e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____ to ____

Commission File Number 1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		75-1056913

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		(Identification No.)

100 Crescent Court, Suite 1600
Dallas, Texas		75201-6927

(Address of principal executive offices)		(Zip Code)

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

Former name, former address and former fiscal year, if changed since last report

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

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

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

29,808,613 shares of Common Stock, par value $.01 per share, were outstanding on October 31, 2005.

PART I — FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

References throughout this document to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly Report on Form 10-Q has 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.

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations,” “Liquidity and Capital Resources” and “Additional Factors that May Affect Future Results” (including “Risk Management”) in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I and those in Item 1 “Legal Proceedings” in Part II, are forward-looking statements. These statements are based on management’s belief and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

	•		risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets;

	•		the demand for and supply of crude oil and refined products;

	•		the spread between market prices for refined products and market prices for crude oil;

	•		the possibility of constraints on the transportation of refined products;

	•		the possibility of inefficiencies or shutdowns in refinery operations or pipelines;

	•		effects of governmental regulations and policies;

	•		the availability and cost of our financing;

	•		the effectiveness of our capital investments and marketing strategies;

	•		our efficiency in carrying out construction projects;

	•		our ability to acquire refined product operations or pipeline or terminal operations on acceptable terms and to integrate any future acquired operations;

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

	•		general economic conditions;

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation in conjunction with the forward-looking statements included in this Form 10-Q that are referred to above. This summary discussion should be read in conjunction with the discussion under the heading “Additional Factors That May Affect Future Results” included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004 and in conjunction with the discussion in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the headings “Liquidity and Capital Resources” and “Additional Factors That May Affect Future Results.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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DEFINITIONS

Within this report, the following terms have these specific meanings:

“Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse of cracking).

“BPD” means the number of barrels per day of crude oil or petroleum products.

“BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products.

“Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha fractionated directly from crude oil to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the main source of hydrogen for the refinery.

“Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.

“Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing slightly above atmospheric pressure the vapor back to liquid in order to purify, fractionate or form the desired products.

“FCC,” or fluid catalytic cracking, means the breaking down of large, complex hydrocarbon molecules into smaller, more useful ones by the application of heat, pressure and a chemical (catalyst) to speed the process.

“Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures.

“HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.

“Isomerization” means a refinery process for converting C5/C6 gasoline compounds into their isomers, i.e., rearranging the structure of the molecules without changing their size or chemical composition.

“LPG” means liquid petroleum gases.

“MTBE” means methyl tertiary butyl ether, a high octane gasoline blend stock that is used to make various grades of gasoline.

“Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane stocks produced to make various grades of gasoline.

“Refining gross margin” or “refinery gross margin” means the difference between average net sales price and average costs of products per barrel of produced refined products. This does not include the associated depreciation, depletion and amortization costs.

“Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks while producing hydrogen in the process.

“Solvent deasphalter / residuum oil supercritical extraction (“ROSE”)” means a refinery process that uses a light hydrocarbon like propane or butane to extract non asphaltene heavy oils from asphalt or atmospheric reduced crude. These deasphalted oils are then further converted to gasoline and diesel in the FCC process. The remaining asphaltenes are either sold, blended to fuel oil or blended with other asphalt as a hardener.

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Item 1. Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands, except share data)


	September 30,			December 31,
	2005			2004
	(Unaudited)

ASSETS
Current assets:
Cash and cash equivalents	$	76,309		$	67,460
Marketable securities		184,361			96,215

Accounts receivable: Product and transportation		209,277			105,998
Crude oil sales		272,000			175,732

		481,277			281,730

Inventories: Crude oil and refined products		100,128			92,544
Materials and supplies		14,281			12,424

		114,409			104,968

Income taxes receivable		—			6,394
Prepayments and other		15,883			16,139

Total current assets		872,239			572,906

Properties, plants and equipment, at cost		533,246			572,147
Less accumulated depreciation, depletion and amortization		(244,904	)		(259,874	)

		288,342			312,273

Marketable securities (long-term)		12,981			55,590
Transportation agreements		—			4,718
Investments in and advances to joint ventures		—			12,423

Other assets: Turnaround costs (long-term)		9,021			13,535
Intangibles and other		14,674			11,268

		23,695			24,803


Total assets	$	1,197,257		$	982,713


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	553,097		$	377,717
Accrued liabilities		32,173			37,975
Income taxes payable		23,117			—
Current maturities of long-term debt		8,572			8,572

Total current liabilities		616,959			424,264

Deferred income taxes		22,488			20,462
Long-term debt, less current maturities		—			25,000
Other long-term liabilities		13,106			15,521
Commitments and contingencies		—			—
Minority interests		—			157,550
Distributions in excess of investment in Holly Energy Partners		155,683			—

Stockholders’ equity:
Preferred stock, $1.00 par value — 1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value — 50,000,000 shares authorized; 35,374,896 and 34,804,796 shares issued as of September 30, 2005 and December 31, 2004, respectively		354			348
Additional capital		40,140			29,281
Retained earnings		458,872			339,798
Accumulated other comprehensive loss		(1,654	)		(1,719	)
Common stock held in treasury, at cost — 5,262,033 and 3,510,036 shares as of September 30, 2005 and December 31, 2004, respectively		(108,691	)		(27,792	)

Total stockholders’ equity		389,021			339,916


Total liabilities and stockholders’ equity	$	1,197,257		$	982,713

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)

(In thousands, except per share data)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004

Sales and other revenues	$	935,279		$	597,448		$	2,358,300		$	1,629,240

Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		772,887			507,630			1,933,915			1,308,179
Operating expenses (exclusive of depreciation, depletion, and amortization)		46,947			46,762			146,187			127,494
General and administrative expenses (exclusive of depreciation, depletion, and amortization)		12,616			12,001			35,527			35,947
Depreciation, depletion and amortization		9,390			9,985			34,336			29,840
Exploration expenses, including dry holes		69			122			310			550

Total operating costs and expenses		841,909			576,500			2,150,275			1,502,010

Income from operations		93,370			20,948			208,025			127,230

Other income (expense):
Equity in earnings (loss) of joint ventures		—			348			(685	)		293
Equity in earnings of Holly Energy Partners		3,296			—			3,296			—
Minority interests in income of partnerships		—			(2,704	)		(6,721	)		(3,699	)
Interest income		1,202			933			4,455			3,323
Interest expense		(501	)		(922	)		(4,706	)		(2,628	)

		3,997			(2,345	)		(4,361	)		(2,711	)

Income before income taxes		97,367			18,603			203,664			124,519

Income tax provision:
Current		37,015			31,381			76,425			70,953
Deferred		(698	)		(24,303	)		131			(22,928	)

		36,317			7,078			76,556			48,025


Income before cumulative change in accounting principle		61,050			11,525			127,108			76,494
Cumulative effect of accounting change (net of income tax expense of $426)		669			—			669			—


Net Income	$	61,719		$	11,525		$	127,777		$	76,494


Basic earnings per share:
Income before cumulative change in accounting principle	$	2.00		$	0.37		$	4.07		$	2.43
Cumulative effect of accounting change		0.02			—			0.02			—

Net income	$	2.02		$	0.37		$	4.09		$	2.43


Diluted earnings per share:
Income before cumulative change in accounting principle	$	1.95		$	0.36		$	3.98		$	2.37
Cumulative effect of accounting change		0.02			—			0.02			—

Net income	$	1.97		$	0.36		$	4.00		$	2.37


Cash dividends declared per common share	$	0.10		$	0.08		$	0.28		$	0.21


Average number of common shares outstanding:
Basic		30,618			31,513			31,253			31,444
Diluted		31,386			32,420			31,980			32,316

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(In thousands)


	Nine Months Ended
	September 30,
	2005			2004
Cash flows from operating activities:
Net income	$	127,777		$	76,494
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		34,336			29,840
Deferred income taxes		131			(22,928	)
Minority interests in income of partnerships		6,721			3,699
Equity in (earnings) loss of joint ventures		685			(293	)
Equity in earnings of HEP		(3,296	)		—
Equity based compensation expense		1,608			1,321
(Increase) decrease in current assets:
Accounts receivable		(199,045	)		(115,522	)
Inventories		(1,336	)		16,966
Income taxes receivable		10,735			7,806
Prepayments and other		(10	)		(3,458	)
Increase (decrease) in current liabilities:
Accounts payable		166,589			101,919
Accrued liabilities		(1,026	)		11,378
Income taxes payable		18,964			23,738
Turnaround expenditures		(1,038	)		—
Prepaid transportation refund		—			25,000
Other, net		(3,236	)		4,421


Net cash provided by operating activities		158,559			160,381
Cash flows from investing activities:
Additions to properties, plants and equipment		(58,062	)		(27,915	)
Proceeds from HEP offering		—			145,460
HEP formation costs		—			(3,476	)
Acquisition by HEP of pipeline and terminal assets		(121,853	)		—
Proceeds from sale of intermediate pipelines to HEP (excludes deemed distribution)		5,800			—
Decrease in cash due to deconsolidation of HEP		(54,310	)		—
Investments and advances to joint ventures		—			(3,314	)
Purchase of additional interest in joint venture, net of cash		(18,506	)		—
Proceeds from sale of interest in joint venture		832			—
Distributions from joint ventures		—			4,410
Distributions from HEP subsequent to deconsolidation		4,317			—
Purchases of marketable securities		(254,801	)		(87,488	)
Sales and maturities of marketable securities		209,371			3,060

Net cash provided by (used for) investing activities		(287,212	)		30,737

Cash flows from financing activities:
Proceeds from issuance of HEP senior notes, net of underwriter discount		181,955			—
Net decrease in borrowings under revolving credit agreements		(25,000	)		(25,000	)
Debt issuance costs		(948	)		(3,018	)
Issuance of common stock upon exercise of options		2,736			3,508
Purchase of treasury stock		(80,899	)		(15,293	)
Cash dividends		(8,232	)		(5,808	)
Cash distributions to minority interests		(9,486	)		(2,820	)
Deemed distribution from HEP related to the sale of intermediate pipelines		71,851			—
Excess tax benefit from equity based compensation		5,525			3,124

Net cash provided by (used for) financing activities		137,502			(45,307	)

Cash and cash equivalents:

Increase for the period		8,849			145,811
Beginning of period		67,460			11,690

End of period	$	76,309		$	157,501


Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	1,486		$	1,481
Income taxes	$	40,569		$	36,241

See accompanying notes.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

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, this Quarterly report on Form 10-Q has 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.

As of September 30, 2005, we:

	•		owned and operated three refineries consisting of a petroleum refinery in Artesia, New Mexico that 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”), and refineries in Woods Cross, Utah and Great Falls, Montana;

	•		owned approximately 800 miles of crude oil pipelines located principally in West Texas and New Mexico;

	•		owned 100% of NK Asphalt Partners which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and

	•		owned a 45.0% interest in Holly Energy Partners, L.P. (“HEP”), which owns logistic assets including approximately 1,600 miles of petroleum product pipelines located in Texas, New Mexico and Oklahoma (including 340 miles of leased pipeline); eleven refined product terminals; two refinery truck rack facilities, a refined products tank farm facility, and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

On July 8, 2005, we closed on a transaction for HEP to acquire our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities, which reduced our ownership interest in HEP to 45.0%. Under the provision of the Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised) (“FIN 46”) “Consolidation of Variable Interest Entities,” we have deconsolidated HEP effective July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward (see Note 2).

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of September 30, 2005, the consolidated results of operations and comprehensive income for the three months and nine months ended September 30, 2005 and 2004 and consolidated cash flows for the nine months ended September 30, 2005 and 2004 in accordance with the rules and regulations of the SEC. Although certain notes and other information required by accounting principles generally accepted in the United States have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2004 filed with the SEC.

We use the last-in, first-out (“LIFO”) method of valuing inventory. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation.

Our results of operations for the first nine months of 2005 are not necessarily indicative of the results to be expected for the full year. Certain reclassifications have been made to prior reported amounts to conform to current classifications.

On February 28, 2005, HEP closed on the acquisition of assets from Alon USA, Inc. and certain of its affiliates (collectively “Alon”). See Note 3 for additional information regarding HEP’s asset acquisition from Alon.

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HOLLY CORPORATION

In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by a subsidiary of Koch Materials Company (“Koch”) increasing our ownership in NK Asphalt Partners from 49% to 100%. The partnership now does business under the name of “Holly Asphalt Company.” Additionally, on February 28, 2005, we sold our 49% interest in MRC Hi-Noon LLC to our joint venture partner. See Note 7 for additional information regarding both of these transactions.

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and NK Asphalt Partners. Prior to our deconsolidation of HEP on July 1, 2005 our operations were organized into two business divisions, which were Refining and HEP. Our operations that are not included in either the Refining or HEP (prior to its deconsolidation) business divisions include the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program, and prior to the deconsolidation of HEP, the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us as well as the recognition of the minority interests’ income of HEP.

New Accounting Pronouncements

SFAS No. 123 (revised) “Share-Based Payment”

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. This standard was to become effective for us for the first interim period beginning after June 15, 2005, however in April 2005, the SEC allowed for a delay in the implementation of this standard, with the result that we are not required to adopt this standard until our 2006 year. SFAS 123 (revised) allows for either modified prospective recognition of compensation expense or modified retrospective recognition, which may be back to the original issuance of SFAS 123 or only to interim periods in the year of adoption. We elected for early adoption of this standard on July 1, 2005 based on modified retrospective application with early application under SFAS 123 to prior quarters in the current year (see Note 5).

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”

In December 2004, the FASB issued SFAS 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4.” This amendment requires abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) to be recognized as current-period charges. This standard also requires that the allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. This standard will be effective for fiscal years beginning after June 15, 2005. We are studying the provisions of this new standard to determine the impact, if any, on our financial statements.

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

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principles and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement becomes effective for fiscal years beginning after December 15, 2005. We believe the adoption of this standard should not have an impact on our financial statements.

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HOLLY CORPORATION


NOTE 2:		Investment in Holly Energy Partners and Their Acquisition of Our Intermediate Feedstock Pipelines

On July 8, 2005, we closed on a transaction where HEP acquired our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total acquisition price was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 in common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the approximately $77.7 million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale of 1.1 million of its common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and the recently completed offering of an additional $35.0 million in principal amount of their 6.25% senior notes due 2015. This acquisition was made pursuant to an option to purchase these pipelines we granted to HEP at the time of their initial public offering in July 2004. Following the acquisition, HEP plans to expend up to $3.5 million to expand the capacity of the pipelines to meet the needs of the expansion at our Navajo Refinery. We have agreed to a 15-year pipelines agreement with a minimum annual volume commitment of 72,000 BPD on the pipelines, which will result in revenues to HEP of approximately $11.8 million per calendar year. In addition, we have agreed to indemnify HEP, subject to certain limits, for any environmental noncompliance and remediation liabilities occurring or existing prior to the closing date. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including the 2% general partner interest.

In January 2003 (revised December 2003), FASB issued Interpretation No. 46, “ Consolidation of Variable Interest Entities” (“FIN 46”), which we adopted on December 31, 2003. This interpretation defined a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity, or have voting rights that are not proportionate to their economic interests. This standard requires a company to consolidate a variable interest entity (“VIE”) if it is allocated a majority of the entity’s expected losses or expected residual returns. Through June 30, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own as a minority interest in the ownership and earnings. HEP is a VIE as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines, we have determined that our beneficial variable interest in HEP is now less than 50%; and therefore as required by FIN 46, we are deconsolidating HEP as of July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward, and our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, will now be recorded using the equity method. HEP does have risk associated with its operations. HEP has three major customers, one being us. If any of the customers fails to meet the desired shipping levels or terminates its contracts, HEP could suffer substantial losses unless a new customer if found. If HEP does suffer losses, we would recognize our percentage of those losses based on our ownership percentage at that time.

In addition to the intermediate feedstock pipelines acquired by HEP, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or the intermediate pipelines acquisition. With respect to intermediate pipelines transaction, this resulted in a deemed distribution to us from HEP of $71.9 million. Due to the historical basis being less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP from our consolidated financial statements on July 1, 2005. The balance of distributions in excess of our investment in HEP was $155.7 million at September 30, 2005.

As of July 1, 2005, the impact of this deconsolidation was an increase in the liability account of investments in HEP of $83.8 million, a decrease in property, plant and equipment of $157.8 million, a decrease in cash of $54.3 million, a decrease in other current assets of $3.6 million, a decrease in transportation agreements of $62.7 million, a decrease in other assets of $4.5 million, a decrease in minority interest of $ 179.5 million, a decrease in current liabilities of $3.9 million and a decrease in other long-term liabilities of $183.3 million.

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HOLLY CORPORATION

The following tables provide summary financial results for HEP subsequent to its formation on July 13, 2004.


	September 30,		December 31,
	2005		2004
	(In thousands)

Current assets	$	25,925	$	22,533
Properties and equipment, net		163,508		74,626
Other assets		64,829		6,599

Total assets	$	254,262	$	103,758


Current liabilities	$	6,037	$	3,413
Long-term liabilities		181,713		25,585
Minority interest		11,681		13,232
Partners’ equity		54,831		61,528

Total liabilities and partners’ equity	$	254,262	$	103,758


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)

Revenues	$	21,517		$	12,190		$	57,551		$	12,190
Operating costs and expenses		11,332			6,758			31,347			6,758

Operating income		10,185			5,432			26,204			5,432
Other expenses		(2,893	)		(573	)		(6,545	)		(573	)

Net income	$	7,292		$	4,859		$	19,659		$	4,859

We have related party transactions with HEP for pipeline and terminal services, certain employee costs, insurance costs, and administrative costs under the original Pipelines and Terminals Agreement, Intermediate Pipelines Agreement and Omnibus Agreement. Pipeline and terminal expenses paid to HEP were $12.5 million for the three months ended September 30, 2005. Under the Omnibus Agreement, we charged HEP $0.5 million for the three months ended September 30, 2005 for general and administrative services and $1.8 million for reimbursement of employee costs supporting our operations, which we record as a reduction in expenses. In the three months ended September 30, 2005, we received $4.3 million in distributions from HEP as regular distributions on our subordinated units and general partner interest. We also have a receivable of $3.8 million and a payable of $4.8 million with HEP which is included in accounts receivable — product and transportation and accounts payable, respectively, in our consolidated balance sheet at September 30, 2005.

NOTE 3: HEP’s Alon Acquisition

As HEP is no longer consolidated in our financial statements effective July 1, 2005 (see Note 2), we no longer include in our consolidated financial statements the assets acquired on February 28, 2005 by HEP as discussed in this note below. As we reported HEP as a consolidated subsidiary during the six months ended June 30, 2005, the following summarizes HEP’s acquisition during that period.

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HOLLY CORPORATION

The total consideration paid by HEP for these pipeline and terminal assets was $120 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units in five years following the acquisition date. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015. HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under its credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. HEP amended its credit agreement prior to the Alon acquisition and note offering to allow for these events as well as to amend certain of the restrictive covenants. In connection with the Alon transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon. Under this agreement, Alon agreed to transport on the pipelines and throughput volumes through the terminals, a volume of refined products that would result in minimum revenues to HEP of $20.2 million per year. The agreed upon tariffs at the minimum volume commitment will increase or decrease each year at a rate equal to the percentage change in the producer price index, but not below the initial tariffs. Alon’s minimum volume commitment was calculated based on 90% of Alon’s recent usage of these pipeline and terminals taking into account a 5,000 BPSD expansion of Alon’s Big Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue amount, as adjusted for changes in the producer price index, Alon will receive an annual 50% discount on incremental revenues. Alon’s obligations under the pipelines and terminals agreement may be reduced or suspended under certain circumstances. HEP granted Alon a second mortgage on the pipelines and terminals to secure certain of Alon’s rights under the pipelines and terminals agreement. Alon will have a right of first refusal to purchase the pipelines and terminals if HEP decides to sell them in the future. Additionally, HEP entered into an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon, under which Alon will indemnify HEP subject to a $100,000 deductible and a $20 million maximum liability cap.

The acquisition of the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The aggregate consideration amounted to $146.6 million, which consisted of $24.7 million fair value of HEP’s Class B subordinated units, $120 million in cash and $1.9 million of transaction costs. In accounting for this acquisition, we recorded pipeline and terminal assets of $86.9 million and an intangible asset of $59.7 million, representing the value of the 15-year pipelines and terminals agreement for transportation.

NOTE 4: Earnings Per Share

Basic income per share is calculated as net income divided by average number of shares of common stock outstanding. Diluted income per share assumes, when dilutive, issuance of the net incremental shares from stock options and variable performance shares. Income per share amounts reflect the two-for-one stock split in August 2004. The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations for income:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(In thousands)

Net income	$	61,719	$	11,525	$	127,777	$	76,494

Average number of shares of common stock outstanding		30,618		31,513		31,253		31,444
Effect of dilutive stock options and variable restricted shares		768		907		727		872

Average number of shares of common stock outstanding assuming dilution		31,386		32,420		31,980		32,316


Income per share — basic	$	2.02	$	0.37	$	4.09	$	2.43

Income per share — diluted	$	1.97	$	0.36	$	4.00	$	2.37

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HOLLY CORPORATION

NOTE 5: Stock-Based Compensation

We elected early adoption of SFAS 123 (revised) on July 1, 2005 based on modified retrospective application with early application under SFAS 123 to prior quarters in the current year. Also as part of this adoption, we recorded a cumulative effect of a change in accounting principle relating to our performance units, as discussed below.

On September 30, 2005, we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for those plans was $5.6 million and $7.2 million for the nine months ended September 30, 2005 and 2004 respectively. No compensation cost was recorded during 2004 related to the stock options as the stock options were being measured in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $2.2 million and $2.8 million for the nine months ended September 30, 2005 and 2004, respectively. It is currently our policy to issue new shares for settlement of option exercises or restricted stock grants. At September 30, 2005, 1,606,946 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which allows for awards of options, restricted stock, or other performance awards.

Previously awarded stock options and all other compensation arrangements based on the market value of our common stock have been adjusted to reflect the two-for-one stock split in August 2004.

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 of each option awarded was estimated on the date of grant using the Black-Scholes option pricing model.

A summary of option activity as of September 30, 2005, and changes during the nine months ended September 30, 2005 is presented below:


						Weighted-
				Weighted–		Average		Aggregate
				Average		Remaining		Intrinsic
				Exercise		Contractual		Value
Options	Shares			Price		Term		($000)

Outstanding at January 1, 2005		1,734,400		$	5.19
Exercised		(485,650	)		5.63
Forfeited or expired		(4,000	)		5.95

Outstanding at September 30, 2005		1,244,750		$	5.01		4.7	$	73,402

Exercisable at September 30, 2005		986,750		$	4.66		4.5	$	58,533

The total intrinsic value of options exercised during the nine months ended September 30, 2005 and 2004, was $14.7 million and $8.1 million, respectively.

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HOLLY CORPORATION

A summary of the status of our nonvested options as of September 30, 2005 and changes during the nine months ended September 30, 2005, is presented below:


				Weighted-
				Average
				Grant-Date
Nonvested Options	Options			Fair Value

Nonvested at January 1, 2005		508,000		$	1.85
Vested		(246,000	)		1.62
Forfeited		(4,000	)		1.82

Nonvested at September 30, 2005		258,000		$	2.06

As of September 30, 2005, there was $254,000 of total unrecognized compensation cost related to the stock options granted. That cost is expected to be recognized over a weighted-average period of one half of one year. The total fair value of shares vested during the nine months ended September 30, 2005 and 2004, was $0.4 million and $0.7 million, respectively.

Cash received from option exercises under the stock option plans for the nine months ended September 30, 2005 and 2004, was $2.7 million and $3.5 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $5.7 million and $3.1 million for the nine months ended September 30, 2005 and 2004, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with vesting generally over a period of two to five years. Although ownership of the shares does not transfer to the recipients until the shares vest, recipients have dividend and voting 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 was measured at the market price as of the date of grant and is being amortized over the vesting periods, including the shares issued to the key executives, as we expect those share to fully vest.

A summary of restricted stock grant activity as of September 30, 2005, and changes during the nine months ended September 30, 2005 is presented below:


				Weighted–
				Average
				Grant-Date		Aggregate Intrinsic
Restricted Stock	Grants			Fair Value		Value ($000)

Outstanding at January 1, 2005 (not vested)		288,104		$	15.00
Vesting and transfer of ownership to recipients		(74,450	)		13.63
Granted		64,600			34.06
Forfeited		(4,100	)		22.54

Outstanding at September 30, 2005 (not vested)		274,154		$	19.75	$	17,540

The total intrinsic value of restricted stock vested and transferred to recipients during the nine months ended September 30, 2005 was $2.5 million. There was no restricted stock vested and transferred to recipients during 2004. As of September 30, 2005, there was $3.2 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 2.4 years. The total fair value of shares vested during the nine months ended September 30, 2005 was $1.0 million.

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HOLLY CORPORATION

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 cash upon meeting the performance criteria over the service period, and generally vest over a period of one to three years. The cash benefit payable under these grants is based upon our share price and upon our total shareholder return during the requisite period as compared to the total shareholder return of our peer group of refining companies. The fair value of each performance share unit award is being revalued quarterly based on our valuation model and the corresponding expense is being amortized over the vesting periods.

The fair value of the performance share units is based on an expected cash flow approach at the grant date and at the end of each subsequent quarter. The analysis utilizes the current stock price, dividend yield, historical total returns as of the measurement date, expected total returns based on a capital asset pricing model methodology, standard deviation of historical returns and comparison of expected total returns with the peer group. The expected total return and historical standard deviation is applied to a lognormal expected return distribution in a Monte Carlo simulation model to identify the expected range of potential returns and probabilities of expected returns. For our performance share units, the price of the stock ranges from $16.50 to $63.98, the expected dividend yields range from 0.6% to 1.9%, and the risk-free rates range from 2.64% to 4.18% at the various measurement dates. The range of inputs reflects changes in the remaining life of the performance share units and changes in market conditions between measurement dates. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information available at each measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:


		Standard
Company	Expected Return on Equity	Deviation (Monthly)
Holly	11.0% to 12.5%	8.2% to 11.1%
Peer group	9.0% to 14.0%	6.5% to 20.4%

A summary of performance share units activity as of September 30, 2005, and changes during the nine months ended September 30, 2005 is presented below:


Performance Share Units	Grants

Outstanding at January 1, 2005 (not vested)		277,350
Vesting and payment of cash benefit to recipients		(162,900	)
Granted		69,162
Forfeited		(4,100	)

Outstanding at September 30, 2005 (not vested)		179,512

The total amount of cash paid related to vested performance share units during the nine months ended September 30, 2005 was $6.3 million. There was no cash paid related to the units during 2004. As of September 30, 2005, the liability associated with these awards was $5.6 million and is recorded in accrued liabilities on our consolidated balance sheet. Based on the weighted average fair value at September 30, 2005 of $73.39, there was $7.6 million of total unrecognized compensation cost related to nonvested performance share units. That cost is expected to be recognized over a weighted-average period of 1.8 years.

With the adoption SFAS 123 (revised), we recorded a cumulative effect of a change in accounting principle relating to our performance units, due to the initial effect of measuring these awards at fair value, where previously they were measured at intrinsic value. The total cumulative effect of a change in accounting principle recorded upon adoption was a gain of $669,000, net of a deferred tax expense of $426,000.

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HOLLY CORPORATION

NOTE 6: Restated Financial Statements for 2005

Under the modified retrospective application of SFAS 123 (revised) (see Note 5), which allows early application under SFAS 123 to prior quarters in the current year, we are restating our financial statements for periods ended March 31, 2005 and June 30, 2005. We have also elected to reclass all marketing costs associated with our refining operations to operating expenses from the line item previously named selling, general and administrative expenses and rename that line general and administrative expenses. The following tables provide restated income statements for these periods and are unaudited.


	Six Months Ended			Three Months Ended
	June 30, 2005			June 30, 2005			March 31, 2005
	(In thousands)

Sales and other revenues	$	1,423,021		$	771,296		$	651,725

Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		1,161,028			604,835			556,193
Operating expenses (exclusive of depreciation, depletion, and amortization)		99,240			53,054			46,186
General and administrative expenses (exclusive of depreciation, depletion, and amortization)		22,911			12,325			10,586
Depreciation, depletion and amortization		24,946			13,127			11,819
Exploration expenses, including dry holes		241			139			102

Total operating costs and expenses		1,308,366			683,480			624,886

Income from operations		114,655			87,816			26,839

Other income (expense):
Equity in earnings (loss) of joint ventures		(685	)		—			(685	)
Minority interests in income of partnerships		(6,721	)		(3,119	)		(3,602	)
Interest income		3,253			2,085			1,168
Interest expense		(4,205	)		(2,661	)		(1,544	)

		(8,358	)		(3,695	)		(4,663	)

Income before income taxes		106,297			84,121			22,176

Income tax provision		40,239			31,697			8,542

Net Income	$	66,058		$	52,424		$	13,634


Basic earnings per share:
Net income as previously reported	$	2.06		$	1.64		$	0.41
Adoption of FASB 123 (revised)		0.03			0.02			0.02

Net income as adjusted	$	2.09		$	1.66		$	0.43


Diluted earnings per share:
Net income as previously reported	$	2.01		$	1.61		$	0.41
Adoption of FASB 123 (revised)		0.03			0.01			0.01

Net income as adjusted	$	2.04		$	1.62		$	0.42


Cash dividends declared per common share	$	0.18		$	0.10		$	0.08


Average number of common shares outstanding:
Basic		31,576			31,637			31,514
Diluted		32,282			32,359			32,195

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HOLLY CORPORATION

NOTE 7: 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.

Starting in the third quarter of 2004, we began investing 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”) and auction rate securities (“ARS”). Although VRDN and ARS 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. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS 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 temporary and reported as a component of accumulated other comprehensive income.

The following is a summary of our available-for-sale securities at September 30, 2005:


	Available-for-Sale Securities
			Gross		Estimated
			Unrealized		Fair Value
			(Gains)		(Net Carrying
	Amortized Cost		Losses		Amount)
	(Dollars in thousands)
States and political subdivisions	$	193,756	$	314	$	193,442
Corporate debt securities		3,900		—		3,900

Total debt securities	$	197,656	$	314	$	197,342

During the nine months ended September 30, 2005 and 2004, we recognized $0.3 million in losses related to 168 sales and maturities and less than $0.1 million in gains related to two sales and maturities where we received $209.4 million and $3.1 million in proceeds, respectively. The realized gains and losses represent the difference between the purchase price and market value on the maturity date or sales date.

NOTE 8: Investments in Joint Ventures

Prior to February 2005, NK Asphalt Partners was owned 49% by us and 51% by Koch, and did business under the name “Koch Asphalt Solutions – Southwest.” We accounted for this investment using the equity method. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by Koch for $16.9 million plus working capital. This purchase increased our ownership in NK Asphalt Partners from 49% to 100% and eliminated any further obligations we had with respect to additional contributions under the joint venture agreement. The partnership manufactures and markets asphalt and asphalt products from various terminals in Arizona and New Mexico and now does business under the name of “Holly Asphalt Company.” From the date of acquisition of the additional 51%, we have consolidated the results of NK Asphalt Partners in our consolidated financial statements. All intercompany transactions have been eliminated in consolidation. The purchase price was preliminarily allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. The final allocation of the purchase price is pending an independent appraisal, which is currently expected to be completed by year-end. The total purchase consideration for the 51% interest, including expenses, was $21.9 million, less cash of $3.4 million which was recorded due to the consolidation of NK Asphalt Partners at the time of the 51% acquisition.

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HOLLY CORPORATION

In addition to the cash, at the date of the acquisition, we preliminarily recorded current assets of $11.7 million, net property, plant and equipment of $20.5 million, intangible assets of $5.3 million, goodwill of $0.9 million, and current liabilities of $8.5 million, and eliminated our equity investment. All asphalt produced at our Navajo Refinery is sold at market prices to an affiliate under a supply agreement. Sales to the joint venture during 2005, prior to the acquisition, were $3.9 million and for the nine months ended September 30, 2004 were $25.6 million.

Prior to February 28, 2005, we had a 49% interest in MRC Hi-Noon LLC, a joint venture operating retail service stations and convenience stores in Montana, and we accounted for our share of earnings from the joint venture using the equity method. At December 31, 2004, we had a reserve balance of approximately $0.8 million related to the collectability of advances to the joint venture and related accrued interest. On February 28, 2005, we sold our 49% interest to our joint venture partner and agreed to accept partial payment on the advances we previously made to the joint venture. In connection with this transaction, we received $0.8 million, which resulted in a book gain to us of $0.5 million.

NOTE 9: Environmental

Consistent with our accounting policy for environmental remediation and cleanup costs, we expensed $0.4 million and $2.6 million during the nine months ended September 30, 2005 and 2004 for environmental remediation and cleanup obligations. The accrued environmental liability reflected in the consolidated balance sheet was $3.2 million and $3.6 million at September 30, 2005 and December 31, 2004, respectively, of which $2.2 million and $2.4 million was classified as other long-term liabilities, respectively. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 10: Debt


	September 30,			December 31,
	2005			2004
	(In thousands)
Senior Notes
Series C	$	5,572		$	5,572
Series D		3,000			3,000
HEP — 6.25% senior notes		—			—

		8,572			8,572

Credit agreement facility
Holly Corporation		—			—
HEP		—			25,000

		—			25,000

Total debt		8,572			33,572

Current maturities of long-term debt		(8,572	)		(8,572	)

Total debt classified as long-term	$	—		$	25,000

Credit Facility

On July 1, 2004, we entered into a new $175 million secured revolving credit facility with Bank of America as administrative agent and lender, with a term of four years and an option to increase the facility to $225 million subject to certain conditions. The credit facility may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at September 30, 2005. At September 30, 2005, we had outstanding letters of credit totaling $2.3 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.7 million at September 30, 2005.

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HOLLY CORPORATION

HEP Debt Information

As HEP is no longer consolidated in our financial statements effective July 1, 2005 (see Note 2), we no longer include the debt of HEP in our consolidated financial statements. As we reported HEP as a consolidated subsidiary during the six months ended June 30, 2005, the following summarizes HEP’s debt activity during the year.

HEP’s Credit Facility

One of our affiliates, Holly Energy Partners — Operating, L.P., a wholly-owned subsidiary of HEP, entered into a four-year $100 million credit facility with Union Bank of California, as administrative agent and lender, in conjunction with the initial public offering of HEP, with an option to increase the amount to $175 million under certain conditions. The credit facility is available to fund capital expenditures, acquisitions, working capital and for general partnership purposes. The credit facility matures in July 2008. The credit facility was amended effective February 28, 2005 to allow for the closing of the Alon transaction and the related senior notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from its senior note offering, HEP repaid $30 million of outstanding indebtedness under the credit facility, including $5 million drawn shortly before the closing of the Alon transaction. The credit facility was amended effective July 8, 2005 to allow for the closing of our intermediate pipelines transaction as well as to amend certain of the restrictive covenants.

HEP’s Senior Notes Due 2015

HEP financed the $120 million cash portion of the Alon transaction through its private offering on February 28, 2005 of $150 million principal amount of 6.25% senior notes due 2015 (“Senior Notes”). HEP used the balance to repay $30 million of outstanding indebtedness under its credit facility, including $5 million drawn shortly before the closing of the Alon transaction.

HEP financed a portion of the cash piece of the consideration for the intermediate pipelines with the private offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes.

The Senior Notes mature on March 1, 2015 and bear interest at 6.25%. The Senior Notes are unsecured and impose certain restrictive covenants, including limitations on 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 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 Senior Notes.

On July 28, 2005, HEP filed a registration statement to allow the holders of the Senior Notes to exchange the Senior Notes for exchange notes registered with the SEC with substantially identical terms, which registration became effective in September 2005. The exchange offer launched September 22, 2005 and closed on October 25, 2005 with all the Senior Notes being exchanged. The exchange notes are generally freely transferable but are a new issue of securities for which certain of the initial purchasers have indicated they intend to make a market but for which there may not initially be a market.

The $185.0 million principal amount of Senior Notes is not recorded on our accompanying consolidated balance sheet at September 30, 2005 due to the deconsolidation of HEP on July 1, 2005. Although the Senior Notes were reflected on our consolidated balance sheet (because HEP was a consolidated subsidiary) through June 30, 2005, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable for $150 million of principal amount of the Senior Notes either directly or as guarantors. Through our subsidiaries, we have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of $35 million of the principal amount of the Senior Notes.

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HOLLY CORPORATION

Interest Rate Risk Management

HEP has entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of its Senior Notes from a fixed rate to variable rates. The interest rate on the $60 million notional amount will be equal to the three month LIBOR rate plus an applicable margin of 1.1575%, which equaled an effective interest rate of 4.5% on $60 million of the debt during the six months ended June 30, 2005, which represents the time HEP was a consolidated subsidiary. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes. HEP accounts for this swap as an effective fair value hedge, so the swap has only a nominal effect on earnings.

Other Debt Information

The carrying amounts of our debt recorded on our consolidated balance sheet are approximately equal to fair value.

NOTE 11: Minority Interests

As HEP is no longer consolidated in our financial statements effective July 1, 2005 (see Note 2), we no longer have minority interest reported on our consolidated balance sheet.

The following table sets forth the changes in the minority interests balance attributable to third-party investors’ interests in HEP.


Minority interests at December 31, 2004	$	157,550

Minority interests’ share of HEP earnings		6,721
Cash distributions to minority interests		(9,486	)
Issuance by HEP of Class B subordinated units in conjunction with Alon asset acquisition		24,674
Amortization of HEP restricted units		25
Deconsolidation of HEP		(179,484	)

Minority interests at September 30, 2005	$	—

NOTE 12: Stockholders’ Equity

Two-For-One Stock Split: On August 2, 2004, we announced that our Board of Directors approved a two-for-one stock split payable in the form of a stock dividend of one share of common stock for each issued and outstanding share of common stock. The dividend was paid on August 30, 2004 to all record holders of common stock at the close of business on August 16, 2004. The average number of shares outstanding has been adjusted to reflect the two-for-one stock split.

Common Stock Repurchases: On May 19, 2005, we announced that our Board of Directors authorized the repurchase of up to $100.0 million of our 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 nine months ended September 30, 2005, we repurchased 1,727,207 shares at a cost of approximately $83.1 million (of which $3.0 million of the cash settlement was after September 30, 2005) or an average of $48.10 per share under this repurchase initiative.

During the three months ended March 31, 2005, we repurchased at current market price from certain executives 24,790 shares of our common stock at a cost of approximately $0.8 million; these purchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means.

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HOLLY CORPORATION

NOTE 13: Other Comprehensive Income

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 three months ended September 30, 2005
Unrealized gain on securities available for sale	$	131		$	51		$	80

Other comprehensive loss	$	131		$	51		$	80


For the three months ended September 30, 2004
Unrealized loss on securities available for sale	$	(141	)	$	(54	)	$	(87	)

Other comprehensive loss	$	(141	)	$	(54	)	$	(87	)


For the nine months ended September 30, 2005
Unrealized gain on securities available for sale	$	106		$	41		$	65

Other comprehensive loss	$	106		$	41		$	65


For the nine months ended September 30, 2004
Hedging activities	$	(599	)	$	(230	)	$	(369	)
Unrealized loss on securities available for sale		(141	)		(54	)		(87	)

Other comprehensive loss	$	(740	)	$	(284	)	$	(456	)

The temporary unrealized loss or gain on securities available for sale is due to market changes of securities.

Accumulated other comprehensive loss in the equity section of our consolidated balance sheet includes:


	September 30,			December 31,
	2005			2004
	(In thousands)

Pension obligation adjustment	$	(1,462	)	$	(1,462	)
Unrealized loss on securities available for sale		(192	)		(257	)

Accumulated other comprehensive loss	$	(1,654	)	$	(1,719	)

NOTE 14: 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 under the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

The net periodic pension expense consisted of the following components:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)

Service cost	$	862		$	760		$	2,585		$	2,281
Interest cost		941			880			2,824			2,640
Expected return on assets		(791	)		(720	)		(2,372	)		(2,161	)
Amortization of prior service cost		66			66			196			196
Amortization of net loss		241			171			724			514

Net periodic benefit cost	$	1,319		$	1,157		$	3,957		$	3,470

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HOLLY CORPORATION

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2005 and 2004 net periodic benefit cost. We have contributed $10.0 million to the retirement plan during 2005 and do not expect to make any further contributions in 2005.

NOTE 15: Derivative Instruments and Hedging Activities

We periodically utilize petroleum commodity futures contracts to reduce our exposure to the price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. Additionally, we entered into certain transactions during the 2005 third quarter as discussed below. We regularly utilize contracts that provide for the purchase of crude oil and other feedstocks and for the sale of refined products. Certain of these contracts may meet the definition of a derivative instrument in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. Accordingly, we have designated these contracts as normal purchases and normal sales contracts and are not required to record these as derivative instruments under SFAS No. 133.

During the third quarter of 2005, we entered into two different sets of hedging transactions, both of which we did not designate as hedging instruments per the requirements of SFAS No. 133, and therefore all gains and losses are being recorded as incurred. The first transaction was entered into in July 2005 and related to our forecasted August 2005 liquidation of 100,000 barrels of crude oil at our Woods Cross Refinery, where our objective was to fix the price of crude oil associated with the liquidation. To effect the hedge, we sold crude oil futures contracts in July 2005 and liquidated the positions in August 2005 matching when the crude oil inventory was slated for production. We recognized a loss of $535,000 on this transaction and recorded it as an increase in cost of products sold. The other set of transactions we have been entering into from time-to-time starting in July 2005 relate to forecasted sales of diesel fuel from our refineries, where our principal objective is to take advantage of the recent high margins (or crack spreads, being the difference between the price of diesel fuel and the cost of crude oil) on a portion of our diesel fuel sales. To effect these hedges, we sold heating oil futures (which most closely match diesel fuel pricing) and bought crude oil futures. We have also entered into commodity swap transactions (the terms of which mirror the futures contracts entered into) to effect the same strategy on a portion of these hedges. Our objective is either to liquidate the positions as the crack spreads return to more normalized levels, or to hold these positions until the forecasted diesel fuel sales are made, effectively locking in the diesel fuel crack spreads (or margins) at the high levels. Our strategy is to enter into these transactions only when the margins are at historically very high levels, and to have no more than 25% of our diesel fuel production hedged at any given time. During the 2005 third quarter, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. As of September 30, 2005, we had open positions covering 825,000 barrels. Through September 30, 2005, we recognized a net loss on these transactions of $2.3 million which was recorded as an increase in cost of products sold. Included in that amount was a realized gain on the closed positions of $1.1 million and an unrealized loss on the open positions of $3.4 million. Subsequent to September 30, 2005, we have liquidated all of the open positions, resulting in a realized gain on the September 30, 2005 open positions of approximately $2.0 million.

In October 2003, we entered into price swaps to help manage the exposure to price volatility relating to forecasted purchases of natural gas from December 2003 to March 2004. We designated these transactions as cash flow hedges of forecasted purchases. The contracts to hedge natural gas costs were for 6,000 MMBtu, 500 MMBtu, and 2,000 MMBtu per day for the Navajo Refinery, Montana Refinery, and the Woods Cross Refinery, respectively. The January to March 2004 contracts resulted in net realized gains of $270,000 and were recorded as a reduction to refinery operating expenses. There was no ineffective portion of these hedges, and since March 31, 2004, no price swaps have been outstanding.

See Note 10 for information on an interest rate swap contract entered into by HEP.

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HOLLY CORPORATION

NOTE 16: Contingencies

The Final Order and Judgment (the “Order”) of the Delaware Court of Chancery in a lawsuit between Holly and Frontier Oil Corporation (“Frontier”) was issued in May 2005 and became final in June 2005. The lawsuit related to a 2003 merger agreement between the two companies. The Order, which is based on the court’s April 29, 2005 opinion in the case, provides that Frontier pay to us $1 in nominal damages and approximately $2,500 in actual court costs and filing fees and that we pay nothing to Frontier. Frontier has paid the amounts specified in the Order, neither party has filed an appeal, and the time for filing an appeal has expired. Prior developments in this litigation are described in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

In July 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion on petitions for review of rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against Kinder Morgan’s SFPP, L.P. (“SFPP”). The appeals court ruled in favor of our positions on most of the disputed issues that concern us and remanded the case to the FERC for additional consideration of several issues, some of which are involved in our claims. The court denied rehearing and rehearing en banc in October 2004. In January 2005, SFPP filed a petition for writ of certiorari to the United States Supreme Court seeking a review of certain aspects of the appeals court’s July 2004 decision, and in mid-May 2005 the United States Supreme Court denied this petition. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships; this issue was one of the issues in the SFPP case remanded to the FERC by the appeals court, and the position taken in the FERC’s general policy statement is contrary to our position in this case. In June 2005, the FERC issued an order on remand in this case which resolved certain remanded issues and provided for further proceedings with respect to issues concerning the treatment of income taxes, and we thereafter filed a petition for review to the court of appeals with respect to this order and related orders of the FERC; our petition for review remains pending before the appeals court. In August 2005, SFPP and the FERC filed with the court of appeals a joint motion to hold proceedings in our case and other similar cases in abeyance pending further proceedings in the FERC; in September 2005 we filed a response in opposition to this joint motion. The court of appeals has not yet taken action on the joint motion and our response. 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 an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. Rulings by the FERC that were the subject of proceedings in the appeals court resulted in reparations payments to us in 2003 totaling approximately $15.3 million relating principally to the period from 1993 through July 2000. Because proceedings in the FERC on remand have not been completed and our petition for review to the court of appeals with respect to the FERC’s order on remand is pending, it is not possible to determine whether the amount of reparations actually due to us for the period at issue will be found to be less than or more than the $15.3 million we received in 2003. Although it is not possible at the date of this report to predict the final outcome of these proceedings, we believe that future proceedings in this case are not likely to result in an obligation for us to repay a significant portion of the reparations payments already received and could result in payment of additional reparations to us. The final reparations amount will be determined only after further proceedings in the FERC on issues that have not been finally determined by the FERC, further proceedings in the appeals court with respect to determinations by the FERC, and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

The Environmental Protection Agency (“EPA”) and the State of Utah have recently asserted that we have Clean Air Act liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We are currently assessing whether it will be feasible to settle the issues presented by means of an agreement similar to the 2001 Consent Decree we entered into for our Navajo and Montana refineries. The EPA and Utah authorities have indicated that any such agreement in the case of the Woods Cross Refinery would likely involve undertakings by us to make specified capital investments and to make changes in operating procedures at the refinery as well as the payment of a penalty. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. At the date of this report, it is not possible to predict whether we will be able to reach a mutually acceptable agreement with the EPA and Utah environmental authorities, what the terms of any agreement would be,

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HOLLY CORPORATION

what the outcome would be if the matter were resolved in a lawsuit brought by the EPA and Utah authorities, or what portion of claims asserted by the EPA and the Utah authorities would ultimately be paid by ConocoPhillips.

We are a party to various other litigation and proceedings not mentioned in this Form 10-Q which we believe, based on advice of counsel, will not have a materially adverse impact on our financial condition, results of operations or cash flows.

NOTE 17: Segment Information

Our operations are currently organized into one business division, Refining. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and NK Asphalt Partners. Our operations that are not included in the Refining business division include the operations of Holly Corporation, the parent company, and a small-scale oil and gas exploration and production program.

Prior to our deconsolidation of HEP, our operations were organized into two business divisions, which were Refining and HEP. These segments have been in effect since July 13, 2004, the closing of the initial public offering of HEP. Our operations that were not included in either the Refining or HEP business divisions included the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program and the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us.

We reported results of operations in 2004 under both our segments prior to July 13, 2004 and our segments including HEP after July 13, 2004. The Refining segment presented in the September 30, 2004 quarterly report on Form 10-Q is not the same Refining segment as presented below. The Refining segment presented below for the three months and nine months ended September 30, 2004 includes results of operations involving certain assets currently included in HEP. We are not reporting any activity for HEP prior to July 13, 2004, as we did not restate the operations of the original segments prior to HEP’s formation date as it was not practical to do so. 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, Montana Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Montana, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil and intermediate product pipelines, prior to July 8, 2005 (see Note 2), that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes the equity in earnings from our 49% interest in NK Asphalt Partners prior to February 2005. In February 2005, we acquired the remaining 51% interest in the asphalt joint venture from the other partner; subsequent to the purchase, we are including the operations of NK Asphalt Partners in our consolidated financials statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California. The cost of pipeline transportation and terminal services provided by HEP is also included in the Refining segment. The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of its pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain States. The HEP segment also included its 70% interest in Rio Grande, which provides petroleum products transportation. 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. Results of operations prior to July 13, 2004 involving the assets included in the HEP segment are included in the Refining segment for reporting purposes. Our operations not included in the two reportable segments are included in Corporate and Other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations column included the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us. These items are no longer included after the deconsolidation of HEP on July 1, 2005.

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HOLLY CORPORATION

The accounting policies for the segments, other than our accounting change due to the adoption of SFAS 123 (revised) (see Note 5), are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2004. Our reportable segments prior to July 1, 2005 were strategic business units that offered different products and services.


					Corporate and			Consolidations			Consolidated
	Refining		HEP		Other			and Eliminations			Total
	(In thousands)

Three Months Ended September 30, 2005
Sales and other revenues	$	934,987	$	—	$	417		$	(125	)	$	935,279
Depreciation and amortization	$	9,096	$	—	$	294		$	—		$	9,390
Income (loss) from operations	$	105,922	$	—	$	(12,552	)	$	—		$	93,370

Three Months Ended September 30, 2004
Sales and other revenues	$	593,010	$	12,190	$	399		$	(8,151	)	$	597,448
Depreciation and amortization	$	8,136	$	1,503	$	346		$	—		$	9,985
Income (loss) from operations	$	25,421	$	5,432	$	(9,905	)	$	—		$	20,948

Nine Months Ended September 30, 2005
Sales and other revenues	$	2,340,931	$	36,034	$	1,034		$	(19,699	)	$	2,358,300
Depreciation and amortization	$	27,218	$	6,212	$	906		$	—		$	34,336
Income (loss) from operations	$	225,708	$	16,019	$	(33,702	)	$	—		$	208,025
Total assets	$	908,715	$	—	$	288,542		$	—		$	1,197,257

Nine Months Ended September 30, 2004
Sales and other revenues	$	1,623,936	$	12,190	$	1,496		$	(8,382	)	$	1,629,240
Depreciation and amortization	$	27,375	$	1,503	$	962		$	—		$	29,840
Income (loss) from operations	$	152,231	$	5,432	$	(30,433	)	$	—		$	127,230
Total assets	$	590,573	$	102,601	$	232,180		$	79,760		$	1,005,114

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HOLLY CORPORATION

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 2 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of Part I of this quarterly report of Form 10-Q. In this document, the words “we”, “our” 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.

OVERVIEW

We are principally an independent petroleum refiner operating three refineries in Artesia and Lovington, New Mexico (operated as one refinery), Woods Cross, Utah and Great Falls, Montana. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At September 30, 2005, we also owned a 45.0% interest in Holly Energy Partners, L.P. (“HEP”) which owns and operates pipeline and terminalling assets and owns a 70% interest in the Rio Grande Pipeline Company (“Rio Grande”).

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 western United States. Our sales and other revenues for the nine months ended September 30, 2005 were $2,358.3 million as compared to $1,629.2 million for the nine months ended September 30, 2004. Our net income for the nine months ended September 30, 2005 was $127.8 million as compared to $76.5 million for the nine months ended September 30, 2004. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for nine months ended September 30, 2005 were $2,150.3 million, an increase from $1,502.1 million for the nine months ended September 30, 2004.

In January 2003 (revised December 2003), FASB issued Interpretation No. 46, “ Consolidation of Variable Interest Entities” (“FIN 46”), which we adopted on December 31, 2003. This interpretation defined a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity, or have voting rights that are not proportionate to their economic interests. This standard requires a company to consolidate a variable interest entity (“VIE”) if it is allocated a majority of the entity’s losses or income. Through June 30, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own shown as a minority interest in the ownership and earnings. HEP is a VIE as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines discussed below, we have determined that our beneficial variable interest in HEP is now less than 50%; and therefore as required by FIN 46, we are deconsolidating HEP as of July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward, and our share of the earnings of HEP will now be recorded using the equity method.

On July 8, 2005, we closed on a transaction for HEP to acquire from us two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total acquisition price was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 in common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. This acquisition was made pursuant to an option to purchase these pipelines we granted to HEP at the time of its initial public offering in July 2004. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including the 2% general partner interest.

In addition to the intermediate feedstock pipelines acquired by HEP, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or the intermediate pipelines acquisition. With respect to the intermediate pipelines transaction, this resulted in a deemed distribution to us from HEP of $71.9 million. Due to the historical basis being less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP from our consolidated financial statements on July 1, 2005. The net balance of distributions in excess of our investment in HEP was $155.7 million at September 30, 2005.

On February 28, 2005, HEP acquired from Alon USA, Inc. and certain of its affiliates (collectively “Alon”) over 500 miles of light products pipelines and two light product terminals for $120 million in cash and 937,500 HEP

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HOLLY CORPORATION

Class B subordinated units valued at $24.7 million. As HEP is no longer consolidated in our financial statements effective July 1, 2005, we no longer include in our consolidated financial statements these assets acquired from Alon.

The Final Order and Judgment (the “Order”) of the Delaware Court of Chancery in a lawsuit between Holly and Frontier Oil Corporation (“Frontier”) was issued in May 2005 and became final in June 2005. The lawsuit related to a 2003 merger agreement between the two companies. The Order, which is based on the court’s April 29, 2005 opinion in the case, provides that Frontier pay to us $1 in nominal damages and approximately $2,500 in actual court costs and filing fees and that we pay nothing to Frontier. Frontier has paid the amounts specified in the Order, neither party has filed an appeal, and the time for filing an appeal has expired. Prior developments in this litigation are described in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

On May 19, 2005, we announced that our Board of Directors authorized the repurchase of up to $100 million of our common stock. Repurchases were 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 nine months ended September 30, 2005, we repurchased 1,727,207 shares at a cost of approximately $83.1 million or an average of $48.10 per share under this program. In October 2005, we completed the remainder of the repurchases under the $100 million repurchase program.

As a result of a two-for-one stock split effective August 30, 2004, all references to the number of shares of common stock and per share amounts have been adjusted to reflect the split on a retroactive basis.

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HOLLY CORPORATION

RESULTS OF OPERATIONS

Financial Data (Unaudited)


	Three Months Ended
	September 30,						Change from 2004
	2005			2004			Change			Percent
	(In thousands, except per share data)

Sales and other revenues	$	935,279		$	597,448		$	337,831			56.5	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		772,887			507,630			265,257			52.3
Operating expenses (exclusive of depreciation, depletion, and amortization)		46,947			46,762			185			0.4
General and administrative expenses (exclusive of depreciation, depletion and amortization)		12,616			12,001			615			5.1
Depreciation, depletion and amortization		9,390			9,985			(595	)		(6.0	)
Exploration expenses, including dry holes		69			122			(53	)		(43.4	)

Total operating costs and expenses		841,909			576,500			265,409			46.0


Income from operations		93,370			20,948			72,422			345.7
Other income (expense):
Equity in earnings (loss) of joint ventures		—			348			(348	)		(100.0	)
Equity in earnings of HEP		3,296			—			3,296			100.0
Minority interests in income of partnerships		—			(2,704	)		2,704			(100.0	)
Interest income		1,202			933			269			28.8
Interest expense		(501	)		(922	)		421			(45.7	)

		3,997			(2,345	)		6,342			(270.4	)

Income before income taxes		97,367			18,603			78,764			423.4
Income tax provision		36,317			7,078			29,239			413.1

Income before cumulative change in accounting principle		61,050			11,525			49,525			429.7
Cumulative effect of accounting change (net of tax expense of $426)		669			—			669			100.0

Net income	$	61,719		$	11,525		$	50,194			435.5	%


Basic earnings per share:
Income before cumulative change in accounting principle	$	2.00		$	0.37		$	1.63			440.5	%
Cumulative affect of accounting change		0.02			—			0.02			100.0

Net income	$	2.02		$	0.37		$	1.65			445.9	%


Diluted earnings per share:
Income before cumulative change in accounting principle	$	1.95		$	0.36		$	1.59			441.7	%
Cumulative affect of accounting change		0.02			—			0.02			100.0

Net income	$	1.97		$	0.36		$	1.61			447.2	%


Cash dividends declared per common share	$	0.10		$	0.08		$	0.02			25.0	%

Average number of common shares outstanding:
Basic		30,618			31,513			(895	)		(2.8	)%
Diluted		31,386			32,420			(1,034	)		(3.2	)%

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HOLLY CORPORATION


	Nine Months Ended
	September 30,						Change from 2004
	2005			2004			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	2,358,300		$	1,629,240		$	729,060			44.7	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		1,933,915			1,308,179			625,736			47.8
Operating expenses (exclusive of depreciation, depletion, and amortization)		146,187			127,494			18,693			14.7
General and administrative expenses (exclusive of depreciation, depletion and amortization)		35,527			35,947			(420	)		(1.2	)
Depreciation, depletion and amortization		34,336			29,840			4,496			15.1
Exploration expenses, including dry holes		310			550			(240	)		(43.6	)

Total operating costs and expenses		2,150,275			1,502,010			648,265			43.2


Income from operations		208,025			127,230			80,795			63.5
Other income (expense):
Equity in earnings (loss) of joint ventures		(685	)		293			(978	)		(333.8	)
Equity in earnings of HEP		3,296			—			3,296			100.0
Minority interests in income of partnerships		(6,721	)		(3,699	)		(3,022	)		81.7
Interest income		4,455			3,323			1,132			34.1
Interest expense		(4,706	)		(2,628	)		(2,078	)		79.1

		(4,361	)		(2,711	)		(1,650	)		60.9

Income before income taxes		203,664			124,519			79,145			63.6
Income tax provision		76,556			48,025			28,531			59.4

Income before cumulative change in accounting principle		127,108			76,494			50,614			66.2
Cumulative effect of accounting change (net of tax expense of $426)		669			—			669			100.0

Net income	$	127,777		$	76,494		$	51,283			67.0	%


Basic earnings per share:
Income before cumulative change in accounting principle	$	4.07		$	2.43		$	1.64			67.5	%
Cumulative affect of accounting change		0.02			—			0.02			100.0

Net income	$	4.09		$	2.43		$	1.66			68.3	%


Diluted earnings per share:
Income before cumulative change in accounting principle	$	3.98		$	2.37		$	1.61			67.9	%
Cumulative affect of accounting change		0.02			—			0.02			100.0

Net income	$	4.00		$	2.37			1.63			68.8	%


Cash dividends declared per common share	$	0.28		$	0.21		$	0.07			33.3	%

Average number of common shares outstanding:
Basic		31,253			31,444			(191	)		(0.6	)%
Diluted		31,980			32,316			(336	)		(1.0	)%

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HOLLY CORPORATION

Balance Sheet Data (Unaudited)


	September 30,		December 31,
	2005⁽²⁾		2004
	(In thousands)

Cash, cash equivalents and investments in marketable securities	$	273,651	$	219,265
Working capital	$	255,280	$	148,642
Total assets	$	1,197,257	$	982,713
Total debt, including current maturities and bank borrowings ⁽¹⁾	$	8,572	$	33,572
Minority interests	$	—	$	157,550
Stockholders’ equity	$	389,021	$	339,916


(1)		Includes HEP’s bank borrowings of $25.0 million at December 31, 2004.

(2)		There are no HEP balances included at September 30, 2005 due to the deconsolidation on July 1, 2005.

Other Financial Data (Unaudited)


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
				(In thousands)

Net cash provided by operating activities	$	86,079		$	37,081	$	158,559		$	160,381
Net cash provided by (used for) investing activities	$	(136,789	)	$	46,980	$	(287,212	)	$	30,737
Net cash provided by (used for) financing activities	$	15,418		$	9,042	$	137,502		$	(45,307	)
Capital expenditures	$	29,417		$	8,796	$	58,062		$	27,915
EBITDA ⁽¹⁾	$	106,725		$	28,577	$	238,920		$	153,664


(1)		Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

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HOLLY CORPORATION

Our reportable business segment is Refining after the deconsolidation of HEP on July 1, 2005 and our two business segments were Refining and HEP prior to the deconsolidation. The Refining segment presented in the September 30, 2004 quarterly report on Form 10-Q is not the same Refining segment as presented below. The Refining segment for the three months and nine months ended September 30, 2004 includes results of operations involving assets included in HEP prior to the contribution on July 13, 2004. The HEP segment did not have any activity prior to HEP’s formation on July 13, 2004 or subsequent to the deconsolidation effective July 1, 2005.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
				(In thousands)

Sales and other revenues ⁽¹⁾							$			$
Refining	$	934,987		$	593,010			2,340,931			1,623,936
HEP		—			12,190			36,034			12,190
Corporate and Other		417			399			1,034			1,496
Consolidations and Eliminations		(125	)		(8,151	)		(19,699	)		(8,382	)

Consolidated	$	935,279		$	597,448		$	2,358,300		$	1,629,240


Income (loss) from operations ⁽¹⁾
Refining	$	105,922		$	25,421		$	225,708		$	152,231
HEP		—			5,432			16,019			5,432
Corporate and Other		(12,552	)		(9,905	)		(33,702	)		(30,433	)

Consolidated	$	93,370		$	20,948		$	208,025		$	127,230


(1)		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, Montana Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Montana, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil and intermediate product pipelines, prior to July 8, 2005 (see Note 2 to our consolidated financial statements), that we owned and operated in conjunction with our refining operations as part of the supply networks of the refineries. In February 2005, we acquired the remaining 51% interest in our asphalt joint venture from the other partner; subsequent to the purchase, we are including the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California. The cost of pipeline transportation and terminal services provided by HEP is also included in the Refining segment. The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of its pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain States. The HEP segment also included HEP’s 70% interest in Rio Grande, which provides petroleum products transportation. Revenues of the HEP segment were 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. Results of operations involving the assets included in the HEP segment prior to July 13, 2004 are included in the Refining segment for reporting purposes. Our operations not included in the two reportable segments are included in Corporate and Other, which includes costs of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations amount includes the elimination of the revenue associated with our pipeline transportation services between us and HEP for the six months ended June 30, 2005.

Refining Operating Data (Unaudited)

Our refinery operations include the Navajo Refinery, the Woods Cross Refinery and the Montana Refinery. The following tables set forth information, including non-GAAP performance measures about our refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation, depletion and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part I of the Form 10-Q.

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HOLLY CORPORATION


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
*Navajo Refinery*
Crude charge (BPD) ⁽¹⁾		73,030			69,470			73,080			70,160
Refinery production (BPD) ⁽²⁾		79,660			76,250			80,470			77,910
Sales of produced refined products (BPD)		80,280			76,810			80,160			77,410
Sales of refined products (BPD) ⁽³⁾		87,830			86,660			89,130			85,050

Refinery utilization ⁽⁴⁾		97.4	%		92.6	%		97.4	%		93.5	%

Average per produced barrel ⁽⁵⁾
Net sales	$	79.18		$	52.71		$	67.46		$	50.12
Cost of products ⁽⁶⁾		63.38			44.15			54.21			39.00

Refinery gross margin		15.80			8.56			13.25			11.12
Refinery operating expenses ⁽⁷⁾		3.65			3.47			3.48			3.24

Net operating margin	$	12.15		$	5.09		$	9.77		$	7.88


Feedstocks:
Sour crude oil		87	%		86	%		88	%		82	%
Sweet crude oil		2	%		3	%		1	%		6	%
Other feedstocks and blends		11	%		11	%		11	%		12	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		57	%		57	%		58	%		58	%
Diesel fuels		29	%		27	%		28	%		26	%
Jet fuels		4	%		5	%		4	%		6	%
Asphalt		5	%		8	%		6	%		7	%
LPG and other		5	%		3	%		4	%		3	%

Total		100	%		100	%		100	%		100	%


*Woods Cross Refinery*
Crude charge (BPD) ⁽¹⁾		24,350			25,560			23,970			23,750
Refinery production (BPD) ⁽²⁾		26,190			25,560			25,760			23,930
Sales of produced refined products (BPD)		27,240			24,600			26,710			23,720
Sales of refined products (BPD) ⁽³⁾		28,840			25,800			27,960			24,330

Refinery utilization ⁽⁴⁾		93.7	%		102.2	%		92.2	%		95.0	%

Average per produced barrel ⁽⁵⁾
Net sales	$	81.72		$	53.06		$	68.23		$	50.34
Cost of products ⁽⁶⁾		68.65			48.80			59.26			44.00

Refinery gross margin		13.07			4.26			8.97			6.34
Refinery operating expenses ⁽⁷⁾		4.11			3.93			4.18			3.93

Net operating margin	$	8.96		$	0.33		$	4.79		$	2.41


Feedstocks:
Sour crude oil		7	%		7	%		8	%		6	%
Sweet crude oil		81	%		88	%		81	%		88	%
Other feedstocks and blends		12	%		5	%		11	%		6	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		63	%		58	%		61	%		59	%
Diesel fuels		30	%		33	%		29	%		32	%
Jet fuels		2	%		2	%		2	%		1	%
Fuel oil		4	%		6	%		6	%		7	%
LPG and other		1	%		1	%		2	%		1	%

Total		100	%		100	%		100	%		100	%

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HOLLY CORPORATION


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
*Montana Refinery*
Crude charge (BPD) ⁽¹⁾		8,240			8,310			7,900			7,460
Refinery production (BPD) ⁽²⁾		8,790			8,910			8,380			7,920
Sales of produced refined products (BPD)		10,980			10,010			8,510			7,960
Sales of refined products (BPD) ⁽³⁾		11,280			10,210			8,700			8,180

Refinery utilization ⁽⁴⁾		103.0	%		103.9	%		98.8	%		93.3	%

Average per produced barrel ⁽⁵⁾
Net sales	$	52.47		$	43.79		$	52.70		$	42.89
Cost of products ⁽⁶⁾		44.66			37.60			43.58			35.36

Refinery gross margin		7.81			6.19			9.12			7.53
Refinery operating expenses ⁽⁷⁾		4.61			4.83			6.10			5.61

Net operating margin	$	3.20		$	1.36		$	3.02		$	1.92


Feedstocks:
Sour crude oil		92	%		91	%		93	%		92	%
Other feedstocks and blends		8	%		9	%		7	%		8	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		29	%		35	%		38	%		41	%
Diesel fuels		13	%		15	%		17	%		17	%
Jet fuels		5	%		6	%		5	%		6	%
Asphalt		50	%		41	%		36	%		32	%
LPG and other		3	%		3	%		4	%		4	%

Total		100	%		100	%		100	%		100	%


*Consolidated*
Crude charge (BPD) ⁽¹⁾		105,620			103,340			104,950			101,370
Refinery production (BPD) ⁽²⁾		114,640			110,720			114,610			109,760
Sales of produced refined products (BPD)		118,500			111,420			115,380			109,090
Sales of refined products (BPD) ⁽³⁾		127,950			122,670			125,790			117,560

Refinery utilization ⁽⁴⁾		96.9	%		95.7	%		96.3	%		93.9	%

Average per produced barrel ⁽⁵⁾
Net sales	$	77.29		$	51.99		$	66.55		$	49.64
Cost of products ⁽⁶⁾		62.86			44.58			54.60			39.82

Refinery gross margin		14.43			7.41			11.95			9.82
Refinery operating expenses ⁽⁷⁾		3.85			3.70			3.84			3.56

Net operating margin	$	10.58		$	3.71		$	8.11		$	6.26


Feedstocks:
Sour crude oil		69	%		68	%		70	%		66	%
Sweet crude oil		20	%		23	%		19	%		24	%
Other feedstocks and blends		11	%		9	%		11	%		10	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		56	%		56	%		58	%		57	%
Diesel fuels		27	%		27	%		27	%		27	%
Jet fuels		4	%		4	%		4	%		5	%
Asphalt		8	%		9	%		7	%		7	%
LPG and other		5	%		4	%		4	%		4	%

Total		100	%		100	%		100	%		100	%

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HOLLY CORPORATION


(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 our refineries.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity.

(5)		Represents average per barrel amounts for produced refined products sold, which are non-GAAP. Reconciliations to amounts reported under GAAP are located under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

(6)		Subsequent to the formation of HEP, transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of our refinery, exclusive of depreciation, depletion, and amortization, and excludes refining segment expenses of product pipelines and terminals.

Results of Operations — Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Summary

Net income for the three months ended September 30, 2005 was $61.7 million ($1.97 per diluted share) compared to net income of $11.5 million ($0.36 diluted share) for the three months ended September 30, 2004. Earnings for the third quarter of 2005 as compared to the third quarter of 2004 were up by $50.2 million principally due to the very high refined product margins experienced in the current year’s third quarter. Additionally impacting earnings favorably were increased refined production volumes offset by higher refinery operating costs and expenses. Overall refinery production levels increased 4% in the 2005 third quarter as compared to the same period in 2004. Company-wide refinery gross margins were $14.43 per produced barrel for the third quarter of 2005 compared to margins of $7.41 per produced barrel for the third quarter of 2004.

Sales and Other Revenues

Sales and other revenues increased 56.5% from $597.4 million for the three months ended September 30, 2004 to $935.3 million for the three months ended September 30, 2005 due principally to higher refined product sales prices, and to a lesser degree, small increases in volumes sold. The average sales price we received per produced barrel sold increased 49% from $51.99 in the third quarter of 2004 to $77.29 in the third quarter of 2005. The total volume of refined products we sold increased 4% in the third quarter of 2005 as compared to the third quarter of 2004. Additionally impacting sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture (now doing business as Holly Asphalt Company) in the 2005 consolidated financial statements, following our February 2005 purchase of the other partner’s interest, offset by the exclusion of revenues for HEP due to the deconsolidation of HEP effective July 1, 2005.

Cost of Products Sold

Cost of products sold increased 52.3% from $507.6 million in the third quarter of 2004 to $773.9 million in the third quarter of 2005 due principally to higher costs of crude oil, and to a lesser degree, increased volumes sold. The average price we paid per barrel of crude oil purchased increased 41% from $44.58 in the third quarter of 2004 to $62.86 in the third quarter of 2005. Additionally impacting cost of sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements.

Gross Refinery Margins

The gross refining margin per produced barrel increased 95% from $7.41 in the third quarter of 2004 to $14.43 in the third quarter of 2005. Gross refinery margin does not include the effect of depreciation, depletion or amortization. See “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.

Operating Expenses

Operating expenses increased 0.4% from $46.8 million in the third quarter of 2004 to $46.9 million in the third quarter of 2005 due to increased utility and catalyst costs and the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated statements, offset by the exclusion of HEP’s operating costs due to the deconsolidation of HEP.

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HOLLY CORPORATION

General and Administrative Expenses

General and administrative expenses increased 5.1% from $12.0 million in the third quarter of 2004 to $12.6 million in the third quarter of 2005 due primarily to increased equity-based incentive compensation, offset by reduced legal fees and by the exclusion of general and administrative expenses due to the deconsolidation of HEP.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization decreased 6.0% from $10.0 million in the third quarter of 2004 to $9.4 million in the third quarter of 2005. This decrease is due to exclusion of HEP’s depreciation resulting from the deconsolidation of HEP, offset by inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements and increased depreciation and amortization on other capital assets placed in service in 2004 and 2005 at our refineries.

Equity in Earnings of HEP

As part of the deconsolidation of HEP on July 1, 2005, we show equity in earnings for our ownership percentage of HEP, currently 45.0%, including any incentive distributions paid through our general partner interest, due to equity based accounting for our investment in HEP. The equity in earnings of HEP was $3.3 million for the three months ended September 30, 2005 which represents our 45.0% total share of HEP’s earnings. There was no equity in earnings of HEP for the three months ended September 30, 2004 as HEP was a consolidated subsidiary during that time period.

Equity in Earnings of Joint Ventures and Minority Interests

There was no equity in earnings of joint ventures in the third quarter of 2005 as all previously owned interests have been consolidated in our financials or have been sold prior to April 1, 2005. There was no minority interest in income of partnerships in the third quarter of 2005 due to the deconsolidation of HEP on July 1, 2005. Equity in earnings of joint ventures in the third quarter of 2004 included income of $0.3 million from our interest in the NK Asphalt joint venture. Minority interests in income of partnerships in the third quarter of 2004 reduced income by $2.6 million. This represented the minority interest partners’ 49% ownership share of HEP (subsequent to HEP’s initial public offering in July 2004) and the minority owner’s 30% ownership share of the Rio Grande joint venture’s income.

Interest Income

Interest income for the third quarter of 2005 was $1.2 million compared to $0.9 million for the third quarter of 2004. Interest income in 2005 represents interest earned on our investable funds resulting from the receipt of proceeds from the initial public offering of HEP, sale of our intermediate pipelines to HEP in July 2005 and internally generated cash flows.

Interest Expense

Interest expense was $0.5 million for the third quarter of 2005 as compared to $0.9 million for the third quarter of 2004. The decrease for the current year’s third quarter as compared to the same period in 2004 resulted from inclusion of borrowings made under HEP’s credit agreement during 2004 and reduced interest during 2005 related to our senior notes, as the amortized balance is now half the amount it was in 2004.

Income Taxes

Income taxes increased 413.1% from $7.1 million for the third quarter of 2004 to $36.3 million for the third quarter of 2005 due to significantly higher earnings during the 2005 third quarter as compared to the 2004 third quarter. The effective tax rate for the third quarter of 2005 was 37.3%, as compared to 38.1% for the third quarter of 2004.

Cumulative Effect of Accounting Change

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HOLLY CORPORATION

adoption was a gain of $669,000, net of a deferred tax expense of $426,000.

Results of Operations — Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Summary

Net income for the nine months ended September 30, 2005 was $127.8 million ($4.00 per diluted share) compared to net income of $76.5 million ($2.37 diluted share) for the nine months ended September 30, 2004. Earnings for the first nine months of 2005 as compared to the first nine months of 2004 increased 67.0% or $51.3 million principally due to the very high refined product margins experienced in the current year’s third quarter. Additionally impacting earnings favorably were increased refinery production volumes, offset by higher refinery operating costs and expenses. In the nine months ended September 30, 2004, we received 100% of the benefit of the refined product pipelines and terminals contributed to HEP prior to its initial public offering in July 2004, where as subsequent to July 2004, including the nine months ended September 30, 2005, approximately half of the income from HEP’s refined product pipelines and terminals is attributable to other owners. Overall refinery production levels increased 4% to a total production level of 114,610 BPD for the first nine months of 2005 due to increased production at all refineries. Company-wide refinery margins were $11.95 per barrel for the nine months ended September 30, 2005 compared to margins of $9.82 per barrel for the nine months ended September 30, 2004.

Sales and Other Revenues

Sales and other revenues increased 44.7% from $1,629.2 million for the nine months ended September 30, 2004 to $2,358.3 million for the nine months ended September 30, 2005 due principally to higher refined product sales prices, and to a lesser degree, increased volumes sold at our refineries. The average sales price we received per produced barrel sold increased 34% from $49.64 for the first nine months of 2004 to $66.55 for the first nine months of 2005. The total volume of refined products we sold increased 7% in the first nine months of 2005 as compared to the first nine months of 2004. Additionally impacting sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements, following our February 2005 purchase of the other partner’s interest, and the inclusion of revenues from HEP’s assets acquired from Alon from March through June 2005.

Cost of Products Sold

Cost of products sold increased 47.8% from $1,308.2 million for the nine months ended September 30, 2004 to $1,933.9 million for the nine months ended September 30, 2005 due principally to higher costs of crude oil, and to a lesser degree, increased volumes sold. The average price we paid per barrel of crude oil purchased increased 37% from $39.82 in the first nine months of 2004 to $54.60 in the first nine months of 2005. Additionally impacting costs of sales were increases in the current year due to the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements.

We recognized $2.8 million in income in the first nine months of 2004 resulting from the liquidations of certain last-in, first-out (“LIFO”) inventory quantities that were carried at lower costs compared to current costs. There were no similar adjustments for the first nine months of 2005.

Gross Refinery Margins

The gross refinery margin per produced barrel increased 22% from $9.82 for the nine months ended September 30, 2004 to $11.95 for the nine months ended September 30, 2005. Gross refinery margin does not include the effect of depreciation, depletion or amortization. See “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.

Operating Expenses

Operating expenses increased 14.7% from $127.5 million for the nine months ended September 30, 2004 to $146.2 million for the nine months ended September 30, 2005 due to the higher production levels, increased utility and

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HOLLY CORPORATION

catalyst costs, operating costs associated with the assets HEP acquired from Alon from March to June 2005 prior to the HEP deconsolidation, and the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements.

General and Administrative Expenses

General and administrative expenses decreased 1.2% from $35.9 million for the nine months ended September 30, 2004 to $35.5 million for the nine months ended September 30, 2005 due primarily to reduced legal fees for 2005 as compared to 2004, offset by increased equity-based incentive compensation and incremental expenses prior to the deconsolidation of HEP related to HEP being a separate public entity.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 15.1% from $29.8 million for the nine months ended September 30, 2004 to $34.3 million for the nine months ended September 30, 2005 due to depreciation on the assets HEP acquired from Alon through June 30, 2005, the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated statements and increased depreciation and amortization on other capital assets placed in service in 2004 and 2005.

Equity in Earnings of HEP

As part of the deconsolidation of HEP effective July 1, 2005, we now show equity in earnings in HEP for our ownership percentage of HEP, currently 45.0%, including any incentive distributions paid through our general partner interest. For the nine months ended September 30, 2005 the equity in earnings of HEP was $3.3 million, which represents our 45.0% of HEP’s earnings for the third quarter of 2005. There was no equity in earnings of HEP for the nine months ended September 30, 2004 as HEP was a consolidated subsidiary from its commencement of operations.

Equity in Earnings of Joint Ventures and Minority Interests

Equity in earnings of joint ventures for the nine months ended September 30, 2005 included a loss of $0.7 million from our interest in NK Asphalt joint venture prior to our 100% ownership in February 2005. Minority interests in income of partnerships for the nine months ended September 30, 2005 was a reduction in income of $6.7 million which represented the minority interest partners’ 52.1% ownership share of HEP’s income prior to July 2005 (49% prior to HEP’s asset acquisition from Alon on February 28, 2005). As of July 1, 2005, minority interests are no longer being recognized due to deconsolidation of HEP. Equity in earnings of joint ventures for the nine months ended September 30, 2004 included income of $0.3 million from our interest in NK Asphalt joint venture. Minority interests in income of partnerships for the nine months ended September 30, 2004 resulted in a reduction of income of $3.6 million. This represented the minority interest partners’ 49% ownership of HEP (subsequent to HEP’s July 2004 initial public offering) and the minority owner’s 30% ownership share of the Rio Grande joint venture’s income (prior to HEP’s initial public offering).

Interest Income

Interest income for the nine months ended September 30, 2005 was $4.5 million compared to $3.3 million for the nine months ended September 30, 2004. Interest income in 2005 represents interest earned on our investable funds resulting from the receipt of proceeds from the initial public offering of HEP, sale of intermediate pipelines to HEP and internally generated cash flows. The interest income in 2004 mainly resulted from the $2.2 million accrued interest received with $25.0 million of principal from Longhorn Partners Pipeline, L.P. on July 1, 2004.

Interest Expense

Interest expense was $4.7 million for the nine months ended September 30, 2005 as compared to $2.6 million for the nine months ended September 30, 2004. The increase for the first nine months of 2005 as compared to the same period in 2004 was principally due to higher interest costs associated with the senior notes of HEP through June 30, 2005.

Income Taxes

Income taxes increased 59.4% from $48.0 million for the nine months ended September 30, 2004 to $76.6 million for the nine months ended September 30, 2005 due principally to the higher earnings during the nine months ended

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HOLLY CORPORATION

September 30, 2005 as compared to the same period in 2004. The effective tax rate for the nine months ended September 30, 2005 was 37.6%, as compared to 38.6% for the nine months ended September 30, 2004.

Cumulative Effect of Accounting Change

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”) and auction rate securities (“ARS”). Although VRDN and ARS 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. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS 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 September 30, 2005, we had cash and cash equivalents of $76.3 million, marketable securities with maturities under one year of $184.4 million and marketable securities with maturities greater than one year, but less than two years, of $13.0 million.

Cash and cash equivalents increased by $8.8 million during the nine months ended September 30, 2005. The cash flow provided by financing activities of $137.5 million, combined with the cash generated from operating activities of $158.5 million, exceeded the cash used for investing activities of $287.2 million. Working capital increased during the nine months ended September 30, 2005 by $106.6 million.

On July 1, 2004, we entered into a new $175 million secured revolving credit facility with Bank of America as administrative agent and a lender, with a term of four years and an option to increase it to $225 million subject to certain conditions. The credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of September 30, 2005, we had letters of credit outstanding under our revolving credit facility of $2.3 million and had no borrowings outstanding. We were in compliance with all covenants at September 30, 2005. Additionally, a credit facility is in place for the benefit of HEP, as described below.

We believe our current cash, cash equivalents, and marketable securities, along with future internally generated cash flow, and funds available under our credit facility provide sufficient resources to fund planned capital projects, scheduled repayments of Holly’s senior notes, continued payment of dividends and our working capital liquidity needs for the foreseeable future.

Sale of Intermediate Pipelines to HEP

On July 8, 2005, we closed on a transaction in which HEP acquired our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities. The total acquisition price was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 in common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the approximately $77.7

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million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale of 1.1 million of its common units for $45.1 million to a limited number of institutional investors, which closed simultaneously with the acquisition, and the recently completed offering of an additional $35.0 million in principal amount of their 6.25% senior notes due 2015 (discussed below). This acquisition was made pursuant to an option to purchase these pipelines we granted to HEP at the time of HEP’s initial public offering in July 2004. Following the acquisition, HEP plans to expend up to $3.5 million to expand the capacity of the pipelines to meet the needs of the expansion at our Navajo Refinery. We have agreed to a 15-year pipelines agreement with a minimum annual volume commitment of 72,000 BPD on the pipelines, which will result in revenues to HEP of approximately $11.8 million per calendar year. In addition, we have agreed to indemnify HEP, subject to certain limits, for any environmental noncompliance and remediation liabilities occurring or existing prior to the closing date. As a result of this transaction, our ownership interest in HEP has been reduced to 45.0%, including our 2% general partner interest.

Other HEP Activity

Since HEP is no longer consolidated in our financial statements effective July 1, 2005, we no longer include the accounts of HEP in our consolidated financial statements, and our share of the earnings of HEP is now reported using the equity method of accounting. As we reported HEP as a consolidated subsidiary during the six months ended June 30, 2005, the following summarizes other activity of HEP during the year.

HEP’s Alon Transaction

On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines aggregating approximately 500 miles, an associated tank farm and two refined products terminals with aggregate storage capacity of approximately 347,000 barrels. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s 65,000 BPSD capacity refinery in Big Spring, Texas. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest and other investors in HEP owned 52.1%. The total consideration paid by HEP for these pipeline and terminal assets was $120 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units in five years. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015 (discussed below). HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction and used the balance to repay $30 million of outstanding indebtedness under its credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. HEP amended its credit agreement prior to the Alon acquisition and note offering to allow for these events as well as to amend certain of the restrictive covenants. In connection with the Alon transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon.

HEP’s Credit Facility

On July 7, 2004, one of our affiliates, Holly Energy Partners — Operating, L.P., a wholly owned subsidiary of HEP, entered into a four-year $100 million credit facility with Union Bank of California, as administrative agent and a lender, in conjunction with the initial public offering, with an option to increase the amount to $175 million under certain conditions. HEP amended the credit facility effective February 28, 2005 to allow for the closing of the Alon transaction and the related senior notes offering as well as to amend certain of the restrictive covenants. With a portion of the proceeds from the senior notes offering, HEP repaid $30 million of outstanding indebtedness under the credit facility, including $5 million drawn shortly before the closing of the Alon transaction. The credit facility was amended effective July 8, 2005 to allow for the closing of the Holly intermediate pipelines transaction as well as to amend certain of the restrictive covenants.

HEP’s Senior Notes Due 2015

HEP financed the Alon transaction through its private offering on February 28, 2005 of $150 million principal amount of 6.25% senior notes due 2015 (“Senior Notes”). HEP used the proceeds of the offering to fund the $120 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of

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outstanding indebtedness under its credit facility, including $5 million drawn shortly before the closing of the Alon transaction. HEP partially financed the purchase of our intermediate feedstock pipelines on July 8, 2005 through the offering in June 2005 of an additional $35.0 million in principal of HEP’s 6.25% Senior Notes due 2015.

The $185 million principal amount of Senior Notes is not recorded on our accompanying consolidated balance sheet at September 30, 2005 due to the deconsolidation of HEP on July 1, 2005. Although the Senior Notes were reflected on our consolidated balance sheet (because HEP was a consolidated subsidiary) through June 30, 2005, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable for $150 million of principal amount of the Senior Notes either directly or as guarantors. Through our subsidiaries we have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of $35 million of the principal amount of the Senior Notes.

Cash Flows — Operating Activities

Net cash flows provided by operating activities amounted to $158.5 million for the nine months ended September 30, 2005 compared to $160.4 million for the nine months ended September 30, 2004, a decrease of $1.9 million. Net income for the nine months ended September 30, 2005 was $127.8 million, an increase of $51.3 million from net income of $76.5 million for the nine months ended September 30, 2004. The non-cash items of depreciation and amortization, deferred taxes, minority interests, equity in earnings, and equity-based compensation increased by $28.5 million in the first nine months of 2005 from the same period in 2004. Working capital items decreased cash flows by $5.1 million during the nine months ended September 30, 2005, as compared to increased cash flows of $42.8 million for the nine months ended September 30, 2004. Changes in inventories were a primary cause of the decrease in cash flows from working capital items for the first three quarters of 2005 as compared to the first three quarters of 2004. For the first nine months of 2005, inventories increased by $1.4 million, as compared to a decrease in inventories for the first nine months of 2004 of $17.0 million, due to a prior year build-up of inventory. Additionally, in the first nine months of 2005, accounts receivable increased $199.0 million and accounts payable increased $166.6 million, as compared to the first nine months of 2004 when accounts receivable increased $115.5 million and accounts payable increased $101.9 million. These increases were principally due to increases in prices for refined products and crude oil.

Cash Flows — Investing Activities and Capital Projects

Net cash flows used for investing activities were $287.2 million for the nine months ended September 30, 2005, as compared to net cash flows provided by investing activities of $30.7 million for the nine months ended September 30, 2004, a net change of $317.9 million. Cash expenditures for property, plant and equipment for the first nine months of 2005 totaled $58.1 million as compared to $27.9 million for the same period of 2004. On February 28, 2005, HEP closed on its Alon transaction which required $120.0 million in cash plus transaction costs of $1.9 million. We received cash proceeds from HEP of $77.7 million from our July 2005 sale to them of our intermediate pipelines. The portion of the proceeds in excess of our basis in the assets sold ($71.9 million) is considered a deemed distribution and is reported under financing activities. Upon the deconsolidation of HEP, we no longer include the cash of HEP in our consolidated financial statements, and therefore the June 30, 2005 cash balance of HEP is shown as a use of cash. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by the other partner. The total purchase consideration for the 51% interest, including expenses, was $21.9 million, less cash of $3.4 million which was recorded due to the consolidation of NK Asphalt Partners at the time of our acquisition of the remaining 51% interest. We also invested $254.8 million in marketable securities and received proceeds of $209.4 million from the sale or maturity of marketable securities during the nine months ended September 30, 2005. Subsequent to the deconsolidation of HEP on July 1, 2005, we received quarterly distribution

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payments in 2005 of $4.3 million from HEP. In the first nine months of 2004, we received $145.5 million in net proceeds from the HEP initial public offering. We expended $3.5 million in formation costs for HEP. We also invested $87.5 million in marketable securities and received proceeds of $3.1 million from the sale or maturity of marketable securities during 2004. Also, in the first nine months of 2004, we invested $3.3 million and received distributions of $4.4 million from joint ventures.

Planned Capital Expenditures

Each year our Board of Directors approves capital projects that our management is authorized to undertake in our annual capital budget. 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 2005 is approximately $116.1 million, including $73.8 million approved late in 2004 for ultra low sulfur diesel (“ULSD”) projects at the Woods Cross and Navajo refineries and a ROSE asphalt project at the Navajo Refinery, all described below. The capital budget is comprised of $60.3 million for refining improvement projects for the Navajo Refinery, $40.8 million for projects at the Woods Cross Refinery, $2.1 million for projects at the Montana Refinery, $8.4 million for transportation and marketing projects, and $4.5 million for information technology and other miscellaneous projects. Additionally, HEP’s Board of Directors approved a capital budget for 2005 of $1.5 million for HEP projects. For 2005 we expect to expend approximately $80.0 million on capital projects, which amount includes certain carryovers of capital projects from previous years, less carryovers to 2006 of certain of the currently approved capital projects.

Our clean fuels / expansion strategy for the Navajo Refinery calls for the expansion / conversion of the distillate hydrotreater to gas oil service, the conversion of the gas oil hydrotreater to ULSD service, the expansion of the continuous catalytic reformer, the conversion of the kerosene hydrotreater to naphtha service, and the installation of an additional sulfur recovery unit, which should allow us to produce ULSD by the 2006 deadline. In addition, we plan to revamp our crude and vacuum units at Artesia and Lovington for improved energy conservation / product cutpoints and install a 10 million standard cubic feet per day hydrogen plant, which will permit processing of up to 85,000 BPSD of crude. We estimate the total cost to complete the USLD project and expansion of crude oil refining capacity to 85,000 BPSD to range from $54 million to $59 million (excluding approximately $17 million for the cost of the hydrogen plant, which we plan to lease). In order to avoid additional unit downtime, we plan to phase in the crude expansion starting in the second quarter of 2006 with completion expected in the fourth quarter of 2007. It is anticipated that these projects will also allow the Navajo Refinery, without significant additional investment, to comply with low sulfur gasoline (“LSG”) specifications required by the end of 2010.

We have purchased and relocated and are in the process of refurbishing an existing 4,500 BPSD ROSE asphalt unit for the Navajo Refinery at a total estimated cost of $16.4 million. This project will upgrade asphalt to higher valued gasoline and diesel and is expected to be operational by the end of 2005.

Our clean fuels strategy for the Woods Cross Refinery calls for the construction of a diesel hydrotreater unit, at an estimated cost of $33.7 million, and execution of a long term hydrogen contract that should allow Holly Refining and Marketing – Woods Cross to produce ULSD by the 2006 deadline. This project will also create the infrastructure to allow for another potential project (which at the date of this report has not been included in our capital budget) that would permit us to increase the percentage of sour crude oil runs through the refinery. The Woods Cross Refinery is also required to meet maximum achievable control technology (“MACT”) requirements on its FCC flue gas by January 1, 2010 and we plan to add equipment to the new diesel hydrotreater to desulfurize FCC feed prior to this 2010 date to comply with these requirements as well as the future LSG requirements.

The Montana Refinery is capable, with a minimal additional investment, of producing LSG as required by June 2008 and we are studying changes necessary to comply by June 2010 with ULSD requirements.

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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/or incur additional operating costs to meet applicable requirements.

On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. Among other things, the Act creates tax incentives for small business refiners preparing to produce ULSD. The Act provides 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. We estimate the present value of tax savings that we will derive from capital expenditures associated with ULSD projects to be in excess of $20.0 million, representing the difference between the value of allowed deductions and credits under the Act as compared to the value of depreciating investments over normal depreciable lives.

Cash Flows — Financing Activities

Net cash flows provided by financing activities were $137.5 million for the nine months ended September 30, 2005, as compared to cash flows used for financing activities of $45.3 million for the nine months ended September 30, 2004, a net change of $182.8 million. In connection with HEP’s Alon asset acquisition on February 28, 2005, HEP received proceeds of $147.4 million from the issuance of senior notes. In connection with HEP’s purchase of our intermediate lines, HEP received proceeds of $34.6 million from additional issuance of their senior notes. Additionally during the nine months ended September 30, 2005, we paid $8.2 million in dividends, received $2.7 million for common stock issued upon exercise of stock options, made distributions of $1.6 million to the minority interest partner of Rio Grande, made distributions of $7.9 million to the minority interests holders of HEP, paid down borrowings under HEP’s credit facility netting to $25.0 million, incurred $0.9 million of debt issuance costs related to HEP’s senior debt and recognized $5.5 million in excess tax benefits on our equity based compensation. Under our stock repurchase program announced May 19, 2005, we purchased treasury stock of $80.1 million. Also, during the nine months ended September 30, 2005, we repurchased at current market price from certain executives 24,790 shares of our common stock at a cost of approximately $0.8 million; these purchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means. Additionally in conjunction with the sale of the intermediate pipelines to HEP, we received the deemed distribution of $71.9 million as discussed above. During the first nine months of 2004 we repaid in full our borrowings under our credit facility of $50.0 million, and during the third quarter of 2004 HEP borrowed $25.0 million under their credit facility. Additionally, during the first nine months of 2004, we paid $5.8 million in dividends, repurchased treasury stock for $15.3 million, received $3.5 million for common stock issued upon the exercise of options, made distributions of $2.8 million to the minority interest partner of Rio Grande and recognized $3.1 million in excess tax benefits on our equity based compensation.

Contractual Obligations and Commitments

The following table presents our long-term contractual obligations in total and by period due as of September 30, 2005.


			Payments Due by Period
			Less than						Over
Contractual Obligations	Total		1 Year		2-3 Years		4-5 Years		5 Years
	(In thousands)

Long-term debt (stated maturities)	$	8,572	$	8,572	$	—	$	—	$	—
Operating leases	$	7,700	$	1,810	$	2,720	$	1,926	$	1,244
Minimum revenue agreements with HEP	$	682,889	$	48,510	$	97,021	$	97,021	$	440,337

In December 2001, we entered into a Consent Agreement (“Consent Agreement”) with the Environmental Protection Agency (“EPA”), the New Mexico Environment Department, and the Montana Department of Environmental Quality. The Consent Agreement requires us to make investments at our New Mexico and Montana refineries for the installation of certain state of the art pollution control equipment currently expected to total approximately $15.0 million over a period expected to end in 2010, of which approximately $9.5 million has been

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expended to date.

In connection with the HEP initial public offering, we entered into a 15-year pipelines and terminals agreement with HEP under which we agreed generally to transport or terminal volumes on certain of HEP’s initial facilities that will result in revenue to HEP that will equal or exceed a specified minimum revenue amount annually (which is at $35.4 million in the first year and will adjust upward based on the producer price index) over the term of the agreement. Additionally in connection with HEP’s purchase of our intermediate pipelines in July 2005, we entered into a 15-year pipelines agreement with HEP under which we agreed to transport a minimum annual volume commitment of 72,000 BPD on the pipelines, which will result in approximately $11.8 million per calendar year (which also will adjust upward based on the producer price index).

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.

Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Conditions and Operations – Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2004. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method of valuing certain inventories, the amortization of deferred costs for regular major maintenance and repairs at our refineries, assessing the possible impairment of certain long-lived assets, and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2005.

New Accounting Pronouncements

SFAS No. 123 (revised) “Share-Based Payment”

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. This standard was to become effective for us for the first interim period beginning after June 15, 2005; however in April 2005, the SEC allowed for a delay in the implementation of this standard, with the result that we are not required to adopt this standard until our 2006 year. SFAS 123 (revised) allows for either modified prospective recognition of compensation expense or modified retrospective recognition, which may be back to the original issuance of SFAS 123 or only to interim periods in the year of adoption. We elected for early adoption of this standard on July 1, 2005 based on modified retrospective application with early application under SFAS 123 to prior quarters in the current year (see Note 5 to our consolidated financial statements).

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”

In December 2004, the FASB issued FASB 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4.” This amendment requires abnormal amounts of idle facility expense, freight, handling costs and wasted materials

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(spoilage) to be recognized as current-period charges. This standard also requires that the allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. This standard will be effective for fiscal years beginning after June 15, 2005. We are studying the provisions of this new standard to determine the impact, if any, on our financial statements.

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

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principles and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement becomes effective for fiscal years beginning after December 15, 2005. We believe the adoption of this standard should not have an impact on our financial statements.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

This discussion should be read in conjunction with the discussion under the heading “Additional Factors That May Affect Future Results” included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004.

Other legal proceedings that could affect future results are described below in Part II, Item 1 “Legal Proceedings.”

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 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. Our profitability depends largely on the spread between market prices for refined products and market prices for crude oil. A substantial or prolonged reduction in this spread could have a significant negative effect on our earnings, financial condition and cash flows.

We periodically utilize petroleum commodity futures contracts to reduce our exposure to price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. Additionally, we entered into certain transactions during the 2005 third quarter as discussed below. We regularly utilize contracts that provide for the purchase of crude oil and other feedstocks and for the sale of refined products. Certain of these contracts may meet the definition of a derivative instrument in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. Accordingly, these contracts are designated as normal purchases and normal sales contracts and are not required to be recorded as derivative instruments under SFAS No. 133.

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2005 liquidation of 100,000 barrels of crude oil at our Woods Cross Refinery, where our objective was to fix the price of crude oil associated with the liquidation. To effect the hedge, we sold crude oil futures contracts in July 2005 and liquidated the positions in August 2005 matching when the crude oil inventory was slated for production. We recognized a loss of $535,000 on this transaction and recorded it as an increase in cost of products sold. The other set of transactions we have been entering into from time-to-time starting in July 2005 relate to forecasted sales of diesel fuel from our refineries, where our principal objective is to take advantage of the recent high margins (or crack spreads, being the difference between the price of diesel fuel and the cost of crude oil) on a portion of our diesel fuel sales. To effect these hedges, we sold heating oil futures (which most closely match diesel fuel pricing) and bought crude oil futures. We have also entered into commodity swap transactions (the terms of which mirror the futures contracts entered into) to effect the same strategy on a portion of these hedges. Our objective is either to liquidate the positions as the crack spreads return to more normalized levels, or to hold these positions until the forecasted diesel fuel sales are made, effectively locking in the diesel fuel crack spreads (or margins) at the high levels. Our strategy is to enter into these transactions only when the margins are at historically very high levels, and to have no more than 25% of our diesel fuel production hedged at any given time. During the 2005 third quarter, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. As of September 30, 2005, we had open positions covering 825,000 barrels. Through September 30, 2005, we recognized a net loss on these transactions of $2.3 million which was recorded as an increase in cost of products sold. Included in that amount was a realized gain on the closed positions of $1.1 million and an unrealized loss on the open positions of $3.4 million. Subsequent to September 30, 2005, we have liquidated all of the open positions, resulting in a realized gain on the September 30, 2005 open positions of approximately $2.0 million.

In October 2003, we entered into price swaps to help manage the exposure to price volatility relating to forecasted purchases of natural gas from December 2003 to March 2004. These transactions were designated as cash flow hedges of forecasted purchases. The contracts to hedge natural gas costs were for 6,000 MMBtu, 500 MMBtu, and 2,000 MMBtu per day for the Navajo Refinery, Montana Refinery, and the Woods Cross Refinery, respectively. The January to March 2004 contracts resulted in net realized gains of $270,000 and were recorded as a reduction to refinery operating expenses. There was no ineffective portion of these hedges, and since March 31, 2004, no price swaps have been outstanding.

HEP has entered into an interest rate swap contract to effectively convert the interest expense associated with $60 million of its Senior Notes from a fixed rate to variable rates. The interest rate on the $60 million notional amount is equal to three month LIBOR plus an applicable margin of 1.1575%. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes. HEP accounts for this swap as an effective fair value hedge, so the swap has only a nominal effect on earnings.

At September 30, 2005, we had outstanding unsecured debt of $8.6 million. We do not have significant exposure to changing interest rates on the $8.6 million unsecured debt because the interest rates are fixed, the average maturity is less than one year and such debt represents approximately 2% of our total capitalization. As the interest rates on our bank borrowings are reset frequently based on either the bank’s daily effective prime rate, or the LIBOR rate, interest rate market risk on any bank borrowings would be very low. At times, we have used borrowings under our credit facility to finance our working capital needs. There were no borrowings under the credit facilities at September 30, 2005. Before July 2004, we invested any available cash only 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 was low. Beginning in July 2004, we are also investing certain 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 or cash flow since all of our long-term debt matures in less than one year and any borrowings under the credit facilities and investments are at market rates and such interest has historically not been significant as compared to our total operations. A hypothetical 10% change in the market interest rate over the next

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year would not materially impact our financial condition since the maturity of all our long-term debt is less than one year, such debt represents approximately 2% of our total capitalization, and any borrowings under our credit facilities and investments are at market rates.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.

Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation based upon accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants.

Set forth below is our calculation of EBITDA.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
				(In thousands)

Net income	$	61,719		$	11,525		$	127,777		$	76,494
Add provision for income tax		36,317			7,078			76,556			48,025
Add interest expense		501			922			4,706			2,628
Subtract interest income		(1,202	)		(933	)		(4,455	)		(3,323	)
Add depreciation, depletion and amortization		9,390			9,985			34,336			29,840

EBITDA	$	106,725		$	28,577		$	238,920		$	153,664

Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements.

Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis.

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HOLLY CORPORATION

We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation, depletion and amortization. Each of these component performance measures can be reconciled directly to our Consolidated Statement of Income.

Other companies in our industry may not calculate these performance measures in the same manner.

Refinery Gross Margin

Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Refinery gross margin for each of our refineries and for all of our refineries on a consolidated basis is calculated as shown below.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average per produced barrel

*Navajo Refinery*
Net sales	$	79.18	$	52.71	$	67.46	$	50.12
Less cost of products		63.38		44.15		54.21		39.00

Refinery gross margin	$	15.80	$	8.56	$	13.25	$	11.12


*Woods Cross Refinery*
Net sales	$	81.72	$	53.06	$	68.23	$	50.34
Less cost of products		68.65		48.80		59.26		44.00

Refinery gross margin	$	13.07	$	4.26	$	8.97	$	6.34


*Montana Refinery*
Net sales	$	52.47	$	43.79	$	52.70	$	42.89
Less cost of products		44.66		37.60		43.58		35.36

Refinery gross margin	$	7.81	$	6.19	$	9.12	$	7.53


*Consolidated*
Net sales	$	77.29	$	51.99	$	66.55	$	49.64
Less cost of products		62.86		44.58		54.60		39.82

Refinery gross margin	$	14.43	$	7.41	$	11.95	$	9.82

Net Operating Margin

Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. Net operating margin for each of our refineries and for all of our refineries on a consolidated basis is calculated as shown below.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average per produced barrel

*Navajo Refinery*
Refinery gross margin	$	15.80	$	8.56	$	13.25	$	11.12
Less refinery operating expenses		3.65		3.47		3.48		3.24

Net operating margin	$	12.15	$	5.09	$	9.77	$	7.88

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HOLLY CORPORATION


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average per produced barrel

*Woods Cross Refinery*
Refinery gross margin	$	13.07	$	4.26	$	8.97	$	6.34
Less refinery operating expenses		4.11		3.93		4.18		3.93

Net operating margin	$	8.96	$	0.33	$	4.79	$	2.41


*Montana Refinery*
Refinery gross margin	$	7.81	$	6.19	$	9.12	$	7.53
Less refinery operating expenses		4.61		4.83		6.10		5.61

Net operating margin	$	3.20	$	1.36	$	3.02	$	1.92


*Consolidated*
Refinery gross margin	$	14.43	$	7.41	$	11.95	$	9.82
Less refinery operating expenses		3.85		3.70		3.84		3.56

Net operating margin	$	10.58	$	3.71	$	8.11	$	6.26

Below are reconciliations to our Consolidated Statement of Income for (i) net sales, cost of products and operating expenses, in each case averaged per produced barrel sold, and (ii) net operating margin and refinery gross margin. Due to rounding of reported numbers, some amounts may not calculate exactly.

Reconciliations of refined product sales from produced products sold to total sales and other revenue


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

*Navajo Refinery*
Average sales price per produced barrel sold	$	79.18	$	52.71	$	67.46	$	50.12
Times sales of produced refined products sold (BPD)		80,280		76,810		80,160		77,410
Times number of days in period		92		92		273		274

Refined product sales from produced products sold	$	584,804	$	372,476	$	1,476,273	$	1,063,062


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	81.72	$	53.06	$	68.23	$	50.34
Times sales of produced refined products sold (BPD)		27,240		24,600		26,710		23,720
Times number of days in period		92		92		273		274

Refined product sales from produced products sold	$	204,797	$	120,085	$	497,522	$	327,174


*Montana Refinery*
Average sales price per produced barrel sold	$	52.47	$	43.79	$	52.70	$	42.89
Times sales of produced refined products sold (BPD)		10,980		10,010		8,510		7,960
Times number of days in period		92		92		273		274

Refined product sales from produced products sold	$	53,003	$	40,327	$	122,434	$	93,545

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HOLLY CORPORATION


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Sum of refined products sales from produced products sold from our three refineries ⁽³⁾	$	842,604		$	532,888		$	2,096,229		$	1,483,781
Add refined product sales from purchased products and rounding ⁽¹⁾		69,739			58,293			196,185			126,032

Total refined products sales		912,343			591,181			2,292,414			1,609,813
Add other refining segment revenue ⁽²⁾		22,644			1,829			48,517			14,123

Total refining segment revenue		934,987			593,010			2,340,931			1,623,936
Add HEP sales and other revenue		—			12,190			36,034			12,190
Add corporate and other revenues		417			399			1,034			1,496
Subtract consolidations and eliminations		(125	)		(8,151	)		(19,699	)		(8,382	)

Sales and other revenues	$	935,279		$	597,448		$	2,358,300		$	1,629,240


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet deliver commitments.

(2)		Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to their consolidation in February 2005 (see Note 8 to our consolidated financial statements) and revenues during 2004 from terminal and pipeline assets that are now owned by HEP.

(3)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average sales price per produced barrel sold	$	77.29	$	51.99	$	66.55	$	49.64
Times sales of produced refined products sold (BPD)		118,500		111,420		115,380		109,090
Times number of days in period		92		92		273		274

Refined product sales from produced products sold	$	842,604	$	532,888	$	2,096,229	$	1,483,781

Reconciliation of average cost of products per produced barrel sold to total costs of products sold


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
*Navajo Refinery*
Average cost of products per produced barrel sold	$	63.38	$	44.15	$	54.21	$	39.00
Times sales of produced refined products sold (BPD)		80,280		76,810		80,160		77,410
Times number of days in period		92		92		273		274

Cost of products for produced products sold	$	468,109	$	311,987	$	1,186,314	$	827,203


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	68.65	$	48.80	$	59.26	$	44.00
Times sales of produced refined products sold (BPD)		27,240		24,600		26,710		23,720
Times number of days in period		92		92		273		274

Cost of products for produced products sold	$	172,042	$	110,444	$	432,114	$	285,968


*Montana Refinery*
Average cost of products per produced barrel sold	$	44.66	$	37.60	$	43.58	$	35.36
Times sales of produced refined products sold (BPD)		10,980		10,010		8,510		7,960
Times number of days in period		92		92		273		274

Cost of products for produced products sold	$	45,114	$	34,627	$	101,246	$	77,122

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HOLLY CORPORATION


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Sum of cost of products for produced products sold from our three refineries ⁽³⁾	$	685,265		$	457,058		$	1,719,674		$	1,190,293
Add refined product costs from purchased products sold and rounding ⁽¹⁾		71,039			58,723			200,061			126,268

Total refined costs of products sold		756,304			515,781			1,919,735			1,316,561
Add other refining segment costs of products sold ⁽²⁾		16,708			—			33,879			—

Total refining segment cost of products sold		773,012			515,781			1,953,614			1,316,561
Subtract consolidations and eliminations		(125	)		(8,151	)		(19,699	)		(8,382	)

Costs of products sold (exclusive of depreciation, depletion and amortization)	$	772,887		$	507,630		$	1,933,915		$	1,308,179


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.

(2)		Other refining segment costs of products sold includes the cost of products for NK Asphalt Partners subsequent to their consolidation in February 2005 (see Note 8 to our consolidated financial statements).

(3)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average cost of products per produced barrel sold	$	62.86	$	44.58	$	54.60	$	39.82
Times sales of produced refined products sold (BPD)		118,500		111,420		115,380		109,090
Times number of days in period		92		92		273		274

Cost of products for produced products sold	$	685,265	$	457,058	$	1,719,674	$	1,190,293

Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	3.65	$	3.47	$	3.48	$	3.24
Times sales of produced refined products sold (BPD)		80,280		76,810		80,160		77,410
Times number of days in period		92		92		273		274

Refinery operating expenses for produced products sold	$	26,958	$	24,521	$	76,155	$	68,722


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	4.11	$	3.93	$	4.18	$	3.93
Times sales of produced refined products sold (BPD)		27,240		24,600		26,710		23,720
Times number of days in period		92		92		273		274

Refinery operating expenses for produced products sold	$	10,300	$	8,894	$	30,480	$	25,542


*Montana Refinery*
Average refinery operating expenses per produced barrel sold	$	4.61	$	4.83	$	6.10	$	5.61
Times sales of produced refined products sold (BPD)		10,980		10,010		8,510		7,960
Times number of days in period		92		92		273		274

Refinery operating expenses for produced products sold	$	4,657	$	4,448	$	14,172	$	12,236

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HOLLY CORPORATION


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Sum of refinery operating expenses per produced products sold from our three refineries ⁽¹⁾	$	41,915	$	37,863	$	120,807	$	106,500
Add other refining segment operating expenses and rounding ⁽²⁾		5,032		4,509		13,544		16,471

Total refining segment operating expenses		46,947		42,372		134,351		122,971
Add HEP operating expenses		—		4,368		11,836		4,368
Add corporate and other costs		—		22		—		155

Operating expenses (exclusive of depreciation, depletion and amortization)	$	46,947	$	46,762	$	146,187	$	127,494


(1)		Other refining segment operating expenses includes the marketing costs associated with our refining segment, the operating expenses of NK Asphalt Partners subsequent to their consolidation in February 2005 (see Note 8 to our consolidated financial statements) and the operating expenses during 2004 of terminal and pipeline assets now owned by HEP.

(2)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Average refinery operating expenses per produced barrel sold	$	3.85	$	3.70	$	3.84	$	3.56
Times sales of produced refined products sold (BPD)		118,500		111,420		115,380		109,090
Times number of days in period		92		92		273		274

Refinery operating expenses for produced products sold	$	41,915	$	37,863	$	120,807	$	106,500

Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
*Navajo Refinery*
Net operating margin per produced barrel	$	12.15	$	5.09	$	9.77	$	7.88
Add average refinery operating expenses per produced barrel		3.65		3.47		3.48		3.24

Refinery gross margin per produced barrel		15.80		8.56		13.25		11.12
Add average cost of products per produced barrel sold		63.38		44.15		54.21		39.00

Average net sales per produced barrel sold	$	79.18	$	52.71	$	67.46	$	50.12
Times sales of produced refined products sold (BPD)		80,280		76,810		80,160		77,410
Times number of days in period		92		92		273		274

Refined product sales from produced products sold	$	584,804	$	372,476	$	1,476,273	$	1,063,062

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HOLLY CORPORATION


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
*Woods Cross Refinery*
Net operating margin per produced barrel	$	8.96		$	0.33		$	4.79		$	2.41
Add average refinery operating expenses per produced barrel		4.11			3.93			4.18			3.93

Refinery gross margin per produced barrel		13.07			4.26			8.97			6.34
Add average cost of products per produced barrel sold		68.65			48.80			59.26			44.00

Average net sales per produced barrel sold	$	81.72		$	53.06		$	68.23		$	50.34
Times sales of produced refined products sold (BPD)		27,240			24,600			26,710			23,720
Times number of days in period		92			92			273			274

Refined product sales from produced products sold	$	204,797		$	120,085		$	497,522		$	327,174


*Montana Refinery*
Net operating margin per produced barrel	$	3.20		$	1.36		$	3.02		$	1.92
Add average refinery operating expenses per produced barrel		4.61			4.83			6.10			5.61

Refinery gross margin per produced barrel		7.81			6.19			9.12			7.53
Add average cost of products per produced barrel sold		44.66			37.60			43.58			35.36

Average net sales per produced barrel sold	$	52.47		$	43.79		$	52.70		$	42.89
Times sales of produced refined products sold (BPD)		10,980			10,010			8,510			7,960
Times number of days in period		92			92			273			274

Refined product sales from produced products sold	$	53,003		$	40,327		$	122,434		$	93,545

Sum of refined product sales from produced products sold from our three refineries ⁽³⁾	$	842,604		$	532,888		$	2,096,229		$	1,483,781
Add refined product sales from purchased products and rounding ⁽¹⁾		69,739			58,293			196,185			126,032

Total refining product sales		912,343			591,181			2,292,414			1,609,813
Add other refining segment revenue ⁽²⁾		22,644			1,829			48,517			14,123

Total refining segment revenue		934,987			593,010			2,340,931			1,623,936
Add HEP sales and other revenue		—			12,190			36,034			12,190
Add corporate and other revenues		417			399			1,034			1,496
Subtract consolidations and eliminations		(125	)		(8,151	)		(19,699	)		(8,382	)

Sales and other revenues	$	935,279		$	597,448		$	2,358,300		$	1,629,240


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.

(2)		Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to their consolidation in February 2005 (see Note 8 to our consolidated financial statements) and revenues during 2004 from terminal and pipeline assets that are now owned by HEP.

(3)		The above calculations of refined product sales from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.

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HOLLY CORPORATION

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this quarterly report on Form 10-Q. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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HOLLY CORPORATION

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We have pending in the United States Court of Federal Claims a lawsuit against the Department of Defense relating to claims totaling approximately $299 million with respect to jet fuel sales by two subsidiaries in the years 1982 through 1999. In October 2003, the judge before whom the case is pending issued a ruling that denied the Government’s motion for partial summary judgment on all issues raised by the Government and granted our motion for partial summary judgment on most of the issues we raised. The ruling on the motions for summary judgment in our case did not constitute a final ruling on our claims. The trial judge in our case issued an order in March 2004 to stay proceedings in our case while interlocutory appeals to the United States Court of Appeals for the Federal Circuit were pending on rulings by two other United States Court of Federal Claims judges in cases relating to military fuel sales of two other refining companies, Tesoro Corporation (“Tesoro”) and Hermes Consolidated, Inc. (“Hermes”). In April 2005, a three-judge panel of the appeals court ruled against Tesoro and Hermes on a major legal issue, which had been resolved favorably to the companies in the trial judges’ rulings (including the trial judge’s rulings in our case). The appeals court’s decision in the Tesoro and Hermes cases could have a significant adverse effect on our pending case. In August 2005, the appeals court denied a petition filed by Tesoro and Hermes for the full appeals court (composed of twelve judges) to hear the cases en banc and reconsider the panel’s ruling. In a joint status report on our case filed with the trial judge in September 2005, we stated that we intend to file an amended complaint after the stay in our case is lifted and propose to conduct additional discovery before trial; the Government indicated in the joint status report that it would file a dispositive motion on our case based on the Government’s position that all our claims should be denied based on the court of appeals decision in the Tesoro and Hermes cases or on other grounds. At the date of this report, our case remains stayed by the trial judge. It is not possible to predict the outcome of further proceedings in this case.

In July 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion on petitions for review of rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against Kinder Morgan’s SFPP, L.P. (“SFPP”). The appeals court ruled in favor of our positions on most of the disputed issues that concern us and remanded the case to the FERC for additional consideration of several issues, some of which are involved in our claims. The court denied rehearing and rehearing en banc in October 2004. In January 2005, SFPP filed a petition for writ of certiorari to the United States Supreme Court seeking a review of certain aspects of the appeals court’s July 2004 decision, and in mid-May 2005 the United States Supreme Court denied this petition. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships; this issue was one of the issues in the SFPP case remanded to the FERC by the appeals court, and the position taken in the FERC’s general policy statement is contrary to our position in this case. In June 2005, the FERC issued an order on remand in this case which resolved certain remanded issues and provided for further proceedings with respect to issues concerning the treatment of income taxes, and we thereafter filed a petition for review to the court of appeals with respect to this order and related orders of the FERC; our petition for review remains pending before the appeals court. In August 2005 SFPP and the FERC filed with the court of appeals a joint motion to hold proceedings in our case and other similar cases in abeyance pending further proceedings in the FERC; in September 2005 we filed a response in opposition to this joint motion. The court of appeals has not yet taken action on the joint motion and our response. 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 an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. Rulings by the FERC that were the subject of proceedings in the appeals court resulted in reparations payments to us in 2003 totaling approximately $15.3 million relating principally to the period from 1993 through July 2000. Because proceedings in the FERC on remand have not been completed and our petition for review to the court of appeals with respect to the FERC’s order on remand is pending, it is not possible to determine whether the amount of reparations actually due to us for the period at issue will be found to be less than or more than the $15.3 million we received in 2003. Although it is not possible at the date of this report to predict the final outcome of these proceedings, we believe that future proceedings in this case are not likely to result in an obligation for us to repay a significant portion of the reparations payments already received and could result in payment of additional reparations to us. The final reparations amount

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HOLLY CORPORATION

will be determined only after further proceedings in the FERC on issues that have not been finally determined by the FERC, further proceedings in the appeals court with respect to determinations by the FERC, and possibly future petitions by one or more of the parties seeking United States Supreme Court review of issues in the case.

In November 2004, the Montana Department of Environmental Quality (“MDEQ”) notified us that the MDEQ was initiating an enforcement action against our subsidiary Montana Refining Company (“MRC”) and seeking administrative civil penalties totaling $140,000. This enforcement action relates to alleged air quality violations that resulted from a failure in October 2003 of a vapor combustion unit (“VCU”) at MRC’s truck loading rack in Great Falls, Montana and continued operation of the truck loading rack for seven days following the VCU failure while the VCU was being repaired and could not be operated. In October 2005, MRC entered into a settlement agreement with the MDEQ under the terms of which MRC will carry out a supplemental environmental project to provide additional environmental benefits in the area where MRC operates and the monetary penalty amount has been reduced to approximately $93,000. Following the October 2003 incident that resulted in this enforcement action, MRC took additional steps to avoid future delays in repairs to the VCU and to prevent operation of the truck loading rack without the VCU.

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

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HOLLY CORPORATION

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On May 19, 2005, we announced that our Board of Directors authorized the repurchase of up to $100.0 million of our common stock. Repurchases have been made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. The following table includes the repurchases made through September 30, 2005. We repurchased an additional 304,000 shares in October 2005 to complete the repurchase program announced May 19, 2005.


							Maximum Dollar
					Total Number of		Value of Shares Yet
					Shares Purchased as		to be Purchased as
	Total Number of		Average price Paid		Part of $100		Part of the $100
Period	Shares Purchased		Per Share		Million Program		Million Program
May 1 — May 31		186,366	$	37.64		186,366	$	92,985,876
June 1 — June 30		517,133	$	42.72		517,133	$	70,894,988
July 1 — July 31		316,758	$	47.37		316,758	$	55,889,259
August 1 — August 31		354,150	$	50.79		354,150	$	37,903,694
September 1 — September 30		352,800	$	59.48		352,800	$	16,918,959

Total		1,727,207	$	48.10		1,727,207

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	Three		Nine
	Months		Months
	Ended		Ended
	September 30, 2004

Net income, as reported	$	11,525	$	76,494
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects		105		299

Pro forma net income	$	11,420	$	76,195


Net income per share — basic
As reported	$	0.37	$	2.43
Pro forma	$	0.36	$	2.42

Net income per share — diluted
As reported	$	0.36	$	2.37
Pro forma	$	0.35	$	2.36


			Page
PART I.		FINANCIAL INFORMATION

	Forward-Looking Statements			3

	Definitions			4

Item 1.		Financial Statements

		Consolidated Balance Sheet — (Unaudited) — September 30, 2005 and December 31, 2004		6

		Consolidated Statement of Income (Unaudited) — Three Months and Nine Months Ended September 30, 2005 and 2004		7

		Consolidated Statement of Cash Flows (Unaudited) — Nine Months Ended September 30, 2005 and 2004		8

		Consolidated Statement of Comprehensive Income (Unaudited) — Three Months and Nine Months Ended September 30, 2005 and 2004		9

		Notes to Consolidated Financial Statements (Unaudited)		10

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3.		Quantitative and Qualitative Disclosures About Market Risk		49

Reconciliations to amounts reported under generally accepted accounting principles				49

Item 4.		Controls and Procedures		56

PART II.		OTHER INFORMATION

Item 1.		Legal Proceedings		57

Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		60

Item 6.		Exhibits		61

Signatures				62
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Amendement and Waiver
Amendment


31.1*		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*		The First Amendment and Waiver dated as of January 25, 2005 and entered into by and between Holly Corporation, each of the lenders, and Bank of America, N.A., in its capacity as the Administrative Agent for the lenders under the Credit Agreement.

99.2*		The Second Amendment dated as of May 17, 2005 and entered into by and between Holly Corporation, each of the lenders, and Bank of America, N.A., in its capacity as the Administrative Agent for the lenders under the Credit Agreement.


		HOLLY CORPORATION
		(Registrant)

Date: November 7, 2005		/s/ P. Dean Ridenour

		P. Dean Ridenour
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)

		/s/ Stephen J. McDonnell

		Stephen J. McDonnell
		Vice President and Chief Financial Officer
		(Principal Financial Officer)