive of depreciation and amortization, increased 28% from $209.3 million in 2007 to $267.6 million in 2008 due principally to the inclusion of $35.2 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008. Additionally, higher refinery utility and payroll costs along with increased maintenance costs associated with unplanned downtime contributed to this increase.

General and administrative expenses

General and administrative expenses decreased 20% from $68.8 million in 2007 to $54.9 million in 2008 due principally to a decrease in equity-based compensation expense, which is to some extent affected by our stock price. Additionally, general and administrative expenses for 2008 include $5.6 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Depreciation and amortization expenses

Depreciation and amortization increased 47% from $43.5 million in 2007 to $63.8 million in 2008 due principally to the inclusion of $19.2 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 and depreciation attributable to capitalized refinery improvement projects in 2008 and 2007.

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Management’s discussion and analysis of financial condition and results of operations

Equity in earnings of HEP

Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP was $3.0 million and $19.1 million for the years ended December 31, 2008 and 2007, respectively.

Impairment of equity securities

Impairment of equity securities represents an impairment loss of $3.7 million during the year ended December 31, 2008 that relates to 1,000,000 shares of Connacher common stock that was received in connection with our sale of the Montana Refinery in 2006. We accounted for this impairment as an other-than-temporary decline in the fair value of these securities.

Gain on sale of Holly Petroleum, Inc.

We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6.0 million, resulting in a gain of $6.0 million.

Interest income

Interest income for the year ended December 31, 2008 was $10.8 million compared to $15.1 million for the year ended December 31, 2007 due principally to the effects of a lower interest rate environment combined with a decrease in investments in marketable debt securities.

Interest expense

Interest expense was $24.0 million for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31, 2007. The increase in interest expense was due principally to the inclusion of $21.5 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Income taxes

Income taxes decreased 61% from $165.3 million in 2007 to $64.8 million in 2008 due to lower pre-tax earnings in 2008 compared to 2007. The effective tax rate for the year ended December 31, 2008 was 33.7% compared to 33.1% for the year ended December 31, 2007. We realized a lower effective tax rate during 2007 due principally to a higher utilization of ultra low sulfur diesel tax credits in 2007 that were fully utilized in 2008.

Income attributable to noncontrolling interest

Net income attributable to noncontrolling interest for the year ending December 31, 2008 reduced our income by $7.0 million and represents the noncontrolling interest in HEP’s earnings.

Results of operations—year ended December 31, 2007 compared to year ended December 31, 2006

Summary

Income from continuing operations for the year ended December 31, 2007 was $334.1 million ($6.09 per basic and $5.98 per diluted share) compared to $246.9 million ($4.33 per basic and $4.24 per diluted share) for the year ended December 31, 2006. Net income from continuing operations increased by 35%, or $87.2 million, for the year ended December 31, 2007 compared to the year ended December 31, 2006 due principally to an overall increase in refined product margins during the first half of 2007 combined

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Management’s discussion and analysis of financial condition and results of operations

with an increase in volumes of produced refined products sold, partially offset by an increase in total operating costs and expenses and an overall decrease in refined product margins during the second half of the year. Overall sales of produced refined products from continuing operations for the year ended December 31, 2007 increased 9% compared to the year ended December 31, 2006. Overall refinery gross margins from continuing operations for the year ended December 31, 2007 were $16.74 per produced barrel compared to $15.78 for the year ended December 31, 2006.

Sales and other revenues

Sales and other revenues from continuing operations increased 19% from $4,023.2 million for the year ended December 31, 2006 to $4,791.7 million for the year ended December 31, 2007 due principally to higher refined product sales prices and an increase in volumes of produced refined products sold. The average sales price we received per produced barrel sold increased 12% from $80.21 for the year ended December 31, 2006 to $89.77 for the year ended December 31, 2007. The total volume of produced refined products sold increased 9% for the year ended December 31, 2007 compared to the same period in 2006 due principally to an increase in production following a combined 10,000 BPSD capacity expansion at our Navajo Refinery during 2006 and 2007. Additionally, sales and other revenues for the year ended December 31, 2007 include $23.0 million in sulfur credit sales compared to $15.9 million for the year ended December 31, 2006.

Cost of products sold

Cost of products sold increased 20% from $3,349.4 million in 2006 to $4,003.5 million in 2007 due principally to the higher costs of purchased crude oil and an increase in volumes of produced refined products sold. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation costs of moving the finished products to the market place increased 13% from $64.43 in 2006 to $73.03 in 2007.

We recognized a $0.8 million charge to cost of products sold during 2007 resulting from liquidations of certain LIFO inventory quantities that were carried at higher costs as compared to current costs. In 2006, we recognized a $4.2 million reduction to cost of products sold as liquidated LIFO inventory quantities were carried at lower costs as compared to then current costs.

Refinery gross margin

Refining gross margin per produced barrel increased 6% from $15.78 in 2006 to $16.74 in 2007. Refinery gross margin does not include the effects of depreciation or amortization. See “Annex A—Reconciliations to amounts reported under generally accepted accounting principles” for a reconciliation to the income statements of prices of refined products sold and costs of products purchased.

Operating expenses

Operating expenses, exclusive of depreciation and amortization, increased less than 1% from $208.5 million in 2006 to $209.3 million in 2007.

General and administrative expenses

General and administrative expenses increased 9% from $63.3 million in 2006 to $68.8 million in 2007 due principally to increased equity-based incentive compensation expense and software implementation costs.

Depreciation and amortization expenses

Depreciation and amortization increased 9% from $39.7 million in 2006 to $43.5 million in 2007 due to capitalized refinery improvement projects in 2006 and 2007.

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Management’s discussion and analysis of financial condition and results of operations

Equity in earnings of HEP

Our equity in earnings of HEP was $19.1 million for the year ended December 31, 2007 compared to $12.9 million for the year ended December 31, 2006. The increase in our equity in earnings of HEP was due principally to an increase in HEP’s earnings for the year ended December 31, 2007 compared to the year ended December 31, 2006.

Interest income

Interest income for the year ended December 31, 2007 was $15.1 million compared to $9.8 million for the year ended December 31, 2006. The increase in interest income was due principally to the effects of a higher interest rate environment combined with increased investments in marketable debt securities.

Interest expense

Interest expense was $1.1 million for each of the years ended December 31, 2007 and 2006.

Income taxes

Income taxes increased 21% from $136.6 million in 2006 to $165.3 million in 2007 due to higher pre-tax earnings in 2007 compared to 2006, partially offset by a lower effective tax rate. The effective tax rate for the year ended December 31, 2007 was 33.1% compared to 35.6% for the year ended December 31, 2006. The decrease in our effective tax rate was due principally to a statutory increase from 3% to 6% in the federal tax deduction for domestic manufacturing activities.

Discontinued operations

We had no income from discontinued operations for the year ended December 31, 2007, as our Montana Refinery operations have ceased. Income from discontinued operations was $19.7 million for the year ended December 31, 2006, which consisted of a $14.0 million gain on the sale of the Montana Refinery, net of $8.3 million in income taxes, and $5.7 million of earnings, which was largely due to the liquidation of certain retained quantities of inventories that were not included in the sale of our Montana Refinery on March 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings. We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly and may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale and, as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of March 31, 2009, we had cash and cash equivalents of $53.9 million.

Cash and cash equivalents increased by $13.1 million during the three months ended March 31, 2009. Net cash provided by financing activities of $85.7 million exceeded the combined cash used for

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Management’s discussion and analysis of financial condition and results of operations

operating activities of $2.3 million and investing activities of $70.3 million. Working capital decreased by $35.8 million during the three months ended March 31, 2009.

In April 2009, we entered into a second amended and restated $300.0 million senior secured revolving credit agreement that amends and restates our previous credit agreement in its entirety with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. The credit agreement expires in March 2013 and may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We have the right to request an increase in the maximum amount of the credit agreement of up to $150 million, which would bring the maximum amount of the credit agreement to a total of $450 million. The request will become effective if (a) certain customary conditions specified in the credit agreement are met and (b) one or more existing lenders under the credit agreement or other financial institutions approved by the administrative agent commit to lend the increased amounts under the credit agreement.

Our obligations under the credit agreement are secured by the inventory and accounts receivable owned by us and our wholly-owned subsidiaries designated as Restricted Subsidiaries in the credit agreement. Indebtedness under the credit agreement is recourse to us and is guaranteed by our wholly-owned subsidiaries designated as Restricted Subsidiaries in the credit agreement. HEP and its subsidiaries are not guarantors of our credit agreement.

Indebtedness under the credit agreement bears interest, at our option, at either (a)(i) a base rate equal to the highest of: the Federal Funds Rate plus 1/2 of 1%, London Interbank Offered Rate plus 1% and the prime rate (as publicly announced from time to time by Bank of America, N.A.), as applicable, plus (ii) an applicable margin (ranging from 2.25% to 2.75%) or (b) at a rate equal to the London Interbank Offered Rate plus an applicable margin (ranging from 3.25% to 3.75%). In each case, the applicable margin is based upon the ratio (the “Leverage Ratio”) of our consolidated indebtedness (as defined in the credit agreement) to Consolidated EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the credit agreement) for a given period. We incur a commitment fee on the unused portion of the commitments (the calculation of which excludes amounts borrowed as swing line loans except to the extent that a lender has purchased a participation in a swing line loan) at a rate of 0.50%.

The credit agreement imposes certain restrictions, including: limitations on investments (including distributions to Unrestricted Subsidiaries (as defined in the credit agreement)); 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 Leverage Ratio and a specified EBITDA to interest expense ratio.

We were in compliance with all covenants under our $175 million senior secured revolving credit agreement in existence at March 31, 2009. At March 31, 2009, we had outstanding letters of credit totaling $9.8 million and outstanding borrowings under our then existing credit agreement of $55.0 million. At that level of usage, the unused commitment under such credit agreement was $110.2 million at March 31, 2009.

There are currently a total of twelve lenders under our $300.0 million credit agreement, with individual commitments ranging from $15.0 million up to $47.5 million. If any particular lender could not honor its commitment, we believe the unused capacity under our credit agreement would be available to meet our borrowing needs. Additionally, we have reviewed publicly available information on our lenders in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the credit agreement. We have not experienced, nor do we 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.

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Management’s discussion and analysis of financial condition and results of operations

HEP has a $300.0 million senior secured revolving credit agreement expiring in August 2011 (the “HEP Credit Agreement”). The HEP Credit Agreement is available to fund capital expenditures, acquisitions and working capital or other general partnership purposes. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included in our Consolidated Balance Sheets at March 31, 2009 consist of $4.3 million in cash and cash equivalents, $4.1 million in trade accounts receivable and other current assets, $359.3 million in property, plant and equipment, net and $108.5 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., HEP’s general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement.

As of March 31, 2009, there were a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15.0 million up to $40.0 million. If any particular lender could not honor its commitment, HEP has unused capacity available under its credit agreement, which was $60.0 million as of March 31, 2009, to meet its borrowing needs. Additionally, publicly available information on these lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the HEP Credit Agreement. HEP has not experienced, nor does it expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, HEP believes there would be alternative lenders or options available.

The $185.0 million principal amount outstanding of HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s 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 HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., HEP’s general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of the HEP Senior Notes.

See “—Risk Management” for a discussion of HEP’s interest rate swap contracts.

HEP closed on a public offering of 2,000,000 common units priced at $27.80 per common unit on May 8, 2009. In connection with the offering, HEP granted the underwriters a 30-day option to purchase up to 300,000 additional common units. On May 21, 2009, HEP sold an additional 192,400 common units at a price of $27.80 per common unit pursuant to the underwriters’ exercise of a portion of their over-allotment option. Proceeds from the offering were used to repay bank debt and for general partnership purposes. In addition, we made a capital contribution to HEP to maintain our 2% general partner interest.

We believe our current cash, cash equivalents and marketable securities, along with the net proceeds from the sale of the notes, future internally generated cash flow and funds available under our credit agreement provide sufficient resources to fund currently planned capital projects, including planned capital expenditures at our recently acquired Tulsa Refinery, and our liquidity needs for the foreseeable

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Management’s discussion and analysis of financial condition and results of operations

future. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

Cash flows—operating activities

Three months ended March 31, 2009 compared to three months ended March 31, 2008

Net cash flows used for operating activities were $2.3 million for the three months ended March 31, 2009 compared to net cash provided of $98.9 million for the three months ended March 31, 2008, a net change of $101.2 million. Net income for the first quarter of 2009 was $23.9 million, an increase of $14.4 million compared to net income of $9.5 million for the first quarter of 2008. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense, equity in earnings of SLC Pipeline and interest rate swap adjustments resulted in an increase to operating cash flows of $23.8 million for the three months ended March 31, 2009 compared to $11.9 million for the same period in 2008. Additionally, distributions in excess of equity in earnings of HEP increased 2008 operating cash flows by $3.1 million. Changes in working capital items decreased cash flows by $27.2 million for the three months ended March 31, 2009 compared to an increase of $75.8 million for the three months ended March 31, 2008. Additionally, for the three months ended March 31, 2009, turnaround expenditures increased to $27.0 million from $1.4 million in 2008 due to a planned major maintenance turnaround at our Navajo Refinery in the first quarter of 2009.

Year ended December 31, 2008 compared to year ended December 31, 2007

Net cash flows provided by operating activities were $155.5 million for the year ended December 31, 2008 compared to $422.7 million for the year ended December 31, 2007, a decrease of $267.2 million. Net income for 2008 was $127.6 million, a decrease of $206.5 million from $334.1 million for 2007. Additionally, the non-cash items of depreciation and amortization, deferred taxes, equity-based compensation, gain on the sale of HPI and non-cash interest resulting from changes in the fair value of two of HEP’s interest rate swaps resulted in an increase to operating cash flows of $104.2 million for the year ended December 31, 2008 compared to $76.5 million for the year ended December 31, 2007. Distributions in excess of equity in earnings of HEP decreased to $3.1 million for the year ended December 31, 2008 compared to $3.7 million for the year ended December 31, 2007. Working capital items decreased cash flows by $37.0 million in 2008 compared to an increase of $15.0 million in 2007. For the year ended December 31, 2008, inventories decreased by $15.0 million compared to an increase of $11.0 million for 2007. Also for 2008, accounts receivable decreased by $332.0 million compared to an increase of $216.3 million for 2007 and accounts payable decreased by $393.2 million compared to an increase of $264.2 million for 2007. Additionally, for 2008, turnaround expenditures were $34.8 million compared to $2.7 million for 2007.

Year ended December 31, 2007 compared to year ended December 31, 2006

Net cash flows provided by operating activities were $422.7 million for 2007 compared to $245.2 million for 2006, an increase of $177.5 million. Net income in 2007 was $334.1 million, an increase of $67.5 million from net income of $266.6 million for 2006. The non-cash items of depreciation and amortization, deferred taxes, equity-based compensation and gain on sale of assets resulted in an increase to operating cash flows of $76.5 million for the year ended December 31, 2007 compared to $31.4 million for the year ended December 31, 2006. Distributions in excess of equity in earnings of HEP decreased to $3.7 million for the year ended December 31, 2007 compared to

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Management’s discussion and analysis of financial condition and results of operations

$7.4 million for the year ended December 31, 2006. Working capital items increased cash flows by $15.0 million in 2007 compared to a decrease of $40.9 million in 2006. For the year ended December 31, 2007, inventories increased by $11.0 million compared to an increase of $33.8 million for the year ended December 31, 2006. Also for 2007, accounts receivable increased by $216.3 million compared to a decrease of $12.1 million for 2006, and accounts payable increased by $264.2 million compared to a decrease of $26.4 million for 2006. Additionally, for 2007, turnaround expenditures were $2.7 million compared to $11.6 million for 2006.

Cash flows—investing activities and planned capital expenditures

Three months ended March 31, 2009 compared to three months ended March 31, 2008

Net cash flows used for investing activities were $70.3 million for the three months ended March 31, 2009 compared to net cash flows provided by investing activities of $83.5 million for the three months ended March 31, 2008, a net change of $153.8 million. Cash expenditures for property, plant and equipment for the first three months of 2009 increased to $99.2 million from $72.8 million for the same period in 2008. These include HEP capital expenditures of $10.6 million and $3.3 million for the three months ended March 31, 2009 and 2008, respectively. During the three months ended March 31, 2009, HEP purchased a 25% joint venture interest in the SLC Pipeline for $25.5 million. Additionally we invested $128.7 million in marketable securities and received proceeds of $183.1 million from the sale or maturity of marketable securities. For the three months ended March 31, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP. Also, as a result of our reconsolidation of HEP effective March 1, 2008, our investing activities reflect HEP’s March 1, 2008 cash balance of $7.3 million as a cash inflow. Additionally for the three months ended March 31, 2008, we invested $207.6 million in marketable securities and received proceeds of $185.8 million from the sale or maturity of marketable securities.

Year ended December 31, 2008 compared to year ended December 31, 2007

Net cash flows used for investing activities were $57.8 million for 2008 compared to $293.1 million for 2007, a decrease of $235.3 million. Cash expenditures for property, plant and equipment for 2008 totaled $418.1 million compared to $161.3 million for 2007. Capital expenditures for the year ended December 31, 2008 include $34.3 million attributable to HEP. Also, in 2008 we invested $769.1 million in marketable securities and received proceeds of $945.5 million from the sales and maturities of marketable securities. Additionally for the year ended December 31, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008. We are also presenting HEP’s March 1, 2008 cash balance of $7.3 million as a cash inflow as a result of our reconsolidation of HEP effective March 1, 2008. For the year ended December 31, 2007, we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities.

Year ended December 31, 2007 compared to year ended December 31, 2006

Net cash flows used for investing activities were $293.1 million for 2007 compared to net cash flows provided by investing activities of $35.8 million for 2006, a decrease of $328.9 million. Cash expenditures for property, plant and equipment for 2007 totaled $161.3 million compared to $120.4 million for 2006. Also, in 2007 we invested $641.1 million in marketable securities and received proceeds of $509.3 million from sales and maturities of marketable securities. For the year ended December 31, 2006, we invested $212.0 million in marketable securities and received proceeds of $319.3 million from sales and maturities of marketable securities. Furthermore in 2006, we received cash proceeds of $48.9 million following the sale of our Montana Refinery on March 31, 2006.

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Planned capital expenditures

Holly Corporation

On June 1, 2009 we closed the acquisition of our 85,000 BPSD Tulsa Refinery from Sunoco. See “Our recent acquisition of the Tulsa Refinery.” We plan to construct a new diesel hydrotreater and to expand sulfur recovery capacity, which, once complete, will allow all diesel produced at the Tulsa Refinery to be produced as ULSD. Additionally, this project will allow the Tulsa Refinery to upgrade coker distillate and extracts to ULSD. This project is expected to be mechanically complete in mid-2011 with an expected cost of approximately $150.0 million. Separately, in connection with the modified consent decree that we have assumed with respect to the Tulsa Refinery, we will be required to make certain capital expenditures in order to satisfy obligations under the consent decree, including requirements for NOx reduction from the refinery’s heaters and boilers and requirements to reduce sulfur levels in the refinery’s fuel gas loop. We estimate that the capital expenditures required to address the consent decree requirements will be approximately $23.0 million to be expended through 2013. Additionally, we expect to incur approximately $10.0 million to $15.0 million annually in sustaining capital expenditures at the Tulsa Refinery that is also not included in our 2009 capital budget.

Each year our board of directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total capital budget for 2009 is $19.8 million, not including the capital projects approved in prior years, and our expansion and feedstock flexibility projects at the Navajo and Woods Cross Refineries, as described below, or the purchase of and capital projects for the Tulsa Refinery. That capital budget is comprised of $11.4 million for refining improvement projects for the Navajo Refinery, $5.3 million for projects at the Woods Cross Refinery, $0.4 million for marketing-related projects, $1.4 million for asphalt plant projects and $1.3 million for other miscellaneous projects.

At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units. As of March 31, 2009, phase I is mechanically complete. The total cost of phase I is now expected to be $187.4 million.

Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 at a cost of approximately $98.0 million.

We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt Company facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $21.0 million and are expected to be completed at the same time as the phase II project.

During the first quarter of 2009, the Navajo Refinery also installed a new 100 ton per day sulfur recovery unit at a cost of approximately $31.0 million.

The phase I Navajo projects discussed above and the addition of the sulfur recovery unit are currently in the process of start-up and will enable the Navajo Refinery to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of

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diesel, supply Holly Asphalt Company with all of its performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks, and enable the refinery to meet new LSG specifications required by the EPA.

At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, Black Wax desalting equipment and Black Wax unloading systems. The total cost of this project was approximately $122.0 million. The project was mechanically complete in the fourth quarter of 2008 and is in the start-up phase. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.

To fully take advantage of the economics on the Woods Cross Refinery expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains will permit the transportation of additional crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the “HEP” section of this discussion of planned capital expenditures.

In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD, with the capacity for further expansion to 120,000 BPD. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting HEP an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received in mid-2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective it would be better to delay completion until the fall of 2010.

In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion Pipeline L.P.’s pipeline from Cushing, Oklahoma to Slaughter, Texas. Our board of directors approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico, and a 65-mile pipeline running from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline that will connect HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. We sold the 65-mile Lovington to Artesia, New Mexico pipeline to HEP on June 1, 2009 for $34.2 million. Under the provisions of our omnibus agreement with HEP, HEP will have an option to purchase the remaining transportation assets described above upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009. We plan to grant HEP the option to purchase these transportation assets upon our completion of the project.

In 2009, we expect to spend approximately $275.0 million on currently approved capital projects, including sustaining capital and turnaround costs. This amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved

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capital projects. This amount does not include costs of our Tulsa Refinery acquisition including expected improvement costs.

In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act provided an immediate deduction of 75% of certain costs paid or incurred to comply with the ULSD standards, and a tax credit based on ULSD production of up to 25% of those costs. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act created tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the expansion assets are placed in service. We believe the capacity expansion projects at the Navajo and Woods Cross Refineries will qualify for this deduction.

The above mentioned regulatory compliance items, including the ULSD and LSG requirements, or other presently existing or future environmental regulations could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.

HEP

Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in their current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2009 HEP capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of HEP’s pipeline between Artesia, New Mexico and El Paso, Texas (the “South System”) and the joint venture with Plains discussed below.

In October 2007, we amended our 15 year pipelines and terminals agreement with HEP (the “HEP PTA”) under which HEP has agreed to expand the South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’s El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Construction of the South System pipe replacement and storage tankage is substantially complete. The improvements to Kinder Morgan’s El Paso pump station are expected to be completed by July 2009.

In March 2009, HEP acquired a 25% joint venture interest in the new 95-mile intrastate SLC Pipeline jointly owned by Plains All American Pipeline, L.P. (“Plains”) and HEP. The SLC Pipeline allows various refiners in the Salt Lake City area, including our Woods Cross Refinery, to ship up to 120,000 BPD of 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 HEP’s investment in the SLC Pipeline was $25.5 million.

In June 2009, HEP acquired from us a newly constructed 65-mile Lovington to Artesia, New Mexico pipeline. The purchase price was $34.2 million.

HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to its intermediate pipelines enabling it to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid-2009 at an estimated cost of $6.4 million.

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Cash flows—financing activities

Three months ended March 31, 2009 compared to three months ended March 31, 2008

Net cash flows provided by financing activities were $85.7 million for the three months ended March 31, 2009 compared to net cash used for financing activities of $96.1 million for the three months ended March 31, 2008, a net change of $181.8 million. During the three months ended March 31, 2009, we received advances under our then existing credit agreement of $55.0 million, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $7.5 million in dividends, received a $4.8 million contribution from our UNEV Pipeline joint venture partner and recognized $2.2 million in excess tax benefits on our equity based compensation. Also during this period, HEP received net advances of $40.0 million under the HEP Credit Agreement, paid distributions of $6.9 million to noncontrolling interest holders and purchased $0.6 million in HEP common units in the open market for recipients of its 2009 restricted unit grants. For the three months ended March 31, 2008, we purchased $102.9 million in treasury stock, paid $6.4 million in dividends, received $0.3 million for common stock issued upon the exercise of stock options, recognized $3.2 million in excess tax benefits on our equity based compensation and incurred $0.4 million in deferred financing costs. For this same period, HEP received advances of $10.0 million under the HEP Credit Agreement.

Year ended December 31, 2008 compared to year ended December 31, 2007

Net cash flows used for financing activities were $151.3 million for 2008 compared to $189.4 million for 2007, a decrease of $38.1 million. For the period from March 1, 2008 through December 31, 2008, HEP had net short-term borrowings of $29.0 million under the HEP Credit Agreement and purchased $0.8 million in HEP common units in the open market for restricted unit grants. Additionally in 2008, we paid an aggregate of $0.9 million in deferred financing costs related to our credit agreement and the HEP Credit Agreement. Under our common stock repurchase program, we purchased treasury stock of $151.1 million in 2008. We also paid $29.1 million in dividends, received a $17.0 million contribution from our UNEV Pipeline joint venture partner, received $1.0 million for common stock issued upon the exercise of stock options and recognized $5.7 million in excess tax benefits on our equity based compensation during 2008. Also during this period, HEP paid $22.1 million in distributions to noncontrolling interest holders. During 2007, we purchased treasury stock of $207.2 million under our stock repurchase program, paid $23.2 million in dividends, received $2.3 million for common stock issued upon the exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.

Year ended December 31, 2007 compared to year ended December 31, 2006

Net cash flows used for financing activities were $189.4 million for 2007 compared to $175.9 million for 2006, an increase of $13.5 million. Under our common stock repurchase program, we purchased treasury stock of $207.2 million in 2007. We also paid $23.2 million in dividends, received $2.3 million for common stock issued upon the exercise of stock options and recognized $30.4 million in excess tax benefits on our equity based compensation during 2007. During 2006, we purchased treasury stock of $175.4 million under our stock repurchase program, paid $15.0 million in dividends, received $2.6 million for common stock issued upon the exercise of stock options and recognized $11.8 million in excess tax benefits on our equity based compensation. During 2007, we also received an $8.3 million contribution from our UNEV Pipeline joint venture partner.

Contractual obligations and commitments

The following table presents our long-term contractual obligations as of December 31, 2008 in total and by period due beginning in 2009. Effective March 1, 2008, we reconsolidated HEP. As a result, the table below

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does not include our contractual obligations to HEP under our three long-term transportation agreements with HEP. A description of these agreements is provided under “Business—Holly Energy Partners, L.P.” Also, the table below does not reflect renewal options on our operating leases that are likely to be exercised.

			Payments due by period
			Less than						Over 5
Contractual obligations(1)(2)	Total		1 year		1-3 years		3-5 years		years
	(in thousands)
Holly Corporation
Operating leases	$	6,062	$	2,461	$	3,327	$	190	$	84
Hydrogen supply agreement(3)		91,570		6,315		12,630		12,630		59,995
Other service agreements(4)		13,953		2,371		3,970		3,857		3,755
		111,585		11,147		19,927		16,677		63,834
Holly Energy Partners
Long-term debt—principal(5)		356,000		—		171,000		—		185,000
Long-term debt—interest(6)		85,240		15,344		29,427		23,125		17,344
Pipeline operating and right of way leases		54,473		6,364		12,709		12,645		22,755
Other agreements		23,049		5,221		5,178		4,600		8,050
		518,762		26,929		218,314		40,370		233,149
Total	$	630,347	$	38,076	$	238,241	$	57,047	$	296,983

(1)	Amounts shown do not include obligations under crude oil transportation agreements providing that we will ship quantities of crude oil with each agreement having initial terms of 10 years. Our obligations under these agreements are subject to certain conditions including completion of construction and expansion projects by the transportation companies. Our shipping commitments shall begin upon completion of these projects which we expect to begin in the fourth quarter of 2009 with the remaining commitments to be phased in through the first quarter of 2011. In addition, amounts shown do not include our 10-year commitment to ship on the UNEV Pipeline, in which we own a 75% interest, an annual average of 15,000 barrels per day of refined products at an agreed tariff. Our commitment to ship on the UNEV Pipeline will begin with the completion of the pipeline.
(2)	We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits of $4.4 million as of December 31, 2008, have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 12 to the Consolidated Financial Statements included elsewhere in this offering memorandum.
(3)	We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross Refinery hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a fifteen year period commencing July 1, 2008. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term. We have estimated the future payments in the table above using current market rates. Therefore, actual amounts expended for this obligation in the future could vary significantly from the amounts presented above.
(4)	Other services agreements include $13.4 million for transportation of natural gas and feedstocks to our refineries under contracts expiring in 2015 and 2016; and various service contracts with expiration dates through 2011.

(footnotes continued on following page)

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	(5) HEP’s long-term debt consists of the $185.0 million principal balance on the HEP Senior Notes and $171.0 million of outstanding principal under the HEP Credit Agreement all of which has been classified as long-term debt.
(6)	Interest payments consist of interest on HEP’s 6.25% Senior Notes and interest on long-term debt under the HEP Credit Agreement. Interest on the long term debt under the HEP Credit Agreement is based on the effective interest rate of 2.21% at December 31, 2008.

During the three months ended March 31, 2009, we received advances of $55.0 million under our then existing credit agreement that were classified as short term borrowings.

On June 1, 2009 we acquired our 85,000 BPSD Tulsa Refinery from Sunoco for $65.0 million. Under the terms of the purchase agreement, we agreed to purchase related inventory from Sunoco. The inventory was valued at market prices at closing and we expect to pay between $90 and $100 million for the inventory by July 1, 2009. See “Our recent acquisition of the Tulsa Refinery.”

There were no other significant changes to our contractual obligations and commitments during the three months ended March 31, 2009.

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. For additional information, see Note 1 to the Consolidated Financial Statements “Description of Business and Summary of Significant Accounting Policies” included elsewhere in this offering memorandum.

Inventory valuation

Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology, and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. Historically, our LIFO inventory layers have been valued at historical costs that were established in years when price levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.

Deferred maintenance costs

Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so

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that some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges and amortize the deferred costs over the expected periods of benefit.

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 values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the three months ended March 31, 2009 and the years ended December 31, 2008, 2007 and 2006.

Variable interest entity

HEP is a variable interest entity as defined under Financial Accounting Standards Board Interpretation No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

Contingencies

We are 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 matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.

New accounting pronouncements

Statement of Financial Accounting Standard (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of Accounting Research Bulletin No. 51”

In December 2007, the FASB issued SFAS No. 160, which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. We adopted this standard effective January 1, 2009. As a result, all previous references to “minority interest” in our historical financial statements have been replaced with “noncontrolling interest.” Additionally, net income attributable to the noncontrolling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interests in earnings of Holly Energy Partners,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly Corporation stockholders.

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SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133.”

In March 2008, the FASB issued SFAS No. 161, which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. We adopted this standard effective as of January 1, 2009. See “—Risk Management” below for disclosure of HEP’s derivative instruments and hedging activity.

RISK MANAGEMENT

We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit.

HEP uses interest rate derivatives to manage its exposure to interest rate risk. As of March 31, 2009, HEP had three interest rate swap contracts.

HEP has an interest rate swap that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million advance on the HEP Credit Agreement that HEP used to finance its purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0 million London Interbank Offered Rate (“LIBOR”) based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin of 1.75% as of March 31, 2009, which equaled an effective interest rate of 5.49%. The maturity date of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

HEP designated this interest rate swap as a cash flow hedge. Based on its assessment of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171.0 million variable rate debt resulting from changes in the LIBOR. Under hedge accounting, HEP adjusts its cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive income. Also on a quarterly basis, HEP measures 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 the swap against the expected future interest payments on the $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of March 31, 2009, HEP had no ineffectiveness on its cash flow hedge.

HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 2.42% as of March 31, 2009. The maturity date of this swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.

In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of its hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

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Management’s discussion and analysis of financial condition and results of operations

Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three months ended March 31, 2009, HEP recognized $0.2 million in interest expense attributable to fair value adjustments to its interest rate swaps.

HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.

The interest rate swaps are valued using level 2 inputs. Additional information on HEP’s interest rate swaps at March 31, 2009 is as follows:

	Balance sheet				Location of	Offsetting
Interest rate swaps	location	Fair value			offsetting balance	amount
	(in thousands)
Asset
Fixed-to-variable interest	Other assets	$	3,762		Long-term debt—HEP	$	(2,051	)
rate swap—$60 million of					Equity		(1,942	)(1)
6.25% Senior Notes					Interest expense		231	(2)
		$	3,762			$	(3,762	)
Liability
Cash flow hedge—	Other long-term				Accumulated other
$171 million LIBOR based debt	liabilities	$	(13,117	)	comprehensive loss	$	13,117
Variable-to-fixed interest	Other long-term				Equity		4,166	(1)
rate swap—$60 million	liabilities		(4,064	)	Interest Expense		(102	)
		$	(17,181	)		$	17,181

(1)	Represents prior year charges to interest expense.
(2)	Net of amortization of premium attributable to de-designated hedge.

We have reviewed publicly available information on our counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their respective commitments.

We invest a substantial portion of available cash in investment grade, highly liquid investments with maturities of three months or less, and, hence, the interest rate market risk implicit in these cash investments is low. We also invest the remainder of available cash in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including any cash equivalents invested) of not greater than one year, and, hence, the interest rate market risk implicit in these investments is also low. A hypothetical 10% change in the market interest rate over the next year would not materially impact our earnings, cash flow or financial condition since any borrowings under the credit facilities and our investments are at market rates and interest on borrowings and cash investments has historically not been significant as compared to our total operations.

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Management’s discussion and analysis of financial condition and results of operations

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 oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.

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EX-99.5

Exhibit 99.5

Business

COMPANY OVERVIEW

We are an independent petroleum refiner engaged in the production of high value light petroleum products, such as gasoline, diesel fuel and jet fuel, and high value specialty lubricants. We currently own and operate three refineries having an aggregate annual crude capacity of 216,000 BPSD. Our operations are principally located in the Southwest, Rocky Mountain and Mid-Continent regions of the United States which we believe are attractive refined products markets that possess favorable demographic trends and limited refining capacity.

Our three refineries are:

Ø	A refinery in Artesia, New Mexico, which is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively known as the “Navajo Refinery”). This refinery has crude capacity of 100,000 BPSD, can process up to approximately 100% sour crude oil and serves markets in the southwestern United States and northern Mexico;
Ø	A refinery in Woods Cross, Utah. This refinery, located just north of Salt Lake City, Utah, has a crude capacity of 31,000 BPSD. The Woods Cross Refinery is a high conversion refinery that processes regional sweet and Canadian sour crude oils and serves markets in Utah, Idaho, Nevada, Wyoming and eastern Washington; and
Ø	A refinery in Tulsa, Oklahoma recently acquired from Sunoco. The Tulsa Refinery has a crude capacity of 85,000 BPSD. This refinery processes sweet crudes and yields high-value lubricant products, distillate products (such as off-road diesel and jet fuel) and gasoline and serves fuel markets in the Mid-Continent region and lubricant markets primarily in North and South America. The world’s largest oil futures trading point, Cushing, Oklahoma, is within 50 miles of the Tulsa Refinery. See “Our recent acquisition of the Tulsa Refinery.”

We also own an approximate 41% interest in Holly Energy Partners, L.P. (which includes our 2% general partnership interest), which has logistics assets including approximately 2,600 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico, ten refined product terminals, a jet fuel terminal, two refinery truck rack facilities, a refined products tank farm facility, on-site tankage at both the Navajo and Woods Cross Refineries, a 70% interest in the Rio Grande Pipeline Company and a 25% interest in the joint venture that owns and operates the 95-mile Salt Lake City Pipeline, a crude oil pipeline. HEP and its subsidiaries are not guarantors of the notes offered hereby.

We also own and operate Holly Asphalt Company, which manufactures and markets asphalt products from various terminals in Arizona and New Mexico.

Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery, Holly Asphalt Company and, beginning June 1, 2009, our Tulsa Refinery. The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation).

INDUSTRY OVERVIEW

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel and lubricants. Refining is primarily a margin-based business where both the feedstocks (petroleum products such as crude oil) and the refined finished products are commodities with fluctuating prices. In

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order to increase profitability, it is important for a refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses.

Factors affecting refining profitability

Crack spreads

A variety of so called “crack spread” indicators are used to track the profitability of the refining industry. Among the most commonly referenced are the gasoline crack spread and the heat crack spread, as traded on the New York Mercantile Exchange, or NYMEX. The NYMEX gasoline crack spread is the simple difference in per barrel value between reformulated gasoline in New York Harbor and the NYMEX prompt price of West Texas Intermediate, or WTI, crude oil on any given day. This provides a measure of the profitability when producing gasoline. The NYMEX heat crack spread is a similar measure of the price of Number 2 heating oil in New York Harbor, relative to the value of WTI crude which provides a measure of the profitability of producing distillates. A refinery’s profitability generally increases when crack spreads are higher, as its finished products are more expensive relative to its inputs. Conversely, a refinery’s profitability generally decreases when crack spreads are lower, as its finished products are less expensive relative to its inputs. The profitability of a particular refinery depends on the margins between its actual cost of feedstock inputs and actual prices received for its finished products and on its operating expenses.

Feedstock differentials

In addition to crack spread fluctuations, a refinery’s profitability is affected by differentials in the pricing of various feedstocks. Specifically, the pricing differential between various grades of crude oil greatly influences the economics of refining. Generally, light sweet crude oil trades at a premium to heavy sour crude oil. This is because light sweet crude oil generally yields a higher percentage of high value refined products such as gasoline and diesel, whereas heavy sour crude oil generally yields a higher percentage of lower value refined products such as heavy fuel oil and residual petroleum products. A refiner will generally purchase the cheapest feedstock with which it can produce the largest volume of high value refined products. This is especially true when differentials increase and the cost savings from processing heavy sour crude is maximized.

Complexity

The complexity of a refinery refers to the number, type and capacity of processing units at the refinery and is measured by its Nelson index rating. The complexity rating is often used as a measure of a refinery’s ability to convert lower cost, heavier and sour crudes into greater volumes of higher valued refined products such as gasoline and diesel. Highly complex refineries can more easily capitalize on the feedstock differentials described above by purchasing heavy sour crudes when differentials increase. Less complex refineries which cannot process heavy sour crudes are forced to process the more expensive light sweet crudes and operate at lower levels of profitability.

Location

One of the most important factors affecting profitability is a refinery’s location. Consistent with the overall markets for crack spreads and differentials described above, margins and differentials can vary from location to location. Cracks spreads are generally higher in areas with limited refining capacity and/or strong demand for refined products. In the United States, the Southwestern and Rocky Mountain markets are characterized as having limited refining capacity, as well as above average demand growth. Over the past five years, these areas have generally experienced higher margins for refined products.

In addition, location affects the crude supply which is available to a refinery. Access to less expensive, heavy sour crudes allows a refinery to capitalize on the feedstock differentials described above. In the

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United States, coastal refineries and refineries in the Rocky Mountain and Southwestern regions often have the greatest access to heavy sour crudes, such as West Texas Sour, Black Wax and Western Canadian crude oils.

COMPETITIVE STRENGTHS

We believe that the following are our primary competitive strengths:

Ø	Strong Competitive Position in Diverse Attractive Markets.  Our assets and markets have historically been principally located in the Southwest and Rocky Mountain regions of the United States, and we are now entering the Mid-Continent market and the market for high value lubricant products with our recent acquisition of the Tulsa Refinery. We believe these areas are attractive refined product markets due to a wide variety of available crude feedstocks, favorable demographic trends and limited refining capacity. We believe that high demand due to population growth and infrastructure constraints has historically contributed to higher margins in our core markets.
Ø	High Degree of Crude Source Flexibility.  We have and are continuing to invest in capital projects aimed at increasing feedstock flexibility. All of our refineries either have or will soon have a wide variety of crude types available to them. Our refineries are located in areas where they have access to both domestic and imported crude, as well as crudes of various qualities. Our Navajo and Woods Cross Refineries have access to and can process lower cost crude oils, including Black Wax and heavy sour crude, which are typically lower cost than comparable light sweet crude. This wide range of potential crude oil supplies allows our refineries to avoid being dependent on any single source or type of crude oil, and to capitalize on pricing differentials between various grades of crude as opportunities present themselves. We believe this gives us a significant advantage over our less complex competitors, especially in low margin environments when crude price differentials are the primary driver of profitability.
Ø	High Quality, Complex Refining Asset Base.  The complexity of a refinery refers to the number, type and capacity of processing units at the refinery and is measured by its Nelson index rating. Each of our refineries has a Nelson index rating greater than 10. We believe that our weighted average Nelson index rating is higher than the weighted average rating of most refiners located in our regions. As with most complex refineries, we have the ability to process lower cost, heavy crude oil into higher value light products such as gasoline and diesel fuel.
Ø	Conservative Balance Sheet and Strong Financial Position.  We believe our low debt levels, strong cash flow profile and access to capital provide ample liquidity and allow us to pursue expansion and acquisition opportunities that may arise.
Ø	Our Relationship with HEP Provides Stable Cash Flows.  As of June 1, 2009, we own an approximate 41% interest in HEP, including our 2% general partner interest. The quarterly distributions received from HEP provide us with a steady source of cash flow that strengthens our financial position. For the year ended December 31, 2008, we received $25.6 million in distributions from HEP. For the quarter ended March 31, 2009, we received $6.9 million in distributions from HEP.
Ø	Significant Growth Opportunities.  We are currently undertaking several accretive growth initiatives, such as the construction of the UNEV Pipeline and feedstock flexibility projects. We expect these expansion programs to increase earnings and cash flow by allowing us to enter new markets and to process increased volumes of heavier crude. In addition, on June 1, 2009 we closed our acquisition of the Tulsa Refinery, which has an annual average crude capacity of 85,000 BPSD.
Ø	Experienced Management Team.  Our management team has a proven track record of safely operating and managing a profitable refining business through multiple economic cycles. In addition, the team has successfully executed several key acquisitions and integration efforts.

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BUSINESS STRATEGIES

Our business strategy includes the following major objectives:

Ø	Continue Focus on Safety, Reliability and Operational Excellence.  We devote significant resources to safety, reliability and environmental compliance, which we believe promotes a culture of diligence and minimizes risk.
Ø	Capitalize on Crude Supply Flexibility to Capture Higher Margins.  We have invested, and will continue to invest, in our feedstock flexibility. Our ability to source the lowest cost crude oil is a primary driver invest of profitability and a key to our competitive position. In order to increase our ability to process low cost, heavy sour crude oils, we recently added new hydrocrackers and sulfur recovery facilities at our Navajo and Wood Cross Refineries.
Ø	Maintain a Disciplined Approach to Capital Investment and Growth.  Our strategy is to undertake expansion projects that are immediately accretive and generate cash flow. All potential projects are carefully evaluated based on their potential to increase earnings, as well as their ability to improve our competitive position.
Ø	Maintain Conservative Capital Structure.  Our strong cash flow from operations and stable distributions from HEP have historically allowed us to operate with limited debt, even in low margin environments. We intend to preserve our conservative balance sheet and liquidity by controlling costs and making focused capital investments.
Ø	Selectively Pursue Favorable Acquisition Opportunities.  Like the acquisition of the Tulsa Refinery, we intend to pursue potential acquisitions of additional refining and refining related assets that will strengthen our competitive and financial position.

REFINERY/ASSET DESCRIPTIONS AND HISTORIES

As of March 31, 2009, our refinery operations include the Navajo Refinery and the Woods Cross Refinery. Our Tulsa Refinery was acquired on June 1, 2009 and is not included in the discussion below. For more information on our Tulsa Refinery, see “Our recent acquisition of the Tulsa Refinery.” The following table sets forth information, including performance measures about our refinery operations that are not calculations based upon United States GAAP. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.” Information regarding our Navajo and Woods Cross Refineries is provided later in this section of “—Refinery/Asset Descriptions and Histories.”

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										Three months ended
	Year ended December 31,									March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Consolidated(1)
Crude charge (BPD)(2)		100,680			103,490			96,570			80,994			108,160
Refinery production (BPD)(3)		110,850			113,270			105,730			86,347			120,080
Sales of produced refined products (BPD)		111,950			115,050			105,090			89,171			119,350
Sales of refined products (BPD)(4)		120,750			126,800			119,870			98,802			132,940
Refinery utilization(5)		89.7	%		94.1	%		92.4	%		69.8	%		97.4	%
Average per produced barrel(6)
Net sales	$	108.83		$	89.77		$	80.21		$	55.23		$	103.20
Cost of products(7)		97.87			73.03			64.43			43.30			95.48
Refinery gross margin		10.96			16.74			15.78			11.93			7.72
Refinery operating expenses(8)		5.14			4.43			4.83			6.40			4.78
Net operating margin	$	5.82		$	12.31		$	10.95		$	5.53		$	2.94
Feedstocks:
Sour crude oil		63	%		62	%		61	%		64	%		63	%
Sweet crude oil		23	%		23	%		25	%		24	%		23	%
Black Wax crude oil		4	%		3	%		3	%		8	%		4	%
Other feedstocks and blends		10	%		12	%		11	%		4	%		10	%
Total		100	%		100	%		100	%		100	%		100	%

(1)	The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.
(2)	Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
(3)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
(4)	Includes refined products purchased for resale.
(5)	Represents crude charge divided by total crude capacity measured in BPSD. Our consolidated crude capacity was increased from 101,000 BPSD to 109,000 BPSD during 2006, from 109,000 BPSD to 111,000 BPSD in mid-year 2007 and by an additional 5,000 BPSD in the fourth quarter of 2008, increasing our consolidated crude capacity to 116,000 BPSD. During the first quarter of 2009, we completed a 15,000 BPSD expansion at our Navajo Refinery, increasing our consolidated crude capacity to 131,000 BPSD effective April 1, 2009.
(6)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”
(7)	Transportation costs billed from HEP are included in cost of products.
(8)	Represents operating expenses of our refineries, exclusive of depreciation and amortization.

Set forth below is information regarding our principal products.

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	Year ended December 31,									Three months ended March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Consolidated(1)
Sales of produced refined products:
Gasolines		58	%		60	%		61	%		63	%		60	%
Diesel fuels		32	%		29	%		28	%		29	%		30	%
Jet fuels		1	%		2	%		3	%		1	%		1	%
Fuel oil		3	%		4	%		3	%		2	%		3	%
Asphalt		3	%		2	%		2	%		2	%		3	%
LPG and other		3	%		3	%		3	%		3	%		3	%
Total		100	%		100	%		100	%		100	%		100	%

(1) The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.

We have several significant customers, none of which accounts for more than 10% of our business. Our principal customers for gasoline include other refiners, convenience store chains, independent marketers, and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for military and domestic airline use. Asphalt is sold to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing or blended into fuel oil.

Navajo Refinery

Facilities

The Navajo Refinery has a current crude oil capacity of 100,000 BPSD and has the ability to process sour crude oils into high value light products such as gasoline, diesel fuel and jet fuel. The refinery has a Nelson Complexity Index rating of 11.8. The Navajo Refinery has historically converted approximately 91% of its raw materials throughput into high value light products. For 2008, gasoline, diesel fuel and jet fuel (excluding volumes purchased for resale) represented 57%, 33% and 1%, respectively, of the Navajo Refinery’s sales volumes.

The following table sets forth information about the Navajo Refinery operations, including non-GAAP performance measures. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”

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	Year ended December 31,									Three months ended March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Navajo Refinery
Crude charge (BPD)(1)		79,020			79,460			72,930			57,685			83,200
Refinery production (BPD)(2)		88,680			87,930			80,540			63,061			94,640
Sales of produced refined products (BPD)		89,580			88,920			79,940			62,147			94,050
Sales of refined products (BPD)(3)		97,320			100,460			93,660			71,138			105,410
Refinery utilization(4)		93.0	%		94.6	%		92.9	%		67.9	%		97.9	%
Average per produced barrel(5)
Net sales	$	108.52		$	89.68		$	79.62		$	57.37		$	103.26
Cost of products(6)		98.97			74.10			64.25			44.92			96.83
Refinery gross margin		9.55			15.58			15.37			12.45			6.43
Refinery operating expenses(7)		4.58			4.30			4.74			6.17			4.39
Net operating margin	$	4.97		$	11.28		$	10.63		$	6.28		$	2.04
Feedstocks:
Sour crude oil		79	%		82	%		80	%		87	%		80	%
Sweet crude oil		10	%		9	%		8	%		8	%		8	%
Other feedstocks and blends		11	%		9	%		12	%		5	%		12	%
Total		100	%		100	%		100	%		100	%		100	%

(1)	Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
(2)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
(3)	Includes refined products purchased for resale.
(4)	Represents crude charge divided by total crude capacity measured in BPSD. The crude capacity was increased from 75,000 BPSD to 83,000 BPSD during 2006 and by an additional 2,000 BPSD in mid-year 2007, increasing crude capacity to 85,000 BPSD. During the first quarter of 2009, we completed a 15,000 BPSD refinery expansion, increasing crude capacity to 100,000 BPSD effective April 1, 2009.
(5)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”
(6)	Transportation costs billed from HEP are included in cost of products.
(7)	Represents operating expenses of the refinery, exclusive of depreciation and amortization.

The Navajo Refinery’s Artesia, New Mexico facility is located on a 561 acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 2.0 million barrels of feedstock and product tankage at the site (of which 0.2 million is owned by HEP), and maintenance shops, warehouses and office buildings. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia,

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and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. The Artesia facility is operated in conjunction with an integrated refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. The facility also has an additional 1.1 million barrels of feedstock and product tankage (of which 0.2 million is owned by HEP). The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo facilities is 100,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.

We distribute refined products from the Navajo Refinery to markets in Arizona, New Mexico, west Texas and northern Mexico primarily through two of HEP’s owned pipelines that extend from Artesia, New Mexico to El Paso, Texas. In addition, we use pipelines owned and leased by HEP to transport petroleum products to markets in central and northwest New Mexico. We have refined product storage through our pipelines and terminals agreement with HEP at terminals in El Paso, Texas; Tucson, Arizona; and Artesia, Moriarty and Bloomfield, New Mexico.

We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Texas and northern Mexico through Holly Asphalt Company. We have three manufacturing facilities located in Glendale, Arizona, Albuquerque, New Mexico and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our Navajo Refinery and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our Navajo and Woods Cross Refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.

Markets and competition

The Navajo Refinery primarily serves the growing southwestern United States market, including El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and the northern Mexico market. Our products are shipped through HEP’s pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains All American Pipeline, L.P. (Plains) and from El Paso to Tucson and Phoenix via a products pipeline system owned by Kinder Morgan’s SFPP, L.P. (SFPP). In addition, the Navajo Refinery transports petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, via HEP’s pipelines running from Artesia to San Juan County, New Mexico.

El Paso market

The El Paso market for refined products is currently supplied by a number of area refiners, Gulf Coast refiners and pipelines. Area refiners include Navajo, WRB Refining, LLC (WRB) (a joint venture between ConocoPhillips and EnCana Corp.), Valero, Alon, and Western Refining. Pipelines serving this market include Longhorn, Magellan, NuStar and HEP pipelines. Refined products from the Gulf Coast are transported via the Longhorn and Magellan pipelines. We currently supply approximately 11,000 BPD to the El Paso market, which accounts for approximately 18% of the refined products consumed in that market.

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Arizona market

The Arizona market for refined products is currently supplied by a number of refiners via pipelines and trucks. Refiners include companies located in west Texas, New Mexico, the Gulf Coast and West Coast. We currently supply approximately 54,000 BPD of refined products via the SFPP Pipeline into the Arizona market, comprised primarily of Phoenix and Tucson, which accounts for approximately 17% of the refined products consumed in that market.

New Mexico markets

The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners include Navajo, Valero, Western, Alon and WRB. We currently supply approximately 22,000 BPD of refined products to the New Mexico market, which accounts for approximately 20% of the refined products consumed in that market.

The common carrier pipeline we use to serve the Albuquerque market out of El Paso currently operates at near capacity. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the Leased Pipeline as well as terminalling facilities in Bloomfield, New Mexico, which is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit us to provide a total of up to 45,000 BPD of light products to the growing Albuquerque and Santa Fe, New Mexico areas. If needed, additional pump stations could further increase the pipeline’s capabilities.

The Longhorn Pipeline is a 72,000 BPD common carrier pipeline that has the ability to deliver 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. In 2008, Longhorn Partners Pipeline, L.P., owner of the pipeline, filed for bankruptcy and has put the pipeline up for sale. Flying J, the pipeline’s major shipper also filed for bankruptcy in 2008. The status of current shipping levels is presently unknown.

An additional factor that could affect some of our markets is the presence of pipeline capacity from El Paso and the West Coast into our Arizona markets. Additional increases in shipments of refined products from El Paso and the West Coast into our Arizona markets could result in additional downward pressure on refined product prices in these markets.

Crude oil and feedstock supplies

The Navajo Refinery is situated near the Permian Basin in an area that historically has had abundant supplies of crude oil available both for regional users, such as us, and for export to other areas. We purchase crude oil from producers in nearby southeastern New Mexico and west Texas and from major oil companies. Crude oil is gathered both through HEP’s pipelines and our tank trucks and through third-party crude oil pipeline systems. Crude oil acquired in locations distant from the refinery is exchanged for crude oil that is transportable to the refinery.

We also purchase isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery. In 2008, approximately 5,000 BPD of isobutane and 4,900 BPD of natural gasoline used in the Navajo Refinery’s operations were purchased from a newly operational fractionation facility in Hobbs, New Mexico, which is owned by Enterprise Products, L.P., as well as volumes purchased from the mid-continent area and delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP’s two parallel 65-mile pipelines running from Lovington to Artesia. From time to time, we also purchase gas oil, naphtha and light cycle oil from other oil companies for use as feedstock.

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Principal products and customers

Set forth below is information regarding the principal products produced at the Navajo Refinery:

	Year ended									Three months
	December 31,									ended March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Navajo Refinery
Sales of produced refined products:
Gasolines		57	%		59	%		60	%		61	%		58	%
Diesel fuels		33	%		30	%		28	%		31	%		32	%
Jet fuels		1	%		3	%		4	%		1	%		1	%
Fuel oil		3	%		3	%		2	%		1	%		3	%
Asphalt		3	%		2	%		3	%		3	%		3	%
LPG and other		3	%		3	%		3	%		3	%		3	%
Total		100	%		100	%		100	%		100	%		100	%

Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.

Our gasoline produced at the Navajo Refinery is marketed in the southwestern United States, including the metropolitan areas of El Paso, Phoenix, Albuquerque, Bloomfield, and Tucson, and in portions of northern Mexico. Diesel fuel is sold to other refiners, truck stop chains, wholesalers, and railroads. Historically, jet fuel has been sold primarily for military use. All asphalt produced at the Navajo Refinery and third-party purchased asphalt is marketed through Holly Asphalt Company to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers and carbon black oil is sold for further processing.

Capital improvement projects

We have invested significant amounts in capital expenditures in recent years to expand and enhance the Navajo Refinery and expand our supply and distribution network.

Our board of directors approved a capital budget for 2009 of $11.4 million for refining improvement projects at the Navajo Refinery, not including the capital projects approved in prior years or our expansion and feedstock flexibility projects described below.

At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant, and the expansion of our Lovington crude and vacuum units. Phase I is mechanically complete. The total cost of phase I is expected to be approximately $187.4 million.

Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 at a cost of approximately $98.0 million.

We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt Company facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $21.0 million and are expected to be completed at the same time as the phase II project.

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During the first quarter of 2009, the Navajo Refinery also installed a new 100 ton per day sulfur recovery unit at a cost of approximately $31.0 million.

The Navajo phase I projects and the addition of the sulfur recovery unit discussed above are currently in the process of start-up and will enable the Navajo Refinery to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt Company with all their performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks and enable the refinery to meet new LSG specifications required by the EPA.

In July 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion’s pipeline from Cushing, Oklahoma to its Slaughter Station located in west Texas. Our board of directors approved capital expenditures of up to $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico and a 65-mile pipeline running from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline that will connect HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. On June 1, 2009, we sold the 65-mile pipeline from Lovington to Artesia, New Mexico to HEP for $34.2 million. Under the provisions of our omnibus agreement with HEP, HEP will have an option to purchase the remaining transportation assets described above upon our completion of these projects.

Woods Cross Refinery

Facilities

The Woods Cross Refinery has a crude oil capacity of 31,000 BPSD and is operated by Holly Refining & Marketing Company—Woods Cross, one of our wholly owned subsidiaries. The Woods Cross Refinery is located in Woods Cross, Utah and processes regional sweet and Black Wax crude as well as Canadian sour crude oils into high value light products. The refinery has a Nelson Complexity Index rating of 12.5. For 2008, gasoline and diesel fuel (excluding volumes purchased for resale) represented 63% and 29%, respectively, of the Woods Cross Refinery’s sales volumes.

The following table sets forth information about the Woods Cross Refinery operations, including non-GAAP performance measures about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”

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	Year ended December 31,									Three months ended March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Woods Cross Refinery
Crude charge (BPD)(1)		21,660			24,030			23,640			23,309			24,960
Refinery production (BPD)(2)		22,170			25,340			25,190			23,286			25,440
Sales of produced refined products (BPD)		22,370			26,130			25,150			27,024			25,300
Sales of refined products (BPD)(3)		23,430			26,340			26,210			27,664			27,530
Refinery utilization(4)		79.5	%		92.4	%		90.9	%		75.2	%		96.0	%
Average per produced barrel(5)
Net sales	$	110.07		$	90.09		$	82.09		$	50.31		$	102.96
Cost of products(6)		93.47			69.40			64.99			39.57			90.42
Refinery gross margin		16.60			20.69			17.10			10.74			12.54
Refinery operating expenses(7)		7.42			4.86			5.13			6.92			6.26
Net operating margin	$	9.18		$	15.83		$	11.97		$	3.82		$	6.28
Feedstocks:
Sour crude oil		1	%		2	%		2	%		3	%		3	%
Sweet crude oil		72	%		75	%		79	%		66	%		76	%
Black Wax crude oil		21	%		15	%		10	%		29	%		16	%
Other feedstocks and blends		6	%		8	%		9	%		2	%		5	%
Total		100	%		100	%		100	%		100	%		100	%

(1)	Crude charge represents the barrels per day of crude oil processed at the crude units at our refinery.
(2)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
(3)	Includes refined products purchased for resale.
(4)	Represents crude charge divided by total crude capacity measured in BPSD. The crude capacity was increased by 5,000 BPSD in the fourth quarter of 2008, increasing crude capacity to 31,000 BPSD.
(5)	Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Annex A—Reconciliations to amounts reported under generally accepted accounting principles.”
(6)	Transportation costs billed from HEP are included in cost of products.
(7)	Represents operating expenses of the refinery, exclusive of depreciation and amortization.

The Woods Cross Refinery facility is located on a 200 acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. Other supporting infrastructure includes approximately 1.5 million barrels of feedstock and product tankage of which 0.2 million is owned by HEP, maintenance shops, warehouses and office buildings. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before

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1950. The crude oil capacity of the Woods Cross Refinery is 31,000 BPSD and the facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane, and gas oil.

We own and operate 4 miles of hydrogen pipeline that allows us to connect to a hydrogen plant located at Chevron’s Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allow us to connect our Woods Cross Refinery to common carrier pipeline systems.

Markets and competition

The Woods Cross Refinery is one of five refineries located in Utah. We estimate that the four refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPSD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and ConocoPhillips. The Woods Cross Refinery’s primary markets include Utah, Idaho, Nevada, Wyoming and eastern Washington. Approximately 60% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under various long-term supply agreements.

Utah market

The Utah market for refined products is currently supplied primarily by a number of local refiners and the Pioneer Pipeline. Local area refiners include Woods Cross, Chevron, Tesoro, Big West and Silver Eagle. Other refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and ConocoPhillips. We currently supply approximately 16,000 BPD of refined products into the Utah market, which represents approximately 15% of the refined products consumed in that market, to branded and unbranded customers.

Idaho, Wyoming, Eastern Washington and Nevada markets

We currently supply approximately 7,000 BPD of refined products into the Idaho, Wyoming, eastern Washington and Nevada markets, which represents approximately 2% of the refined products consumed in those markets. Woods Cross ships refined products over Chevron’s common carrier pipeline system to numerous terminals, including HEP’s terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by a third party. We sell to branded and unbranded customers in these markets. We also truck refined products to Las Vegas, Nevada.

The Idaho market for refined products is primarily supplied via Chevron’s common carrier pipeline system from refiners located in the Salt Lake City area and products supplied from the Pioneer Pipeline system. Refiners that could potentially supply the Chevron and Pioneer Pipeline systems include Woods Cross, Chevron, Tesoro, Big West, Silver Eagle, Sinclair, ConocoPhillips and ExxonMobil.

We market refined products in the Wyoming market on a limited basis.

The eastern Washington market is supplied by two common carrier pipelines, Chevron and Yellowstone. Product is also shipped into the area via rail from various points in the United States and Canada. Refined products shipped on Chevron’s pipeline system are supplied by refiners and other pipelines located in the Salt Lake City area and from refiners located in the Pacific Northwest. Pacific Northwest refiners include BP, Tesoro, Shell, ConocoPhillips and US Oil. Products supplied from the sources located in the Pacific Northwest area are generally shipped over the Columbia River via barge at Pasco, Washington.

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The majority of the Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan’s CalNev common carrier pipeline system.

Crude oil and feedstock supplies

The Woods Cross Refinery currently obtains its supply of crude oil primarily from suppliers in Canada, Wyoming, Utah and Colorado via common carrier pipelines that originate in Canada, Wyoming and Colorado. Supplies of Black Wax crude oil are shipped via truck.

Principal products and customers

Set forth below is information regarding the principal products produced at the Woods Cross Refinery:

										Three months ended
	Year ended December 31,									March 31,
	2008			2007			2006			2009			2008
	(in thousands)
Woods Cross Refinery
Sales of produced refined products:
Gasolines		63	%		63	%		63	%		68	%		68	%
Diesel fuels		29	%		27	%		28	%		23	%		23	%
Jet fuels		—	%		2	%		2	%		1	%		—	%
Fuel oil		5	%		5	%		5	%		4	%		5	%
Asphalt		1	%		1	%		—	%		1	%		—	%
LPG and other		2	%		2	%		2	%		3	%		4	%
Total		100	%		100	%		100	%		100	%		100	%

Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made available to customers through truck loading facilities at the refinery and at terminals.

Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. Diesel fuel is sold to other refiners, truck stop chains and wholesalers. Limited quantities of jet fuel is sold for domestic airline use. All asphalt produced is blended to fuel oil and sold locally, shipped by rail to the Gulf Coast, shipped by rail directly to our customers or marketed through Holly Asphalt Company to governmental entities or contractors. LPG’s are sold to LPG wholesalers and LPG retailers.

Capital improvement projects

Our approved capital budget for 2009 capital projects at the Woods Cross Refinery is $5.3 million, not including the major projects described below or other capital projects approved in prior years.

At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, Black Wax desalting equipment and Black Wax unloading systems. The total cost of this project was approximately $122.0 million. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.

To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity was required to move Canadian crude to the Woods Cross Refinery. HEP’s joint venture pipeline with Plains permits the transportation of additional crude oil into the Salt Lake City area.

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In December 2007, we entered into a definitive agreement with Sinclair to jointly build the UNEV Pipeline, a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD, with the capacity for further expansion to 120,000 BPD. The total cost of the pipeline project including terminals is expected to be $300.0 million, with our share of the cost totaling $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 BPD of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 BPD in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into an option agreement with HEP granting HEP an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

The UNEV project is in the final stage of the permit process with the Bureau of Land Management of the United States Department of the Interior. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective it would be better to delay completion until the fall of 2010.

HOLLY ENERGY PARTNERS, L.P.

HEP business

In July 2004, we completed the initial public offering of limited partnership interests in HEP, a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” We formed HEP to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona. HEP owns and operates logistics assets, including approximately 2,600 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico, ten refined product terminals, a jet fuel terminal, two refinery truck rack facilities, a refined products tank farm facility, on-site crude oil tankage at both the Navajo and Woods Cross Refineries, a 70% interest in the Rio Grande Pipeline Company and a 25% interest in the joint venture that runs the 95-mile crude oil Salt Lake City Pipeline. As of May 30, 2009, we own an approximate 41% interest in HEP (which includes our general partnership interest).

HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon USA, Inc. (“Alon”) used in connection with operations at its Big Spring, Texas refinery (“Big Spring Refinery”), by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals and therefore is not directly exposed to changes in commodity prices.

Agreements between Holly and HEP

The substantial majority of HEP’s business is devoted to providing transportation and terminalling services to us. HEP serves our refineries in New Mexico and Utah under three 15-year pipeline, terminal and tankage agreements. One of these agreements relates to the pipelines and terminals contributed by us to HEP at the time of HEP’s initial public offering in 2004 and expires in 2019. HEP’s second agreement with us relates to the intermediate pipelines acquired from us in July 2005 and June 2009 that serve our Lovington and Artesia, New Mexico refinery facilities and expires in 2024. HEP’s third agreement with us relates to the crude pipelines and tankage assets acquired from Holly in February 2008 and expires in 2023. As of December 31, 2008, contractual minimums under these three

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agreements are $41.2 million, $13.3 million and $26.8 million, respectively. HEP also serves the Big Spring Refinery under a pipelines and terminals agreement with Alon that expires in 2020. As of December 31, 2008, contractual minimums under this agreement are $22.0 million.

Under certain provisions of the Omnibus Agreement that we entered into with HEP in July 2004, HEP pays us an annual administrative fee in return for our provision of various general and administrative services to HEP. Initially, this fee was $2.0 million for each of the three years following the closing of HEP’s initial public offering. Effective March 1, 2008, the annual fee was increased to $2.3 million to cover additional general and administrative services attributable to the operations of HEP’s Crude Pipelines and Tankage Assets. This fee includes expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, 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 HEP by Holly. We are also reimbursed by HEP for direct expenses incurred on HEP’s behalf. In addition, HEP also pays for its 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. The fee and the related services may be terminated by either us or HEP at any time.

Conflicts committee

Three members of the board of directors of Holly Logistic Services, L.L.C. (HLS), the general partner of HEP Logistics Holdings, L.P., HEP’s general partner, serve on a conflicts committee to review specific matters, including transactions with Holly, 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 HEP. 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 are conclusively deemed to be fair and reasonable to HEP, approved by all of HEP’s partners, and not a breach by HEP’s general partner of any duties it may owe HEP or its unitholders. Additionally, with respect to certain transactions between Holly and HEP or their respective affiliates, and depending on the size of the transaction, the indenture governing the notes will also require approval by a majority of the disinterested directors of Holly or an opinion from an independent investment bank that the transaction is fair from a financial point of view to Holly. See “Description of notes—Covenants—Transactions with affiliates.”

Indemnification agreements

In connection with the crude pipelines and tankage assets that HEP acquired from us in February 2008, three of our subsidiaries, Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement. Additionally, in connection with the intermediate pipelines that HEP acquired from us in July 2005, Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of HEP’s senior notes. HEP and its subsidiaries are not guarantors of the notes offered hereby.

Under the Omnibus Agreement, we have also agreed to indemnify HEP up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to HEP and occurring or existing prior to the date of such transfers. The Omnibus Agreement provides environmental indemnification of up to $15.0 million through 2014 for the assets transferred to HEP at

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the time of HEP’s initial public offering in 2004, plus up to an additional $2.5 million through 2015 that is limited to indemnification for the Intermediate Pipelines acquired in July 2005. The Omnibus Agreement provides $7.5 million of indemnification through 2023 solely for environmental noncompliance and remediation liabilities specific to the Crude Pipelines and Tankage Assets, which are not covered by the $15.0 in indemnification mentioned above.

Quarterly distributions

We receive quarterly distributions from HEP that provide us with a steady source of cash flow and strengthen our financial position. For the year ended December 31, 2008, we received $25.6 million in distributions from HEP. For the quarter ended March 31, 2009, we received $6.9 million in distributions from HEP.

EMPLOYEES AND LABOR RELATIONS

As of March 31, 2009, we had 979 employees, of which 341 are currently covered by collective bargaining agreements. The foregoing does not include the approximately 400 employees at the Tulsa Refinery, which we acquired on June 1, 2009. We consider our employee relations to be good. We successfully renegotiated the collective bargaining agreement for our Utah refinery and extended the term to 2012 in February, 2009 (subject only to ongoing efforts to document the interim letter agreement with formal contract terms). The collective bargaining agreement for our New Mexico refinery expires in 2010.

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EX-99.6

Exhibit 99.6

Index to financial statements

CONSOLIDATED FINANCIAL STATEMENTS OF HOLLY CORPORATION

Audited Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2008 and 2007	F-3
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	F-5
Consolidated Statements of Equity for the years ended December 31, 2008, 2007 and 2006	F-6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of independent registered public accounting firm

The Board of Directors

and Stockholders of Holly Corporation

We have audited the accompanying consolidated balance sheets of Holly Corporation as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows, equity and comprehensive income for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Holly Corporation at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As described in Note 1 to the consolidated financial statements, the consolidated financial statements have been adjusted for the retrospective application of Statement of Financial Accounting Standards No. 160 “Noncontrolling Interests in Consolidated Financial Statements - an Amendment of Accounting Research Bulletin No. 51”, which became effective January 1, 2009.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Holly Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2009 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 27, 2009,

except for changes as described in Notes 1 and 21, as to which the date is

May 29, 2009

F-2

HOLLY CORPORATION

Consolidated balance sheets

	December 31,			December 31,
	2008			2007
	(in thousands,
	except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	40,805		$	94,369
Marketable securities		49,194			158,233
Accounts receivable: Product and transportation		128,337			242,392
Crude oil resales		161,427			366,226
Related party receivable		—			6,151
		289,764			614,769
Inventories:        Crude oil and refined products		107,811			118,308
Materials and supplies		17,924			22,322
		125,735			140,630
Income taxes receivable		6,350			16,356
Prepayments and other		18,775			10,264
Total current assets		530,623			1,034,621
Properties, plants and equipment, at cost		1,509,701			802,820
Less accumulated depreciation		(304,379	)		(271,970	)
		1,205,322			530,850
Marketable securities (long-term)		6,009			77,182
Other assets: Turnaround costs		34,309			8,705
Goodwill		27,542			—
Intangibles and other		70,420			12,587
		132,271			21,292
Total assets	$	1,874,225		$	1,663,945
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	391,142		$	782,976
Accrued liabilities		42,016			35,104
Short-term debt—Holly Energy Partners		29,000			—
Total current liabilities		462,158			818,080
Long-term debt—Holly Energy Partners		341,914			—
Deferred income taxes		69,491			38,933
Other long-term liabilities		64,330			36,712
Commitments and contingencies
Distributions in excess of investment in Holly Energy Partners		—			168,093
Equity:
Holly Corporation stockholders’ equity:
Preferred stock, $1.00 par value—1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value—160,000,000 and 100,000,000 shares authorized; 73,543,873 and 73,269,219 shares issued as of December 31, 2008 and 2007, respectively		735			733
Additional capital		121,298			109,125
Retained earnings		1,145,388			1,054,974
Accumulated other comprehensive loss		(35,081	)		(19,076	)
Common stock held in treasury, at cost—23,600,653 and 20,653,050 shares as of December 31, 2008 and 2007, respectively		(690,800	)		(551,962	)
Total Holly Corporation stockholders’ equity		541,540			593,794
Noncontrolling interest		394,792			8,333
Total equity		936,332			602,127
Total liabilities and equity	$	1,874,225		$	1,663,945

See accompanying notes.

F-3

Holly Corporation

Consolidated statements of income

	Years ended December 31,
	2008			2007			2006
	(in thousands, except per share data)
Sales and other revenues	$	5,867,668		$	4,791,742		$	4,023,217
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		5,280,699			4,003,488			3,349,404
Operating expenses (exclusive of depreciation and amortization)		267,570			209,281			208,460
General and administrative expenses (exclusive of depreciation and amortization)		54,906			68,773			63,255
Depreciation and amortization		63,789			43,456			39,721
Exploration expenses, including dry holes		372			412			486
Total operating costs and expenses		5,667,336			4,325,410			3,661,326
Income from operations		200,332			466,332			361,891
Other income (expense):
Equity in earnings of Holly Energy Partners		2,990			19,109			12,929
Impairment of equity securities		(3,724	)		—			—
Gain on sale of HPI		5,958			—			—
Interest income		10,824			15,089			9,757
Interest expense		(23,955	)		(1,086	)		(1,076	)
		(7,907	)		33,112			21,610
Income from continuing operations before income taxes		192,425			499,444			383,501
Income tax provision:
Current		31,892			142,245			126,181
Deferred		32,934			23,071			10,422
		64,826			165,316			136,603
Income from continuing operations		127,599			334,128			246,898
Discontinued operations
Income from discontinued operations		—			—			5,660
Gain on sale of discontinued operations		—			—			14,008
Income from discontinued operations, net of taxes		—			—			19,668
Net income		127,599			334,128			266,566
Less net income attributable to noncontrolling interest		7,041			—			—
Net income per share attributable to Holly Corporation stockholders	$	120,558		$	334,128		$	266,566
Net income per share attributable to Holly Corporation stockholders—basic:
Continuing operations	$	2.40		$	6.09		$	4.33
Discontinued operations		—			—			0.35
Net income	$	2.40		$	6.09		$	4.68
Net income per share attributable to Holly Corporation stockholders—diluted:
Continuing operations	$	2.38		$	5.98		$	4.24
Discontinued operations		—			—			0.34
Net income	$	2.38		$	5.98		$	4.58
Average number of common shares outstanding:
Basic		50,202			54,852			56,976
Diluted		50,549			55,850			58,210

See accompanying notes.

F-4

Holly Corporation

Consolidated statements of cash flows

	Years ended December 31,
	2008			2007			2006
	(in thousands)
Cash flows from operating activities:
Net income	$	127,599		$	334,128		$	266,566
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes discontinued operations in 2006)		63,789			43,456			40,270
Deferred income taxes (includes discontinued operations in 2006)		32,934			23,071			7,980
Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures		3,067			3,688			7,379
Equity based compensation expense		7,467			9,993			5,507
Gain on sale of assets, before income taxes		(5,958	)		—			(22,328	)
Change in fair value—interest rate swaps		2,282			—			—
Impairment of equity securities		3,724			—			—
(Increase) decrease in current assets:
Accounts receivable		331,978			(216,295	)		12,059
Inventories		15,006			(10,955	)		(33,792	)
Income taxes receivable		10,006			(7,301	)		(9,055	)
Prepayments and other		(398	)		1,817			5,890
Increase (decrease) in current liabilities:
Accounts payable		(393,186	)		264,217			(26,370	)
Accrued liabilities		(2,149	)		(16,476	)		15,665
Income taxes payable		1,781			—			(5,323	)
Turnaround expenditures		(34,751	)		(2,669	)		(7,672	)
Other, net		(7,701	)		(3,937	)		(11,593	)
Net cash provided by operating activities		155,490			422,737			245,183
Cash flows from investing activities:
Additions to properties, plants and equipment—Holly Corporation		(383,742	)		(161,258	)		(120,429	)
Additions to properties, plants and equipment—Holly Energy Partners		(34,317	)		—			—
Proceeds from sale of crude pipelines and tankage assets		171,000			—			—
Proceeds from sale of HPI		5,958			—			—
Net proceeds from sale of Montana Refinery		—			—			48,872
Increase in cash due to consolidation of Holly Energy Partners		7,295			—			—
Purchases of marketable securities		(769,142	)		(641,144	)		(211,972	)
Sales and maturities of marketable securities		945,461			509,345			319,334
Investment in Holly Energy Partners		(290	)		—			—
Net cash provided by (used for) investing activities		(57,777	)		(293,057	)		35,805
Cash flows from financing activities:
Net borrowings under credit agreement—Holly Energy Partners		29,000			—			—
Deferred financing costs		(913	)		—			—
Purchase of treasury stock		(151,106	)		(207,196	)		(175,394	)
Contribution from joint venture partner		17,000			8,333			—
Dividends		(29,064	)		(23,208	)		(15,002	)
Distributions to noncontrolling interests		(22,098	)		—			—
Issuance of common stock upon exercise of options		1,005			2,288			2,645
Excess tax benefit from equity based compensation		5,694			30,355			11,816
Purchase of units for restricted grants—Holly Energy Partners		(795	)		—			—
Net cash used for financing activities		(151,277	)		(189,428	)		(175,935	)
Cash and cash equivalents:
Increase (decrease) for the period		(53,564	)		(59,748	)		105,053
Beginning of period		94,369			154,117			49,064
End of period	$	40,805		$	94,369		$	154,117

See accompanying notes.

F-5

Holly Corporation

Consolidated statements of equity

Holly Corporation Stockholders’ Equity
									Accumulated
									other						Non-			Total
	Common		Additional			Retained			comprehensive			Treasury			controlling			stockholders’
	stock		capital			earnings			income (loss)			stock			interest			equity
	(in thousands)
Balance at December 31, 2005	$	354	$	43,344		$	495,819		$	(4,802	)	$	(157,364	)	$	—		$	377,351
Net income		—		—			266,566			—			—			—			266,566
Dividends		—		—			(16,391	)		—			—			—			(16,391	)
Other comprehensive income		—		—			—			2,831			—			—			2,831
Issuance of common stock upon exercise of stock options		6		2,638			—			—			—			—			2,644
Tax benefit from stock options		—		12,031			—			—			—			—			12,031
Amortization of stock options		—		139			—			—			—			—			139
Issuance of restricted stock, net of forfeitures		—		5,369			—			—			—			—			5,369
Other equity based compensation		—		3,337			—			—			—			—			3,337
Purchase of treasury stock		—		—			—			—			(178,396	)		—			(178,396	)
Two-for-one stock split		358		(358	)		—			—			—			—			—
Adjustment to initially apply SFAS No. 158, net of tax		—		—			—			(9,387	)		—			—			(9,387	)
Balance at December 31, 2006	$	718	$	66,500		$	745,994		$	(11,358	)	$	(335,760	)	$	—		$	466,094
Net income		—		—			334,128			—			—			—			334,128
Dividends		—		—			(25,148	)		—			—			—			(25,148	)
Other comprehensive loss		—		—			—			(7,718	)		—			—			(7,718	)
Issuance of common stock upon exercise of stock options		11		2,277			—			—			—			—			2,288
Tax benefit from stock options		—		26,017			—			—			—			—			26,017
Issuance of restricted stock, net of forfeitures		4		9,993			—			—			—			—			9,997
Other equity based compensation		—		4,338			—			—			—			—			4,338
Purchase of treasury stock		—		—			—			—			(216,202	)		—			(216,202	)
Contribution from joint venture partner		—		—			—			—			—			8,333			8,333
Balance at December 31, 2007	$	733	$	109,125		$	1,054,974		$	(19,076	)	$	(551,962	)	$	8,333		$	602,127
Net income		—		—			120,558			—			—			7,041			127,599
Dividends		—		—			(30,144	)		—			—			—			(30,144	)
Other comprehensive loss		—		—			—			(16,005	)		—			(7,079	)		(23,084	)
Issuance of common stock upon exercise of stock options		2		1,003			—			—			—			—			1,005
Tax benefit from stock options		—		3,364			—			—			—			—			3,364
Issuance of restricted stock, net of forfeitures		—		5,476			—			—			—			—			5,476
Other equity based compensation		—		2,330			—			—			—			—			2,330
Purchase of treasury stock		—		—			—			—			(138,838	)		—			(138,838	)
Contribution from joint venture partner		—		—			—			—			—			18,500			18,500
Increase in noncontrolling interest due to consolidation of Holly Energy Partners		—		—			—			—			—			389,184			389,184
Distributions to noncontrolling interests		—		—			—			—			—			(22,098	)		(22,098	)
Equity based compensation—Holly Energy Partners		—		—			—			—			—			1,732			1,732
Purchase of common units—Holly Energy Partners		—		—			—			—			—			(795	)		(795	)
Other		—		—			—			—			—			(26	)		(26	)
Balance at December 31, 2008	$	735	$	121,298		$	1,145,388		$	(35,081	)	$	(690,800	)	$	394,792		$	936,332

See accompanying notes.

F-6

Holly Corporation

Consolidated statements of comprehensive income

	Years ended December 31,
	2008			2007			2006
	(in thousands)
Net income	$	127,599		$	334,128		$	266,566
Other comprehensive income (loss):
Securities available-for-sale:
Unrealized gain (loss) on available-for-sale securities		1,146			1,857			(777	)
Reclassification adjustment to net income on sale of securities		(1,315	)		(78	)		(131	)
Total unrealized gain (loss) on available-for-sale securities		(169	)		1,779			(908	)
Retirement medical obligation adjustment		1,433			(5,038	)		—
Minimum pension liability adjustment		(21,572	)		(9,373	)		5,542
Other comprehensive loss of Holly Energy Partners:
Change in fair value of cash flow hedge		(12,967	)		—			—
Other comprehensive income (loss) before income taxes		(33,275	)		(12,632	)		4,634
Income tax expense (benefit)		(10,191	)		(4,914	)		1,803
Other comprehensive income (loss)		(23,084	)		(7,718	)		2,831
Total comprehensive income		104,515			326,410			269,397
Less comprehensive loss attributable to noncontrolling interest		(38	)		—			—
Comprehensive income attributable to Holly Corporation stockholders	$	104,553		$	326,410		$	269,397

See accompanying notes.

F-7

Holly Corporation

Notes to consolidated financial statements

NOTE 1:   DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business:  References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, these financial statements have been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

We are principally an independent petroleum refiner that produces high value light products such as gasoline, diesel fuel and jet fuel. Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”). The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. Our refinery located just north of Salt Lake City, Utah (the “Woods Cross Refinery”) is operated by Holly Refining & Marketing Company—Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and sour Canadian crude oils.

At December 31, 2008, we owned a 46% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined product terminals; a jet fuel terminal; two refinery truck rack facilities, a refined products tank farm facility, on-site crude oil tankage at both our Navajo and Woods Cross Refineries and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

On February 29, 2008, HEP acquired certain crude pipelines and tankage assets from us (the “Crude Pipelines and Tankage Assets”) that service our Navajo and Woods Cross Refineries (see Note 3).

We sold substantially all of the oil and gas properties of Holly Petroleum, Inc. (“HPI”), a subsidiary that previously conducted a small-scale oil and gas exploration and production program, in 2008 for $6.0 million, resulting in a gain of $6.0 million.

On March 31, 2006, we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations (see Note 2).

Principles of Consolidation:  Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through 50% or more ownership or through 50% or more variable interest in entities that are considered variable interest entities. All significant intercompany transactions and balances have been eliminated.

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

F-8

Notes to consolidated financial statements

Cash Equivalents:  We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings.

Marketable Securities:  We consider all marketable debt securities with maturities greater than three months at the date of purchase to be marketable securities. Our marketable securities are primarily issued by government entities with the maximum maturity of any individual issue not more than two years, while the maximum duration of the portfolio of investments is not greater than one year. These instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income.

Fair Value Measurements:  We adopted Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements” on January 1, 2008 for financial instruments that we recognize at fair value on a recurring basis.

This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels. Under this hierarchy, quoted prices in active markets for identical assets or liabilities are considered the most reliable evidence of fair value and are given the highest priority level (level 1). Quoted market prices for similar assets and liabilities in an active market, quoted prices for identical assets or liabilities in an inactive market and calculation techniques utilizing observable market inputs are given a lower priority level (level 2). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3).

We have investments in marketable debt and equity securities that are measured at fair value on a recurring basis using level 1 inputs. Fair value measurements are based on quoted prices in active markets. See Note 6 for additional information on these instruments.

HEP has interest rate swaps that are measured at fair value on a recurring basis using level 2 inputs. Interest rate swap fair value measurements are based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreements. Fair value measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input, at the respective measurement dates. See Note 11 for additional information on the interest rate swaps.

Accounts Receivable:  The majority of the accounts receivable are due from 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, is required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal. Accounts receivable attributable to crude oil resales generally represent the sell side of excess crude oil sales to other purchasers and/or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy/sell exchanges of crude oil. At times we enter into such buy/sell exchanges to facilitate the delivery of quantities to certain locations. In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk.

Inventories:  Inventories are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO

F-9

Notes to consolidated financial statements

layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.

Long-lived assets:  We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. 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. No impairments of long-lived assets were recorded during the years ended December 31, 2008, 2007 and 2006.

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 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 assets due to legal obligations to clean and/or dispose of various component parts at the time they are retired. At December 31, 2008, we have an asset retirement obligation of $1.3 million, which is included in “Other long-term liabilities” in our consolidated balance sheets.

Intangibles and Goodwill:  Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired.

We reconsolidated HEP on March 1, 2008 and as a result, recorded $27.5 million in goodwill. Additionally, our consolidated HEP assets include a third-party transportation agreement having an expected remaining term through 2035. The transportation agreement is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $1.9 million. At December 31, 2008, the balance of this transportation agreement was $52.5 million, net of accumulated amortization of $1.5 million, which is included in “Intangible and Others” in our consolidated balance sheets. Amortization expense for the year ended December 31, 2008 was $1.5 million, representing amortization from March 1, 2008 (date of reconsolidation) through December 31, 2008.

No impairments of intangibles or goodwill were recorded during the years ended December 31, 2008, 2007 and 2006.

Variable Interest Entity:  HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standard Board (“FASB”) Interpretation (“FIN”) No. 46(R). A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk or a controlling interest in the entity, or have voting rights that are not proportionate to their economic interest.

Under the provisions of FIN No. 46(R), HEP’s purchase of certain pipelines and tankage assets from us (see Note 3) qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP.

F-10

Notes to consolidated financial statements

Following this transaction, we reevaluated whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting. As a result, our financial statements include the consolidated results of HEP. Amounts allocated to HEP’s noncontrolling interest holders are recorded to noncontrolling interest.

Under the equity method of accounting, prior to March 1, 2008, we recorded our pro-rata share of earnings in HEP. Contributions to and distributions from HEP were recorded as adjustments to our investment balance.

Investments in Joint Ventures:  We consolidate the results of our joint ventures where we have an ownership interest of greater than 50% and use the equity method of accounting for investments in which we a 50% or less ownership interest. As of December 31, 2008 we have no investments in joint ventures that we account for using the equity method of accounting.

Derivative Instruments:  All derivative instruments are recognized as either assets or liabilities in the balance sheet and measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings unless specific hedge accounting criteria are met. See Note 11, Debt for additional information on HEP’s interest rate swap and hedging activities.

Revenue Recognition:  Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. Pipeline transportation revenues are recognized as products are shipped on our pipelines. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling costs incurred are reported in cost of products sold.

Depreciation:  Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 12 to 25 years for refining facilities, 10 to 25 years for pipeline and terminal facilities, 3 to 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 7 to 30 years for other fixed assets.

Cost Classifications:  Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished products, inclusive of transportation costs. We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. Operating expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating costs. General and administrative expenses include compensation, professional services and other support costs.

Deferred Maintenance Costs:  Our refinery units require regular major maintenance and repairs which are commonly referred to as “turnarounds”. Catalysts used in certain refinery processes also require regular “change-outs”. The required frequency of the maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred.

Environmental Costs:  Environmental costs are charged to operating expenses 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. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

F-11

Notes to consolidated financial statements

Contingencies:  We are 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 matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a change in settlement strategy in dealing with these matters.

Income Taxes:  Provisions for income taxes include deferred taxes resulting from temporary differences in income for financial and tax purposes, using the liability method of accounting for income taxes. The liability method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.

New accounting pronouncements:

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of Accounting Research Bulletin No. 51”

In December 2007, the FASB issued SFAS No. 160 which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. This standard was effective for all fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption was not permitted.

We adopted this standard effective January 1, 2009. These historical financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008 have been updated to reflect our retrospective application of this standard. As a result, all previous references to “minority interest” within these financial statements have been replaced with “noncontrolling interest.” Additionally, net income attributable to the non-controlling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interests in earnings of Holly Energy Partners,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”

In March 2008, the FASB issued SFAS No. 161 which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. We adopted this standard effective January 1, 2009 which did not have a material impact on our financial condition, results of operations and cash flows.

F-12

Notes to consolidated financial statements

NOTE 2:   DISCONTINUED OPERATIONS

On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.3 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.1 million for other assets, with current liabilities assumed amounting to $0.3 million.

The following tables provide summarized income statement information related to discontinued operations:

	Year ended
	December 31,
	2006
	(in thousands)
Sales and other revenues from discontinued operations	$	53,913
Income from discontinued operations before income taxes	$	9,021
Income tax expense		(3,361	)
Income from discontinued operations, net		5,660
Gain on sale of discontinued operations before income taxes		22,328
Income tax expense		(8,320	)
Gain on sale of discontinued operations, net		14,008
Income from discontinued operations, net	$	19,668

In accordance with the Montana Refinery sale agreement, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. As of December 31, 2008, we had an accrual of $1.8 million related to such environmental liabilities which is included in our environmental liability accrual as discussed in Note 10.

NOTE 3:   HOLLY ENERGY PARTNERS

HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. We currently have a 46% ownership interest in HEP, including our 2% general partner interest.

HEP is a variable interest entity as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s acquisition of the Crude Pipelines and Tankage Assets (discussed below) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

On February 29, 2008, we closed on the sale of the Crude Pipelines and Tankage Assets to HEP for $180.0 million. The assets consisted of crude oil trunk lines that deliver crude oil to our Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross Refinery complexes, a jet

F-13

Notes to consolidated financial statements

fuel products pipeline between Artesia and Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. Consideration received consisted of $171.0 million in cash and 217,497 HEP common units having a value of $9.0 million.

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP (the “HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, result in minimum annual payments to HEP of $26.8 million. These annual payments are adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”), but will not decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates on the crude pipelines will generally be increased each year at a rate equal to the percentage change in the Federal Energy Regulatory Commission (“FERC”) Oil Pipeline Index. The FERC Oil Pipeline Index is the change in the PPI plus a FERC adjustment factor. Additionally, we amended our omnibus agreement with HEP (the “Omnibus Agreement”) to provide $7.5 million of indemnification for a period of up to 15-years for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP.

HEP also serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines and/or throughput in their terminals volumes of refined products that will result in minimum annual payments to HEP. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP. Minimum payments for both agreements are adjusted annually on July 1 based on increases in the PPI. Following the July 1, 2008 PPI rate adjustment, minimum payments under the HEP PTA and the HEP IPA are $41.2 million and $13.3 million, respectively, for the twelve months ending June 30, 2009.

The following table sets forth the changes in our investment account in HEP for the period from January 1, 2008 through February 29, 2008, prior to our reconsolidation effective March 1, 2008:

	(in thousands)
Investment in HEP balance at December 31, 2007	$	(168,093	)
Equity in the earnings of HEP		2,990
Regular quarterly distributions from HEP		(6,057	)
Consideration received in excess of basis in Crude Pipeline and Tankage Assets		(153,223	)
HEP common units received		9,000
Purchase of additional HEP common units		104
Contribution made to maintain 2% general partner interest		186
Investment in HEP balance at February 29, 2008	$	(315,093	)

The balance sheet impact of our reconsolidation of HEP on March 1, 2008 was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in property, plant and equipment of $336.9 million, an increase in goodwill, intangibles and other assets of $81.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, a decrease in other long-term liabilities of $0.5 million, an increase in noncontrolling interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under the HEP PTA, HEP IPA, HEP CPTA and the Omnibus Agreement. Effective March 1, 2008, we reconsolidated HEP. As a result, our financial statements

F-14

Notes to consolidated financial statements

include the consolidated results of HEP and intercompany transactions with HEP are eliminated. Related party transactions prior to our reconsolidation of HEP are as follows:

Ø	Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008 and $61.0 million for the year ended December 31, 2007, respectively.
Ø	We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 and $2.0 million for the year ended December 31, 2007, respectively, for general and administrative services under the Omnibus Agreement which we recorded as a reduction in expenses.
Ø	HEP reimbursed us for costs of employees supporting their operations of $2.1 million for the period from January 1, 2008 through February 29, 2008 and $8.5 million for the year ended December 31 2007, respectively, which we recorded as a reduction in expenses.
Ø	We reimbursed HEP $0.3 million for the year ended December 31, 2007 for certain costs paid on our behalf.
Ø	We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008 and $22.8 million for the year ended December 31, 2007, respectively. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 and $2.2 million for the year ending December 31, 2007, respectively, in incentive distributions with respect to our general partner interest.
Ø	We had a related party receivable from HEP of $6.0 million at February 29, 2008 and December 31, 2007.
Ø	We had accounts payable to HEP of zero and $5.7 million at February 29, 2008 and December 31, 2007, respectively.

NOTE 4:  EARNINGS PER SHARE

Basic earnings per share from continuing operations is calculated as income from continuing operations attributable to Holly Corporation stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share from continuing operations assumes, when dilutive, the issuance of the net incremental shares from stock options and variable performance shares. The following is a reconciliation of the denominators of the basic and diluted per share computations:

	Years ended December 31,
	2008		2007		2006
	(in thousands, except per share data)
Income from continuing operations attributable to Holly Corporation stockholders	$	120,558	$	334,128	$	246,898
Average number of shares of common stock outstanding		50,202		54,852		56,976
Effect of dilutive stock options, variable restricted shares and performance share units		347		998		1,234
Average number of shares of common stock outstanding assuming dilution		50,549		55,850		58,210
Income from continuing operations per share attributable to Holly Corporation stockholders—basic	$	2.40	$	6.09	$	4.33
Income from continuing operations per share attributable to Holly Corporation stockholders—diluted	$	2.38	$	5.98	$	4.24

F-15

Notes to consolidated financial statements

NOTE 5:   STOCK-BASED COMPENSATION

On December 31, 2008, Holly had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $7.6 million, $10.8 million and $21.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $2.9 million, $4.2 million and $7.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods. At December 31, 2008, 2,407,172 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.

Additionally in 2008, we recorded $1.7 million of equity based compensation expense attributable to HEP’s equity based compensation plan as a result of our reconsolidation effective March 1, 2008.

Stock options

Under our long-term incentive compensation plan and a previous stock option plan, we have granted stock options to certain officers and other key employees. All the options have been granted at prices equal to the market value of the shares at the time of the grant and normally expire on the tenth anniversary of the grant date. These awards generally vest 20% at the end of each of the five years after the grant date. There have been no options granted since December 2001. The fair value on the date of grant for each option awarded was been estimated using the Black-Scholes option pricing model.

A summary of option activity and changes during the year ended December 31, 2008 is presented below:

						Weighted-
				Weighted-		average		Aggregate
				average		remaining		intrinsic
				exercise		contractual		value
Options	Shares			price		term		($000)
Outstanding at January 1, 2008		491,200		$	2.56
Exercised		(406,000	)	$	2.47
Outstanding at December 31, 2008		85,200		$	2.98		2.2	$	1,300
Exercisable at December 31, 2008		85,200		$	2.98		2.2	$	1,300

The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006, was $8.6 million, $68.0 million and $30.9 million, respectively.

All outstanding stock options granted became fully vested during 2006. The total fair value of options vested during the year ended December 31, 2006 was $0.4 million.

Cash received from option exercises under the stock option plans for the years ended December 31, 2008, 2007 and 2006, was $1.0 million, $2.3 million and $2.6 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $3.4 million, $26.0 million and $12.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Restricted stock

Under our long-term incentive compensation plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of

F-16

Notes to consolidated financial statements

one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the respective vesting period.

A summary of restricted stock activity and changes during the year ended December 31, 2008 is presented below:

				Weighted-
				average		Aggregate
				grant-date		intrinsic
Restricted stock	Grants			fair value		value ($000)
Outstanding at January 1, 2008 (non-vested)		298,565		$	27.22
Vesting and transfer of ownership to recipients		(138,648	)	$	23.58
Granted		86,409		$	45.91
Forfeited		(11,016	)	$	34.87
Outstanding at December 31, 2008 (non-vested)		235,310		$	35.86	$	4,290

The total fair value of restricted stock vested and transferred to recipients during the years ended December 31, 2008, 2007 and 2006 was $2.5 million, $12.9 million and $5.5 million, respectively. As of December 31, 2008, there was $2.0 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.2 years.

Performance share units

Under our long-term incentive compensation plan, we grant certain officers and other key employees performance share units, which are payable in either cash or stock upon meeting certain criteria over the service period, and generally vest over a period of one to three years. Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or a “market performance” criteria.

During the year ended December 31, 2008, we granted 60,605 performance share units with a fair value based on our grant date closing stock price of $47.47. All shares were granted during the first quarter of 2008 and are payable in stock and are subject to certain financial performance criteria.

The fair value of each performance share unit award subject to the financial performance criteria and payable in stock is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of December 31, 2008, estimated share payouts for outstanding non-vested performance share unit awards ranged from 80% to 156%.

The fair value of each performance share unit award based on market performance criteria and payable in stock is computed based on an expected-cash-flow approach. The analysis utilizes the grant date closing stock price, dividend yield, historical total returns, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer group. The expected total return and historical standard deviation are applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns.

F-17

Notes to consolidated financial statements

A summary of performance share unit activity and changes during the year ended December 31, 2008 is presented below:

							Financial
	Market performance						performance
	Payable in			Stock			Stock			Total
	cash			settled			settled			performance
Performance share units	grants			grants			grants			share units
Outstanding at January 1, 2008 (non-vested)		81,450			42,474			116,156			240,080
Vesting and payment of benefit to recipients		(81,450	)		(42,474	)		—			(123,924	)
Granted		—			—			60,605			60,605
Forfeited		—			—			(7,092	)		(7,092	)
Outstanding at December 31, 2008 (non-vested)		—			—			169,669			169,669

For the year ended December 31, 2008 we paid $6.0 million and issued 84,948 shares of our common stock (representing a 200% share payout) having a fair value of $2.7 million related to vested performance share units. Based on the weighted average grant date fair value of $42.50 there was $5.2 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

NOTE 6:   CASH AND CASH EQUIVALENTS AND INVESTMENTS IN MARKETABLE SECURITIES

Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, we have 1,000,000 shares of Connacher common stock that was received as partial consideration upon our sale of the Montana Refinery in 2006.

We invest in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments including investments in equity securities are classified as available-for-sale, and as a result, are reported at fair value. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are considered temporary and are reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

During the year ended December 31, 2008, we recorded an impairment loss of $3.7 million related to our investment in Connacher common stock having an initial cost basis of $4.3 million. Although this investment in equity securities was in an unrealized loss position for less than 12-months, we accounted for this as an other-than-temporary decline due to the severity of the loss in fair value of this investment.

F-18

Notes to consolidated financial statements

The following is a summary of our available-for-sale securities at December 31, 2008:

	Available-for-sale securities
								Estimated
			Gross		Recognized			fair value
	Amortized		unrealized		impairment			(net carrying
	cost		gain		loss			amount)
	(in thousands)
States and political subdivisions	$	54,389	$	210	$	—		$	54,599
Equity securities		4,328		—		(3,724	)		604
Total marketable securities	$	58,717	$	210	$	(3,724	)	$	55,203

For the year ended December 31, 2008, we received a total of $945.5 million related to sales and maturities of marketable debt securities.

The following is a summary of our available-for-sale securities at December 31, 2007:

	Available-for-sale securities
						Estimated
						fair value
	Amortized		Gross unrealized			(net carrying
	cost		gain (loss)			amount)
	(in thousands)
States and political subdivisions	$	230,709	$	866		$	231,575
Equity securities		4,328		(488	)		3,840
Total marketable securities	$	235,037	$	378		$	235,415

For the year ended December 31, 2007, we received a total of $509.3 million related to sales and maturities of marketable debt securities.

NOTE 7:  INVENTORIES

Inventories are stated at the lower of cost, using the LIFO method for crude oil and refined products and the average cost method for materials and supplies, or market. Cost is determined using the LIFO inventory valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods.

F-19

Notes to consolidated financial statements

Inventory consists of the following components:

	December 31,
	2008		2007
	(in thousands)
Crude oil	$	21,446	$	25,364
Other raw materials and unfinished products(1)		2,640		7,226
Finished products(2)		83,725		85,718
Process chemicals(3)		3,800		4,312
Repairs and maintenance supplies and other		14,124		18,010
Total inventory	$	125,735	$	140,630

(1)	Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
(2)	Finished products include gasolines, jet fuels, diesels, asphalts, LPG’s and residual fuels.
(3)	Process chemicals include catalysts, additives and other chemicals.

The excess of current cost over the LIFO value of inventory was $33.0 million and $199.4 million at December 31, 2008 and 2007, respectively. We recognized a reduction in cost of products sold of $8.4 million for the year ended December 31, 2008 and recognized a charge of $0.8 million to cost of products sold for the year ended December 31, 2007. The 2008 cost reduction resulted from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to acquisition costs at the beginning of the year. The $0.8 million charge for 2007 was the result of certain LIFO inventory liquidations that were carried at higher costs as compared to acquisition costs at the beginning of the year.

NOTE 8:   PROPERTIES, PLANTS AND EQUIPMENT

	December 31,
	2008			2007
	(in thousands)
Land, buildings and improvements	$	54,529		$	24,340
Refining facilities		493,706			478,445
Pipelines and terminals		338,558			68,709
Transportation vehicles		19,313			13,564
Oil and gas exploration and development		—			2,917
Other fixed assets		50,187			43,534
Construction in progress		553,408			171,311
		1,509,701			802,820
Accumulated depreciation		(304,379	)		(271,970	)
	$	1,205,322		$	530,850

During the year ended December 31, 2008, $1.0 million in interest attributable to HEP’s construction projects was capitalized. We did not capitalize any interest in 2007.

Depreciation expense was $53.3 million, $35.8 million and $30.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. Depreciation expense for the year ended December 31, 2008 includes $17.5 million of depreciation expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.

F-20

Notes to consolidated financial statements

NOTE 9:   JOINT VENTURE

In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and north Las Vegas areas (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair owns the remaining 25% interest. The total cost of the pipeline project including terminals is expected to be $300.0 million. Our share of this cost would be $225.0 million. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff rate. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.

NOTE 10:   ENVIRONMENTAL COSTS

Consistent with our accounting policy for environmental remediation costs, we expensed $0.4 million, $2.3 million and $5.6 million for the years ended December 31, 2008, 2007 and 2006, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheet was $7.3 million and $8.6 million at December 31, 2008 and 2007, respectively, of which $4.2 million and $5.3 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are expected to be incurred over the next several years and are not discounted to their present value.

NOTE 11:   DEBT

Credit facilities

In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America, N.A. as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at December 31, 2008. At December 31, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at December 31, 2008.

HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Facility expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes. HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. HEP assets that are included in our Consolidated Balance Sheets at December 31, 2008 consist of $5.3 million in cash and cash equivalents, $5.1 million in trade accounts receivable and other current assets, $354.1 million in property, plant and equipment,

F-21

Notes to consolidated financial statements

net and $56.1 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement.

HEP senior notes due 2015

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s 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 HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., their general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than their investment in HEP, are not significant. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service on up to $35.0 million of the principal amount of the HEP Senior Notes.

At December 31, 2008, the carrying amount of HEP’s long-term debt was as follows:

	(in thousands)
HEP Credit Agreement	$	200,000
HEP Senior Notes
Principal		185,000
Unamortized discount		(16,223	)
Unamortized premium—de-designated fair value hedge		2,137
		170,914
Total debt		370,914
Less short-term borrowings under HEP Credit Agreement		29,000
Total long-term debt	$	341,914

Interest rate risk management

As of December 31, 2008, HEP had three interest rate swap contracts.

HEP entered into an interest rate swap to hedge their exposure to the cash flow risk caused by the effects of LIBOR changes on the $171.0 million Credit Agreement advance that HEP used to finance their purchase of the Crude Pipelines and Tankage Assets from us. This interest rate swap effectively converts their $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of December 31, 2008. The maturity date of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

F-22

Notes to consolidated financial statements

HEP designated this interest rate swap as a cash flow hedge. Based on their assessment of effectiveness using the change in variable cash flows method, HEP determined that this interest rate swap is effective in offsetting the variability in interest payments on the $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts their cash flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, HEP measures 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 the swap against the expected future interest payments on the $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of December 31, 2008, HEP had no ineffectiveness on their cash flow hedge.

HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36% as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the maturity of the Senior Notes.

In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of their hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with a corresponding entry to interest expense. For the year ended December 31, 2008, HEP recognized $2.3 million in interest expense attributable to fair value adjustments to its interest rate swaps.

Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. This hedge met the requirements to assume no ineffectiveness and was accounted for using the “shortcut” method of accounting whereby offsetting fair value adjustments to the underlying swap were made to the carrying value of the HEP Senior Notes, effectively adjusting the carrying value of this $60.0 million to its fair value. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction of interest expense.

F-23

Notes to consolidated financial statements

Additional information on HEP’s interest rate swaps is as follows:

	Balance sheet	Fair			Location of	Offsetting
Interest rate swaps	location	value			offsetting balance	amount
					(in thousands)
Asset
Fixed-to-variable interest rate swap—$60 million of 6.25% Senior Notes	Other assets	$	4,079		Long-term debt Interest expense	$	(2,195 (1,884	) )
		$	4,079			$	(4,079	)
Liability
Cash flow hedge—$171 million LIBOR based debt	Other long-term liabilities	$	(12,967	)	Accumulated other comprehensive income	$	12,967
Variable-to-fixed interest rate swap—$60 million	Other long-term liabilities		(4,166	)	Interest expense		4,166
		$	(17,133	)		$	17,133

We made cash interest payments of $14.3 million, $0.8 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE 12:   INCOME TAXES

The provision for income taxes from continuing operations is comprised of the following:

	Years ended December 31,
	2008		2007		2006
	(in thousands)
Current Federal	$	27,795	$	113,999	$	105,469
State		4,097		28,246		20,712
Deferred Federal		27,727		21,867		9,490
State		5,207		1,204		932
	$	64,826	$	165,316	$	136,603

The statutory federal income tax rate applied to pre-tax book income from continuing operations reconciles to income tax expense as follows:

	Years ended December 31,
	2008			2007			2006
	(in thousands)
Tax computed at statutory rate	$	67,349		$	174,805		$	134,225
State income taxes, net of federal tax benefit		7,505			19,478			14,957
Federal tax credits		(1,896	)		(16,078	)		(10,776	)
Domestic production activities deduction		(2,380	)		(8,670	)		—
Tax exempt interest		(2,772	)		(4,200	)		—
Noncontrolling interest		(2,740	)		—			—
Other		(240	)		(19	)		(1,803	)
	$	64,826		$	165,316		$	136,603

F-24

Notes to consolidated financial statements

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities for continuing operations as of December 31, 2008 and 2007 are as follows:

	December 31, 2008
	Assets		Liabilities			Total
	(in thousands)
Deferred taxes
Accrued employee benefits	$	7,135	$	(29	)	$	7,106
Accrued postretirement benefits		2,607		286			2,893
Accrued environmental costs		1,202		—			1,202
Inventory differences		247		489			736
Prepayments and other		1,066		(2,297	)		(1,231	)
Total current(1)		12,257		(1,551	)		10,706
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(122,684	)		(122,684	)
Accrued postretirement benefits		14,824		—			14,824
Accrued environmental costs		1,591		—			1,591
Deferred turnaround costs		—		(11,491	)		(11,491	)
Investments in HEP		44,557		55			44,612
Other		6,212		(2,555	)		3,657
Total noncurrent		67,184		(136,675	)		(69,491	)
Total	$	79,441	$	(138,226	)	$	(58,785	)

	December 31, 2007
	Assets		Liabilities			Total
	(in thousands)
Deferred taxes
Accrued employee benefits	$	9,703	$	(29	)	$	9,674
Accrued postretirement benefits		1,913		—			1,913
Accrued environmental costs		1,282		—			1,282
Inventory differences		247		(6,644	)		(6,397	)
Prepayments and other		2,901		(6,480	)		(3,579	)
Total current(1)		16,046		(13,153	)		2,893
Properties, plants and equipment (due primarily to tax in excess of book depreciation)		—		(108,445	)		(108,445	)
Accrued postretirement benefits		11,479		—			11,479
Accrued environmental costs		2,056		—			2,056
Deferred turnaround costs		—		(1,278	)		(1,278	)
Investments in HEP		43,218		—			43,218
Other		14,037		—			14,037
Total noncurrent		70,790		(109,723	)		(38,933	)
Total	$	86,836	$	(122,876	)	$	(36,040	)

(1) Our net current deferred tax assets are classified as other current assets under “Prepayments and other” in our consolidated balance sheets.

F-25

Notes to consolidated financial statements

We made income tax payments of $21.1 million in 2008, $139.4 million in 2007 and $142.9 million in 2006.

The total amount of unrecognized tax benefits as of December 31, 2008, was $4.4 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	Liability for
	unrecognized
	tax benefits
	(in thousands)
Balance at January 1, 2008	$	3,539
Additions based on tax positions related to the current year		960
Additions for tax positions of prior years		479
Reductions for tax positions of prior years		(628	)
Balance at December 31, 2008	$	4,350

Included in the unrecognized tax benefits at December 31, 2008 are $2.5 million of tax benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new information about a tax position becomes available or the final outcome differs from the amount recorded.

We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. During the year ended December 31, 2008, we recognized $0.8 million in interest (net of related tax benefits) as a component of tax expense. We have not recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any assessment of penalties. We do not expect that unrecognized tax benefits for tax positions taken with respect to 2008 and prior years will significantly change over the next twelve months.

We are subject to U.S. federal income tax, New Mexico income tax and to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through December 31, 2003. This includes a review by the Joint Committee on Taxation Staff of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003 that resulted in no changes to our positions taken on these returns. In 2008, the Internal Revenue Service commenced an examination of our U.S. federal income tax returns for the tax years ended December 31, 2004 and 2005. We anticipate that these audits will be completed by the end of 2009.

NOTE 13:   STOCKHOLDERS’ EQUITY

The following table shows our common shares outstanding and the activity during the year:

	Years ended December 31,
	2008			2007			2006
Common shares outstanding at beginning of year		52,616,169			55,316,615			58,752,942
Issuance of common stock upon exercise of stock options		406,000			1,085,600			902,700
Issuance of restricted stock, excluding restricted stock with performance feature		104,515			230,196			51,952
Vesting of restricted stock with performance feature		84,948			151,000			119,000
Forfeitures of restricted stock		(2,033	)		(23,537	)		(4,984	)
Purchase of treasury stock(1)		(3,266,379	)		(4,143,705	)		(4,504,995	)
Common shares outstanding at end of year		49,943,220			52,616,169			55,316,615

(footnote on following page)

F-26

Notes to consolidated financial statements

(1) Includes shares purchased under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock.

Common Stock Repurchases:  Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the year ended December 31, 2008, we repurchased 3,228,489 shares at a cost of $137.1 million or an average of $42.48 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through December 31, 2008, we have repurchased 16,759,395 shares at a cost of $655.2 million or an average of $39.10 per share.

During the year ended December 31, 2008, we repurchased at market price from certain executives 55,515 shares of our common stock at a cost of $2.0 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

NOTE 14:   OTHER COMPREHENSIVE INCOME (LOSS)

The components and allocated tax effects of other comprehensive income (loss) are as follows:

				Tax expense
	Before-tax			(benefit)			After-tax
	(in thousands)
For the year ended December 31, 2008
Minimum pension liability adjustment	$	(21,572	)	$	(8,391	)	$	(13,181	)
Retirement medical obligation adjustment		1,433			557			876
Unrealized loss on available-for-sale securities		(169	)		(67	)		(102	)
Unrealized loss on HEP cash flow hedge		(12,967	)		(2,290	)		(10,677	)
Other comprehensive loss		(33,275	)		(10,191	)		(23,084	)
Less other comprehensive loss attributable to noncontrolling interest		(7,079	)		—			(7,079	)
Other comprehensive loss attributable to Holly Corporation stockholders	$	(26,196	)	$	(10,191	)	$	(16,005	)
For the year ended December 31, 2007
Minimum pension liability adjustment	$	(9,373	)	$	(3,647	)	$	(5,726	)
Retirement medical obligation adjustment		(5,038	)		(1,960	)		(3,078	)
Unrealized gain on available-for-sale securities		1,779			693			1,086
Other comprehensive loss attributable to Holly Corporation stockholders	$	(12,632	)	$	(4,914	)	$	(7,718	)
For the year ended December 31, 2006
Minimum pension liability adjustment	$	5,542		$	2,156		$	3,386
Unrealized loss on available-for-sale securities		(908	)		(353	)		(555	)
Other comprehensive loss attributable to Holly Corporation stockholders	$	4,634		$	1,803		$	2,831

The temporary unrealized gain (loss) on securities available-for-sale is due to changes in the market prices of securities.

F-27

Notes to consolidated financial statements

Accumulated other comprehensive loss in the Holly Corporation stockholders’ equity section of the balance sheet includes:

	December 31,
	2008			2007
	(in thousands)
Pension obligation adjustment	$	(29,409	)	$	(16,228	)
Retiree medical obligation adjustment		(2,202	)		(3,078	)
Unrealized gain on securities available-for-sale		128			230
Unrealized loss on HEP cash flow hedge, net of noncontrolling interest		(3,598	)		—
Accumulated other comprehensive loss	$	(35,081	)	$	(19,076	)

NOTE 15:   RETIREMENT PLANS

Retirement Plan:  We have a non-contributory defined benefit retirement plan that covers substantially all employees. Our policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

Effective January 1, 2007, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an employee was hired prior to January 1, 2007, and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan was frozen.

F-28

Notes to consolidated financial statements

The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2008 and 2007:

	Years ended December 31,
	2008			2007
	(in thousands)
Change in plan’s benefit obligation
Pension plan’s benefit obligation—beginning of year	$	72,842		$	62,107
Service cost		4,229			4,110
Interest cost		4,692			4,075
Benefits paid		(6,188	)		(5,806	)
Actuarial (gain) loss		(1,087	)		8,356
Pension plan’s benefit obligation—end of year		74,488			72,842
Change in pension plan assets
Fair value of plan assets—beginning of year		56,454			50,414
Actual return on plan assets		(19,924	)		1,846
Benefits paid		(6,188	)		(5,806	)
Employer contributions		15,000			10,000
Fair value of plan assets—end of year		45,342			56,454
Funded status
Under-funded balance	$	(29,146	)	$	(16,388	)
Amounts recognized in consolidated balance sheets
Accrued pension liability	$	(29,146	)	$	(16,388	)
Amounts recognized in accumulated other comprehensive loss
Actuarial loss	$	(43,475	)	$	(21,063	)
Prior service cost		(3,201	)		(3,591	)
Total	$	(46,676	)	$	(24,654	)

The accumulated benefit obligation was $58.7 million and $55.4 million at December 31, 2008 and 2007, respectively. The measurement dates used for our retirement plan were December 31, 2008 and 2007.

The weighted average assumptions used to determine end of period benefit obligations:

	December 31,
	2008			2007
Discount rate		6.50	%		6.40	%
Rate of future compensation increases		4.00	%		4.00	%

F-29

Notes to consolidated financial statements

Net periodic pension expense consisted of the following components:

	Years ended December 31,
	2008			2007			2006
	(in thousands)
Service cost—benefit earned during the year	$	4,229		$	4,110		$	4,270
Interest cost on projected benefit obligations		4,692			4,075			4,133
Expected return on plan assets		(4,793	)		(4,078	)		(3,473	)
Amortization of prior service cost		390			390			258
Amortization of net loss		1,218			908			1,042
Curtailment loss		—			—			663
Settlement loss		—			—			1,589
Net periodic pension expense	$	5,736		$	5,405		$	8,482

The weighted average assumptions used to determine net periodic benefit expense:

	Years ended December 31,
	2008			2007			2006
	(in thousands)
Discount rate		6.40	%		6.00	%		6.05	%
Rate of future compensation increases		4.00	%		4.00	%		4.00	%
Expected long-term rate of return on assets		8.50	%		8.50	%		8.50	%

The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2009 are as follows:

	(in thousands)
Actuarial loss	$	3,984
Prior service cost		390
Total	$	4,374

At year end, our retirement plan assets were allocated as follows:

				Percentage of plan assets
				at year end
	Target allocation			December 31,			December 31,
Asset category	2009			2008			2007
Equity securities		70	%		65	%		68	%
Debt Securities		30	%		35	%		32	%
Total		100	%		100	%		100	%

The investment policy developed for the Holly Corporation Pension Plan (the “Plan”) has been designed exclusively for the purpose of providing the highest probabilities of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are: the Plans’ primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.

The most important component of the investment strategy is the asset allocation between the various classes of securities available to the Plan for investment purposes. The current target asset allocation is 70% equity investments and 30% fixed income investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks.

F-30

Notes to consolidated financial statements

The overall expected long-term rate of return on Plan assets is 8.5% and is estimated using a financial simulation model of asset returns. Model assumptions are derived using historical data given the assumption that capital markets are informationally efficient.

We expect to contribute between $10.0 million to $20.0 million to the retirement plan in 2009. Benefit payments, which reflect expected future service, are expected to be paid as follows: $4.6 million in 2009; $5.2 million in 2010; $5.9 million in 2011; $7.4 million in 2012, $7.6 million in 2013 and $50.4 million in 2014-2018.

Retirement Restoration Plan:  We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal Revenue Code limitations. We expensed $1.1 million, $0.9 million and $0.8 million for the years ended December 31, 2008, 2007 and 2006, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.1 million and $6.6 million at December 31, 2008 and 2007, respectively. As of December 31, 2008, the projected benefit obligation under this plan was $6.1 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $0.2 million in 2009; $0.3 million in 2010; $0.9 million in 2011; $0.6 million in 2012; $1.4 million in 2013 and $2.9 million in 2014-2018.

Defined Contribution Plans:  We have defined contribution “401(k)” plans that cover substantially all employees. Our contributions are based on employee’s compensation and partially match employee contributions. We expensed $3.7 million, $2.8 million and $1.9 million for the years ended December 31, 2008, 2007 and 2006, respectively, in connection with these plans.

Postretirement Medical Plans:  We adopted an unfunded postretirement medical plan as part of the voluntary early retirement program offered to eligible employees in fiscal 2000. As part of the early retirement program, we agreed to allow retiring employees to continue coverage at a reduced cost under our group medical plans until normal retirement age. The accrued liability reflected in the consolidated balance sheets was $6.7 million and $7.5 million at December 31, 2008 and 2007, respectively, related to this plan.

Additionally, we maintain an unfunded postretirement medical plan whereby certain retirees between the ages of 62 and 65 can receive benefits paid by us. Periodic costs under this plan have historically been insignificant.

As of December 31, 2008, the total accumulated postretirement benefit obligation under our postretirement medical plans was $6.7 million.

NOTE 16:   LEASE COMMITMENTS

We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2008, the minimum future rental commitments under operating leases having non-cancellable lease terms in excess of one year are as follows (in thousands):

2009	$	8,825
2010		8,553
2011		7,483
2012		6,453
2013		6,382
Thereafter		22,839
Total	$	60,535

F-31

Notes to consolidated financial statements

Rental expense charged to operations was $9.9 million, $3.2 million and $2.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. Rental expense for the year ended December 31, 2008 includes $6.6 million of rental expense attributable to the operations of HEP as a result of our reconsolidation effective March 1, 2008.

NOTE 17:   CONTINGENCIES AND CONTRACTUAL OBLIGATIONS

Contingencies

In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The income tax issue and the other remaining issues relating to SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding covering the period from 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. A partial settlement covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of approximately $1.3 million in April 2008. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million.

We are a party to various other litigation and proceedings not mentioned in this report that we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.

Contractual obligations

We have entered into a long-term supply agreement to secure a hydrogen supply source for our Woods Cross hydrotreater unit. The contract commits us to purchase a minimum of 5 million standard cubic feet of hydrogen per day at market prices over a 15-year period commencing July 1, 2008. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term.

We also have two crude oil transportation agreements that obligate us to ship a total of approximately 21,000 barrels per day for initial terms of 10 years. Our obligations under these agreements are subject to certain conditions including completion of construction and expansion projects by the transportation companies, and the tariffs that will apply to these commitments have not been finalized. We expect approximately one-half of the total shipment commitment to begin no earlier than the fourth quarter of 2009 and the other one-half to begin no earlier than the fourth quarter of 2010.

F-32

Notes to consolidated financial statements

Other contractual obligations relate to the transportation of natural gas and feedstocks to our refineries under contracts expiring in 2015 through 2023 and various service contracts with expiration dates through 2011.

NOTE 18:   SEGMENT INFORMATION

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

The Refining segment includes the operations of our Navajo Refinery, Woods Cross Refinery and Holly Asphalt Company. The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo and Woods Cross Refineries. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

HEP is a VIE as defined under FIN No. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. The HEP segment also includes a 70% interest in Rio Grande which also provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

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Notes to consolidated financial statements

					Corporate			Consolidations and			Consolidated
	Refining		HEP(1)		and other			eliminations			total
	(in thousands)
Year Ended December 31, 2008
Sales and other revenues	$	5,837,449	$	101,750	$	2,641		$	(74,172	)	$	5,867,668
Depreciation and amortization	$	40,090	$	19,184	$	4,515		$	—		$	63,789
Income (loss) from operations	$	210,252	$	41,734	$	(51,654	)	$	—		$	200,332
Capital expenditures	$	381,227	$	34,317	$	2,515		$	—		$	418,059
Total assets	$	1,288,211	$	458,049	$	141,768		$	(13,803	)	$	1,874,225
Year Ended December 31, 2007
Sales and other revenues	$	4,790,164	$	—	$	1,578		$	—		$	4,791,742
Depreciation and amortization	$	40,325	$	—	$	3,131		$	—		$	43,456
Income (loss) from operations	$	537,118	$	—	$	(70,786	)	$	—		$	466,332
Capital expenditures	$	151,448	$	—	$	9,810		$	—		$	161,258
Total assets	$	1,271,163	$	—	$	392,782		$	—		$	1,663,945
Year Ended December 31, 2006
Sales and other revenues	$	4,021,974	$	—	$	1,752		$	(509	)	$	4,023,217
Depreciation and amortization	$	38,156	$	—	$	1,565		$	—		$	39,721
Income (loss) from operations	$	425,474	$	—	$	(63,583	)	$	—		$	361,891
Capital expenditures	$	105,018	$	—	$	15,411		$	—		$	120,429
Total assets	$	940,400	$	—	$	297,469		$	—		$	1,237,869

(1) HEP segment revenues from external customers were $27.6 million for the year ended December 31, 2008.

NOTE 19:   SIGNIFICANT CUSTOMERS

All revenues were domestic revenues, except for sales of gasoline and diesel fuel for export into Mexico by the Refining segment. The export sales were to an affiliate of PEMEX and accounted for 325.4 million (6%) of our revenues in 2008, $200.0 million (5%) of our revenues in 2007 and $144.4 million (4%) of revenues in 2006. In 2008, 2007 and 2006, we had several significant customers, none of which accounted for more than 10% of our revenues.

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Notes to consolidated financial statements

NOTE 20:   QUARTERLY INFORMATION (UNAUDITED)

	First		Second		Third		Fourth
	quarter		quarter		quarter		quarter		Year
	(in thousands except share data)
Year Ended December 31, 2008
Sales and other revenues	$	1,479,984	$	1,743,822	$	1,719,920	$	923,942	$	5,867,668
Operating costs and expenses	$	1,470,391	$	1,723,596	$	1,636,944	$	836,405	$	5,667,336
Income from operations	$	9,593	$	20,226	$	82,976	$	87,537	$	200,332
Income from continuing operations before income taxes	$	14,146	$	17,801	$	77,496	$	82,982	$	192,425
Net income attributable to Holly Corporation stockholders	$	8,649	$	11,452	$	49,899	$	50,558	$	120,558
Net income per share attributable to Holly Corporation stockholders—basic	$	0.17	$	0.23	$	1.00	$	1.02	$	2.40
Net income per share attributable to Holly Corporation stockholders—diluted	$	0.17	$	0.23	$	1.00	$	1.01	$	2.38
Dividends per common share	$	0.15	$	0.15	$	0.15	$	0.15	$	0.60
Average number of shares of common stock outstanding Basic		51,165		50,158		49,717		49,794		50,202
Diluted		51,515		50,515		50,032		49,997		50,549

F-35

Notes to consolidated financial statements

	First		Second		Third		Fourth
	quarter		quarter		quarter		quarter		Year
	(in thousands except share data)
Year Ended December 31, 2007
Sales and other revenues	$	925,867	$	1,216,997	$	1,208,671	$	1,440,207	$	4,791,742
Operating costs and expenses	$	829,293	$	980,447	$	1,141,039	$	1,374,631	$	4,325,410
Income from operations	$	96,574	$	236,550	$	67,632	$	65,576	$	466,332
Income from continuing operations before income taxes	$	102,228	$	244,763	$	77,267	$	75,186	$	499,444
Net income attributable to Holly Corporation stockholders	$	67,542	$	158,627	$	58,126	$	49,833	$	334,128
Net income per share attributable to Holly Corporation stockholders—basic	$	1.22	$	2.89	$	1.06	$	0.92	$	6.09
Net income per share attributable to Holly Corporation stockholders—diluted	$	1.20	$	2.84	$	1.04	$	0.90	$	5.98
Dividends per common share	$	0.10	$	0.12	$	0.12	$	0.12	$	0.46
Average number of shares of common stock outstanding Basic		55,189		54,959		54,819		54,451		54,852
Diluted		56,318		55,953		55,853		55,098		55,850

NOTE 21:   SUBSEQUENT EVENTS

On April 16, 2009, we entered into a definitive agreement with Sunoco Inc. (R&M) (“Sunoco”) to acquire their refinery located in Tulsa, Oklahoma and associated businesses (the “Tulsa Refinery”) for $65.0 million. Under the terms of the agreement, we will also purchase related inventory which will be valued at market prices at closing. Additionally, we will receive an assignment of the Sunoco specialty lubricant product trademarks in North America and a license to use the same in Central and South America. The transaction is expected to close on June 1, 2009.

HEP closed on a public offering of 2,192,400 common units priced at $27.80 per common unit in May 2009. In addition, we made capital contributions to HEP to maintain our 2% general partner interest.

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