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 June 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

30,794,988 shares of Common Stock, par value $.01 per share, were outstanding on July 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;

	•		the ability of us or Holly Energy Partners, L.P. 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.

- 3 -

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.

- 4 -

Item 1. Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEET
(In thousands, except share data)


	June 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	111,601		$	67,460
Marketable securities		97,581			96,215

Accounts receivable:
Product and transportation		162,567			105,998
Crude oil sales		243,438			175,732

		406,005			281,730

Inventories:
Crude oil and refined products		113,276			92,544
Materials and supplies		14,723			12,424

		127,999			104,968

Income taxes receivable		—			6,394
Prepayments and other		17,582			16,139

Total current assets		760,768			572,906

Properties, plants and equipment, at cost		716,119			572,147
Less accumulated depreciation, depletion and amortization		(285,464	)		(259,874	)

		430,655			312,273

Marketable securities (long-term)		36,450			55,590
Transportation agreements		62,707			4,718
Investments in and advances to joint ventures		—			12,423

Other assets:
Turnaround costs (long-term)		19,575			13,535
Intangibles and other		10,522			11,268

		30,097			24,803


Total assets	$	1,320,677		$	982,713


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	477,883		$	377,717
Accrued liabilities		34,052			37,975
Income taxes payable		19,415			—
Current maturities of long-term debt		8,572			8,572

Total current liabilities		539,922			424,264

Deferred income taxes		21,446			20,462
Long-term debt, less current maturities		182,957			25,000
Other long-term liabilities		13,368			15,521
Commitments and contingencies		—			—
Minority interests		179,484			157,550

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; 35,350,071 and 34,804,796 shares issued as of June 30, 2005 and December 31, 2004, respectively		354			348
Additional capital		40,420			29,281
Retained earnings		399,163			339,798
Accumulated other comprehensive loss		(1,734	)		(1,719	)
Common stock held in treasury, at cost - 4,238,325 and 3,510,036 shares as of June 30, 2005 and December 31, 2004, respectively		(54,703	)		(27,792	)

Total stockholders’ equity		383,500			339,916


Total liabilities and stockholders’ equity	$	1,320,677		$	982,713

See accompanying notes.

- 6 -

HOLLY CORPORATION

CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
(In thousands, except per share data)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Sales and other revenues	$	771,296		$	568,735		$	1,423,021		$	1,031,792

Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		604,835			425,654			1,161,028			800,549
Operating expenses (exclusive of depreciation, depletion, and amortization)		50,347			39,935			94,951			78,607
Selling, general and administrative expenses (exclusive of depreciation, depletion, and amortization)		15,678			11,694			28,776			26,071
Depreciation, depletion and amortization		13,127			9,931			24,946			19,855
Exploration expenses, including dry holes		139			305			241			428

Total operating costs and expenses		684,126			487,519			1,309,942			925,510

Income from operations		87,170			81,216			113,079			106,282

Other income (expense):
Equity in earnings (loss) of joint ventures		—			600			(685	)		(55	)
Minority interests in income of partnerships		(3,119	)		(306	)		(6,721	)		(995	)
Interest income		2,084			2,313			3,252			2,390
Interest expense		(2,661	)		(751	)		(4,205	)		(1,706	)

		(3,696	)		1,856			(8,359	)		(366	)

Income before income taxes		83,474			83,072			104,720			105,916

Income tax provision:
Current		31,685			31,621			39,410			39,572
Deferred		(239	)		444			216			1,375

		31,446			32,065			39,626			40,947

Net Income	$	52,028		$	51,007		$	65,094		$	64,969


Net income per common share — basic	$	1.64		$	1.61		$	2.06		$	2.07


Net income per common share — diluted	$	1.61		$	1.56		$	2.01		$	2.01


Cash dividends declared per common share	$	0.10		$	0.065		$	0.18		$	0.13


Average number of common shares outstanding:
Basic		31,637			31,606			31,576			31,408
Diluted		32,383			32,604			32,307			32,370

See accompanying notes.

- 7 -

HOLLY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(In thousands)


	Six Months Ended
	June 30,
	2005			2004
Cash flows from operating activities:
Net income	$	65,094		$	64,969
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		24,946			19,855
Deferred income taxes		216			1,375
Minority interests in income of partnerships		6,721			995
Equity in earnings (loss) of joint ventures		685			55
Interest receivable		—			(2,189	)
Equity based compensation expense		2,627			722
(Increase) decrease in current assets:
Accounts receivable		(120,946	)		(73,030	)
Inventories		(14,739	)		12,451
Income taxes receivable		11,534			8,992
Prepayments and other		(1,611	)		(6,394	)
Increase (decrease) in current liabilities:
Accounts payable		92,097			60,438
Accrued liabilities		(4,121	)		6,530
Income taxes payable		19,415			25,393
Turnaround expenditures		(1,050	)		—
Other, net		(3,426	)		3,627

Net cash provided by operating activities		77,442			123,789
Cash flows from investing activities:
Additions to properties, plants and equipment		(28,645	)		(19,119	)
Acquisition by HEP of pipeline and terminal assets		(121,853	)		—
Investments and advances to joint ventures		—			(64	)
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		—			2,940
Purchases of marketable securities		(65,078	)		—
Sales and maturities of marketable securities		82,827			—

Net cash used for investing activities		(150,423	)		(16,243	)
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	)		(50,000	)
Debt issuance costs		(948	)		(1,455	)
Issuance of common stock upon exercise of options		2,569			2,634
Purchase of treasury stock		(26,911	)		—
Cash dividends		(5,057	)		(3,767	)
Cash distributions to minority interests		(9,486	)		(2,250	)

Net cash provided by (used for) financing activities		117,122			(54,838	)
Cash and cash equivalents:
Increase for the period		44,141			52,708
Beginning of period		67,460			11,690

End of period	$	111,601		$	64,398


Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	1,337		$	1,352
Income taxes	$	8,391		$	5,174

See accompanying notes.

- 8 -

HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

References herein to the 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 June 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 1,000 miles of crude oil and intermediate product 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 47.9% interest in Holly Energy Partners, L.P. (“HEP”), which owns logistic assets including approximately 1,300 miles of refined 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. 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. Since this acquisition closed after June 30, 2005, these consolidated financial statements do not reflect the effects of such acquisition.

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 June 30, 2005, the consolidated results of operations and comprehensive income for the three months and six months ended June 30, 2005 and 2004 and consolidated cash flows for the six months ended June 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.

- 10 -

HOLLY CORPORATION

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 six 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”), which reduced our ownership interest, at the time, in HEP to 47.9%. See Note 2 for additional information regarding HEP’s asset acquisition from Alon.

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 6 for additional information regarding both of these transactions.

Our operations are currently organized into two business divisions, which are Refining and HEP. The Refining business division includes the Navajo Refinery, Woods Cross Refinery, Montana Refinery and NK Asphalt Partners. Our operations that are not included in either the Refining or HEP business divisions include 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 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 now required to adopt this standard for 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 are evaluating the method of adoption and the impact, if any, of the new standard on our financial statements.

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”

- 11 -

HOLLY CORPORATION

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 change. This statement becomes effective for fiscal years beginning after December 15, 2005.

NOTE 2: HEP’s Alon Acquisition

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%. HEP continues to be included in our consolidated financial statements because of the control relationship between Holly Corporation and HEP.

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. 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 for the Alon pipeline and terminal assets was preliminarily allocated to the individual assets acquired based on their estimated fair values. The final allocation of the consideration is pending an independent appraisal, which is currently expected to be completed by year-end. 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 preliminarily 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.

- 12 -

HOLLY CORPORATION

NOTE 3: 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				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
			(In thousands)
Net income	$	52,028	$	51,007	$	65,094	$	64,969
Average number of shares of common stock outstanding		31,637		31,606		31,576		31,408
Effect of dilutive stock options and variable restricted shares		746		998		731		962

Average number of shares of common stock outstanding assuming dilution		32,383		32,604		32,307		32,370


Income per share — basic	$	1.64	$	1.61	$	2.06	$	2.07

Income per share — diluted	$	1.61	$	1.56	$	2.01	$	2.01

NOTE 4: Stock-Based Compensation

We have compensation plans under which certain officers and employees have been granted stock options. 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. Our stock-based compensation is measured in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Accordingly, no compensation expense is recognized for fixed option plans because the exercise prices of employee stock options equal or exceed the market prices of the underlying stock on the dates of grant.

The following table represents the effect on net income and earnings per share as if we had applied the fair value based method and recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock based employee compensation.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
			(In thousands)
Net income, as reported	$	52,028	$	51,007	$	65,094	$	64,969
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects		72		111		144		194

Pro forma net income	$	51,956	$	50,896	$	64,950	$	64,775


Net income per share — basic
As reported	$	1.64	$	1.61	$	2.06	$	2.07
Pro forma	$	1.64	$	1.61	$	2.06	$	2.06

Net income per share — diluted
As reported	$	1.61	$	1.56	$	2.01	$	2.01
Pro forma	$	1.60	$	1.56	$	2.01	$	2.00

- 13 -

HOLLY CORPORATION

We issued 56,600 shares (net of forfeitures) of restricted stock under our Long Term Incentive Compensation Plan during the six months ended June 30, 2005. These shares vest 33.3% on January 1, 2008, 33.3% on January 1, 2009 and 33.4% on January 1, 2010 (with later performance-based vesting in the case of shares granted to certain key executives). During the year ended December 31, 2004, we issued 270,644 shares (net of forfeitures) of restricted stock under our Long Term Incentive Compensation Plan. Of the 270,644 shares issued, 74,450 shares vested in January or February 2005 and 74,450 shares are scheduled to vest on or after January 1, 2006 (with later performance-based vesting after January 1, 2006 in the case of shares granted to certain key executives). The remaining 121,744 shares vest 33.3% on January 1, 2007, 33.3% on January 1, 2008 and 33.4% on January 1, 2009 (with later performance-based vesting in the case of shares granted to certain key executives). During the six months ended June 30, 2005, we issued 7,525 shares of restricted stock to outside directors with these shares vesting on the date of the Annual Meeting of Stockholders in 2008. During the year ended December 31, 2004, we issued 17,010 shares of restricted stock to outside directors with these shares vesting on the date of the Annual Meeting of Stockholders in 2007. Although ownership in 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. We are recording the cost of these grants over their corresponding vesting periods and have expensed $2.6 million and $0.7 million for the six months ended June 30, 2005 and 2004, respectively.

During the six months ended June 30, 2005, we granted 68,687 performance share units (net of forfeitures) under our Long Term Incentive Compensation Plan. These units generally vest on January 1, 2008. During the year ended December 31, 2004, we granted 276,900 performance share units (net of forfeitures) under our Long Term Incentive Compensation Plan. Of the 276,900 units issued, 162,900 units (net of forfeitures) vested on January 1, 2005. The remaining 114,000 units (net of forfeitures) generally vest on January 1, 2007. The cash benefit payable under these grants is based upon our share price and upon our total shareholder return during the period as compared to the total shareholder return of our peer group of refining companies. We are recording the cost of these grants over their corresponding vesting periods and have expensed $2.7 million and $1.9 million for the six months ended June 30, 2005 and 2004, respectively.

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.

NOTE 5: 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.

- 14 -

HOLLY CORPORATION

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


	Available-for-Sale Securities
			Gross			Estimated
			Unrealized			Fair Value
			(Gains)			(Net Carrying
	Amortized Cost		Losses			Amount)
	(Dollars in thousands)
U.S. Treasury	$	18,087	$	237		$	17,850
U.S. government agency		11,376		(49	)		11,425
Asset backed government and corporate securities		192		4			188
States and political subdivisions		95,299		259			95,040
Corporate debt securities		9,521		(7	)		9,528

Total debt securities	$	134,475	$	444		$	134,031

During the six months ended June 30, 2005, we recognized $2.2 million in gains related to 57 sales and maturities where we received $82.8 million in proceeds. The realized gains represent the difference between the purchase price and market value on the maturity date or sales date.

NOTE 6: 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. 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 asset 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 the affiliate under a supply agreement. Sales to the joint venture during 2005, prior to the acquisition, were $3.9 million and for the six months ended June 30, 2004 were $14.4 million.

Rio Grande is a pipeline joint venture partnership that is owned 70% by HEP and 30% by BP p.l.c., and serves northern Mexico by transporting liquid petroleum gases (“LPG’s”) from a point near Odessa, Texas to Pemex Gas (“Pemex”) at a point near El Paso, Texas. Pemex then transports the LPG’s to its Mendez terminal near Juarez, Mexico. Prior to the initial public offering of HEP on July 13, 2004, Rio Grande was owned 70% by us and 30% by BP p.l.c.

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.

- 15 -

HOLLY CORPORATION

NOTE 7: Environmental

Consistent with our accounting policy for environmental remediation and cleanup costs, we expensed $0.4 million during the six months ended June 30, 2005 and $0.4 million during the six months ended June 30, 2004 for environmental remediation and cleanup obligations. The accrued environmental liability reflected in the consolidated balance sheet was $3.5 million and $3.6 million at June 30, 2005 and December 31, 2004, respectively, of which $2.0 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 8: Debt


	June 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		182,957			—

		191,529			8,572

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

		—			25,000


Total debt		191,529			33,572

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

Total debt classified as long-term	$	182,957		$	25,000

Credit Facilities

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 June 30, 2005. At June 30, 2005, we had outstanding letters of credit totaling $1.2 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $173.8 million at June 30, 2005.

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. As of June 30, 2005, HEP had no amounts outstanding under their credit facility. At that level of usage, the unused commitment under HEP’s credit facility was $100.0 million at June 30, 2005. HEP was in compliance with its covenants at June 30, 2005. 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.

- 16 -

HOLLY CORPORATION

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 after such registration statement is declared effective. The exchange notes will generally be freely transferable but will be 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 recorded at $183.0 million on our accompanying consolidated balance sheet at June 30, 2005. The difference of $2.0 million is due to $3.6 million of unamortized discount net of $1.6 million relating to the interest rate swap contract discussed below.

Interest Rate Risk Management

This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. HEP’s interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the “shortcut” method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps.

The fair value of HEP’s interest rate swap agreement of $1.6 million is classified as part of other assets at June 30, 2005. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is classified as an offset to long-term debt, less current maturities at June 30, 2005.

Other Debt Information

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

Although debt of HEP is reflected on our balance sheet (because HEP is a consolidated subsidiary) for dates when the debt is outstanding, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable for this debt either directly or as guarantors.

- 17 -

HOLLY CORPORATION

NOTE 9: Minority Interests

On February 28, 2005, HEP closed on its acquisition from Alon of over 500 miles of light products pipelines and two light product terminals for $120.0 million in cash and 937,500 HEP Class B subordinated units which will convert into an equal number of HEP common units in five years, subject to certain conditions. On July 8, 2005 we closed on a transaction with HEP in which HEP acquired our two 65-mile parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities for $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. As part of HEP’s financing of the transaction, HEP raised $45.1 million from the private sale of 1.1 million of its common units to a limited number of institutional investors which closed simultaneously with the acquisition. As a result of these transactions, Holly’s ownership interest has been reduced from 51% to 47.9%, following the Alon transaction, and 45.0% following the intermediate pipelines transaction, including the 2% general partner interest.

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 of HEP Class B subordinated units		24,674
Amortization of HEP restricted units		25

Minority interests at June 30, 2005	$	179,484

NOTE 10: 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 have 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 will be 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 three months ended June 30, 2005, we repurchased 703,499 shares at a cost of approximately $29.1 million (of which $3.0 million of the cash settlement was after June 30, 2005) or an average of $41.37 per share.

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 taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such payroll taxes by another means.

- 18 -

HOLLY CORPORATION

NOTE 11: 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 June 30, 2005
Unrealized loss on securities available for sale	$	203		$	79		$	124

Other comprehensive loss	$	203		$	79		$	124


For the three months ended June 30, 2004
Hedging activities	$	—		$	—		$	—

Other comprehensive loss	$	—		$	—		$	—


For the six months ended June 30, 2005
Unrealized loss on securities available for sale	$	(25	)	$	(10	)	$	(15	)

Other comprehensive loss	$	(25	)	$	(10	)	$	(15	)


For the six months ended June 30, 2004
Hedging activities	$	(599	)	$	(230	)	$	(369	)

Other comprehensive loss	$	(599	)	$	(230	)	$	(369	)

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

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


	June 30,			December 31,
	2005			2004
	(In thousands)
Pension obligation adjustment	$	(1,462	)	$	(1,462	)
Unrealized loss on securities available for sale		(272	)		(257	)

Accumulated other comprehensive loss	$	(1,734	)	$	(1,719	)

NOTE 12: 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						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In thousands)
Service cost	$	776		$	775		$	1,723		$	1,521
Interest cost		788			701			1,883			1,760
Expected return on assets		(684	)		(750	)		(1,581	)		(1,441	)
Amortization of prior service cost		65			65			130			130
Amortization of net loss		254			127			483			343

Net periodic benefit cost	$	1,199		$	918		$	2,638		$	2,313

- 19 -

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 expect to contribute $10.0 million to the retirement plan in 2005, of which $5.0 million has been contributed through June 30, 2005.

NOTE 13: 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. 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.

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 at March 31, 2004, no price swaps were outstanding.

See Note 8 for information on an interest rate swap contract entered into by HEP.

NOTE 14: 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 the our Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

- 20 -

HOLLY CORPORATION

Court of Appeals for the District of Columbia Circuit with respect to this order and related orders of the FERC. 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.

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 15: Segment Information

We currently have two business segments: Refining and HEP. As of July 13, 2004, the closing of the initial pubic offering of HEP, we changed our segments to reflect our new business divisions. We reported results of operations in 2004 under both our old segments and our new segments. The Refining segment presented in the June 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 six months ended June 30, 2004 includes results of operations involving certain assets currently included in HEP. We are not reporting any activity for HEP for the three months and six months ended June 30, 2004 as we did not restate the operations of the old 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 that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries (the intermediate product pipelines were acquired by HEP on July 8, 2005 and will become part of the HEP segment). 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 other 51% interest in the joint venture from our 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 involves all of the operations of HEP, 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 includes 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 and interest charges as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations

- 21 -

HOLLY CORPORATION

column includes 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’ share of income of HEP.

The accounting policies for the segments 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 are strategic business units that offer different products and services.


								Consolidations
					Corporate			and			Consolidated
	Refining		HEP		and Other			Eliminations			Total
	(In thousands)
Three Months Ended June 30, 2005
Sales and other revenues	$	761,667	$	19,521	$	252		$	(10,144	)	$	771,296
Depreciation and amortization	$	9,088	$	3,849	$	190		$	—		$	13,127
Income (loss) from operations	$	92,294	$	8,234	$	(13,358	)	$	—		$	87,170
Income (loss) before taxes	$	92,316	$	6,041	$	(11,737	)	$	(3,146	)	$	83,474

Three Months Ended June 30, 2004
Sales and other revenues	$	568,245	$	—	$	607		$	(117	)	$	568,735
Depreciation and amortization	$	9,624	$	—	$	307		$	—		$	9,931
Income (loss) from operations	$	90,169	$	—	$	(8,953	)	$	—		$	81,216
Income (loss) before taxes	$	90,490	$	—	$	(7,418	)	$	—		$	83,072

Six Months Ended June 30, 2005
Sales and other revenues	$	1,405,944	$	36,034	$	617		$	(19,574	)	$	1,423,021
Depreciation and amortization	$	18,122	$	6,212	$	612		$	—		$	24,946
Income (loss) from operations	$	122,671	$	16,019	$	(25,611	)	$	—		$	113,079
Income (loss) before taxes	$	122,018	$	12,367	$	(23,346	)	$	(6,319	)	$	104,720
Total assets	$	747,442	$	286,584	$	206,550		$	80,101		$	1,320,677

Six Months Ended June 30, 2004
Sales and other revenues	$	1,030,926	$	—	$	1,097		$	(231	)	$	1,031,792
Depreciation and amortization	$	19,239	$	—	$	616		$	—		$	19,855
Income (loss) from operations	$	126,922	$	—	$	(20,640	)	$	—		$	106,282
Income (loss) before taxes	$	125,899	$	—	$	(19,983	)	$	—		$	105,916
Total assets	$	713,804	$	—	$	103,233		$	—		$	817,037

- 22 -

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 June 30, 2005, we also owned a 47.9% 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 six months ended June 30, 2005 were $1,423.7 million as compared to $1,031.8 million for the six months ended June 30, 2004. Our net income for the six months ended June 30, 2005 was $65.1 million as compared to $65.0 million for the six months ended June 30, 2004. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for six months ended June 30, 2005 were $1,310.6 million, an increase from $925.5 million for the six months ended June 30, 2004.

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 Class B subordinated units valued at $24.7 million which, subject to certain conditions, will convert into an equal number of HEP common units in five years. As a result of 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%. HEP is included in our consolidated financial statements because of the control relationship between Holly Corporation and HEP. In connection with the transaction, HEP entered into a 15-year pipelines and terminals agreement with Alon. HEP financed the $120 million cash portion of the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015. The balance of proceeds from the offering was used to repay $30 million of outstanding indebtedness under HEP’s revolving credit agreement. Although the senior notes will be reflected on our balance sheet (because HEP is a consolidated subsidiary) for dates when the senior notes are outstanding, Holly Corporation and its operating subsidiaries, other than HEP and its subsidiaries and controlling partners, are not liable for the senior notes either directly or as guarantors.

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. 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 HEP common units for $45.1 million to a limited number of institutional investors which closed simultaneously with the acquisition and the issuance of an additional $35.0 million in principal amount of HEP 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 its 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. Since this acquisition closed after June 30, 2005, our results of operations discussed herein do not reflect the effects of such acquisition.

- 23 -

HOLLY CORPORATION

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 will be 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 three months ended June 30, 2005, we repurchased 703,499 shares at a cost of approximately $29.1 million or an average of $41.37 per share.

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.

- 24 -

HOLLY CORPORATION

RESULTS OF OPERATIONS

Financial Data (Unaudited)


	Three Months Ended
	June 30,						Change from 2004
	2005			2004			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	771,296		$	568,735		$	202,561			35.6	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		604,835			425,654			179,181			42.1
Operating expenses (exclusive of depreciation, depletion, and amortization)		50,347			39,935			10,412			26.1
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization)		15,678			11,694			3,984			34.1
Depreciation, depletion and amortization		13,127			9,931			3,196			32.2
Exploration expenses, including dry holes		139			305			(166	)		(54.4	)

Total operating costs and expenses		684,126			487,519			196,607			40.3

Income from operations		87,170			81,216			5,954			7.3
Other income (expense):
Equity in earnings (loss) of joint ventures		—			600			(600	)		(100.0	)
Minority interests in income of partnerships		(3,119	)		(306	)		(2,813	)		919.3
Interest income		2,084			2,313			(229	)		(9.9	)
Interest expense		(2,661	)		(751	)		(1,910	)		254.3

		(3,696	)		1,856			(5,552	)		(299.1	)

Income before income taxes		83,474			83,072			402			0.5
Income tax provision		31,446			32,065			(619	)		(1.9	)

Net income	$	52,028		$	51,007		$	1,021			2.0	%


Net income per common share — basic	$	1.64		$	1.61		$	0.03			1.9	%

Net income per common share — diluted	$	1.61		$	1.56		$	0.05			3.2	%

Cash dividends declared per common share	$	0.10		$	0.065		$	0.035			53.8	%

Average number of common shares outstanding:
Basic		31,637			31,606			31			0.1	%
Diluted		32,383			32,604			(221	)		(0.7	)%

- 25 -

HOLLY CORPORATION


	Six Months Ended
	June 30,						Change from 2004
	2005			2004			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	1,423,021		$	1,031,792		$	391,229			37.9	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		1,161,028			800,549			360,479			45.0
Operating expenses (exclusive of depreciation, depletion, and amortization)		94,951			78,607			16,344			20.8
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization)		28,776			26,071			2,705			10.4
Depreciation, depletion and amortization		24,946			19,855			5,091			25.6
Exploration expenses, including dry holes		241			428			(187	)		(43.7	)

Total operating costs and expenses		1,309,942			925,510			384,432			41.5

Income from operations		113,079			106,282			6,797			6.4
Other income (expense):
Equity in earnings (loss) of joint ventures		(685	)		(55	)		(630	)		1,145.5
Minority interests in income of partnerships		(6,721	)		(995	)		(5,726	)		575.5
Interest income		3,252			2,390			862			36.1
Interest expense		(4,205	)		(1,706	)		(2,499	)		146.5

		(8,359	)		(366	)		(7,993	)		2,183.9

Income before income taxes		104,720			105,916			(1,196	)		(1.1	)
Income tax provision		39,626			40,947			(1,321	)		(3.2	)

Net income	$	65,094		$	64,969		$	125			0.2	%


Net income per common share — basic	$	2.06		$	2.07		$	(0.01	)		(0.5	)%

Net income per common share — diluted	$	2.01		$	2.01		$	0.01			0.5	%

Cash dividends declared per common share	$	0.18		$	0.13		$	0.05			37.4	%

Average number of common shares outstanding:
Basic		31,576			31,408			168			0.5	%
Diluted		32,307			32,370			(63	)		(0.2	)%

Balance Sheet Data (Unaudited)


	June 30,		December 31,
	2005		2004
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	245,632	$	219,265
Working capital	$	220,846	$	148,642
Total assets	$	1,320,677	$	982,713
Total debt, including current maturities and bank borrowings ⁽¹⁾	$	191,529	$	33,572
Minority interests	$	179,484	$	157,550
Stockholders’ equity	$	383,500	$	339,916


(1)		Includes HEP’s 6.25% senior notes of $183.0 million at June 30, 2005 and HEP bank borrowings of $25.0 million at December 31, 2004.

- 26 -

HOLLY CORPORATION

Other Financial Data (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
				(In thousands)
Net cash provided by operating activities	$	66,041		$	86,458		$	77,442		$	123,789
Net cash used for investing activities	$	(18,670	)	$	(5,347	)	$	(150,423	)	$	(16,243	)
Net cash provided by (used for) financing activities	$	791		$	(38,975	)	$	117,122		$	(54,838	)
Capital expenditures	$	15,197		$	5,671		$	28,645		$	19,119
EBITDA	$	97,178		$	91,441		$	130,619		$	125,087


(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.

Our two major business segments are: Refining and HEP. The Refining segment presented in the June 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 six months ended June 30, 2004 has been reported to include results of operations involving assets included in HEP prior to the contribution on July 13, 2004. The HEP segment did not have any activity for the three months and six months ended June 30, 2004 as HEP was not formed until July 13, 2004.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
				(In thousands)
Sales and other revenues ⁽¹⁾
Refining	$	761,667		$	568,245		$	1,405,944		$	1,030,926
HEP		19,521			—			36,034			—
Corporate and Other		252			607			617			1,097
Consolidations and Eliminations		(10,144	)		(117	)		(19,574	)		(231	)

Consolidated	$	771,296		$	568,735		$	1,423,021		$	1,031,792


Income (loss) from operations ⁽¹⁾
Refining	$	92,294		$	90,169		$	122,671		$	126,922
HEP		8,234			—			16,019			—
Corporate and Other		(13,358	)		(8,953	)		(25,611	)		(20,640	)

Consolidated	$	87,170		$	81,216		$	113,079		$	106,282


(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 that we still own and operate in conjunction with our refining operations as part of the supply networks of the refineries (the intermediate product pipelines were acquired by HEP on July 8, 2005 and will become part of the HEP segment). 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 other 51% interest in the joint venture from our other partner; subsequent to the purchase, we are including the operations of NK Asphalt Partners in our

- 27 -

HOLLY CORPORATION


		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 involves all of the operations of HEP, 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 includes 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 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 and interest charges 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.

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.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
*Navajo Refinery*
Crude charge (BPD) ⁽¹⁾		71,920			73,570			73,100			70,510
Refinery production (BPD) ⁽²⁾		77,750			80,000			80,880			78,740
Sales of produced refined products (BPD)		77,600			77,340			80,230			77,720
Sales of refined products (BPD) ⁽³⁾		85,960			83,850			89,800			84,240

Refinery utilization ⁽⁴⁾		95.9	%		98.1	%		97.5	%		94.0	%

Average per produced barrel ⁽⁵⁾
Net sales	$	65.73		$	52.72		$	61.50		$	48.83
Cost of products ⁽⁶⁾		50.30			37.77			49.47			36.43

Refinery gross margin ⁽⁷⁾		15.43			14.95			12.03			12.40
Refinery operating expenses ⁽⁸⁾		3.84			3.17			3.45			3.12

Net operating margin	$	11.59		$	11.78		$	8.58		$	9.28


Feedstocks:
Sour crude oil		90	%		81	%		88	%		80	%
Sweet crude oil		0	%		9	%		0	%		8	%
Other feedstocks and blends		10	%		10	%		12	%		12	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		56	%		58	%		59	%		59	%
Diesel fuels		30	%		26	%		27	%		26	%
Jet fuels		4	%		6	%		4	%		6	%
Asphalt		7	%		7	%		7	%		6	%
LPG and other		3	%		3	%		3	%		3	%

Total		100	%		100	%		100	%		100	%

- 28 -

HOLLY CORPORATION


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
*Woods Cross Refinery*
Crude charge (BPD) ⁽¹⁾		25,820			24,470			23,780			22,840
Refinery production (BPD) ⁽²⁾		27,170			24,910			25,540			23,110
Sales of produced refined products (BPD)		27,820			24,550			26,450			23,280
Sales of refined products (BPD) ⁽³⁾		29,120			25,050			27,500			23,580

Refinery utilization ⁽⁴⁾		99.3	%		97.9	%		91.5	%		91.4	%

Average per produced barrel ⁽⁵⁾
Net sales	$	67.35		$	53.39		$	61.17		$	48.88
Cost of products ⁽⁶⁾		57.28			42.61			54.35			41.44

Refinery gross margin ⁽⁷⁾		10.07			10.78			6.82			7.44
Refinery operating expenses ⁽⁸⁾		3.86			3.76			4.08			3.93

Net operating margin	$	6.21		$	7.02		$	2.74		$	3.51


Feedstocks:
Sour crude oil		9	%		5	%		9	%		5	%
Sweet crude oil		83	%		88	%		81	%		89	%
Other feedstocks and blends		8	%		7	%		10	%		6	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		60	%		58	%		60	%		59	%
Diesel fuels		31	%		32	%		28	%		31	%
Jet fuels		2	%		2	%		2	%		1	%
Fuel oil		6	%		7	%		7	%		7	%
LPG and other		1	%		1	%		3	%		2	%

Total		100	%		100	%		100	%		100	%


*Montana Refinery*
Crude charge (BPD) ⁽¹⁾		8,030			8,160			7,730			7,030
Refinery production (BPD) ⁽²⁾		8,510			8,550			8,170			7,420
Sales of produced refined products (BPD)		8,990			8,790			7,250			6,920
Sales of refined products (BPD) ⁽³⁾		9,190			8,990			7,380			7,130

Refinery utilization ⁽⁴⁾		100.4	%		102.0	%		96.6	%		87.9	%

Average per produced barrel ⁽⁵⁾
Net sales	$	52.15		$	43.29		$	52.88		$	42.24
Cost of products ⁽⁶⁾		41.04			34.17			42.75			33.72

Refinery gross margin		11.11			9.12			10.13			8.52
Refinery operating expenses ⁽⁸⁾		5.73			5.06			7.08			6.18

Net operating margin	$	5.38		$	4.06		$	3.05		$	2.34


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

Total		100	%		100	%		100	%		100	%

- 29 -

HOLLY CORPORATION


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
*Montana Refinery*
Sales of produced refined products:
Gasolines		39	%		39	%		45	%		45	%
Diesel fuels		17	%		17	%		20	%		19	%
Jet fuels		5	%		5	%		6	%		6	%
Asphalt		35	%		35	%		24	%		25	%
LPG and other		4	%		4	%		5	%		5	%

Total		100	%		100	%		100	%		100	%


*Consolidated*
Crude charge (BPD) ⁽¹⁾		105,770			106,200			104,610			100,380
Refinery production (BPD) ⁽²⁾		113,430			113,460			114,590			109,270
Sales of produced refined products (BPD)		114,410			110,680			113,930			107,920
Sales of refined products (BPD) ⁽³⁾		124,270			117,890			124,680			114,950

Refinery utilization ⁽⁴⁾		97.0	%		98.3	%		96.0	%		92.9	%

Average per produced barrel ⁽⁵⁾
Net sales	$	65.06		$	52.12		$	60.87		$	48.42
Cost of products ⁽⁶⁾		51.27			38.56			50.17			37.34

Refinery gross margin ⁽⁷⁾		13.79			13.56			10.70			11.08
Refinery operating expenses ⁽⁸⁾		3.99			3.45			3.83			3.49

Net operating margin	$	9.80		$	10.11		$	6.87		$	7.59


Feedstocks:
Sour crude oil		70	%		65	%		71	%		65	%
Sweet crude oil		20	%		26	%		18	%		25	%
Other feedstocks and blends		10	%		9	%		11	%		10	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		56	%		56	%		58	%		58	%
Diesel fuels		29	%		27	%		27	%		27	%
Jet fuels		4	%		5	%		4	%		5	%
Asphalt		7	%		7	%		6	%		6	%
LPG and other		4	%		5	%		5	%		4	%

Total		100	%		100	%		100	%		100	%


(1)		Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at 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, included in cost of products are transportation costs billed from HEP.

(7)		For comparability purposes, if amounts paid to HEP for transportation were excluded, as was the case prior to HEP’s initial public offering, the refinery gross margins for the three months and six months ended June 30, 2005 prior to the inclusion of those transportation costs were $16.76 and $13.29 for Navajo Refinery, $10.29 and $7.03 for Woods Cross Refinery, and $14.74 and $11.64 for the consolidated operations, respectively.

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

- 30 -

HOLLY CORPORATION

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

Summary

Net income for the three months ended June 30, 2005 was $52.0 million ($1.61 per diluted share) compared to net income of $51.0 million ($1.56 diluted share) for the three months ended June 30, 2004. Earnings for the second quarter of 2005 as compared to the second quarter of 2004 were up by $1.0 million as higher refined product margins combined with higher refined product sales volumes were partially offset by higher operating costs and expenses and by the attribution in the second quarter of 2005 of approximately half of the income from our refined product pipelines and terminals to third-party owners of interests in HEP. Overall refinery production levels were consistent between 2005 and 2004. Company-wide refinery margins were $13.79 per produced barrel for the second quarter of 2005 compared to reported margins of $13.56 per produced barrel for the second quarter of 2004; however, refinery margins for the second quarter of 2005 were reduced by pipeline and terminalling fees to HEP for transportation services that were not charged against margins in the second quarter of 2004. Excluding pipeline and terminalling fees to HEP for the second quarter of 2005, company-wide refinery margins were $14.74 and $13.56 for the second quarters of 2005 and 2004, respectively.

Sales and Other Revenues

Sales and other revenues increased 35.6% from $568.7 million for the three months ended June 30, 2004 to $771.3 million for the three months ended June 30, 2005 due principally to higher refined product sales prices, and to a lesser degree, increased volumes sold from our Navajo and Woods Cross refineries. The average sales price we received per produced barrel sold increased 25% from $52.12 in the second quarter of 2004 to $65.06 in the second quarter of 2005. The total volume of refined products we sold increased 5% in the second quarter of 2005 as compared to the second 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, and the inclusion of revenues from HEP’s assets recently acquired from Alon.

Cost of Products Sold

Cost of products sold increased 42.1% from $425.7 million in the second quarter of 2004 to $604.8 million in the second quarter of 2005 due principally to higher costs of crude oil, and to a lesser degree, increased volumes sold from our Navajo and Woods Cross refineries. The average price we paid per barrel of crude oil purchased increased 33% from $38.56 in the second quarter of 2004 to $51.27 in the second quarter 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.

Gross Refinery Margins

The gross refining margin per produced barrel increased 2% from $13.56 in the second quarter of 2004 to $13.79 in the second quarter of 2005. After deducting for pipeline and terminalling fees to HEP for the second quarter of 2005, the gross refining margin per produced barrel would be $14.74. 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 26.1% from $39.9 million in the second quarter of 2004 to $50.3 million in the second quarter of 2005 due to increased utility and catalyst costs, the addition of personnel in 2004, operating costs on the assets HEP acquired from Alon, and the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated statements.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased 34.1% from $11.7 million in the second quarter of 2004 to $15.7 million in the second quarter of 2005 due primarily to additional employee compensation expense in 2005 from the addition of personnel in 2004, increased equity-based incentive compensation, and incremental expenses related to HEP being a separate public entity.

- 31 -

HOLLY CORPORATION

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 32.2% from $9.9 million in the second quarter of 2004 to $13.1 million in the second quarter of 2005 due to depreciation on the assets HEP acquired from Alon, the 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.

Equity in Earnings of Joint Ventures and Minority Interests

There were no equity in earnings of joint ventures in the second quarter of 2005 as all previously owned interests have been consolidated in our financials or have been sold prior to April 1, 2005. Minority interests in income of partnerships in the second quarter of 2005 was a reduction in income of $3.1 million which represented the minority interests partners’ 52.1% ownership share of HEP’s income during the second quarter. Equity in earnings of joint ventures in the second quarter of 2004 included income of $0.7 million from our interest in the NK Asphalt joint venture. Minority interests in income of partnerships in the second quarter of 2004 was a reduction in income of $0.3 million. This represented the minority interest partner’s 30% ownership share of the Rio Grande joint venture’s income.

Interest Income

Interest income for the second quarter of 2005 was $2.1 million compared to $2.3 million for the second quarter of 2004. Interest income in 2005 is due to interest earned on our investable funds resulting from the receipt of proceeds from the initial public offering of HEP and internally generated cash flows. The interest income in 2004 mainly resulted from the $2.2 million accrued interest on the $25.0 million principal received from Longhorn Partners Pipeline, L.P. (“Longhorn Partners”) on July 1, 2004.

Interest Expense

Interest expense was $2.7 million for the second quarter of 2005 as compared to $0.8 million for the second quarter of 2004. The increase for the current year’s second quarter as compared to the same period in 2005 was principally due to higher interest costs associated with the senior notes of HEP.

Income Taxes

Income taxes decreased 1.9% from $32.1 million for the second quarter of 2004 to $31.4 million for the second quarter of 2005 due to a slightly lower effective tax rate in the current year. The effective tax rate for the second quarter of 2005 was 37.7%, as compared to 38.6% for the second quarter of 2004.

Results of Operations — Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Summary

Net income for the six months ended June 30, 2005 was $65.1 million ($2.01 per diluted share) compared to net income of $65.0 million ($2.01 diluted share) for the six months ended June 30, 2004. Earnings for the first six of 2005 as compared to the first six months of 2004 were slightly up $0.1 million as an increase in refinery production was offset by higher related operating expenses and by the attribution in 2005 of approximately half of the income from our refined product pipelines and terminals to owners (other than us) of interests in HEP. Overall refinery production levels increased 5% with the six months of 2005 total production at 114,590 BPD, due to increased production at all facilities. Company-wide refinery margins were $10.70 per barrel for the six months ended June 30, 2005 compared to reported margins of $11.08 per barrel for the six months ended June 30, 2004; however, refinery margins for the six months of 2005 were reduced by pipeline and terminalling fees to HEP for transportation services that were not charged against margins for the six months of 2004. Excluding pipeline and terminalling fees to HEP for the six months of 2005, company-wide refinery margins were $11.64 and $11.08 for the six months of 2005 and 2004, respectively.

Sales and Other Revenues

- 32 -

HOLLY CORPORATION

Sales and other revenues increased 37.9% from $1,031.8 million for the six months ended June 30, 2004 to $1,423.0 million for the six months ended June 30, 2005 due principally to higher refined product sales prices, and to a lesser degree, increased volumes sold from our Navajo and Woods Cross refineries. The average sales price we received per produced barrel sold increased 26% from $48.42 for the first six months of 2004 to $60.87 for the first six months of 2005. The total volume of refined products we sold increased 8% in the first six months of 2005 as compared to the first six 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 recently acquired from Alon.

Cost of Products Sold

Cost of products sold increased 45.0% from $800.5 million for the six months ended June 30, 2004 to $1,161.0 million for the six months ended June 30, 2005 due principally to higher costs of crude oil, and to a lesser degree, increased volumes sold from our Navajo and Woods Cross refineries. The average price we paid per barrel of crude oil purchased increased 34% from $37.34 in the first six months of 2004 to $50.17 in the first six 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 six 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 adjustments for the first six months of 2005.

Gross Refinery Margins

The gross refining margin per produced barrel decreased 3% from $11.08 for the six months ended June 30, 2004 to $10.70 for the six months ended June 30, 2005. After deducting for pipeline and terminalling fees to HEP for the first six months of 2005, the gross refining margin per produced barrel would be $11.64. 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 20.8% from $78.6 million in the six months ended June 30, 2004 to $95.0 million for the six months ended June 30, 2005 due to the higher production levels, increased utility and catalyst costs, the addition of personnel in 2004, operating costs associated with the assets HEP acquired from Alon, and the inclusion of the NK Asphalt Partners joint venture in the 2005 consolidated financial statements.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased 10.4% from $26.1 million in the six months ended June 30, 2004 to $28.8 million in the six months ended June 30, 2005 due primarily to additional employee compensation expense in 2005 from the addition of personnel in 2004, increased equity-based incentive compensation, and incremental expenses related to HEP being a separate public entity, partially offset by reduced legal fees for 2005 as compared to 2004.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 25.6% from $19.9 million for the six months ended June 30, 2004 to $24.9 million for the six months ended June 30, 2005 due to depreciation on the assets HEP acquired from Alon, 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 Joint Ventures and Minority Interests

Equity in earnings of joint ventures for the six months ended June 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 six months ended June 30, 2005 was a reduction in income of $6.7 million which represented the minority interests partners’ 52.1% ownership share of HEP’s income (49% prior to HEP’s asset acquisition from

- 33 -

HOLLY CORPORATION

Alon on February 28, 2005). Equity in earnings of joint ventures for the six months ended June 30, 2004 included income of $0.1 million from our interest in NK Asphalt joint venture. Minority interests in income of partnerships resulted in income of $0.1 million. This represented the minority interest partner’s 30% ownership share of the Rio Grande joint venture loss.

Interest Income

Interest income for the six months ended June 30, 2005 was $3.3 million compared to $2.4 million for the six months ended June 30, 2004. Interest income in 2005 is due to interest earned on our investable funds resulting from the receipt of proceeds from the initial public offering of HEP and internally generated cash flows. The interest income in 2004 mainly resulted from the $2.2 million accrued interest on the $25.0 million principal received from Longhorn Partners on July 1, 2004.

Interest Expense

Interest expense was $4.2 million for the six months ended June 30, 2005 as compared to $1.7 million for the six months ended June 30, 2004. The increase for the first six 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.

Income Taxes

Income taxes decreased 3.2% from $40.9 million for the six months ended June 30, 2004 to $39.6 million for the six months ended June 30, 2005 due to a slightly lower effective tax rate. The effective tax rate for the six months ended June 30, 2005 was 37.8%, as compared to 38.7% for the six months ended June 30, 2004.

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 loss. As of June 30, 2005, we had cash and cash equivalents of $111.6 million (including $54.3 million held by HEP), marketable securities with maturities under one year of $97.6 million and marketable securities with maturities greater than one year, but less than two years, of $36.4 million.

Cash and cash equivalents increased by $44.1 million during the six months ended June 30, 2005. The cash flow provided by financing activities of $117.1 million, combined with the cash generated from operating activities of $77.4 million, exceeded the cash used for investing activities of $150.4 million. Working capital increased during the six months ended June 30, 2005 by $72.2 million.

On July 1, 2004, we entered into a new $175 million secured revolving credit facility which replaced our prior revolving credit facility with Canadian Imperial Bank of Commerce. The new credit facility with Bank of America, as administrative agent and a lender, has a term of four years and we may increase it to $225 million subject to certain conditions. The new credit facility may be used to fund working capital requirements, capital expenditures, acquisitions and other general corporate purposes. As of June 30, 2005, we had letters of credit outstanding under our revolving credit facility of $1.2 million and had no borrowings outstanding. We were in compliance with all covenants at June 30, 2005. Additionally, a new credit facility was entered into for the benefit of HEP, as described

- 34 -

HOLLY CORPORATION

below.

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. As of June 30, 2005, HEP had no amounts outstanding under their credit facility. HEP was in compliance with its covenants at June 30, 2005. 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.

We believe our current cash, cash equivalents, and marketable securities, along with future internally generated cash flow, and funds available under our credit facilities provide sufficient resources to fund planned capital projects, scheduled repayments of Holly’s senior notes, continued payment of dividends, distributions by HEP to third-party partners of HEP (although dividend and distribution payments must be approved by the appropriate Board of Directors and cannot be guaranteed) and our working capital liquidity needs for the foreseeable future.

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 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 of an additional $35.0 million in principal of their 6.25% Senior Notes due 2015.

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 after such registration is declared effective. The exchange notes will generally be freely transferable but will be 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 million principal amount of Senior Notes is recorded at $183.0 on our accompanying consolidated balance sheet at June 30, 2005. The difference of $2.0 million from the principal balance is due to the accounting for the $3.6 million discount to the initial purchasers and for $1.6 million relating to the interest rate swap contract discussed below.

HEP’s Alon Transaction

- 35 -

HOLLY CORPORATION

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%. HEP is included in our consolidated financial statements because of the control relationship between Holly Corporation and HEP.

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. 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 to HEP. 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 consideration for the Alon pipeline and terminal assets was preliminarily allocated to the individual assets acquired based on their estimated fair values. The final allocation of the consideration is pending an independent appraisal, which is currently expected to be completed by year-end. 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 preliminarily 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.

Cash Flows — Operating Activities

Net cash flows provided by operating activities amounted to $77.4 million for the six months ended June 30, 2005 compared to $123.8 million for the six months ended June 30, 2004, a decrease of $46.4 million. Net income for the six months ended June 30, 2005 was $65.1 million, an increase of $0.1 million from net income of $65.0 million for the six months ended June 30, 2004. The non-cash items of depreciation and amortization, deferred taxes, minority interests, equity in joint ventures, and equity-based compensation increased by $14.4 million in the first six months of 2005 from the same period in 2004. Working capital items decreased cash flows by $18.4 million during the six months ended June 30, 2005, as compared to increased cash flows of $34.4 million for the six months ended June 30, 2004. A primary cause for the decrease in cash flows from working capital items was due to changes in inventories. For the first six months of 2005, inventories increased by $14.7 million, as compared to a decrease in inventories for the first six months of 2004 of $12.5 million. Additionally, in the first six months of 2005, accounts receivable increased $120.9 million and accounts payable increased $92.1 million, as compared to the first six months of 2004 when accounts receivable increased $73.0 million and accounts payable increased $60.4 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 $150.4 million for the six months ended June 30, 2005, as

- 36 -

HOLLY CORPORATION

compared to $16.2 million for the six months ended June 30, 2004. an increase of $134.2 million. Cash expenditures for property, plant and equipment for the first six months of 2005 totaled $28.6 million, as compared to $19.1 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. 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 the 51% acquisition. In the first six months of 2005, we invested $65.1 million in marketable securities and received proceeds of $82.8 million from the sale or maturity of marketable securities. In the first six months of 2004, we received a distribution of $2.9 million from our asphalt joint venture.

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 $117.6 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, $1.5 million for HEP projects (approved by HEP’s Board of Directors), and $4.5 million for information technology and other miscellaneous 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 tail gas unit, which will allow us to produce ULSD by June 2006. 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 also 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 may lease). In order to avoid additional unit downtime, we plan to phase in the crude expansion starting in the second quarter of 2006 and complete 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 plan to relocate and refurbish 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 early in the first quarter of 2006.

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 will allow Holly Refining and Marketing — Woods Cross to produce ULSD by June 2006. 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.

- 37 -

HOLLY CORPORATION

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

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 $117.1 million for the six months ended June 30, 2005, as compared to cash flows used for financing activities of $54.8 million for the six months ended June 30, 2004, a change of $171.9 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 six months ending June 30, 2005, we paid $5.1 million in dividends, received $2.6 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 and incurred $0.9 million of debt issuance costs related to HEP’s senior debt. Also, during the six months ended June 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 taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such payroll taxes by another means. Under our stock repurchase program announced May 19, 2005, we purchased treasury stock of $26.1 million. During the first six months of 2004, we repaid in full our borrowings under our credit facility of $50.0 million, paid $3.8 million in dividends, received $2.6 million for common stock issued upon the exercise of options and made a distribution of $2.3 million to the minority interest partner of Rio Grande.

Contractual Obligations and Commitments

The following table presents ours and HEP’s long-term contractual obligations in total and by period due as of June 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	$	—	$	—	$	—
HEP long-term debt (stated maturities)	$	185,000	$	—	$	—	$	—	$	185,000
HEP long-term debt (interest)	$	115,657	$	11,595	$	23,125	$	23,125	$	57,812
Operating leases	$	19,473	$	7,582	$	8,474	$	1,934	$	1,483

In December 2001, we entered into a Consent Agreement (“Consent Agreement”) with the Environmental

- 38 -

HOLLY CORPORATION

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 $11.0 million has been 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”

- 39 -

HOLLY CORPORATION

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 (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 change. This statement becomes effective for fiscal years beginning after December 15, 2005.

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. 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.

In October 2003, we entered into price swaps to help manage the exposure to price volatility relating to forecasted

- 40 -

HOLLY CORPORATION

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 at June 30, 2004, no price swaps were 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. This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. HEP’s interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the “shortcut” method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swaps. The fair value of HEP’s interest rate swap agreement of $1.6 million is included in other assets in our accompanying consolidated balance sheet at June 30, 2005. The offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged is recognized as an offset to long-term debt, less current maturities on our accompanying consolidated balance sheet at June 30, 2005.

At June 30, 2005, HEP had an outstanding principal balance on its unsecured Senior Notes of $185.0 million. By means of its interest rate swap contract, HEP has effectively converted $60.0 million of the Senior Notes from a fixed rate to variable rate. For the fixed rate debt portion of $125.0 million, changes in interest rates would generally affect the fair value of the debt, but not our earnings or cash flows. Conversely, for the variable rate debt portion of $60.0 million, changes in interest rates would generally not impact the fair value of the debt, but may affect our future earnings and cash flows. We estimate a hypothetical 10% change in the interest rate applicable to HEP’s fixed rate debt portion of $125.0 million would result in a change of approximately $5.6 million in the fair value of the debt. A hypothetical 10% change in the interest rate applicable to HEP’s variable rate debt portion of $60.0 million would not have a material effect on our earnings or cash flows.

At June 30, 2005, we had outstanding unsecured debt of $8.6 million, excluding HEP’s Senior Notes discussed above. 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 less than 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 June 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 the interest rates on our long-term debt are fixed 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 year would not materially impact our financial condition since the average maturity of our unsecured long-term debt is less than one year, such debt represents less than 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.

- 41 -

HOLLY CORPORATION

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						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In thousands)
Net income	$	52,028		$	51,007		$	65,094		$	64,969
Add provision for income tax		31,446			32,065			39,626			40,947
Add interest expense		2,661			751			4,205			1,706
Subtract interest income		(2,084	)		(2,313	)		(3,252	)		(2,390	)
Add depreciation, depletion and amortization		13,127			9,931			24,946			19,855

EBITDA	$	97,178		$	91,441		$	130,619		$	125,087

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.

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.

- 42 -

HOLLY CORPORATION

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				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average per produced barrel

*Navajo Refinery*
Net sales	$	65.73	$	52.72	$	61.50	$	48.83
Less cost of products		50.30		37.77		49.47		36.43

Refinery gross margin	$	15.43	$	14.95	$	12.03	$	12.40


*Woods Cross Refinery*
Net sales	$	67.35	$	53.39	$	61.17	$	48.88
Less cost of products		57.28		42.61		54.35		41.44

Refinery gross margin	$	10.07	$	10.78	$	6.82	$	7.44


*Montana Refinery*
Net sales	$	52.15	$	43.29	$	52.88	$	42.24
Less cost of products		41.04		34.17		42.75		33.72

Refinery gross margin	$	11.11	$	9.12	$	10.13	$	8.52


*Consolidated*
Net sales	$	65.06	$	52.12	$	60.87	$	48.42
Less cost of products		51.27		38.56		50.17		37.34

Refinery gross margin	$	13.79	$	13.56	$	10.70	$	11.08

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				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average per produced barrel

*Navajo Refinery*
Refinery gross margin	$	15.43	$	14.95	$	12.03	$	12.40
Less refinery operating expenses		3.84		3.17		3.45		3.12

Net operating margin	$	11.59	$	11.78	$	8.58	$	9.28


*Woods Cross Refinery*
Refinery gross margin	$	10.07	$	10.78	$	6.82	$	7.44
Less refinery operating expenses		3.86		3.76		4.08		3.93

Net operating margin	$	6.21	$	7.02	$	2.74	$	3.51

- 43 -

HOLLY CORPORATION


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average per produced barrel

*Montana Refinery*
Refinery gross margin	$	11.11	$	9.12	$	10.13	$	8.52
Less refinery operating expenses		5.73		5.06		7.08		6.18

Net operating margin	$	5.38	$	4.06	$	3.05	$	2.34


*Consolidated*
Refinery gross margin	$	13.79	$	13.56	$	10.70	$	11.08
Less refinery operating expenses		3.99		3.45		3.83		3.49

Net operating margin	$	9.80	$	10.11	$	6.87	$	7.59

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						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
*Navajo Refinery*
Average sales price per produced barrel sold	$	65.73		$	52.72		$	61.50		$	48.83
Times sales of produced refined products sold (BPD)		77,600			77,340			80,230			77,720
Times number of days in period		91			91			181			182

Refined product sales from produced products sold	$	464,159		$	371,040		$	893,080		$	690,702


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	67.35		$	53.39		$	61.17		$	48.88
Times sales of produced refined products sold (BPD)		27,820			24,550			26,450			23,280
Times number of days in period		91			91			181			182

Refined product sales from produced products sold	$	170,505		$	119,276		$	292,848		$	207,103


*Montana Refinery*
Average sales price per produced barrel sold	$	52.15		$	43.29		$	52.88		$	42.24
Times sales of produced refined products sold (BPD)		8,990			8,790			7,250			6,920
Times number of days in period		91			91			181			182

Refined product sales from produced products sold	$	42,663		$	34,627		$	69,392		$	53,199


Sum of refined products sales from produced products sold from our three refineries ⁽²⁾	$	677,327		$	524,943		$	1,255,320		$	951,004
Add refined product sales from purchased products and rounding ⁽¹⁾		62,122			37,552			124,635			67,353

Total refined products sales		739,449			562,495			1,379,955			1,018,357
Add other refining segment revenue		22,218			5,750			25,989			12,569

Total refining segment revenue		761,667			568,245			1,405,944			1,030,926
Add HEP sales and other revenue		19,521			—			36,034			—
Add corporate and other revenues		252			607			617			1,097
Subtract consolidations and eliminations		(10,144	)		(117	)		(19,574	)		(231	)

Sales and other revenues	$	771,296		$	568,735		$	1,423,021		$	1,031,792

- 44 -

HOLLY CORPORATION


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments where we choose to redirect produced products to more profitable markets.

(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				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average sales price per produced barrel sold	$	65.06	$	52.12	$	60.87	$	48.42
Times sales of produced refined products sold (BPD)		114,410		110,680		113,930		107,920
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	677,327	$	524,943	$	1,255,220	$	951,004

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
*Navajo Refinery*
Average cost of products per produced barrel sold	$	50.30		$	37.77		$	49.47		$	36.43
Times sales of produced refined products sold (BPD)		77,600			77,340			80,230			77,720
Times number of days in period		91			91			181			182

Cost of products for produced products sold	$	355,198		$	265,823		$	718,385		$	515,304


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	57.28		$	42.61		$	54.35		$	41.44
Times sales of produced refined products sold (BPD)		27,820			24,550			26,450			23,280
Times number of days in period		91			91			181			182

Cost of products for produced products sold	$	145,011		$	95,193		$	260,198		$	175,580


*Montana Refinery*
Average cost of products per produced barrel sold	$	41.04		$	34.17		$	42.75		$	33.72
Times sales of produced refined products sold (BPD)		8,990			8,790			7,250			6,920
Times number of days in period		91			91			181			182

Cost of products for produced products sold	$	33,574		$	27,332		$	56,099		$	42,468


Sum of cost of products for produced products sold from our three refineries ⁽²⁾	$	533,783		$	388,348		$	1,034,682		$	733,352
Add refined product costs from purchased products sold and rounding ⁽¹⁾		65,041			37,423			128,908			67,428

Total refined costs of products sold		598,824			425,771			1,163,590			800,780
Add other refining segment costs of products sold		16,155			—			17,012			—

Total refining segment cost of products sold		614,979			425,771			1,180,602			800,780
Subtract consolidations and eliminations		(10,144	)		(117	)		(19,574	)		(231	)

Costs of products sold (exclusive of depreciation, depletion and amortization)	$	604,835		$	425,654		$	1,161,028		$	800,549


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments where we choose to redirect produced products to more profitable markets.

(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.

- 45 -

HOLLY CORPORATION


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average cost of products per produced barrel sold	$	51.27	$	38.56	$	50.17	$	37.34
Times sales of produced refined products sold (BPD)		114,410		110,680		113,930		107,920
Times number of days in period		91		91		181		182

Cost of products for produced products sold	$	533,783	$	388,348	$	1,034,682	$	733,352

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	3.84	$	3.17	$	3.45	$	3.12
Times sales of produced refined products sold (BPD)		77,600		77,340		80,230		77,720
Times number of days in period		91		91		181		182

Refinery operating expenses for produced products sold	$	27,117	$	22,310	$	50,100	$	44,133


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	3.86	$	3.76	$	4.08	$	3.93
Times sales of produced refined products sold (BPD)		27,820		24,550		26,450		23,280
Times number of days in period		91		91		181		182

Refinery operating expenses for produced products sold	$	9,772	$	8,400	$	19,533	$	16,651


*Montana Refinery*
Average refinery operating expenses per produced barrel sold	$	5.73	$	5.06	$	7.08	$	6.18
Times sales of produced refined products sold (BPD)		8,990		8,790		7,250		6,920
Times number of days in period		91		91		181		182

Refinery operating expenses for produced products sold	$	4,688	$	4,047	$	9,291	$	7,783


Sum of refinery operating expenses per produced products sold from our three refineries ⁽¹⁾	$	41,577	$	34,757	$	78,924	$	68,567
Add other refining segment operating expenses and rounding		2,322		5,086		4,191		9,907

Total refining segment operating expenses		43,899		39,843		83,115		78,474
Add HEP operating expenses		6,448		—		11,836		—
Add corporate and other costs		—		92		—		133

Operating expenses (exclusive of depreciation, depletion and amortization)	$	50,347	$	39,935	$	94,951	$	78,607


(1)		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.

- 46 -

HOLLY CORPORATION


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Average refinery operating expenses per produced barrel sold	$	3.99	$	3.45	$	3.83	$	3.49
Times sales of produced refined products sold (BPD)		114,410		110,680		113,930		107,920
Times number of days in period		91		91		181		182

Refinery operating expenses for produced products sold	$	41,577	$	34,757	$	78,924	$	68,567

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
*Navajo Refinery*
Net operating margin per produced barrel	$	11.59	$	11.78	$	8.58	$	9.28
Add average refinery operating expenses per produced barrel		3.84		3.17		3.45		3.12

Refinery gross margin per produced barrel		15.43		14.95		12.03		12.40
Add average cost of products per produced barrel sold		50.30		37.77		49.47		36.43

Average net sales per produced barrel sold	$	65.73	$	52.72	$	61.50	$	48.83
Times sales of produced refined products sold (BPD)		77,600		77,340		80,230		77,720
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	464,159	$	371,040	$	893,080	$	690,702


*Woods Cross Refinery*
Net operating margin per produced barrel	$	6.21	$	7.02	$	2.74	$	3.51
Add average refinery operating expenses per produced barrel		3.86		3.76		4.08		3.93

Refinery gross margin per produced barrel		10.07		10.78		6.82		7.44
Add average cost of products per produced barrel sold		57.28		42.61		54.35		41.44

Average net sales per produced barrel sold	$	67.35	$	53.39	$	61.17	$	48.88
Times sales of produced refined products sold (BPD)		27,820		24,550		26,450		23,280
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	170,505	$	119,276	$	292,848	$	207,103


*Montana Refinery*
Net operating margin per produced barrel	$	5.38	$	4.06	$	3.05	$	2.34
Add average refinery operating expenses per produced barrel		5.73		5.06		7.08		6.18

Refinery gross margin per produced barrel		11.11		9.12		10.13		8.52
Add average cost of products per produced barrel sold		41.04		34.17		42.75		33.72

Average net sales per produced barrel sold	$	52.15	$	43.29	$	52.88	$	42.24
Times sales of produced refined products sold (BPD)		8,990		8,790		7,250		6,920
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	42,663	$	34,627	$	69,392	$	53,199

- 47 -

HOLLY CORPORATION


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Sum of refined product sales from produced products sold from our three refineries ⁽²⁾	$	677,327		$	524,943		$	1,255,320		$	951,004
Add refined product sales from purchased products and rounding ⁽¹⁾		62,122			37,552			124,635			67,353

Total refining product sales		739,449			562,495			1,379,955			1,018,357
Add other refining segment revenue		22,218			5,750			25,989			12,569

Total refining segment revenue		761,667			568,245			1,405,944			1,030,926
Add HEP sales and other revenue		19,521			—			36,034			—
Add corporate and other revenues		252			607			617			1,097
Subtract consolidations and eliminations		(10,144	)		(117	)		(19,574	)		(231	)

Sales and other revenues	$	771,296		$	568,735		$	1,423,021		$	1,031,792


(1)		We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments where we choose to redirect produced products to more profitable markets.

(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				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Net operating margin per produced barrel	$	9.80	$	10.11	$	6.87	$	7.59
Average refinery operating expenses per produced barrel		3.99		3.45		3.83		3.49

Refinery gross margin per produced barrel		13.79		13.56		10.70		11.08
Add average cost of products per produced barrel sold		51.27		38.56		50.17		37.34

Average net sales per produced barrel sold	$	65.06	$	52.12	$	60.87	$	48.42
Times sales of produced refined products sold (BPD)		114,410		110,680		113,930		107,920
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	677,327	$	524,943	$	1,255,320	$	951,004

- 48 -

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 be disclosed 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.

- 49 -

HOLLY CORPORATION

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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.

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 does 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”). On April 26, 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). If the ruling of the appeals court becomes final, it could have a significant adverse effect on our pending case. Tesoro and Hermes have filed a petition for the full appeals court (composed of twelve judges) to hear the cases en banc and reconsider the panel’s ruling. This petition has not yet been acted upon by the appeals court. Our case has been stayed by the trial judge until there is a final disposition of the pending appeal in the Tesoro and Hermes cases.

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. On May 4, 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. On June 1, 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. On June 13, 2005, we filed a petition for review to the Court of Appeals for the District of Columbia Circuit with respect to this order and related orders of the FERC. 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

- 50 -

HOLLY CORPORATION

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.

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. MRC has tentatively agreed with the MDEQ that MRC will carry out a supplemental environmental project to provide additional environmental benefits in the area where MRC operates and the monetary penalty amount will be reduced to approximately $92,000. Following the October 2003 incident that resulted in this enforcement action, MRC has taken additional steps to avoid future delays in repairs to the VCU and to prevent operation of the truck loading rack without the VCU.

- 51 -

HOLLY CORPORATION

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

(c)

Common Stock Repurchases Made in the Quarter

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 will be 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 during the second quarter of 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 Million		Part of the $100
Period	Shares Purchased		Per Share		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

Total		703,499	$	41.37		703,499	$	70,894,988

Item 4. Submission of Matters to a Vote of Security Holders

At the annual meeting of stockholders on May 9, 2005, all ten of the nominees for directors as listed in the proxy statement were elected.

Election of Directors


	Total Votes		Total Votes
	“For”		“Withheld”
Buford P. Berry		30,071,392		647,977
Matthew P. Clifton		24,819,186		5,900,183
W. John Glancy		24,817,416		5,901,953
William J. Gray		24,686,414		6,032,955
Marcus R. Hickerson		25,089,493		5,629,876
Thomas K. Matthews, II		29,139,279		1,580,090
Robert G. McKenzie		29,036,813		1,682,556
C. Lamar Norsworthy, III		25,145,483		5,573,886
Jack P. Reid		24,868,488		5,850,881
Paul T. Stoffel		28,310,159		2,409,210

- 52 -

HOLLY CORPORATION

Item 6. Exhibits

(a)

Exhibits

	2.1		Purchase and Sale Agreement, dated July 6, 2005 by and among Holly Corporation, Navajo Pipeline Co., L.P., Navajo Refining Company, L.P., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P. and HEP Pipeline, L.L.C. (incorporated by reference to Exhibit 2.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed with the SEC on July 12, 2005).

	4.1		Registration Rights Agreement, dated July 8, 2005, among Holly Energy Partners, L.P., Fiduciary/Claymore MLP Opportunity Fund, Perry Partners, L.P., Structured Finance Americas, LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed with the SEC on July 12, 2005).

	4.2		First Supplemental Indenture, dated March 10, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified therein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005).

	4.3		Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors identified herein, and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005).

	10.1*		First Amendment to the Holly Corporation Long-Term Incentive Compensation Plan, as amended and restated (formerly designated the Holly Corporation 2000 Stock Option Plan).

	10.2		Pipelines Agreement, dated July 8, 2005, among Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., Holly Corporation, HEP Pipeline, L.L.C., Navajo Refining Company, L.P., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed with the SEC on July 12, 2005).

	10.3		Waiver and Amendment No. 3, dated June 17, 2005, among Holly Energy Partners, L.P., Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.3 of Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005).

	10.4		Consent and Amendment No. 4, dated July 8, 2005, among Holly Energy Partners, L.P., Union Bank of California, N.A., as administrative agent, and certain other lending institutions identified therein (incorporated by reference to Exhibit 10.3 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed with the SEC on July 12, 2005).

	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.

- 53 -


	HOLLY CORPORATION
	(Registrant)

Date: August 8, 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)


		Page
PART I.	FINANCIAL INFORMATION

Forward-Looking Statements			3

Definitions			4

Item 1.	Financial Statements

	Consolidated Balance Sheet - (Unaudited) - June 30, 2005 and December 31, 2004		6

	Consolidated Statement of Income (Unaudited) - Three Months and Six Months Ended June 30, 2005 and 2004		7

	Consolidated Statement of Cash Flows (Unaudited) - Six Months Ended June 30, 2005 and 2004		8

	Consolidated Statement of Comprehensive Income (Unaudited) - Three Months and Six Months Ended June 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		23

Item 3.	Quantitative and Qualitative Disclosures About Market Risks		42

Reconciliations to amounts reported under generally accepted accounting principles			42

Item 4.	Controls and Procedures		49

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings		50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		52

Item 4.	Submission of Matters to a Vote of Security Holders		52

Item 6.	Exhibits		53

Signatures			55
First Amendment to Long-Term Incentive Compensation Plan
Certification of CEO under Section 302
Certification of CFO under Section 302
Certification of CEO under Section 906
Certification of CFO under Section 906