HF Sinclair 10-Q 2006 Q2 Quarterly report

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, 2006

OR

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 Number1-3876

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	75201-6915
(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. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act). (Check one):

Large accelerated filerþ                    Accelerated filero                     Non-accelerated filero

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

57,857,327 shares of Common Stock, par value $.01 per share, were outstanding on July 31, 2006.

HOLLY CORPORATION
INDEX

			Page
PART I.		FINANCIAL INFORMATION
	Forward-Looking Statements			3
	Definitions			4
	Item 1.	Financial Statements
		Consolidated Balance Sheets June 30, 2006 (Unaudited) and December 31, 2005		6
		Consolidated Statements of Income (Unaudited) Three Months and Six Months Ended June 30, 2006 and 2005		7
		Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2006 and 2005		8
		Consolidated Statements of Comprehensive Income (Unaudited) Three Months and Six Months Ended June 30, 2006 and 2005		9
		Notes to Consolidated Financial Statements (Unaudited)		10
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		43
	Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles			43
	Item 4.	Controls and Procedures		50
PART II.		OTHER INFORMATION
	Item 1.	Legal Proceedings		51
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53
	Item 4.	Submission of Matters to a Vote of Security Holders		53
	Item 6.	Exhibits		54
Signatures				55
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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 beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. 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, curtailments or shutdowns in refinery operations or pipelines;

• effects of governmental regulations and policies;

• the availability and cost of our financing;

• the effectiveness of our capital investments and marketing strategies;

• our efficiency in carrying out construction projects;

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

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

• general economic conditions; and

• 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 of risk factors and other cautionary statements under the heading “Risk Factors” included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2005 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.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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DEFINITIONS

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

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

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

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

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

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

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

     “Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.

     “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.

     “LSG” or low sulfur gasoline, means gasoline that contains less than 30 PPM of total sulfur.

     “MMBtu” or one million British thermal units, means for each unit, the amount of heat required to raise one pound of water one degree Fahrenheit at one atmosphere pressure.

     “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.

     “PPM” means parts-per-million.

     “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.

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     “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.

     “Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude oil” means crude oil containing quantities of sulfur less than 0.4 percent by weight.

     “ULSD” or ultra low sulfur diesel, means diesel fuel that contains less than 15 PPM of total sulfur.

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

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Item 1.Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	June 30,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	117,856		$	49,064
Marketable securities		110,737			189,978
Accounts receivable: Product and transportation		185,251			145,736
Crude oil resales		276,569			254,734
Related party receivable		1,848			1,434
		463,668			401,904
Inventories: Crude oil and refined products		132,222			91,257
Materials and supplies		13,607			12,082
		145,829			103,339
Prepayments and other		21,243			14,639
Assets of discontinued operations		2,466			30,612
Total current assets		861,799			789,536
Properties, plants and equipment, at cost		590,980			532,641
Less accumulated depreciation, depletion and amortization		(222,536	)		(216,502	)
		368,444			316,139
Marketable securities (long-term)		4,410			15,800
Other assets: Turnaround costs (long-term)		4,965			7,309
Intangibles and other		17,724			14,116
		22,689			21,425
Total assets	$	1,257,342		$	1,142,900
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	556,569		$	518,584
Accrued liabilities		45,038			41,235
Income taxes payable		16,263			5,538
Liabilities of discontinued operations		8,503			14,076
Total current liabilities		626,373			579,433
Deferred income taxes		12,646			9,989
Other long-term liabilities		21,867			19,101
Commitments and contingencies		—			—
Distributions in excess of investment in Holly Energy Partners		162,111			157,026
Stockholders’ equity:
Preferred stock, $1.00 par value – 1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value – 100,000,000 and 50,000,000 shares authorized; 71,666,960 and 35,378,646 shares issued as of June 30 2006 and December 31, 2005, respectively		717			354
Additional capital		59,981			43,344
Retained earnings		628,274			495,819
Accumulated other comprehensive loss		(4,930	)		(4,802	)
Common stock held in treasury, at cost – 14,726,391 and 6,002,175 shares as of June 30, 2006 and December 31, 2005, respectively		(249,697	)		(157,364	)
Total stockholders’ equity		434,345			377,351
Total liabilities and stockholders’ equity	$	1,257,342		$	1,142,900

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Sales and other revenues	$	1,120,840		$	728,655		$	1,912,434		$	1,353,374
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		908,009			569,933			1,583,494			1,103,347
Operating expenses (exclusive of depreciation, depletion and amortization)		49,092			48,268			101,559			89,744
General and administrative expenses (exclusive of depreciation, depletion and amortization)		18,731			12,328			32,247			22,908
Depreciation, depletion and amortization		10,683			12,317			18,707			23,345
Exploration expenses, including dry holes		100			139			227			241
Total operating costs and expenses		986,615			642,985			1,736,234			1,239,585
Income from operations		134,225			85,670			176,200			113,789
Other income (expense):
Equity in loss of joint ventures		—			—			—			(685	)
Equity in earnings of Holly Energy Partners		1,516			—			4,728			—
Minority interests in income of partnerships		—			(3,119	)		—			(6,721	)
Interest income		2,408			2,085			4,143			3,253
Interest expense		(272	)		(2,661	)		(547	)		(4,205	)
		3,652			(3,695	)		8,324			(8,358	)
Income from continuing operations before income taxes		137,877			81,975			184,524			105,431
Income tax provision:
Current		49,038			30,831			63,844			39,025
Deferred		1,110			41			1,791			887
		50,148			30,872			65,635			39,912
Income from continuing operations		87,729			51,103			118,889			65,519
Discontinued operations
Income from discontinued operations		5,604			1,321			6,991			539
Gain (loss) on sale of discontinued operations		(232	)		—			14,025			—
Income from discontinued operations, net of taxes		5,372			1,321			21,016			539
Net income	$	93,101		$	52,424		$	139,905		$	66,058
Basic earnings per share:
Continuing operations	$	1.53		$	0.81		$	2.06		$	1.04
Discontinued operations		0.09			0.02			0.36			0.01
Net income	$	1.62		$	0.83		$	2.42		$	1.05
Diluted earnings per share:
Continuing operations	$	1.51		$	0.79		$	2.01		$	1.01
Discontinued operations		0.09			0.02			0.36			0.01
Net income	$	1.60		$	0.81		$	2.37		$	1.02
Cash dividends declared per common share	$	0.08		$	0.05		$	0.13		$	0.09
Average number of common shares outstanding:
Basic		57,186			63,274			57,819			63,152
Diluted		58,363			64,718			59,072			64,564

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2006			2005
Cash flows from operating activities:
Net income	$	139,905		$	66,058
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization (includes discontinued operations)		19,257			24,946
Deferred income taxes (includes discontinued operations)		(651	)		829
Minority interests in income of partnerships		—			6,721
Equity based compensation expense		2,442			1,051
Distributions in excess of equity in earnings in HEP and joint ventures		5,085			685
Gain on sale of assets, before income taxes		(22,358	)		—
(Increase) decrease in current assets:
Accounts receivable		(55,553	)		(120,946	)
Inventories		(49,946	)		(14,739	)
Income taxes receivable		—			11,534
Prepayments and other		(6,201	)		(1,611	)
Increase (decrease) in current liabilities:
Accounts payable		33,284			92,096
Accrued liabilities		8,360			(4,121	)
Income taxes payable		10,879			14,453
Turnaround expenditures		(5,680	)		(1,050	)
Other, net		972			(3,426	)
Net cash provided by operating activities		79,795			72,480
Cash flows from investing activities:
Additions to properties, plants and equipment		(67,494	)		(28,645	)
Net cash proceeds from sale of Montana Refinery		48,872			—
Acquisition by HEP of pipeline and terminal assets		—			(121,853	)
Purchase of additional interest in joint venture, net of cash		—			(18,506	)
Proceeds from sale of partial interest in joint venture		—			832
Purchases of marketable securities		(103,283	)		(65,078	)
Sales and maturities of marketable securities		198,033			82,827
Net cash provided by (used for) investing activities		76,128			(150,423	)
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	)
Debt issuance costs		—			(948	)
Issuance of common stock upon exercise of options		2,181			2,569
Purchase of treasury stock		(92,333	)		(26,911	)
Cash dividends		(5,866	)		(5,057	)
Cash distributions to minority interests		—			(9,486	)
Excess tax benefit from equity based compensation		8,887			4,962
Net cash provided by (used for) financing activities		(87,131	)		122,084
Cash and cash equivalents:
Increase for the period		68,792			44,141
Beginning of period		49,064			67,460
End of period	$	117,856		$	111,601
Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	349		$	1,337
Income taxes	$	59,007		$	8,391

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006			2005		2006			2005
Net income	$	93,101		$	52,424	$	139,905		$	66,058
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain (loss) on available for sale securities		(428	)		203		(199	)		(25	)
Reclassification adjustment to net income on sale of equity securities		10			—		(10	)		—
Total unrealized gain (loss) on available for sale securities		(418	)		203		(209	)		(25	)
Income tax expense (benefit)		(162	)		79		(81	)		(10	)
Other comprehensive income (loss)		(256	)		124		(128	)		(15	)
Total comprehensive income	$	92,845		$	52,548	$	139,777		$	66,043

See accompanying notes.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly report on Form 10-Q has been written in the first person. In this document, the words “we”, “our”, “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

     As of the close of business on June 30, 2006, we:

• owned and operated two 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 a refinery in Woods Cross, Utah;

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

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

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

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

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. Under the provision of the Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised) (“FIN 46”) “Consolidation of Variable Interest Entities,” we have deconsolidated HEP effective July 1, 2005. The deconsolidation is being presented from July 1, 2005 forward (see Note 3).

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, 2006, the consolidated results of operations and comprehensive income for the three months and six months ended June 30, 2006 and 2005 and consolidated cash flows for the six months ended June 30, 2006 and 2005 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, 2005 filed with the SEC.

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

Our results of operations for the first six months of 2006 are not necessarily indicative of the results to be expected for the full year. Certain reclassifications, which we determined to be immaterial, have been made to prior reported amounts to conform to current classifications. Due to the sale of the Montana Refinery, we reclassified certain amounts previously reported and now report such amounts as from discontinued operations. Also, as previously

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HOLLY CORPORATION

reported, we adopted Statement of Financial Accounting Standards (“SFAS”) 123 (revised) on July 1, 2005 based on modified retrospective application with early application under SFAS 123 (revised) to earlier quarters in 2005, resulting in a previously reported restatement to the financial statements for the three months and six months ended June 30, 2005.

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

New Accounting Pronouncements

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”
In December 2004, the FASB issued SFAS No. 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 is effective for fiscal years beginning after June 15, 2005. We adopted the standard effective January 1, 2006. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

The Emerging Issues Task Force reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it in September 2005. This standard addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when purchases and sales should be recorded as an exchange measured at the book value of the item sold. The consensus in this standard is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. We adopted this standard effective April 1, 2006 and no longer account for certain crude oil transactions on a net basis.

With respect to supplying crude oil to our refineries, crude oil is often purchased in locations distant from our refineries and exchanged for crude oil that is transportable to our refineries. These buy/sell exchanges are done in contemplation of one another and allow us to receive the optimal crude blend and quantities at our refineries. All of the crude oil buy/sell transactions done in supplying crude oil to our refineries are recorded as exchanges with the net differential reflected in costs of sales. We also purchase crude oil from producers and other petroleum companies in excess of the needs of our refineries for resale to other purchasers or users of crude oil. With respect to these resales that are in the form of buy/sell exchanges with the same counterparty, the net differential of the exchanges is reflected in cost of products sold. Additionally, certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under the new accounting guidance, these direct sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included in cost of products sold. Prior to our adoption of EITF 04-13, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. During the quarter ended June 30, 2006, these crude oil sales amounted to $131.3 million with a corresponding cost of $131.1 million, resulting in a gain on these transactions of $0.2 million.

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HOLLY CORPORATION

NOTE 2: Discontinued Operations

On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at approximately $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.4 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.0 million for other assets, with current liabilities assumed amounting to $0.3 million.

We retained certain quantities of finished product inventories that were not included in the sale to Connacher. These inventories were liquidated during the second quarter of 2006.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Sales and other revenues from discontinued operations	$	20,678		$	42,641		$	53,861		$	69,647
Income from discontinued operations before income taxes	$	8,943		$	2,146		$	11,145		$	866
Income tax expense		(3,339	)		(825	)		(4,154	)		(327	)
Income from discontinued operations, net		5,604			1,321			6,991			539
Gain (loss) on sale of discontinued operations before income taxes		(280	)		—			22,358			—
Income tax (expense) benefit		48			—			(8,333	)		—
Gain (loss) on sale of discontinued operations, net		(232	)		—			14,025			—
Income from discontinued operations, net	$	5,372		$	1,321		$	21,016		$	539

NOTE 3: Investment in Holly Energy Partners

HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. We currently have a 45.0% ownership interest in HEP, including our 2% general partner interest.

HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines or throughput in their terminals a volume of refined products that will result in a minimum level of revenue to HEP of $36.7 million annually. Under the HEP IPA, we agreed to transport volumes of intermediate products on the intermediate pipelines that will result in a minimum level of revenues to HEP of approximately $11.8 million annually. Minimum revenues for both agreements will adjust upward based on increases in the producer price index over the term of the agreements. Additionally, we agreed to indemnify HEP up to an aggregate amount of $17.5 million for any environmental noncompliance and remediation liabilities associated with the assets transferred to HEP and occurring or existing prior to the date of the transfers of ownership to HEP. Of this total, indemnification in excess of $15 million relates solely to the intermediate pipelines.

On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s refinery in Big Spring, Texas. 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 five years after the acquisition date. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest. HEP financed the Alon transaction through a private offering of $150 million principal amount of 6.25% senior notes due 2015 (“HEP Senior Notes”). HEP used the proceeds of the offering to fund the $120 million

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HOLLY CORPORATION

cash portion of the consideration for the Alon transaction, and used the balance to repay $30 million of outstanding indebtedness under HEP’s credit agreement, including $5 million drawn shortly before the closing of the Alon transaction. The consideration paid for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The aggregate consideration amounted to $146.6 million, which consisted of $24.7 million fair value of HEP’s Class B subordinated units, $120 million in cash and $1.9 million of transaction costs. In accounting for this acquisition, HEP 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.

On July 8, 2005, we closed on the transaction in which HEP acquired our two parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities (our revenue commitments on the intermediate pipelines are discussed above under the HEP IPA). The total consideration was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 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, which closed simultaneously with the acquisition, of 1.1 million of its common units for $45.1 million to a limited number of institutional investors and the offering, completed in June 2005, of an additional $35 million in principal amount of HEP Senior Notes. As a result of this transaction, our ownership interest in HEP was reduced to the current 45%, including the 2% general partner interest.

HEP is a variable interest entity (“VIE”) as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines, we have determined that our beneficial variable interest in HEP was less than 50%; therefore, as required by FIN 46, we deconsolidated HEP effective as of July 1, 2005. The deconsolidation was presented from July 1, 2005 forward, and our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, is now reported using the equity method of accounting. HEP has risk associated with its operations. HEP has three major customers, of which we are one. If any of the customers fails to meet the desired shipping levels or terminates its contracts, HEP could suffer substantial losses unless a new customer is found. If HEP does suffer losses, we would recognize our percentage of those losses based on our ownership percentage in HEP at that time.

As of July 1, 2005, the impact of deconsolidation of HEP was an increase in the liability account of investments in HEP of $83.8 million, a decrease in property, plant and equipment of $157.8 million, a decrease in cash of $20.4 million, a decrease in other current assets of $3.6 million, a decrease in transportation agreements of $62.7 million, a decrease in other assets of $4.5 million, a decrease in minority interest of $179.5 million, a decrease in current liabilities of $3.9 million and a decrease in other long-term liabilities of $149.4 million.

The HEP Senior Notes are not recorded on our accompanying consolidated balance sheets due to the deconsolidation of HEP effective July 1, 2005. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of $35 million of the principal amount of the HEP Senior Notes.

We hold 7,000,000 subordinated units and 70,000 common units of HEP as of June 30, 2006. Our rights as holder of subordinated units to receive distributions of cash from HEP are subordinated to the rights of the common unitholders to receive such distributions.

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

The following table sets forth the changes in our investment account balance with HEP for the six months ended June 30, 2006:

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HOLLY CORPORATION

Investment in HEP balance at December 31, 2005	$	(157,026	)
Equity in the earnings of HEP		4,728
Regular quarterly distributions from HEP		(9,813	)
Investment in HEP balance at June 30, 2006	$	(162,111	)

The following tables provide summary financial results for HEP.

	June 30,		December 31,
	2006		2005
	(In thousands)
Current assets	$	24,715	$	28,705
Properties and equipment, net		160,538		162,298
Transportation agreements and other		61,521		63,772
Total assets	$	246,774	$	254,775
Current liabilities	$	13,396	$	9,251
Long-term liabilities		181,706		181,711
Minority interest		10,826		11,753
Partners’ equity		40,846		52,060
Total liabilities and partners’ equity	$	246,774	$	254,775

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Revenues	$	18,527		$	19,521		$	40,965		$	36,034
Operating costs and expenses		12,499			11,287			24,625			20,015
Operating income		6,028			8,234			16,340			16,019
Other expenses, net		(3,030	)		(2,193	)		(6,207	)		(3,652	)
Net income	$	2,998		$	6,041		$	10,133		$	12,367

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs, and administrative costs under the Holly PTA, Holly IPA and an Omnibus Agreement.

• Pipeline and terminal expenses paid to HEP were $10.6 million and $9.9 million for the three months ended June 30, 2006 and 2005, respectively, and $23.1 million and $19.4 million for the six months ended June 30, 2006 and 2005, respectively.

• We charged HEP $0.5 million for the three months ended June 30, 2006 and 2005 and $1.0 million for the six months ended June 30, 2006 and 2005 for general and administrative services under the Omnibus Agreement, which we recorded as a reduction in expenses.

• HEP reimbursed us for costs of employees supporting their operations of $1.8 million and $1.6 million for the three months ended June 30, 2006 and 2005, respectively, and $3.7 million and $3.0 million for the six months ended June 30, 2006 and 2005, respectively, which we recorded as a reduction in expenses.

• We reimbursed HEP $40,000 and $66,000 for certain costs paid on our behalf for the three months ended June 30, 2006 and 2005, respectively, and $96,000 and $114,000 for the six months ended June 30, 2006 and 2005, respectively.

• We received as regular distributions on our subordinated units, common units and general partner interest, $5.0 million and $4.0 million for the three months ended June 30, 2006 and 2005, respectively, and $9.8 million and $7.7 million for the six months ended June 30, 2006 and 2005, respectively. Our distributions for the three months ended June 30, 2006 and 2005 included $0.3 million and zero, respectively, in incentive distributions with respect to our general partner interest. General partner incentive distributions of

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HOLLY CORPORATION

	$0.5 million and zero were included in our distributions for the six months ended June 30, 2006 and 2005, respectively.
•	We had a net payable to HEP of $3.3 million and $3.6 million at June 30, 2006 and December 31, 2005, respectively.

NOTE 4: Earnings Per Share

Basic income per share is calculated as net income divided by average number of shares of common stock outstanding. Diluted income per share assumes, when dilutive, issuance of the net incremental shares from stock options and variable performance shares. The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective June 1, 2006. The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations of income:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(In thousands, except per share data)
Net income	$	93,101	$	52,424	$	139,905	$	66,058
Average number of shares of common stock outstanding		57,186		63,274		57,819		63,152
Effect of dilutive stock options and variable restricted shares		1,177		1,444		1,253		1,412
Average number of shares of common stock outstanding assuming dilution		58,363		64,718		59,072		64,564
Income per share – basic	$	1.62	$	0.83	$	2.42	$	1.05
Income per share – diluted	$	1.60	$	0.81	$	2.37	$	1.02

NOTE 5: Stock-Based Compensation

On June 30, 2006 we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $10.8 million and $5.4 million for the six months ended June 30, 2006 and 2005, respectively. The total income tax benefit recognized in the income statements for share-based compensation arrangements was $4.2 million and $2.1 million for the six months ended June 30, 2006 and 2005, respectively. It is currently our practice to issue new shares for settlement of option exercises, restricted stock grants or performance share units settled in stock. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods, which results in a higher expense in the earlier periods of the grants. At June 30, 2006, 2,639,796 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.

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 effective June 1, 2006.

Stock Options

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

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HOLLY CORPORATION

A summary of option activity as of June 30, 2006, and changes during the six months ended June 30, 2006 is presented below:

						Weighted-
				Weighted–		Average		Aggregate
				Average		Remaining		Intrinsic
				Exercise		Contractual		Value
Options	Shares			Price		Term		($000)
Outstanding at January 1, 2006		2,479,500		$	2.50
Exercised		(743,700	)	$	2.93
Forfeited or expired		—			—
Outstanding at June 30, 2006		1,735,800		$	2.31		3.8	$	79,653
Exercisable at June 30, 2006		1,695,800		$	2.25		3.8	$	77,923

The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005, was $23.2 million and $13.2 million, respectively.

A summary of the status of our nonvested options as of June 30, 2006 and changes during the six months ended June 30, 2006, is presented below:

				Weighted-
				Average
				Grant-Date
Nonvested Options	Options			Fair Value
Nonvested at January 1, 2006		408,800		$	1.02
Vested		(368,800	)	$	0.91
Forfeited		—			—
Nonvested at June 30, 2006		40,000		$	1.99

As of June 30, 2006, there was $38,000 of total unrecognized compensation cost related to the stock options granted. That cost is expected to be recognized over a weighted-average period of three months. The total fair value of shares vested during the six months ended June 30, 2006 and 2005, was $0.3 million and $0.3 million, respectively.

Cash received from option exercises under the stock option plans for the six months ended June 30, 2006 and 2005, was $2.2 million and $2.6 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $8.9 million and $5.1 million for the six months ended June 30, 2006 and 2005, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until the shares vest, recipients have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the vesting periods, as we assume all restricted shares will fully vest.

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HOLLY CORPORATION

A summary of restricted stock grant activity as of June 30, 2006, and changes during the six months ended June 30, 2006 is presented below:

				Weighted–
				Average
				Grant-Date		Aggregate Intrinsic
Restricted Stock	Grants			Fair Value		Value ($000)
Outstanding at January 1, 2006 (not vested)		545,808		$	9.85
Vesting and transfer of ownership to recipients		(148,900	)	$	6.82
Granted		102,998		$	32.38
Forfeited		(4,984	)	$	17.93
Outstanding at June 30, 2006 (not vested)		494,922		$	15.55	$	23,855

The total intrinsic value of restricted stock vested and transferred to recipients during the six months ended June 30, 2006 and 2005 was $5.5 million and $2.5 million, respectively. As of June 30, 2006, there was $4.7 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.7 years. The total fair value of shares vested during the six months ended June 30, 2006 was $1.0 million.

Performance Share Units

Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, some of which are payable in cash and some are payable in stock upon meeting certain criteria over the service period, and generally vest over a period of one to three years.

During the 2006 first quarter, certain grantees agreed to amend their outstanding performance share units to provide for the settlement in the form of our common stock instead of cash. The performance criteria of both the amended performance share units and the original performance share units not amended are based upon our share price and upon our total shareholder return during the requisite period as compared to the total shareholder return of our peer group of refining companies (referred to as “market performance” criteria). In addition, during the 2006 first quarter, we granted new performance share units that will be settled in our common stock based on certain measurements of our financial performance as compared to a select peer group of companies (referred to as “financial performance” criteria).

The fair value of each performance share unit award payable in cash is being revalued quarterly based on our valuation model and the corresponding expense is being amortized over the vesting periods. The fair value of each performance share unit award settled in stock is determined at the grant date (or the amendment date in the case of our amended agreements) and the corresponding expense is being amortized over the vesting periods.

The fair value of each performance share unit award based on financial performance criteria was measured based on the grant date stock price at February 16, 2006 of $29.50 (adjusted for two-for-one stock split) and will apply to the number of shares ultimately issued for each award. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies and can range from zero to 200% of the number of performance share units issued. We currently have estimated the final payout of shares at 150%.

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

For the six months ended June 30, 2006, this valuation analysis was performed for the performance share units with market based performance on the date of conversion, February 10, 2006, and at the end of the six months, June 30, 2006.

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HOLLY CORPORATION

At February 10, 2006, the price of our stock was $31.96 (adjusted for two-for-one stock split), the latest quarterly dividend was $0.05 (adjusted for two-for-one stock split), and the risk-free rates ranged from 4.68% to 4.70%, depending on the remaining performance period. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information available at each measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

				Standard
Company	Expected Return on Equity			Deviation (Monthly)
Holly		12.25	%	10.9% to 12.1%
Peer group	10.0% to 13.5%			7.9% to 16.0%

At June 30, 2006, the price of our stock was $48.02, the latest quarterly dividend was $0.08, and the risk-free rates ranged from 4.38% to 5.22%, depending on the remaining performance period. The inputs affecting the range of expected total returns for us and the peer group are based on a capital asset pricing model utilizing information available at each measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The range of expected returns and standard deviation is presented below:

				Standard
Company	Expected Return on Equity			Deviation (Monthly)
Holly		12.6	%	13.4% to 16.3%
Peer group	10.8% to 14.1%			8.1% to 15.3%

A summary of performance share units activity as of June 30, 2006, and changes during the six months ended June 30, 2006 is presented below:

						Financial
	Market Performance					Performance
	Payable in			Stock		Stock		Total
	Cash			Settled		Settled		Performance
Performance Share Units	Grants			Grants		Grants		Share Units
Outstanding at January 1, 2006 (nonvested)		356,524			—		—		356,524
Amended to settle in stock		(128,574	)		128,574		—		—
Vesting and payment of benefit to recipients		—			—		—		—
Granted		—			—		75,984		75,984
Forfeited		(4,456	)		—		—		(4,456	)
Outstanding at June 30, 2006 (nonvested)		223,494			128,574		75,984		428,052

There was no cash paid during the six months ended June 30, 2006 related to vested performance share units, while $6.3 million was paid during the six months ended June 30, 2005 related to vested performance share units. As of June 30, 2006, the cash liability associated with these awards was $12.3 million and is recorded in accrued liabilities on our consolidated balance sheets. Based on the weighted average fair value at June 30, 2006 of $58.01, there was $9.3 million of total unrecognized compensation cost related to nonvested performance share units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

NOTE 6: Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, as part of the sale of the Montana Refinery, we received 1,000,000 shares of Connacher common stock.

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HOLLY CORPORATION

We invest in highly-rated marketable debt securities primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”) and auction rate securities (“ARS”). Although VRDN and ARS may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income.

The following is a summary of our available-for-sale securities at June 30, 2006:

	Available-for-Sale Securities
						Estimated
			Gross			Fair Value
			Unrealized			(Net Carrying
	Amortized Cost		Losses			Amount)
	(In thousands)
States and political subdivisions	$	111,521	$	(234	)	$	111,287
Equity securities		4,328		(468	)		3,860
Total marketable securities	$	115,849	$	(702	)	$	115,147

During the six months ended June 30, 2006 and 2005, we recognized $10,000 in gains related to 152 sales and maturities and $2.2 million in gains related to 57 sales and maturities respectively, in which we received $198.0 million and $82.8 million in proceeds, respectively. The realized gains and losses represent the difference between the purchase price and market value on the maturity or sales dates.

NOTE 7: Investments in Joint Ventures

Prior to February 2005, NK Asphalt Partners was owned 49% by us and 51% by a subsidiary of Koch Materials Company (“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 “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 allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. The total purchase consideration for the 51% interest, including expenses, was $21.8 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 recorded current assets of $11.7 million, net property, plant and equipment of $20.4 million, intangible assets of $5.2 million, goodwill of $1.0 million, and current liabilities of $8.5 million and eliminated our equity investment. Sales to the joint venture during 2005, prior to the acquisition, were $3.9 million.

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

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HOLLY CORPORATION

NOTE 8: Environmental

Consistent with our accounting policy for environmental remediation and cleanup costs, we expensed $3.1 million during the six months ended June 30, 2006 and $0.4 million during the six months ended June 30, 2005 for environmental remediation and cleanup obligations. The accrued environmental liability reflected in the consolidated balance sheets was $6.0 million and $3.1 million at June 30, 2006 and December 31, 2005, respectively, of which $4.8 million and $2.0 million was classified as other long-term liabilities, respectively. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 9: Debt

Credit Facility

We have a $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. This credit facility expires in 2008 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at June 30, 2006. At June 30, 2006, we had outstanding letters of credit totaling $2.3 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.7 million at June 30, 2006.

NOTE 10: Income taxes

The effective tax rate for continuing operations for the first six months of 2006 was 35.6%, as compared to 37.8% for the first six months of 2005. The reduction in the effective tax rate was principally due to income tax credits available to small business refiners incurring costs to produce ultra low sulfur diesel fuel.

NOTE 11: Stockholders’ Equity

Two-For-One Stock Split:On May 11, 2006, 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 stock dividend was paid on June 1, 2006 to all holders of record of common stock at the close of business on May 22, 2006. All references to the number of shares of common stock (other than authorized shares and other than issued shares and treasury shares at December 31, 2005 shown on our Consolidated Balance Sheets) and per share amounts have been adjusted to reflect the split on a retrospective basis.

Common Stock Repurchases:On November 7, 2005, we announced that our Board of Directors authorized the repurchase of up to $200.0 million of our common stock. Repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2006, we repurchased under this repurchase initiative 2,675,653 shares at a cost of approximately $90.9 million (of which $3.0 million of the cash settlement was after June 30, 2006) or an average of $33.99 per share. Since inception of this repurchase initiative through June 30, 2006, we have repurchased 3,663,253 shares at a cost of approximately $120.9 million or an average of $33.00 per share.

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HOLLY CORPORATION

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 were made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During 2005, we repurchased 4,062,414 shares at a cost of approximately $100.0 million or an average of $24.62 per share under this repurchase initiative. This program was completed in October 2005.

During the six months ended June 30, 2006, we repurchased at current market price from certain executives 46,388 shares of our common stock at a cost of approximately $1.4 million. During the six months ended June 30, 2005, we repurchased at current market price from certain executives 49,580 shares of our common stock at a cost of approximately $0.8 million. These repurchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means.

NOTE 12: 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, 2006
Unrealized loss on securities available for sale	$	(418	)	$	(162	)	$	(256	)
Other comprehensive loss	$	(418	)	$	(162	)	$	(256	)
For the three months ended June 30, 2005
Unrealized gain on securities available for sale	$	203		$	79		$	124
Other comprehensive income	$	203		$	79		$	124
For the six months ended June 30, 2006
Unrealized loss on securities available for sale	$	(209	)	$	(81	)	$	(128	)
Other comprehensive loss	$	(209	)	$	(81	)	$	(128	)
For the six months ended June 30, 2005
Unrealized loss on securities available for sale	$	(25	)	$	(10	)	$	(15	)
Other comprehensive loss	$	(25	)	$	(10	)	$	(15	)

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

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

	June 30,			December 31,
	2006			2005
	(In thousands)
Pension obligation adjustment	$	(4,501	)	$	(4,501	)
Unrealized loss on securities available for sale		(429	)		(301	)
Accumulated other comprehensive loss	$	(4,930	)	$	(4,802	)

NOTE 13: 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 employees’ years of service and compensation.

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HOLLY CORPORATION

The net periodic pension expense consisted of the following components:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Service cost	$	1,179		$	776		$	2,226		$	1,723
Interest costs		1,083			788			2,097			1,883
Expected return on assets		(892	)		(684	)		(1,748	)		(1,581	)
Amortization of prior service cost		67			65			133			130
Amortization of net loss		288			254			608			483
One time cost incurred with sale of Montana Refinery		300			—			300			—
Net periodic benefit cost	$	2,025		$	1,199		$	3,616		$	2,638

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2006 and 2005 net periodic benefit cost. We expect to contribute between $10.0 million and $13.0 million to the retirement plan in the third quarter of 2006.

NOTE 14: Contingencies

We have pending proceedings in the United States Court of Appeals for the District of Columbia Circuit with respect to rulings by the Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against Kinder Morgan’s SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. Rulings by the FERC relating principally to the period from 1993 through July 2000 resulted in reparations payments from SFPP to us in 2003 totaling approximately $15.3 million. In 2004 the appeals court issued its opinion relating principally to the period from 1993 through July 2000, ruling 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. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships. The FERC in a later order applied this general policy statement to SFPP and such application is contrary to our position in this case. We and certain other refining companies have pending before the court of appeals petitions challenging the FERC policy on income taxes, decisions by the FERC in 2005 and early 2006 on certain of the remanded issues, and rulings by the FERC on some issues relating to periods after July 2000. In March 2006, SFPP submitted computations asserted to be based on the most recent determinations of the FERC in the case. In April 2006, we filed a protest and comments concerning a number of elements of these computations. One element of the computations, which is based on the FERC’s disputed 2005 policy on treatment of income taxes, would if ultimately sustained result in a requirement for us to repay to SFPP approximately $3 million of the $15.3 million reparations amount received by us from SFPP in 2003. Because proceedings in the FERC on remand have not been completed and our petitions for review to the court of appeals with respect to the FERC’s orders are pending, it is not possible to determine whether the amount of reparations actually due to us for the period from 1993 through July 2000 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 are not likely to result in an obligation for us to repay more than the amount now asserted in SFPP’s most recent computations (approximately $3 million) and that the more likely final result would be either a smaller repayment by us than is now asserted by SFPP or a payment to us of additional reparations. The ultimate amount of reparations payable to us 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.

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HOLLY CORPORATION

In discussions beginning in the last half of 2005, the Environmental Protection Agency (“EPA”) and the State of Utah have asserted that we have liabilities relating to the Federal Clean Air Act at our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have tentatively agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The tentative settlement agreement, which has not yet been put into a final written agreement, includes proposed obligations for us to make specified additional capital investments expected to total up to approximately $10 million over several years and to make changes in operating procedures at the refinery. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the tentative settlement.

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

NOTE 15: Segment Information

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

Prior to our deconsolidation of HEP effective July 1, 2005, our operations were organized into two business divisions, which were Refining and HEP. These segments have been in effect since July 13, 2004, the closing of the initial public offering of HEP. Our operations that were not included in either the Refining or HEP business divisions included the operations of Holly Corporation, the parent company, a small-scale oil and gas exploration and production program and the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us.

The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil pipelines that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes the equity in earnings from our 49% interest in NK Asphalt Partners prior to February 2005. In February 2005, we acquired the remaining 51% interest in the asphalt joint venture from the other partner; subsequent to the purchase, we include the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, dba Holly Asphalt Company, manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and California. The cost of pipeline transportation and terminal services provided by HEP to us is also included in the Refining segment. The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain states. The HEP segment also included a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which provides petroleum products transportation. Revenues from the HEP segment were earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande. Our operations not included in the reportable segment or segments were included in Corporate and Other, which included costs of Holly Corporation,

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HOLLY CORPORATION

the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations column included the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us. These items are no longer included after the deconsolidation of HEP effective July 1, 2005.

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, 2005. Our reportable segments prior to July 1, 2005 were strategic business units that offered different products and services.

								Consolidations
					Corporate			and			Consolidated
	Refining		HEP		and Other			Eliminations			Total
	(In thousands)
Three Months Ended June 30, 2006
Sales and other revenues	$	1,120,838	$	—	$	143		$	(141	)	$	1,120,840
Depreciation, depletion and amortization	$	10,265	$	—	$	418		$	—		$	10,683
Income (loss) from operations	$	153,307	$	—	$	(19,082	)	$	—		$	134,225
Income (loss) from continuing operations before income taxes	$	155,099	$	—	$	(17,222	)	$	—		$	137,877
Three Months Ended June 30, 2005
Sales and other revenues	$	719,026	$	19,521	$	252		$	(10,144	)	$	728,655
Depreciation, depletion and amortization	$	8,278	$	3,849	$	190		$	—		$	12,317
Income (loss) from operations	$	88,845	$	8,234	$	(11,409	)	$	—		$	85,670
Income (loss) from continuing operations before income taxes	$	88,867	$	6,041	$	(9,787	)	$	(3,146	)	$	81,975
Six Months Ended June 30, 2006
Sales and other revenues	$	1,912,186	$	—	$	524		$	(276	)	$	1,912,434
Depreciation, depletion and amortization	$	17,967	$	—	$	740		$	—		$	18,707
Income (loss) from operations	$	208,895	$	—	$	(32,695	)	$	—		$	176,200
Income (loss) from continuing operations before income taxes	$	213,856	$	—	$	(29,332	)	$	—		$	184,524
Six Months Ended June 30, 2005
Sales and other revenues	$	1,336,297	$	36,034	$	617		$	(19,574	)	$	1,353,374
Depreciation, depletion and amortization	$	16,521	$	6,212	$	612		$	—		$	23,345
Income (loss) from operations	$	118,920	$	16,019	$	(21,150	)	$	—		$	113,789
Income (loss) from continuing operations before income taxes	$	118,267	$	12,367	$	(18,884	)	$	(6,319	)	$	105,431

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HOLLY CORPORATION

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

This Item 2 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of Part I of this quarterly report of Form 10-Q. In this document, the words “we”, “our” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person.

OVERVIEW

We are principally an independent petroleum refiner operating two refineries in Artesia and Lovington, New Mexico (operated as one refinery) and Woods Cross, Utah. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At June 30, 2006, we also owned a 45% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in 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 southwestern and western United States. Additionally, starting April 1, 2006, we began recording direct sales of crude oil as revenues with the related acquisition costs included in cost of products, as required by recent accounting guidance (see” New Accounting Pronouncements” under “Critical Account Policies” below for additional discussion on this new accounting guidance). Prior to April 1, 2006, sales and cost of sales attributable to such crude oil direct sales were netted and presented in cost of products sold. During the quarter ended June 30, 2006, these crude oil sales amounted to $131.3 million with a corresponding cost of $131.1 million, resulting in a gain on these transactions of $0.2 million. Our total sales and other revenues for the three months ended June 30, 2006 were $1,120.8 million and our net income for the three months ended June 30, 2006 was $93.1 million. Our sales and other revenues and net income for the three months ended June 30, 2005 were $728.7 million and $52.4 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the three months ended June 30, 2006 were $986.6 million, an increase from $643.0 million for the three months ended June 30, 2005.

On May 11, 2006, we announced that our Board of Directors had 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 stock dividend was paid on June 1, 2006 to all holders of record of common stock at the close of business on May 22, 2006. All references to the number of shares of common stock (other than authorized shares and other than issued shares and treasury shares at December 31, 2005 shown on our Consolidated Balance Sheets) and per share amounts have been adjusted to reflect the split on a retrospective basis.

On March 31, 2006 we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at approximately $4.3 million at March 31, 2006. We have presented in discontinued operations the results of operations and a gain of $14.0 million on the sale.

On November 7, 2005, we announced that our Board of Directors had authorized the repurchase of up to $200.0 million of our common stock. Repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2006, we repurchased under this repurchase initiative 2,675,653 shares at a cost of approximately $90.9 million (of which $3.0 million of the cash settlement was after June 30, 2006) or an average of $33.99 per share. Since inception of this repurchase initiative through June 30, 2006, we have repurchased 3,663,253 shares at a cost of approximately $120.9 million or an average of $33.00 per share.

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HOLLY CORPORATION

RESULTS OF OPERATIONS

Financial Data (Unaudited)

	Three Months Ended
	June 30,						Change from 2005
	2006			2005 (1)			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	1,120,840		$	728,655		$	392,185			53.8	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		908,009			569,933			338,076			59.3
Operating expenses (exclusive of depreciation, depletion and amortization)		49,092			48,268			824			1.7
General and administrative expenses (exclusive of depreciation, depletion and amortization)		18,731			12,328			6,403			51.9
Depreciation, depletion and amortization		10,683			12,317			(1,634	)		(13.3	)
Exploration expenses, including dry holes		100			139			(39	)		(28.1	)
Total operating costs and expenses		986,615			642,985			343,630			53.4
Income from operations		134,225			85,670			48,555			56.7
Other income (expense):
Equity in loss of joint ventures		—			—			—			—
Equity in earnings of HEP		1,516			—			1,516			—
Minority interests in income of partnerships		—			(3,119	)		3,119			(100.0	)
Interest income		2,408			2,085			323			15.5
Interest expense		(272	)		(2,661	)		2,389			(89.8	)
		3,652			(3,695	)		7,347			(198.8	)
Income from continuing operations before income taxes		137,877			81,975			55,902			68.2
Income tax provision		50,148			30,872			19,276			62.4
Income from continuing operations		87,729			51,103			36,626			71.7
Income from discontinued operations, net of taxes		5,372			1,321			4,051			306.7
Net income	$	93,101		$	52,424		$	40,677			77.6	%
Basic earnings per share:
Continuing operations	$	1.53		$	0.81		$	0.72			88.9	%
Discontinued operations		0.09			0.02			0.07			350.0
Net income	$	1.62		$	0.83		$	0.79			95.2	%
Diluted earnings per share:
Continuing operations	$	1.51		$	0.79		$	0.72			91.1	%
Discontinued operations		0.09			0.02			0.07			350.0
Net income	$	1.60		$	0.81		$	0.79			97.5	%
Cash dividends declared per common share	$	0.08		$	0.05		$	0.03			60.0	%
Average number of common shares outstanding:
Basic		57,186			63,274			(6,088	)		(9.6	)%
Diluted		58,363			64,718			(6,355	)		(9.8	)%

(1) Due to the sale of the Montana Refinery, we have reclassified certain amounts previously reported and now report such amounts as from discontinued operations. Also, as previously reported, we adopted Statement of Financial Accounting Standards (“SFAS”) 123 (revised) on July 1, 2005 based on modified retrospective application with early application under SFAS 123 (revised) to earlier quarters in 2005, resulting in a previously reported restatement to the financial statements for the three months ended June 30, 2005.

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HOLLY CORPORATION

	Six Months Ended
	June 30,						Change from 2005
	2006			2005 (1)			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	1,912,434		$	1,353,374		$	559,060			41.3	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		1,583,494			1,103,347			480,147			43.5
Operating expenses (exclusive of depreciation, depletion and amortization)		101,559			89,744			11,815			13.2
General and administrative expenses (exclusive of depreciation, depletion and amortization)		32,247			22,908			9,339			40.8
Depreciation, depletion and amortization		18,707			23,345			(4,638	)		(19.9	)
Exploration expenses, including dry holes		227			241			(14	)		(5.8	)
Total operating costs and expenses		1,736,234			1,239,585			496,649			40.1
Income from operations		176,200			113,789			62,411			54.8
Other income (expense):
Equity in loss of joint ventures		—			(685	)		685			(100.0	)
Equity in earnings of HEP		4,728			—			4,728			—
Minority interests in income of partnerships		—			(6,721	)		6,721			(100.0	)
Interest income		4,143			3,253			890			27.4
Interest expense		(547	)		(4,205	)		3,658			(87.0	)
		8,324			(8,358	)		16,682			(199.6	)
Income from continuing operations before income taxes		184,524			105,431			79,093			75.0
Income tax provision		65,635			39,912			25,723			64.4
Income from continuing operations		118,889			65,519			53,370			81.5
Income from discontinued operations, net of taxes		21,016			539			20,477			—
Net income	$	139,905		$	66,058		$	73,847			111.8	%
Basic earnings per share:
Continuing operations	$	2.06		$	1.04		$	1.02			98.1	%
Discontinued operations		0.36			0.01			0.35			—
Net income	$	2.42		$	1.05		$	1.37			130.5	%
Diluted earnings per share:
Continuing operations	$	2.01		$	1.01		$	1.00			99.0	%
Discontinued operations		0.36			0.01			0.35			—
Net income	$	2.37		$	1.02		$	1.35			132.4	%
Cash dividends declared per common share	$	0.13		$	0.09		$	0.04			44.4	%
Average number of common shares outstanding:
Basic		57,819			63,152			(5,333	)		(8.4	)%
Diluted		59,072			64,564			(5,492	)		(8.5	)%

(1) Due to the sale of the Montana Refinery, we have reclassified certain amounts previously reported and now report such amounts as from discontinued operations. Also, as previously reported, we adopted Statement of Financial Accounting Standards (“SFAS”) 123 (revised) on July 1, 2005 based on modified retrospective application with early application under SFAS 123 (revised) to earlier quarters in 2005, resulting in a previously reported restatement to the financial statements for the six months ended June 30, 2005.

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HOLLY CORPORATION

Balance Sheet Data (Unaudited)

	June 30,		December 31,
	2006		2005
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	233,003	$	254,842
Working capital	$	235,426	$	210,103
Total assets	$	1,257,342	$	1,142,900
Stockholders’ equity	$	434,345	$	377,351

Other Financial Data (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Net cash provided by operating activities	$	98,135		$	65,673		$	79,795		$	72,480
Net cash provided by (used for) investing activities	$	(43,760	)	$	(18,670	)	$	76,128		$	(150,423	)
Net cash provided by (used for) financing activities	$	(31,130	)	$	1,159		$	(87,131	)	$	122,084
Capital expenditures	$	35,259		$	15,197		$	67,494		$	28,645
EBITDA from continuing operations(1)	$	146,424		$	94,868		$	199,635		$	129,728

(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. We are reporting EBITDA from continuing operations. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

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HOLLY CORPORATION

Our sole reportable business segment is Refining after the deconsolidation of HEP effective July 1, 2005. From the closing of the initial public offering of HEP on July 13, 2004 through June 30, 2005, our segments reflected two business divisions, Refining and HEP. The HEP segment did not have any activity subsequent to the deconsolidation effective July 1, 2005.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Sales and other revenues(1)
Refining	$	1,120,838		$	719,026		$	1,912,186		$	1,336,297
HEP		—			19,521			—			36,034
Corporate and other		143			252			524			617
Consolidations and eliminations		(141	)		(10,144	)		(276	)		(19,574	)
Consolidated	$	1,120,840		$	728,655		$	1,912,434		$	1,353,374
Income from operations(1)
Refining	$	153,307		$	88,845		$	208,895		$	118,920
HEP		—			8,234			—			16,019
Corporate and other		(19,082	)		(11,409	)		(32,695	)		(21,150	)
Consolidated	$	134,225		$	85,670		$	176,200		$	113,789

(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 and Woods Cross Refinery. Although we previously included the Montana Refinery in the Refining segment, the results from the Montana Refinery are now reported in discontinued operations and are not included in the above tables. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil pipelines that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes the equity in earnings from our 49% interest in NK Asphalt partners prior to February 2005. In February 2005, we acquired the other 51% interest in the joint venture from our other partner; subsequent to the purchase, we include the operations of NK Asphalt Partners in our consolidated financial statements. NK Asphalt Partners, doing business as 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 included in the Refining segment. The HEP segment involved all of the operations of HEP, including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain states. The HEP segment also included a 70% interest in Rio Grande which provides petroleum products transportation. Revenues from the HEP segment were earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from its interest in Rio Grande. Our operations not included in the reportable segment or 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 pipeline transportation services between us and HEP prior to July 1, 2005.

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HOLLY CORPORATION

Refining Operating Data (Unaudited)

Our refinery operations include the Navajo Refinery and the Woods Cross Refinery. The following tables set forth information, including non-GAAP performance measures about our 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 this Form 10-Q.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Navajo Refinery
Crude charge (BPD)(1)		60,380			71,920			66,420			73,100
Refinery production (BPD)(2)		65,600			77,750			73,320			80,880
Sales of produced refined products (BPD)		66,320			77,600			73,000			80,230
Sales of refined products (BPD)(3)		83,940			85,960			87,340			89,800
Refinery utilization(4)		80.5	%		95.9	%		88.6	%		97.5	%
Average per produced barrel(5)
Net sales	$	90.76		$	65.73		$	82.49		$	61.50
Cost of products(6)		67.34			50.30			64.90			49.47
Refinery gross margin		23.42			15.43			17.59			12.03
Refinery operating expenses(7)		5.37			3.84			5.07			3.45
Net operating margin	$	18.05		$	11.59		$	12.52		$	8.58
Feedstocks:
Sour crude oil		80	%		90	%		81	%		88	%
Sweet crude oil		9	%		0	%		7	%		0	%
Other feedstocks and blends		11	%		10	%		12	%		12	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		57	%		56	%		60	%		59	%
Diesel fuels		27	%		30	%		26	%		27	%
Jet fuels		5	%		4	%		5	%		4	%
Asphalt		4	%		7	%		3	%		7	%
LPG and other		7	%		3	%		6	%		3	%
Total		100	%		100	%		100	%		100	%
Woods Cross Refinery
Crude charge (BPD)(1)		25,270			25,820			24,010			23,780
Refinery production (BPD)(2)		27,030			27,170			25,530			25,540
Sales of produced refined products (BPD)		27,500			27,820			25,410			26,450
Sales of refined products (BPD)(3)		28,800			29,120			26,640			27,500
Refinery utilization(4)		97.2	%		99.3	%		92.3	%		91.5	%
Average per produced barrel(5)
Net sales	$	89.63		$	67.35		$	80.52		$	61.17
Cost of products(6)		69.80			57.28			65.42			54.35
Refinery gross margin		19.83			10.07			15.10			6.82
Refinery operating expenses(7)		4.36			3.86			4.99			4.08
Net operating margin	$	15.47		$	6.21		$	10.11		$	2.74

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HOLLY CORPORATION

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Woods Cross Refinery
Feedstocks:
Sour crude oil		3	%		9	%		4	%		9	%
Sweet crude oil		89	%		83	%		87	%		81	%
Other feedstocks and blends		8	%		8	%		9	%		10	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		64	%		60	%		63	%		60	%
Diesel fuels		30	%		31	%		28	%		28	%
Jet fuels		1	%		2	%		2	%		2	%
Fuel oil		4	%		6	%		5	%		7	%
LPG and other		1	%		1	%		2	%		3	%
Total		100	%		100	%		100	%		100	%
Consolidated(8)
Crude charge (BPD)(1)		85,650			97,740			90,430			96,880
Refinery production (BPD)(2)		92,630			104,920			98,850			106,420
Sales of produced refined products (BPD)		93,820			105,420			98,410			106,680
Sales of refined products (BPD)(3)		112,740			115,080			113,980			117,300
Refinery utilization(4)		84.8	%		96.8	%		89.5	%		95.9	%
Average per produced barrel(5)
Net sales	$	90.43		$	66.16		$	81.98		$	61.42
Cost of products(6)		68.06			52.14			65.03			50.68
Refinery gross margin		22.37			14.02			16.95			10.74
Refinery operating expenses(7)		5.08			3.84			5.05			3.61
Net operating margin	$	17.29		$	10.18		$	11.90		$	7.13
Feedstocks:
Sour crude oil		58	%		69	%		61	%		69	%
Sweet crude oil		32	%		22	%		28	%		20	%
Other feedstocks and blends		10	%		9	%		11	%		11	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		59	%		57	%		61	%		59	%
Diesel fuels		27	%		30	%		27	%		28	%
Jet fuels		4	%		3	%		4	%		3	%
Asphalt		3	%		5	%		2	%		5	%
LPG and other		7	%		5	%		6	%		5	%
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 (BPSD).
(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)	Transportation costs billed from HEP are included in cost of products.
(7)	Represents operating expenses of our refinery, exclusive of depreciation, depletion and amortization, and excludes refining segment expenses of product pipelines and terminals.
(8)	The Montana Refinery was sold on March 31, 2006. Amounts reported are for the Navajo and Woods Cross Refineries.

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HOLLY CORPORATION

Results of Operations — Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Summary
Net income for the three months ended June 30, 2006 was $93.1 million ($1.60 per diluted share) compared to net income of $52.4 million ($0.81 per diluted share) for the three months ended June 30, 2005. Earnings for the second quarter of 2006 as compared to the second quarter of 2005 increased by $40.7 million principally due to improved refined product margins experienced in the current year, combined with additional earnings attributable to the liquidation of inventories retained upon the sale of our Montana Refinery and the sale of sulfur credits under environmental laws, partially offset by reduced production volumes and higher general and administrative expenses. Additionally, the start-up of our new ROSE unit (the ROSE unit converts a significant portion of lower value asphalt into high value transportation fuels) in December 2005 contributed to higher refinery yields in the current quarter. Overall refinery production levels from continuing operations showed a decrease of 12% in the 2006 second quarter as compared to the same period in 2005 due to production downtime arising from planned capital and refinery maintenance projects at our Navajo and Woods Cross Refineries. Refinery gross margins from continuing operations were $22.37 per produced barrel for the second quarter of 2006 compared to margins of $14.02 per produced barrel for the second quarter of 2005.

Sales and Other Revenues
Sales and other revenues increased 54% from $728.7 million for the three months ended June 30, 2005 to $1,120.8 million for the three months ended June 30, 2006, due principally to higher refined product sales prices, combined with the recording of direct sales of crude oil as revenues which began April 1, 2006, partially offset by a small decrease in volumes sold. The average sales price we received per produced barrel sold increased 37% from $66.16 in the second quarter of 2005 to $90.43 in the second quarter of 2006. The total volume of refined products we sold decreased 2% in the second quarter of 2006 as compared to the second quarter of 2005 due to lower refinery production levels attributable to our refinery capital and maintenance projects. The 2006 second quarter increase also includes $131.3 million of revenue attributable to certain excess crude oil sales that were previously netted against the corresponding cost and presented in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006. Additionally, revenues increased by the sales of $12.0 million of sulfur credits generated because our Navajo Refinery is making gasoline that is substantially lower in sulfur than required by EPA regulations. Revenues were reduced due to the exclusion of the operations of HEP in the 2006 second quarter resulting from the deconsolidation of HEP effective July 1, 2005.

Diesel fuel produced at our Navajo and Woods Cross refineries was required to meet certain nationwide ultra low sulfur diesel fuel requirements as of June 2006. To meet this requirement, we completed certain ULSD projects at our Navajo and Woods Cross refineries. In addition, we also incurred additional downtime as we timed an expansion at our Navajo Refinery and conducted other refinery maintenance projects in conjunction with the ULSD projects. These capital projects were a principal factor in our reduced production levels during the second quarter of 2006.

Cost of Products Sold
Cost of products sold increased 59% from $569.9 million in the second quarter of 2005 to $908.0 million in the second quarter of 2006 due principally to higher costs of crude oil, combined with the recording of related costs associated with the direct sales of crude oil which began April 1, 2006, partially offset by the effect of the 2% decrease in refined product volumes sold as discussed above. The average price we paid per barrel of crude oil and feedstocks purchased and the transportation costs of moving the finished products to the market place increased 31% from $52.14 in the second quarter of 2005 to $68.06 in the second quarter of 2006. Also, cost of products sold for the 2006 second quarter increased by $131.1 million due to the inclusion of costs attributable to certain excess crude oil sales that were previously netted against the corresponding revenues and included in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006. Additionally, cost of products sold was reduced due to the exclusion of the operations of HEP in the 2006 second quarter resulting from the deconsolidation of HEP effective July 1, 2005.

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HOLLY CORPORATION

Gross Refinery Margins
Gross refining margin per produced barrel increased 60% from $14.02 in the second quarter of 2005 to $22.37 in the second quarter of 2006. Gross refinery margin does not include the effects 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 statements of prices of refined products sold and costs of products purchased.

Operating Expenses
Operating expenses increased 2% from $48.3 million in the second quarter of 2005 to $49.1 million in the second quarter of 2006 due principally to refinery maintenance projects and increased utility costs, partially offset by the exclusion of HEP’s operating costs in the 2006 second quarter due to the deconsolidation of HEP effective July 1, 2005.

General and Administrative Expenses
General and administrative expenses increased 52% from $12.3 million for the second quarter of 2005 to $18.7 million for the second quarter of 2006 due primarily to increased equity-based incentive compensation.

Depreciation, Depletion and Amortization Expenses
Depreciation, depletion and amortization decreased 13% from $12.3 million in the second quarter of 2005 to $10.7 million in the second quarter of 2006 due primarily to the exclusion of HEP’s depreciation resulting from the deconsolidation of HEP.

Equity in Earnings of HEP and Minority Interests
As part of the deconsolidation of HEP on July 1, 2005, we show equity in earnings for our ownership percentage of HEP, currently 45%, including any incentive distributions paid through our general partner interest. Our equity in earnings of HEP was $1.5 million for the three months ended June 30, 2006. There was no equity in earnings of HEP for the three months ended June 30, 2005 as HEP was a consolidated subsidiary for that period, with the then minority interest partners’ share of HEP’s earnings reported as minority interest. Minority interests in income of HEP in the second quarter of 2005 reduced income by $3.1 million.

Equity in Earnings of Joint Ventures
There was no equity in earnings of joint ventures for the three months ended June 30, 2006 and 2005 as all previously owned interests in joint ventures have been consolidated in our financials or have been sold.

Interest Income
Interest income for the second quarter of 2006 was $2.4 million compared to $2.1 million for the second quarter of 2005. The increase in interest income was principally due to a higher interest rate environment.

Interest Expense
Interest expense was $0.3 million for the second quarter of 2006 as compared to $2.7 million for the second quarter of 2005. The decrease for the current year’s second quarter as compared to the same period in 2005 was principally due to the inclusion of HEP’s interest expense for the 2005 second quarter prior to the deconsolidation of HEP effective July 1, 2005.

Income Taxes
Income taxes increased 62% from $30.9 million for the second quarter of 2005 to $50.1 million for the second quarter of 2006 due to significantly higher pre-tax earnings during the 2006 second quarter as compared to the 2005 second quarter, partially offset by a lower effective tax rate. The effective tax rate for the second quarter of 2006 was 36.4%, as compared to 37.7% for the second quarter of 2005. The reduction of the effective tax rate was primarily due to income tax credits available to small business refiners. See below under “Planned Capital Expenditures” for a discussion of tax benefits available to refiners.

Discontinued Operations
Income from discontinued operations was $5.4 million for the second quarter of 2006 as compared to $1.3 million for the second quarter of 2005. We retained certain quantities of finished product inventories that were not included in the sale of our Montana Refinery at March 31, 2006. The increase in earnings from discontinued operations was due largely to the liquidation of this inventory that had been carried at lower costs as compared to current values.

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HOLLY CORPORATION

Results of Operations — Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Summary
Net income for the six months ended June 30, 2006 was $139.9 million ($2.37 per diluted share) compared to net income of $66.1 million ($1.02 per diluted share) for the six months ended June 30, 2005. Earnings for the six months ended June 30, 2006 as compared to the six months ended June 30, of 2005 increased by $73.8 million principally due to improved refined product margins experienced in the current year, the gain on the sale of the Montana Refinery assets, and the sale of sulfur credits under environmental laws, partially offset by reduced production volumes and higher refinery operating and general and administrative expenses. Additionally, the start-up of our new ROSE unit in December 2005 contributed to higher refinery yields in the current year. Overall refinery production levels from continuing operations showed a decrease of 7% for the six months ended June 30, 2006 as compared to the same period in 2005. During the six months ended June 30, 2006, production was reduced due to a power outage at the Navajo Refinery in February 2006 and production downtime arising from planned capital and refinery maintenance projects at the Navajo and Woods Cross Refineries during the second quarter of 2006. Refinery gross margins from continuing operations were $16.95 per produced barrel for the six months ended June 30, 2006 compared to margins of $10.74 per produced barrel for the six months ended June 30, 2005.

Sales and Other Revenues
Sales and other revenues increased 41% from $1,353.4 million for the six months ended June 30, 2005 to $1,912.4 million for the six months ended June 30, 2006, due principally to higher refined product sales prices, combined with the recording of direct sales of crude oil as revenues beginning April 1, 2006, partially offset by a small decrease in volumes sold. The average sales price we received per produced barrel sold increased 33% from $61.42 for the six months ended June 30, 2005 to $81.98 for the six months ended June 30 2006. The total volume of refined products we sold decreased 3% for the six months ended June 30, 2006 as compared to the same period in 2005 due to lower refinery production levels attributable to a power outage at the Navajo Refinery in February 2006 and our refinery capital and maintenance projects in the second quarter of 2006. The increase in sales and other revenues for the six months ended June 30, 2006 also includes $131.3 million of revenue attributable to certain excess crude oil sales that were previously netted against the corresponding cost and presented in cost of products sold prior to our adoption of new accounting guidance on April 1, 2006. Additionally, revenues increased by the sales of $12.0 million of sulfur credits generated because our Navajo Refinery is making gasoline that is substantially lower in sulfur than required by EPA regulations. Revenues were reduced due to the exclusion of the operations of HEP in 2006 resulting from the deconsolidation of HEP effective July 1, 2005, which reduction was partially offset by revenues from NK Asphalt Partners joint venture (doing business as Holly Asphalt Company) which we included for only part of the six months ended June 30, 2005, following our February 2005 acquisition of the other partner’s interest.

Cost of Products Sold
Cost of products sold increased 44% from $1,103.3 million for the six months ended June 30, 2005 to $1,583.5 million for the six months ended June 30, 2006, due principally to higher costs of crude oil, combined with the recording of related costs associated with the direct sales of crude oil beginning April 1, 2006, partially offset by the effect of the 3% decrease in volumes sold as discussed above. The average price we paid per barrel of crude oil and feedstocks purchased and the transportation costs of moving the finished products to the market place increased 28% from $50.68 for the first six months of 2005 to $65.03 for the first six months of 2006. Also, cost of products sold for the six months ended June 30, 2006 increased by $131.1 million due to the inclusion of costs attributable to certain excess crude oil sales that were previously netted against the corresponding revenues and included in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006. Additionally, cost of products sold was reduced due to the exclusion of the operations of HEP in 2006 resulting from the deconsolidation of HEP effective July 1, 2005, which reduction was partially offset by increases in the current year due to the inclusion of NK Asphalt Partners for the entire six months ended June 30, 2006 versus only part of the six months ended June 30, 2005, following our February 2005 acquisition of the other partner’s interest.

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HOLLY CORPORATION

Gross Refinery Margins
Gross refining margin per produced barrel increased 58% from $10.74 in the first six months of 2005 to $16.95 in the first six months of 2006. Gross refinery margin does not include the effects 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 statements of prices of refined products sold and cost of products purchased.

Operating Expenses
Operating expenses increased 13% from $89.7 million in the first six months of 2005 to $101.6 million in the first six months of 2006 due principally to refinery maintenance projects, increased utility costs and environmental remediation expenses, partially offset by the exclusion of HEP’s operating costs in the first six months of 2006 due to the deconsolidation of HEP effective July 1, 2005.

General and Administrative Expenses
General and administrative expenses increased 41% from $22.9 million for the first six months of 2005 to $32.2 million for the first six months of 2006 due primarily to increased equity-based incentive compensation.

Depreciation, Depletion and Amortization Expenses
Depreciation, depletion and amortization decreased 20% from $23.3 million in the first six months of 2005 to $18.7 million in the first six months of 2006 due primarily to the exclusion of HEP’s depreciation resulting from the deconsolidation of HEP.

Equity in Earnings of HEP and Minority Interests
As part of the deconsolidation of HEP on July 1, 2005, we show equity in earnings for our ownership percentage of HEP, currently 45%, including any incentive distributions paid through our general partner interest. Our equity in earnings of HEP was $4.7 million for the six months ended June 30, 2006. There was no equity in earnings of HEP for the six months ended June 30, 2005 as HEP was a consolidated subsidiary for that period, with the then minority interest partners’ share of HEP’s earnings reported as minority interest. Minority interests in income of HEP in the first six months of 2005 reduced income by $6.7 million.

Equity in Earnings of Joint Ventures
There was no equity in earnings of joint ventures for the six months ended June 30, 2006 as all previously owned interests in joint ventures have been consolidated in our financials or have been sold. Equity in earnings of joint ventures for the six months ended June 30, 2005 reduced income by $0.7 million, reflecting our interest in the NK Asphalt joint venture prior to our acquisition of the other partner’s interest.

Interest Income
Interest income for the first six months of 2006 was $4.1 million compared to $3.3 million for the first six months of 2005. The increase in interest income was principally due to a higher interest rate environment.

Interest Expense
Interest expense was $0.5 million for the six months ended June 30, 2006 as compared to $4.2 million for the six months ended June 30, 2005. The decrease for this six month period as compared to the same period in 2005 was principally due to the inclusion of HEP’s interest expense for the six months ended June 30, 2005 prior to the deconsolidation of HEP effective July 1, 2005.

Income Taxes
Income taxes increased 64% from $39.9 million for the six months ended June 30, 2005 to $65.6 million for the six months ended June 30, 2006 due to significantly higher pre-tax earnings during the first six months of 2006 as compared to the same period in 2005, partially offset by a lower effective tax rate. The effective tax rate for the six months ended June 30, 2006 was 35.6%, as compared to 37.8% for the six months ended June 30, 2005. The reduction of the effective tax rate was primarily due to income tax credits available to small business refiners.

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HOLLY CORPORATION

Discontinued Operations

Income from discontinued operations was $21.0 million for the six months ended June 30, 2006 as compared to $0.5 million for the six months ended June 30, 2005. Included in the six months ended June 30, 2006 was the gain on the sale of the Montana Refinery of $14.0 million, net of $8.3 million in income taxes. Comparing the operations of the Montana Refinery, these operations generated $7.0 million of earnings for the first six months of 2006 and $0.5 million for the same period in 2005. The increase in earnings from discontinued operations was also due in part to the liquidation in the 2006 second quarter of retained finished product inventories that had been carried at lower costs as compared to current values.

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 primarily conservative, highly-rated instruments issued by financial institutions or government entities with strong credit ratings.

We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities greater than three months. These securities include investments in variable rate demand notes (“VRDN”) and auction rate securities (“ARS”). Although VRDN and ARS may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss.

As of June 30, 2006, we had cash and cash equivalents of $117.9 million, marketable securities with maturities under one year of $106.8 million, marketable securities with maturities greater than one year, but less than two years, of $4.4 million, and one million shares of Connacher stock valued at $3.9 million.

Cash and cash equivalents increased by $68.8 million during the six months ended June 30, 2006. The cash flow provided by operating activities of $79.8 million and investing activities of $76.1 million, exceeded the cash used for financing activities of $87.1 million. Working capital increased during the six months ended June 30, 2006 by $25.3 million.

We have a $175 million secured revolving credit facility with Bank of America as administrative agent and a lender, with a term of four years through 2008 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 and other general corporate purposes. As of June 30, 2006, we had letters of credit outstanding under our revolving credit facility of $2.3 million and had no borrowings outstanding. We were in compliance with all covenants at June 30, 2006.

On November 7, 2005, we announced that our Board of Directors authorized the repurchase of up to $200 million of our common stock. Repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2006, we repurchased under this repurchase initiative 2,675,653 shares at a cost of approximately $90.9 million (of which $3.0 million of the cash settlement was after June 30, 2006) or an average of $33.99 per share. Since inception of this repurchase initiative through June 30, 2006, we have repurchased 3,663,253 shares at a cost of approximately $120.9 million or an average of $33.00 per share.

We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facility provide sufficient resources to fund currently planned capital

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HOLLY CORPORATION

projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and the repurchase of our common stock under our $200 million program. In addition, components of our growth strategy may include selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

Cash Flows — Operating Activities

Net cash flows provided by operating activities amounted to $79.8 million for the six months ended June 30, 2006, compared to net cash flows provided by operating activities of $72.5 million for the six months ended June 30, 2005, a change of $7.3 million. Net income for the six months ended June 30, 2006 was $139.9 million, an increase of $73.8 million from net income of $66.1 million for the six months ended June 30, 2005. Additionally, the non-cash items included in net income - depreciation and amortization, deferred taxes, minority interests, equity-based compensation and gain on an asset sale — resulted in a reduction of cash flows of $1.3 million during the six months ended June 30, 2006 as compared to an increase in cash flows of $33.5 million for the same period in 2005. Distributions in excess of equity in earnings of Holly Energy Partners and joint ventures increased by $4.4 million for the six months ended June 30, 2006 as compared to the same period in 2005. Working capital items decreased cash flows by $59.2 million during the six months ended June 30, 2006, as compared to $23.3 million for the six months ended June 30, 2005. Changes in inventories were a primary cause of the reduced cash flow for the first six months of 2006 as compared to the first six months of 2005 principally due to a build-up of crude oil inventories attributable to the production downtime arising from our planned capital and maintenance projects during the second quarter of 2006. Inventories increased by $49.9 million in the first six months of 2006 as compared to $14.7 million for the first six months of 2005. Additionally, in the first six months of 2006, there were increases in both accounts receivable of $55.6 million and accounts payable of $33.3 million, principally due to increases in prices for refined products and crude oil. For the first six months of 2005, there were increases in both accounts receivable of $120.9 million and accounts payable of $92.1 million, principally due to increases in prices for refined products and crude oil.

Cash Flows — Investing Activities and Capital Projects

Net cash flows provided by investing activities were $76.1 million for the six months ended June 30, 2006, as compared to net cash flows used for investing activities of $150.4 million for the six months ended June 30, 2005, a net change of $226.5 million. On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Cash expenditures for property, plant and equipment for the first six months of 2006 totaled $67.5 million as compared to $28.6 million for the same period of 2005. In February 2005, we purchased the 51% interest in NK Asphalt Partners owned by the other partner. The total purchase consideration for the 51% interest, including expenses, was $21.9 million, less cash of $3.4 million which was recorded due to the consolidation of NK Asphalt Partners at the time of our acquisition of the remaining 51% interest. Also in February 2005, HEP closed on its Alon transaction which required $120.0 million in cash plus transaction costs of $1.8 million through June 30, 2005. We also invested $103.3 million in marketable securities and received proceeds of $198.0 million from the sale or maturity of marketable securities during the six months ended June 30, 2006. For the six months ended June 30, 2005, we invested $65.1 million in marketable securities and received proceeds of $82.8 million from the sale or maturity of marketable securities.

Planned Capital Expenditures

Each year our Board of Directors approves in our annual capital budget, capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s

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capital budget as well as, in certain cases, expenditures for capital projects approved in capital budgets for prior years. Our total new capital budget for 2006 is approximately $62.2 million, not including the capital projects approved in prior years, mainly our ULSD projects at the Navajo and Woods Cross refineries, as described below. The 2006 capital budget is comprised of $46.9 million for improvement projects for the Navajo Refinery, $4.7 million for projects at the Woods Cross Refinery, $5.1 million for transportation projects, $0.4 million for marketing related projects, $0.7 million for asphalt plant projects and $4.4 million for information technology and other miscellaneous projects. See below for discussion of significant additional planned capital projects at both the Navajo and Woods Cross facilities, which have not yet been finally approved by our Board of Directors as of the date of this report.

In 2006 we expect to expend approximately $111.0 million on capital projects, which amount primarily consists of certain current year capital budget items and carryovers of capital projects from previous years, less carryovers to 2007 of certain of the currently approved capital projects, combined with certain preliminary expenditures on the newly planned capital projects.

We have completed the first phase of a clean fuels / expansion project at the Navajo Refinery calling 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 / expansion of the kerosene hydrotreater to naphtha service, and the installation of additional sulfur recovery capacity, which enables us to produce ULSD. In addition, we are revamping our crude and vacuum units at Artesia and Lovington for improved energy conservation / product cutpoints and installing a 10 million standard cubic feet per day hydrogen plant, which will enable 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 to be approximately $76.0 million, which was approved in prior years’ capital budgets. In order to avoid additional unit downtime, we are phasing in this crude expansion. Our current crude capacity has just been increased from 75,000 BPSD to 82,000 BPSD and we plan to phase in a further increase to 85,000 BPSD in the fourth quarter of 2007. An additional 100 ton per day sulfur recovery unit included in the 2006 capital budget at a cost of $26.0 million is planned for start-up in the second quarter of 2008. It is anticipated that these projects will also enable the Navajo Refinery, without significant additional investment, to comply with LSG specifications required by the end of 2010.

We have completed a clean fuels project at the Woods Cross Refinery calling for the construction of a diesel hydrotreater unit, at an approximate cost of $35.0 million, which was approved in prior years, and execution of a long term hydrogen contract that has enabled Holly Refining and Marketing – Woods Cross to produce ULSD. This project will also create the infrastructure required for the additional Woods Cross project discussed below. The Woods Cross Refinery is required to meet Maximum Achievable Control Technology (“MACT”) requirements on its FCC flue gas by January 1, 2010. We plan to desulfurize FCC feed prior to this 2010 date to comply with these requirements as well as the future LSG 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.

We have recently announced preliminary plans for significant new capital projects at both our Navajo and Woods Cross refineries to provide feedstock flexibility and expansions of refining capacity at both facilities. These additional planned projects have not at this point been approved by our Board of Directors. The proposed strategy for the Navajo Refinery calls for the installation of a new crude unit, gas oil hydrocracker, solvent de-asphalter and hydrogen plant, which would permit processing up to 100,000 BPSD of crude. The Navajo project would enable us to increase our ability to capture light/heavy crude differentials on 20,000 BPSD. We currently estimate that the cost of the Navajo project would be approximately $240 million and that the project could be completed in the third quarter of 2008. The proposed strategy for the Woods Cross Refinery calls for the expansion and revamp of its crude unit for heavier crudes, the installation of a 10,000 BPSD gas oil hydrotreater which is expandable to 15,000 BPSD and can be converted in the future to a hydrocracker, the expansion and revamp of the solvent de-asphalter to 12,000 BPSD, and the addition of extra sulfur recovery capacity, which would enable processing of up to 30,000 BPSD of crude. Additionally, the Woods Cross project would enable us to increase Canadian heavy/sour crude runs

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to approximately 20,000 BPSD. This would enable us to take advantage of the wide discounts on Canadian crude when available, and provide a basis for additional crude flexibility and expansion. We currently estimate the cost of the Woods Cross project would be approximately $60 million and that the project could be completed in the third quarter of 2008. If we proceed with the projects described above for the Navajo and Woods Cross refineries, we estimate that our total capital expenditures in 2007 and 2008 would be approximately $200 million each year.

To fully take advantage of the economics on the Woods Cross project under consideration, additional crude pipeline capacity would be required to move Canadian crude to the Woods Cross Refinery. We are currently working with HEP to explore options available. We are also working with HEP in evaluating a refined products pipeline from Salt Lake City to Las Vegas.

On October 22, 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act 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 tax savings that we would derive from planned capital expenditures associated with the 2004 Act would result in a reduction in our income tax expense of approximately $10.0 million in both 2006 and 2007, representing the difference between the value of allowed credits under the 2004 Act as compared to the value of depreciating the investments. On August 8, 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act creates tax incentives for refiners by providing for an immediate deduction of 50% of certain refinery capacity expansion costs when the assets are placed in service.

Cash Flows — Financing Activities

Net cash flows used for financing activities were $87.1 million for the six months ended June 30, 2006, as compared to cash flows provided by financing activities of $122.1 million for the six months ended June 30, 2005, a net change of $209.2 million. Under our stock repurchase program announced November 7, 2005, we purchased treasury stock of $90.9 million during the six months ended June 30, 2006. Under our stock repurchase program announced May 19, 2005, we purchased treasury stock of $26.1 million during the six months ended June 30, 2005. Also, during the six months ended June 30, 2006 and 2005, we repurchased at current market price from certain executives common stock at a cost of approximately $1.4 million and $0.8 million, respectively; these purchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means. During the six months ended June 30, 2006, we paid $5.9 million in dividends, received $2.2 million for common stock issued upon exercise of stock options, and recognized $8.9 million in excess tax benefits on our equity based compensation. 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 and paid down borrowings under its credit facility netting to $25.0 million. In connection with HEP’s purchase of our intermediate lines, HEP received proceeds of $34.6 million from additional issuance of their HEP Senior Notes. Additionally, during the first six months of 2005, we paid $5.1 million in dividends, received $2.6 million for common stock issued upon exercise of stock options, made distributions of $9.5 million to the minority interest partners of HEP and recognized $5.0 million in excess tax benefits on our equity based compensation.

Contractual Obligations and Commitments

During the six months ended June 30, 2006, there were no significant changes to our contractual obligations and commitments.

HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on HEP’s refined product pipelines or throughput in HEP’s terminals a volume of refined products that will result in a minimum level of revenue to HEP of $36.7 million annually. During the six months ended June 30, 2006, the HEP PTA was amended to reflect certain rate changes, most significantly a re-negotiation of the tariffs on our refined products shipped on the pipelines that serve our Navajo Refinery, but such

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amendment did not affect our obligations under the minimum revenue commitment. Under the HEP IPA, we agreed to transport volumes of intermediate products on the intermediate pipelines that will result in a minimum level of revenues to HEP of approximately $11.8 million annually. Minimum revenues for both agreements will adjust upward based on increases in the producer price index over the term of the agreements. Additionally, we agreed to indemnify HEP up to an aggregate amount of $17.5 million for any environmental noncompliance and remediation liabilities associated with the assets transferred to HEP and occurring or existing prior to the date of the transfers of ownership to HEP. Of this total, indemnification in excess of $15 million relates solely to the intermediate pipelines.

HEP financed the Alon transaction through a private offering of $150 million principal amount of HEP Senior Notes. HEP increased these notes to $185 million as part of the purchase of our intermediate pipelines. The $185 million HEP Senior Notes are not recorded on our accompanying consolidated balance sheets due to the deconsolidation of HEP effective July 1, 2005. The HEP Senior Notes were reflected on our consolidated balance sheets (because HEP was a consolidated subsidiary) through June 30, 2005. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of $35 million of the principal amount of the HEP Senior Notes.

In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have liabilities relating to the Federal Clean Air Act at our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have tentatively agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The tentative settlement agreement, which has not yet been put into a final written agreement, includes proposed obligations for us to make specified additional capital investments expected to total up to approximately $10 million over several years and to make changes in operating procedures at the refinery. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the tentative settlement. With respect to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries, following the sale of the Montana Refinery in March 2006 our remaining commitment relates to the Navajo Refinery and, with the investments made to date, our outstanding required investments are no longer significant.

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.

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, 2005. 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 2006.

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.

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New Accounting Pronouncements

SFAS No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4”
In December 2004, the FASB issued SFAS No. 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 is effective for fiscal years beginning after June 15, 2005. We have adopted the standard effective beginning January 1, 2006. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

The Emerging Issues Task Force reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it in September 2005. This standard addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The consensus in this standard is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. We adopted this standard effective April 1, 2006 and no longer account for certain crude oil transactions on a net basis.

With respect to supplying crude oil to our refineries, crude oil is often purchased in locations distant from our refineries and exchanged for crude oil that is transportable to our refineries. These buy/sell exchanges are done in contemplation of one another and allow us to receive the optimal crude blend and quantities at our refineries. All of the crude oil buy/sell transactions done in supplying crude oil to our refineries are recorded as exchanges with the net differential reflected in costs of sales. We also purchase crude oil from producers and other petroleum companies in excess of the needs of our refineries for resale to other purchasers or users of crude oil. With respect to these resales that are in the form of buy/sell exchanges with the same counterparty, the net differential of the exchanges is reflected in costs of products sold. Additionally, certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under the new accounting guidance, these direct sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included in cost of products sold. Prior to our adoption of EITF 04-13, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold. During the quarter ended June 30, 2006, these crude oil sales amounted to $131.3 million with a corresponding cost of $131.1 million, resulting in a gain on these transactions of $0.2 million.

ADDITIONAL FACTORS THAT MAY AFFECT FUTURE RESULTS

This discussion should be read in conjunction with the discussion under the heading “Risk Factors” included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2005.

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 that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit. 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.

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We periodically utilize petroleum commodity futures contracts to reduce our exposure to price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. Additionally, in 2005 we entered into certain transactions relating to forecasted sales of diesel fuel from our refineries, where our principal objective was to take advantage of the recent high margins (or crack spreads, being the difference between the price of diesel fuel and the cost of crude oil) on a portion of our diesel fuel sales. To effect these hedges, we sold heating oil futures (which most closely match diesel fuel pricing) and bought crude oil futures (or entered into commodity swap transactions with terms that mirror the futures market). Our objective has been to either liquidate the positions as the crack spreads return to more normalized levels or to hold these positions until the forecasted diesel fuel sales are made, effectively locking in the diesel fuel crack spreads (or margins) at the high levels. Our strategy has been to enter into these transactions only when the margins are at historically very high levels, and to have no more than 25% of our diesel fuel production hedged at any given time. During 2005, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. The positions were fully liquidated during August to November 2005 resulting in a realized gain of $3.2 million, which was recorded as a decrease in cost of products sold in 2005. We have not had any open positions since November 2005.

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.

At June 30, 2006, we had no outstanding debt. 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, 2006. We invest a substantial part of available cash in investment grade, highly liquid investments with maturities of three months or less and hence the interest rate market risk implicit in these cash investments was low. We also invest the remainder of available cash in portfolios of highly rated marketable debt securities, primarily issued by government entities, that have an average remaining duration (including any cash equivalents invested) of not greater than one year and hence the interest rate market risk implicit in these investments is also low. A hypothetical 10% change in the market interest rate over the next year would not materially impact our earnings, cash flow or financial condition since any borrowings under the credit facilities and our investments are at market rates and interest on borrowings and cash investments has historically not been significant as compared to our total operations.

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.

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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. We are reporting EBITDA only from continuing operations.

Set forth below is our calculation of EBITDA from continuing operations.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
				(In thousands)
Income from continuing operations	$	87,729		$	51,103		$	118,889		$	65,519
Add provision for income tax		50,148			30,872			65,635			39,912
Add interest expense		272			2,661			547			4,205
Subtract interest income		(2,408	)		(2,085	)		(4,143	)		(3,253	)
Add depreciation, depletion and amortization		10,683			12,317			18,707			23,345
EBITDA from continuing operations	$	146,424		$	94,868		$	199,635		$	129,728

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 Statements of Income.

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

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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 both of our refineries on a consolidated basis is calculated as shown below.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Average per produced barrel:
Navajo Refinery
Net sales	$	90.76	$	65.73	$	82.49	$	61.50
Less cost of products		67.34		50.30		64.90		49.47
Refinery gross margin	$	23.42	$	15.43	$	17.59	$	12.03
Woods Cross Refinery
Net sales	$	89.63	$	67.35	$	80.52	$	61.17
Less cost of products		69.80		57.28		65.42		54.35
Refinery gross margin	$	19.83	$	10.07	$	15.10	$	6.82
Consolidated
Net sales	$	90.43	$	66.16	$	81.98	$	61.42
Less cost of products		68.06		52.14		65.03		50.68
Refinery gross margin	$	22.37	$	14.02	$	16.95	$	10.74

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 both of our refineries on a consolidated basis is calculated as shown below.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Average per produced barrel:
Navajo Refinery
Refinery gross margin	$	23.42	$	15.43	$	17.59	$	12.03
Less refinery operating expenses		5.37		3.84		5.07		3.45
Net operating margin	$	18.05	$	11.59	$	12.52	$	8.58
Woods Cross Refinery
Refinery gross margin	$	19.83	$	10.07	$	15.10	$	6.82
Less refinery operating expenses		4.36		3.86		4.99		4.08
Net operating margin	$	15.47	$	6.21	$	10.11	$	2.74
Consolidated
Refinery gross margin	$	22.37	$	14.02	$	16.95	$	10.74
Less refinery operating expenses		5.08		3.84		5.05		3.61
Net operating margin	$	17.29	$	10.18	$	11.90	$	7.13

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Below are reconciliations to our Consolidated Statements 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,
	2006			2005			2006			2005
Navajo Refinery
Average sales price per produced barrel sold	$	90.76		$	65.73		$	82.49		$	61.50
Times sales of produced refined products sold (BPD)		66,320			77,600			73,000			80,230
Times number of days in period		91			91			181			181
Refined product sales from produced products sold	$	547,747		$	464,159		$	1,089,940		$	893,080
Woods Cross Refinery
Average sales price per produced barrel sold	$	89.63		$	67.35		$	80.52		$	61.17
Times sales of produced refined products sold (BPD)		27,500			27,820			25,410			26,450
Times number of days in period		91			91			181			181
Refined product sales from produced products sold	$	224,299		$	170,505		$	370,328		$	292,848
Sum of refined products sales from produced products sold from our two refineries(4)	$	772,046		$	634,664		$	1,460,268		$	1,185,928
Add refined product sales from purchased products and rounding(1)		168,064			60,863			252,343			123,030
Total refined products sales		940,110			695,527			1,712,611			1,308,958
Add direct sales of excess crude oil(2)		131,275			—			131,275			—
Add other refining segment revenue(3)		49,453			23,499			68,300			27,339
Total refining segment revenue		1,120,838			719,026			1,912,186			1,336,297
Add HEP sales and other revenue		—			19,521			—			36,034
Add corporate and other revenues		143			252			524			617
Subtract consolidations and eliminations		(141	)		(10,144	)		(276	)		(19,574	)
Sales and other revenues	$	1,120,840		$	728,655		$	1,912,434		$	1,353,374

(1)	We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
(2)	We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)	Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to its consolidation in February 2005 and revenue derived from sulfur credit sales.
(4)	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,
	2006		2005		2006		2005
Average sales price per produced barrel sold	$	90.43	$	66.16	$	81.98	$	61.42
Times sales of produced refined products sold (BPD)		93,820		105,420		98,410		106,680
Times number of days in period		91		91		181		181
Refined product sales from produced products sold	$	772,046	$	634,664	$	1,460,268	$	1,185,928

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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,
	2006			2005			2006			2005
Navajo Refinery
Average cost of products per produced barrel sold	$	67.34		$	50.30		$	64.90		$	49.47
Times sales of produced refined products sold (BPD)		66,320			77,600			73,000			80,230
Times number of days in period		91			91			181			181
Cost of products for produced products sold	$	406,405		$	355,198		$	857,524		$	718,385
Woods Cross Refinery
Average cost of products per produced barrel sold	$	69.80		$	57.28		$	65.42		$	54.35
Times sales of produced refined products sold (BPD)		27,500			27,820			25,410			26,450
Times number of days in period		91			91			181			181
Cost of products for produced products sold	$	174,675		$	145,011		$	300,880		$	260,198
Sum of cost of products for produced products sold from our two refineries(4)	$	581,080		$	500,209		$	1,158,404		$	978,583
Add refined product costs from purchased products sold and rounding(1)		172,348			63,712			257,966			127,295
Total refined cost of products sold		753,428			563,921			1,416,370			1,105,878
Add crude oil cost of direct sales of excess crude oil(2)		131,061			—			131,061			—
Add other refining segment costs of products sold(3)		23,661			16,156			36,339			17,043
Total refining segment cost of products sold		908,150			580,077			1,583,770			1,122,921
Add corporate and other costs		—			—			—			—
Subtract consolidations and eliminations		(141	)		(10,144	)		(276	)		(19,574	)
Costs of products sold (exclusive of depreciation, depletion and amortization)	$	908,009		$	569,933		$	1,583,494		$	1,103,347

(1)	We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
(2)	We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)	Other refining segment costs of products sold includes the costs of products for NK Asphalt Partners subsequent to its consolidation in February 2005 and costs attributable to sulfur credit sales.
(4)	The above calculations of costs of products 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,
	2006		2005		2006		2005
Average cost of products per produced barrel sold	$	68.06	$	52.14	$	65.03	$	50.68
Times sales of produced refined products sold (BPD)		93,820		105,420		98,410		106,680
Times number of days in period		91		91		181		181
Cost of products for produced products sold	$	581,080	$	500,209	$	1,158,404	$	978,583

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HOLLY CORPORATION

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006			2005		2006		2005
Navajo Refinery
Average refinery operating expenses per produced barrel sold	$	5.37		$	3.84	$	5.07	$	3.45
Times sales of produced refined products sold (BPD)		66,320			77,600		73,000		80,230
Times number of days in period		91			91		181		181
Refinery operating expenses for produced products sold	$	32,409		$	27,117	$	66,990	$	50,100
Woods Cross Refinery
Average refinery operating expenses per produced barrel sold	$	4.36		$	3.86	$	4.99	$	4.08
Times sales of produced refined products sold (BPD)		27,500			27,820		25,410		26,450
Times number of days in period		91			91		181		181
Refinery operating expenses for produced products sold	$	10,911		$	9,772	$	22,950	$	19,533
Sum of refinery operating expenses per produced products sold from our two refineries(2)	$	43,320		$	36,889	$	89,940	$	69,633
Add other refining segment operating expenses and rounding(1)		5,790			4,931		11,603		8,275
Total refining segment operating expenses		49,110			41,820		101,543		77,908
Add HEP operating expenses		—			6,448		—		11,836
Add corporate and other costs		(18	)		—		16		—
Operating expenses (exclusive of depreciation, depletion and amortization)	$	49,092		$	48,268	$	101,559	$	89,744

(1)	Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt Partners subsequent to its consolidation in February 2005.
(2)	The above calculations of refinery operating expenses 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,
	2006		2005		2006		2005
Average refinery operating expenses per produced barrel sold	$	5.08	$	3.84	$	5.05	$	3.61
Times sales of produced refined products sold (BPD)		93,820		105,420		98,410		106,680
Times number of days in period		91		91		181		181
Refinery operating expenses for produced products sold	$	43,320	$	36,889	$	89,940	$	69,633

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HOLLY CORPORATION

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,
	2006			2005			2006			2005
Navajo Refinery
Net operating margin per barrel	$	18.05		$	11.59		$	12.52		$	8.58
Add average refinery operating expenses per produced barrel		5.37			3.84			5.07			3.45
Refinery gross margin per barrel		23.42			15.43			17.59			12.03
Add average cost of products per produced barrel sold		67.34			50.30			64.90			49.47
Average sales price per produced barrel sold	$	90.76		$	65.73		$	82.49		$	61.50
Times sales of produced refined products sold (BPD)		66,320			77,600			73,000			80,230
Times number of days in period		91			91			181			181
Refined products sales from produced products sold	$	547,747		$	464,159		$	1,089,940		$	893,080
Woods Cross Refinery
Net operating margin per barrel	$	15.47		$	6.21		$	10.11		$	2.74
Add average refinery operating expenses per produced barrel		4.36			3.86			4.99			4.08
Refinery gross margin per barrel		19.83			10.07			15.10			6.82
Add average cost of products per produced barrel sold		69.80			57.28			65.42			54.35
Average sales price per produced barrel sold	$	89.63		$	67.35		$	80.52		$	61.17
Times sales of produced refined products sold (BPD)		27,500			27,820			25,410			26,450
Times number of days in period		91			91			181			181
Refined products sales from produced products sold	$	224,299		$	170,505		$	370,328		$	292,848
Sum of refined products sales from produced products sold from our two refineries(4)	$	772,046		$	634,664		$	1,460,268		$	1,185,928
Add refined product sales from purchased products and rounding(1)		168,064			60,863			252,343			123,030
Total refined products sales		940,110			695,527			1,712,611			1,308,958
Add direct sales of excess crude oil(2)		131,275			—			131,275			—
Add other refining segment revenue(3)		49,453			23,499			68,300			27,339
Total refining segment revenue		1,120,838			719,026			1,912,186			1,336,297
Add HEP sales and other revenue		—			19,521			—			36,034
Add corporate and other revenues		143			252			524			617
Subtract consolidations and eliminations		(141	)		(10,144	)		(276	)		(19,574	)
Sales and other revenues	$	1,120,840		$	728,655		$	1,912,434		$	1,353,374

(1)	We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.
(2)	We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)	Other refining segment revenue includes the revenues associated with NK Asphalt Partners subsequent to its consolidation in February 2005 and revenue derived from sulfur credit sales.

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HOLLY CORPORATION

(4) 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,
	2006		2005		2006		2005
Net operating margin per barrel	$	17.29	$	10.18	$	11.90	$	7.13
Add average refinery operating expenses per produced barrel		5.08		3.84		5.05		3.61
Refinery gross margin per barrel		22.37		14.02		16.95		10.74
Add average cost of products per produced barrel sold		68.06		52.14		65.03		50.68
Average sales price per produced barrel sold	$	90.43	$	66.16	$	81.98	$	61.42
Times sales of produced refined products sold (BPD)		93,820		105,420		98,410		106,680
Times number of days in period		91		91		181		181
Refined product sales from produced products sold	$	772,046	$	634,664	$	1,460,268	$	1,185,928

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HOLLY CORPORATION

Item 4.Controls and Procedures

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

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

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HOLLY CORPORATION

PART II. OTHER INFORMATION

Item 1.Legal Proceedings

We have pending proceedings in the United States Court of Appeals for the District of Columbia Circuit with respect to rulings by the FERC in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize an SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. Rulings by the FERC relating principally to the period from 1993 through July 2000 resulted in reparations payments from SFPP to us in 2003 totaling approximately $15.3 million. In 2004 the appeals court issued its opinion relating principally to the period from 1993 through July 2000, ruling 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. In May 2005, the FERC issued a general policy statement on an issue concerning the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships. The FERC in a later order applied this general policy statement to SFPP and such application is contrary to our position in this case. We and certain other refining companies have pending before the court of appeals petitions challenging the FERC policy on income taxes, decisions by the FERC in 2005 and early 2006 on certain of the remanded issues, and rulings by the FERC on some issues relating to periods after July 2000. In March 2006, SFPP submitted computations asserted to be based on the most recent determinations of the FERC in the case. In April 2006, we filed a protest and comments concerning a number of elements of these computations. One element of the computations, which is based on the FERC’s disputed 2005 policy on treatment of income taxes, would if ultimately sustained result in a requirement for us to repay to SFPP approximately $3 million of the $15.3 million reparations amount received by us from SFPP in 2003. Because proceedings in the FERC on remand have not been completed and our petitions for review to the court of appeals with respect to the FERC’s orders are pending, it is not possible to determine whether the amount of reparations actually due to us for the period from 1993 through July 2000 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 are not likely to result in an obligation for us to repay more than the amount now asserted in SFPP’s most recent computations (approximately $3 million) and that the more likely final result would be either a smaller repayment by us than is now asserted by SFPP or a payment to us of additional reparations. The ultimate amount of reparations payable to us 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 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. Our claims are similar to claims in a number of other cases also pending in the United States Court of Federal Claims brought by other refining companies concerning military fuel sales. In response to our request, the judge in our case issued in February 2006 an order continuing the stay of our case originally ordered in March 2004. While the stay of our case is in effect we expect that further judicial proceedings in one or more other cases brought by other refining companies may clarify the legal standards that will apply to our case. It is not possible to predict the outcome of further proceedings in our case.

In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal Clean Air Act liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have tentatively agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement similar to the 2001 Consent Agreement we entered into for our Navajo and Montana refineries. The tentative settlement agreement, which has not yet been put into a final written agreement, includes proposed obligations for us to make specified additional capital investments expected to total up to approximately $10 million over several years and to make changes in operating procedures at the refinery. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising

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HOLLY CORPORATION

from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the tentative settlement.

Our Navajo Refining Company subsidiary is named as a defendant, along with approximately 45 other companies involved in oil refining and marketing and related businesses, in a lawsuit filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico. The lawsuit alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying methyl tertiary butyl ether (“MTBE”) or gasoline or other products containing MTBE. The claims made are for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy. The suit seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. As of the close of business on the day prior to the date of this report, Navajo has not been served in this case. It is not possible to predict the likely course or outcome of this litigation.

The Montana Department of Environmental Quality (“MDEQ”) has notified us that the MDEQ proposes to seek enforcement of a proposed penalty of $106,000 against us based on alleged violations by the Montana Refinery in late 2004 and early 2005 of certain limitations on sulfur dioxide in the refinery’s air emissions permit. We do not believe that the permit should be interpreted as proposed by the MDEQ with respect to most of the alleged violations and we are not able to predict the outcome of this matter.

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

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HOLLY CORPORATION

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

     (c)Common Stock Repurchases Made in the Quarter

On November 7, 2005, we announced that our Board of Directors authorized the repurchase of up to $200.0 million of our common stock. Repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. The following table includes the repurchases made during the quarter ended June 30, 2006. The number of shares repurchased prior to our two-for-one stock split effective June 1, 2006 and the per share amounts have been adjusted to reflect the split on a retrospective basis.

							Maximum Dollar
					Total Number of		Value of Shares Yet
					Shares Purchased as		to be Purchased as
	Total Number of		Average Price Paid		Part of $200 Million		Part of the $200
Period	Shares Purchased		Per Share		Program		Million Program
April 2006		284,738	$	38.64		284,738	$	95,160,521
May 2006		—		—		—	$	95,160,521
June 2006		391,515	$	41.03		391,515	$	79,096,799
Total		676,253	$	40.03		676,253

The total shares purchased during the second quarter of 2006 reflected herein include 67,999 shares at a total cost of $3.0 million that were not settled until July 2006, and therefore are not included on our cash flow statement for the six months ended June 30, 2006.

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

At the annual meeting of stockholders on May 11, 2006, 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		25,546,620		1,022,827
Matthew P. Clifton		21,759,502		4,809,945
W. John Glancy		21,027,352		5,542,095
William J. Gray		20,245,531		6,323,916
Marcus R. Hickerson		20,049,297		6,520,150
Thomas K. Matthews, II		23,759,179		2,810,268
Robert G. McKenzie		24,240,429		2,329,018
C. Lamar Norsworthy, III		21,117,954		5,451,493
Jack P. Reid		24,101,049		2,468,398
Paul T. Stoffel		24,576,430		1,993,017

Our stockholders approved an amendment to our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 50,000,000 shares to 100,000,000.

			Broker
Total Votes “For”	Total Votes “Withheld”	Abstentions	Non-Votes
23,940,927	2,563,545	64,975	—

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HOLLY CORPORATION

Item 6.Exhibits

(a) Exhibits

31.1+	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1+	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

+ Filed herewith.

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HOLLY CORPORATION

SIGNATURES

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

	HOLLY CORPORATION
	(Registrant)
Date: August 7, 2006		/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)

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