HF Sinclair 10-Q 2007 Q1 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      March 31, 2007     

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 Number     1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	75-1056913
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer 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.

Yes þ  No o                  

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 filer þ  Accelerated filer o  Non-accelerated filer o

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

Yes o  No þ                  

55,048,142 shares of Common Stock, par value $.01 per share, were outstanding on April 30, 2007.

HOLLY CORPORATION
INDEX

			Page
PART I.		FINANCIAL INFORMATION
	Forward-Looking Statements			3
	Definitions			4
	Item 1.	Financial Statements
		Consolidated Balance Sheets — (Unaudited) — March 31, 2007 and December 31, 2006		6
		Consolidated Statements of Income (Unaudited) — Three Months Ended March 31, 2007 and 2006		7
		Consolidated Statements of Cash Flows (Unaudited) — Three Months Ended March 31, 2007 and 2006		8
		Consolidated Statements of Comprehensive Income (Unaudited) — Three Months Ended March 31, 2007 and 2006		9
		Notes to Consolidated Financial Statements (Unaudited)		10
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36
	Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles			36
	Item 4.	Controls and Procedures		42
PART II.		OTHER INFORMATION
	Item 1.	Legal Proceedings		43
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		45
	Item 6.	Exhibits		46
Signatures
				47
Agreement Concerning Payment of Benefits Under Retirement Restoration Plan
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 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.

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 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, 2006 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 a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.

     “Hydrocracker” means a refinery unit that breaks down large complex hydrocarbon molecules into smaller more useful ones using a fixed bed of catalyst at high pressure and temperature with hydrogen.

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

     “Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes.

     “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 rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.

     “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.

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     “PPM” means parts-per-million.

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

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

     “ROSE”, or “Solvent deasphalter / residuum oil supercritical extraction,” means a refinery unit 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 equal to or 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)

	March 31,			December 31,
	2007			2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	151,179		$	154,117
Marketable securities		119,497			96,168
Accounts receivable:
Product and transportation		180,492			199,083
Crude oil resales		178,910			196,842
Related party receivable		3,390			2,198
		362,792			398,123
Inventories:
Crude oil and refined products		130,267			115,100
Materials and supplies		15,166			14,575
		145,433			129,675
Income taxes receivable		—			9,055
Prepayments and other		10,751			12,081
Assets of discontinued operations		—			355
Total current assets		789,652			799,574
Properties, plants and equipment, at cost		669,490			642,740
Less accumulated depreciation, depletion and amortization		(246,355	)		(237,270	)
		423,135			405,470
Marketable securities (long-term)		9,721			5,668
Other assets:
Turnaround costs (long-term)		10,307			12,061
Intangibles and other		14,227			15,096
		24,534			27,157
Total assets	$	1,247,042		$	1,237,869
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	481,023		$	507,566
Accrued liabilities		35,237			51,173
Income taxes payable		16,109			—
Liabilities of discontinued operations		—			654
Total current liabilities		532,369			559,393
Deferred income taxes		19,755			20,776
Other long-term liabilities		29,195			27,201
Commitments and contingencies		—			—
Distributions in excess of investment in Holly Energy Partners		166,494			164,405
Stockholders’ equity:
Preferred stock, $1.00 par value — 1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value — 100,000,000 shares authorized; 72,169,371 and 71,825,960 shares issued as of March 31, 2007 and December 31, 2006, respectively		719			718
Additional capital		72,580			66,500
Retained earnings		807,969			745,994
Accumulated other comprehensive loss		(12,844	)		(11,358	)
Common stock held in treasury, at cost — 17,135,488 and 16,509,345 shares as of March 31, 2007 and December 31, 2006, respectively		(369,195	)		(335,760	)
Total stockholders’ equity		499,229			466,094
Total liabilities and stockholders’ equity	$	1,247,042		$	1,237,869

See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(In thousands, except per share data)

	Three Months Ended
	March 31,
	2007			2006
Sales and other revenues	$	925,867		$	791,594
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		751,714			675,485
Operating expenses (exclusive of depreciation, depletion, and amortization)		50,129			52,467
General and administrative expenses (exclusive of depreciation, depletion, and amortization)		15,847			13,516
Depreciation, depletion and amortization		11,451			8,024
Exploration expenses, including dry holes		152			127
Total operating costs and expenses		829,293			749,619
Income from operations		96,574			41,975
Other income (expense):
Equity in earnings of Holly Energy Partners		3,346			3,212
Interest income		2,560			1,735
Interest expense		(252	)		(275	)
		5,654			4,672
Income from continuing operations before income taxes		102,228			46,647
Income tax provision:
Current		34,758			14,806
Deferred		(72	)		681
		34,686			15,487
Income from continuing operations		67,542			31,160
Discontinued operations
Income from discontinued operations		—			1,387
Gain on sale of discontinued operations		—			14,257
Income from discontinued operations, net of taxes		—			15,644
Net income	$	67,542		$	46,804
Basic earnings per share:
Continuing operations	$	1.22		$	0.53
Discontinued operations		—			0.27
Net income	$	1.22		$	0.80
Diluted earnings per share:
Continuing operations	$	1.20		$	0.52
Discontinued operations		—			0.26
Net income	$	1.20		$	0.78
Cash dividends declared per common share	$	0.10		$	0.05
Average number of common shares outstanding:
Basic		55,189			58,458
Diluted		56,318			60,028

See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

	Three Months Ended
	March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	67,542		$	46,804
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization (includes discontinued operations)		11,451			8,574
Deferred income taxes (includes discontinued operations)		(72	)		(1,761	)
Equity based compensation expense		1,231			780
Distributions in excess of equity in earnings in HEP and joint ventures		2,089			1,601
Gain on sale of assets, before income taxes		—			(22,638	)
(Increase) decrease in current assets:
Accounts receivable		35,682			30,569
Inventories		(15,758	)		(53,423	)
Income taxes receivable		9,055			—
Prepayments and other		1,330			787
Increase (decrease) in current liabilities:
Accounts payable		(25,478	)		(35,712	)
Accrued liabilities		(16,552	)		(2,808	)
Income taxes payable		16,109			11,962
Turnaround expenditures		(198	)		(4,080	)
Other, net		(130	)		1,005
Net cash provided by (used for) operating activities		86,301			(18,340	)
Cash flows from investing activities:
Additions to properties, plants and equipment		(26,750	)		(32,235	)
Net cash proceeds from sale of Montana Refinery		—			48,872
Purchases of marketable securities		(89,165	)		(51,442	)
Sales and maturities of marketable securities		62,140			154,693
Net cash provided by (used for) investing activities		(53,775	)		119,888
Cash flows from financing activities:
Issuance of common stock upon exercise of options		263			1,401
Purchase of treasury stock		(35,837	)		(59,271	)
Cash dividends		(4,477	)		(2,957	)
Excess tax benefit from equity based compensation		4,587			4,826
Net cash used for financing activities		(35,464	)		(56,001	)
Cash and cash equivalents:
Increase (decrease) for the period		(2,938	)		45,547
Beginning of period		154,117			49,064
End of period	$	151,179		$	94,611
Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	14		$	176
Income taxes	$	5,006		$	9,812

See accompanying notes.

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HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In thousands)

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Net income	$	67,542		$	46,804
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain on available for sale securities		378			229
Reclassification adjustment to net income on sale of equity securities		(21	)		(20	)
Total unrealized gain on available for sale securities		357			209
Retirement medical obligation adjustment		(2,792	)		—
Other comprehensive income (loss) before income taxes		(2,435	)		209
Income tax expense (benefit)		(949	)		81
Other comprehensive income (loss)		(1,486	)		128
Total comprehensive income	$	66,056		$	46,932

See accompanying notes.

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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 March 31, 2007, 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 (“Woods Cross Refinery”);

• 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 does business under the name of “Holly Asphalt Company;” and

• owned a 45.0% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest, which has logistic assets including approximately 1,700 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 net gain of $14.3 million on the sale are shown in discontinued operations (see Note 2).

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of March 31, 2007, the consolidated results of operations and comprehensive income for the three months ended March 31, 2007 and 2006 and consolidated cash flows for the three months ended March 31, 2007 and 2006 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, 2006 filed with the SEC.

We use the last-in, first-out (“LIFO”) method of valuing inventory. Under the LIFO method, an actual valuation of inventory can only be made 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 three months of 2007 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.

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New Accounting Pronouncements

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No 115. SFAS No. 159, which amends SFAS No. 115, allows certain financial assets and liabilities to be recognized, at a company’s election, at fair market value, with any gains or losses for the period recorded in the statement of income. SFAS No. 159 includes available-for-sale securities in the assets eligible for this treatment. Currently, we record the gains or losses for the period as a component of comprehensive income and in the equity section of the balance sheet. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years. While we are currently evaluating the provisions of SFAS No. 159, we do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits.

We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.

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

SFAS No. 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We do not anticipate that the adoption of this interpretation will have a material impact on our financial condition, results of operations and cash flows.

NOTE 2: Discontinued Operations

On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.6 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.1 million for other assets, with current liabilities assumed amounting to $0.3 million.

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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 March 31,
	2007		2006
	(In thousands)
Sales and other revenues from discontinued operations	$	—	$	33,183
Income from discontinued operations before income tax expense	$	—	$	2,202
Income tax expense		—		(815	)
Income from discontinued operations, net		—		1,387
Gain on sale of discontinued operations before income taxes		—		22,638
Income tax expense		—		(8,381	)
Gain on sale of discontinued operations, net		—		14,257
Income from discontinued operations, net	$	—	$	15,644

In accordance with the Montana Refinery sale agreement, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. Based on our estimates, we had accruals of $1.3 million as of March 31, 2007 and December 31, 2006 related to such environmental liabilities which is included in our environmental liability accrual as discussed in Note 7.

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% 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, volumes of refined products that will result in minimum annual payments to HEP, currently $38.5 million. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP, currently $12.4 million. Minimum payments 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 $15.0 million relates solely to the intermediate pipelines.

HEP is a variable interest entity (“VIE”) as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines in 2005, we have determined that our beneficial variable interest in HEP was less than 50%. We report our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, 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.

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We hold 7,000,000 subordinated units and 70,000 common units of HEP as of March 31, 2007. 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.

The following table sets forth the changes during the three months ended March 31, 2007 in our investment account balance with HEP:

Investment in HEP balance at December 31, 2006	$	(164,405	)
Equity in the earnings of HEP		3,346
Regular quarterly distributions from HEP		(5,435	)
Investment in HEP balance at March 31, 2007	$	(166,494	)

The following tables provide summary financial results for HEP.

	March 31,		December 31,
	2007		2006
	(In thousands)
Current assets	$	19,358	$	23,624
Properties and equipment, net		158,324		160,484
Transportation agreements and other		58,271		59,465
Total assets	$	235,953	$	243,573
Current liabilities	$	10,735	$	14,174
Long-term liabilities		182,312		182,210
Minority interest		11,390		10,963
Partners’ equity		31,516		36,226
Total liabilities and partners’ equity	$	235,953	$	243,573

	Three Months Ended March 31,
	2007			2006
	(In thousands)
Revenues	$	23,872		$	22,438
Operating costs and expenses		13,135			12,126
Operating income		10,737			10,312
Other expenses, net		(3,303	)		(3,177	)
Net income	$	7,434		$	7,135

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 $13.8 million and $12.5 million for the three months ended March 31, 2007 and 2006, respectively.

• We charged HEP $0.5 million for three months ended March 31, 2007 and 2006 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 $2.3 million and $1.9 million for the three months ended March 31, 2007 and 2006, respectively, which we recorded as a reduction in expenses.

• We reimbursed HEP $0.1 million for the three months ended March 31, 2007 and 2006 for certain costs paid on our behalf.

• We received as regular distributions on our subordinated units, common units and general partner interest, $5.4 million and $4.8 million for the three months ended March 31, 2007 and 2006, respectively. Our distributions for the three months ended March 31, 2007 and 2006 included $0.4 million and $0.2 million, respectively, in incentive distributions with respect to our general partner interest.

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• We had a related party receivable from HEP of $3.4 million and $2.2 million at March 31, 2007 and December 31, 2006, respectively.

• We had accounts payable to HEP of $5.3 million and $5.7 million at March 31, 2007 and December 31, 2006, respectively.

• “Prepayments and other” includes $0.8 million and $0.2 million at March 31, 2007 and December 31, 2006, respectively, related to minimum payments under the HEP IPA which may be applied as credits against future billings from HEP if our shipments exceed the minimum volume commitments on the intermediate pipelines.

NOTE 4: Earnings Per Share

Basic earnings per share from continuing operations is calculated as income from continuing operations divided by the average number of shares of common stock outstanding. Diluted earnings per share from continuing operations assumes, when dilutive, the issuance of the net incremental shares from stock options, variable restricted shares and performance share units. The average number of shares of common stock outstanding 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 denominators of the basic and diluted per share computations for income from continuing operations:

	Three Months Ended
	March 31,
	2007		2006
	(In thousands, except per share data)
Income from continuing operations	$	67,542	$	31,160
Average number of shares of common stock outstanding		55,189		58,458
Effect of dilutive stock options, variable restricted shares and performance share units		1,129		1,570
Average number of shares of common stock outstanding assuming dilution		56,318		60,028
Basic earnings per share from continuing operations	$	1.22	$	0.53
Diluted earnings per share from continuing operations	$	1.20	$	0.52

NOTE 5: Stock-Based Compensation

On March 31, 2007 we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for those plans was $4.4 million and $3.7 million for the three months ended March 31, 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $1.5 million and $1.4 million for the three months ended March 31, 2007 and 2006, 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 March 31, 2007, 2,508,409 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.

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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.

A summary of option activity as of March 31, 2007, and changes during the three months ended March 31, 2007 is presented below:

						Weighted-Average
				Weighted-Average		Remaining		Aggregate Intrinsic
Options	Shares			Exercise Price		Contractual Term		Value ($000)
Outstanding at January 1, 2007		1,576,800		$	2.25
Exercised		(72,600	)		3.62
Forfeited or expired		—			—
Outstanding at March 31, 2007		1,504,200		$	2.18		2.9	$	85,914
Exercisable at March 31, 2007		1,504,200		$	2.18		2.9	$	85,914

The total intrinsic value of options exercised during the three months ended March 31, 2007 and 2006, was $3.6 million and $12.6 million, respectively.

At March 31, 2007 and December 31, 2006, all stock options granted were fully vested. The total fair value of shares vested during the three months ended March 31, 2006 was $0.3 million.

Cash received from option exercises under the stock option plans for the three months ended March 31, 2007 and 2006, was $0.3 million and $1.4 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $1.4 million and $4.9 million for the three months ended March 31, 2007 and 2006, respectively.

Restricted Stock

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

A summary of restricted stock grant activity and changes during the three months ended March 31, 2007 is presented below:

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				Weighted-Average
				Grant-Date Fair		Aggregate Intrinsic
Restricted Stock	Grants			Value		Value ($000)
Outstanding at January 1, 2007 (nonvested)		494,922		$	15.07
Vesting and transfer of ownership to recipients		(108,079	)		13.96
Granted		53,145			55.47
Forfeited		(2,150	)		16.94
Outstanding at March 31, 2007 (nonvested)		437,838		$	20.23	$	25,964

The total intrinsic value of restricted stock vested and transferred to recipients during the three months ended March 31, 2007 and 2006 was $6.4 million and $5.5 million, respectively. As of March 31, 2007, there was $4.9 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 1.3 years. The total fair value of shares vested during the three months ended March 31, 2007 and 2006 was $1.5 million and $1.0 million, respectively.

Performance Share Units

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

During the 2007 first quarter, we granted 42,813 performance share units with a fair value based on our grant date closing stock price of $55.47. These units are payable in stock and are subject to certain financial performance criteria.

The fair value of each performance share unit award subject to the financial performance criteria and payable in stock is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of March 31, 2007, estimated share payouts for outstanding nonvested performance share unit awards ranged from 100% to 200%.

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

The fair value of each performance share unit award payable in cash is computed quarterly using 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.

At March 31, 2007, the price of our stock was $59.30, the latest quarterly dividend was $0.10, and the risk-free rate was 4.88%. The inputs affecting the expected total return for us and the peer group are based on a capital asset pricing model utilizing information available at the measurement date. The monthly standard deviation of returns is based on the standard deviation of historical return information. The expected return and standard deviation are presented below:

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		Standard
Company	Expected Return on Equity	Deviation (Monthly)
Holly	12.1%	7.6%
Peer group	10.6% to 13.6%	6.5% to 11.0%

A summary of performance share units’ activity and changes during the three months ended March 31, 2007 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, 2007 (nonvested)		227,350			125,774			74,928			428,052
Vesting and payment of benefit to recipients		(145,900	)		(75,500	)		—			(221,400	)
Granted		—			—			42,813			42,813
Forfeited		—			(900	)		(528	)		(1,428	)
Outstanding at March 31, 2007 (nonvested)		81,450			49,374			117,213			248,037

For the three months ended March 31, 2007 we paid $15.5 million and issued 75,500 shares of our common stock having a fair value of $3.6 million related to vested performance share units. As of March 31, 2007, the cash liability associated with nonvested performance share units was $7.1 million and is recorded in “Accrued liabilities” in our consolidated balance sheets. Based on the weighted average fair value at March 31, 2007 of $63.45, there was $8.3 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 1.5 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.

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. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

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

	Available-for-Sale Securities
						Estimated
			Gross			Fair Value
			Unrealized			(Net Carrying
	Amortized Cost		Losses			Amount)
	(In thousands)
States and political subdivisions	$	125,937	$	(69	)	$	125,868
Equity securities		4,328		(978	)		3,350
Total marketable securities	$	130,265	$	(1,047	)	$	129,218

Interest income on our marketable debt securities for the three months ended March 31, 2007 and 2006 included $1.4 million and $2.0 million, respectively, of interest earned, $21,000 and $20,000, respectively, in realized losses and amortization of $0.3 million and $0.8 million, respectively, in net premiums paid related to our marketable debt securities. We had 53 and 115 sales and maturities during the three months ended March 31, 2007 and 2006, respectively, in which we received a total of $62.1 million and $154.7 million, respectively. The realized losses represent the difference between the purchase price, as amortized, and the market value on the maturity or sales date.

NOTE 7: Environmental

Consistent with our accounting policy for environmental remediation costs, we expensed $0.1 million and $2.3 million for the three months ended March 31, 2007 and 2006, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $7.5 million and $7.6 million at March 31, 2007 and December 31, 2006, respectively, of which $5.7 million and $6.1 million, respectively, were classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 8: Debt

Credit Facility

We have a $175.0 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 $225.0 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 March 31, 2007. At March 31, 2007, 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 March 31, 2007.

We made cash interest payments of $14,000 and $0.2 million for the three months ended March 31, 2007 and 2006, respectively.

NOTE 9: Income Taxes

The effective tax rate for continuing operations for the first quarter of 2007 was 33.9%, as compared to 33.2% for the first quarter of 2006.

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NOTE 10: 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 and per share amounts for all periods presented have been adjusted to reflect the split on a retrospective basis.

Common Stock Repurchases:Under our $300.0 million common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the three months ended March 31, 2007, we repurchased 545,439 shares at a cost of approximately $29.2 million (of which $0.6 million of the cash settlement was after March 31, 2007) or an average of $53.56 per share under this repurchase initiative. Since inception of this repurchase initiative in November 2005 through March 31, 2007, we have repurchased 5,991,646 shares at a cost of approximately $236.2 million or an average of $39.42 per share.

During the three months ended March 31, 2007, we repurchased at current market price from certain officers and key employees 80,704 shares of our common stock at a cost of approximately $4.2 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

NOTE 11: Other Comprehensive Income

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

				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
For the three months ended March 31, 2007
Retirement medical obligation adjustment	$	(2,792	)	$	(1,086	)	$	(1,706	)
Unrealized gain on available-for-sale securities		357			137			220
Other comprehensive loss	$	(2,435	)	$	(949	)	$	(1,486	)
For the three months ended March 31, 2006
Unrealized gain on available-for-sale securities	$	209		$	81		$	128
Other comprehensive income	$	209		$	81		$	128

The temporary unrealized 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 include:

	March 31,			December 31,
	2007			2006
	(In thousands)
Pension obligation adjustment	$	(1,115	)	$	(1,115	)
Unrealized loss on available-for-sale securities		(636	)		(856	)
Adjustment to initially apply adoption of SFAS No. 158, net of income tax effect of $7,063		(11,093	)		(9,387	)
Accumulated other comprehensive loss	$	(12,844	)	$	(11,358	)

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NOTE 12: Retirement Plan

We have a non-contributory defined benefit retirement plan that covers most of our employees who were hired prior to January 1, 2007. Our policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

The net periodic pension expense consisted of the following components:

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Service cost	$	1,589		$	1,048
Interest cost		1,404			1,014
Expected return on assets		(1,566	)		(856	)
Amortization of prior service cost		63			65
Amortization of net loss		284			320
Net periodic benefit cost	$	1,774		$	1,591

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2007 and 2006 net periodic benefit cost. We expect to contribute between zero and $10.0 million to the retirement plan during 2007. No contributions were made during the three months ended March 31, 2007.

NOTE 13: 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 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 $3.0 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

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to repay more than the amount now asserted in SFPP’s most recent computations (approximately $3.0 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.

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 Refinery and previously-owned Montana Refinery. 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 $10.0 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.

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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 on 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 collectively known as the “Navajo Refinery”) and Woods Cross, Utah (the “Woods Cross Refinery”). Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At March 31, 2007, we also owned a 45% interest in Holly Energy Partners, L.P. (“HEP”), which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States. Our sales and other revenues for the three months ended March 31, 2007 were $925.9 million and our net income for the three months ended March 31, 2007 was $67.5 million. Our sales and other revenues and net income for the three months ended March 31, 2006 were $791.6 million and $46.8 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the three months ended March 31, 2007 were $829.3 million, an increase from $749.6 million for the three months ended March 31, 2006.

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. We have presented in discontinued operations the results of operations and a gain of $14.3 million on the sale.

Under our $300.0 million common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the three months ended March 31, 2007, we repurchased 545,439 shares at a cost of approximately $29.2 million (of which $0.6 million of the cash settlement was after March 31, 2007) or an average of $53.56 per share under this repurchase initiative. Since inception of this repurchase initiative in November 2005 through March 31, 2007, we have repurchased 5,991,646 shares at a cost of approximately $236.2 million or an average of $39.42 per share.

-22-

RESULTS OF OPERATIONS

Financial Data (Unaudited)

	Three Months Ended
	March 31,						Change from 2006
	2007			2006			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	925,867		$	791,594		$	134,273			17.0	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		751,714			675,485			76,229			11.3
Operating expenses (exclusive of depreciation, depletion and amortization)		50,129			52,467			(2,338	)		(4.5	)
General and administrative expenses (exclusive of depreciation, depletion and amortization)		15,847			13,516			2,331			17.2
Depreciation, depletion and amortization		11,451			8,024			3,427			42.7
Exploration expenses, including dry holes		152			127			25			19.7
Total operating costs and expenses		829,293			749,619			79,674			10.6
Income from operations		96,574			41,975			54,599			130.1
Other income (expense):
Equity in earnings of HEP		3,346			3,212			134			4.2
Interest income		2,560			1,735			825			47.6
Interest expense		(252	)		(275	)		23			(8.4	)
		5,654			4,672			982			21.0
Income from continuing operations before income taxes		102,228			46,647			55,581			119.2
Income tax provision		34,686			15,487			19,199			124.0
Income from continuing operations		67,542			31,160			36,382			116.8
Income from discontinued operations, net of taxes		—			15,644			(15,644	)		(100.0	)
Net income	$	67,542		$	46,804		$	20,738			44.3	%
Basic earnings per share:
Continuing operations	$	1.22		$	0.53		$	0.69			130.2	%
Discontinued operations		—			0.27			(0.27	)		(100.0	)
Net income	$	1.22		$	0.80		$	0.42			52.5	%
Diluted earnings per share:
Continuing operations	$	1.20		$	0.52		$	0.68			130.8	%
Discontinued operations		—			0.26			(0.26	)		(100.0	)
Net income	$	1.20		$	0.78		$	0.42			53.8	%
Cash dividends declared per common share	$	0.10		$	0.05		$	0.05			100.0	%
Average number of common shares outstanding:
Basic		55,189			58,458			(3,269	)		(5.6	)%
Diluted		56,318			60,028			(3,710	)		(6.2	)%

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Balance Sheet Data (Unaudited)

	March 31,		December 31,
	2007		2006
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	280,397	$	255,953
Working capital	$	257,283	$	240,181
Total assets	$	1,247,042	$	1,237,869
Stockholders’ equity	$	499,229	$	466,094

Other Financial Data (Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Net cash provided by (used for) operating activities	$	86,301		$	(18,340	)
Net cash provided by (used for) investing activities	$	(53,775	)	$	119,888
Net cash used for financing activities	$	(35,464	)	$	(56,001	)
Capital expenditures	$	26,750		$	32,235
EBITDA from continuing operations (1)	$	111,371		$	53,211

(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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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 consolidated 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
	March 31,
	2007			2006
Navajo Refinery
Crude charge (BPD)(1)		76,820			72,520
Refinery production (BPD)(2)		86,100			81,110
Sales of produced refined products (BPD)		85,390			79,760
Sales of refined products (BPD)(3)		96,360			90,780
Refinery utilization (4)		92.6	%		96.7	%
Average per produced barrel (5)
Net sales	$	75.58		$	75.54
Cost of products(6)		59.04			62.85
Refinery gross margin		16.54			12.69
Refinery operating expenses (7)		4.18			4.39
Net operating margin	$	12.36		$	8.30
Feedstocks:
Sour crude oil		75	%		82	%
Sweet crude oil		10	%		5	%
Other feedstocks and blends		15	%		13	%
Total		100	%		100	%
Sales of produced refined products:
Gasolines		61	%		62	%
Diesel fuels		27	%		26	%
Jet fuels		3	%		5	%
Fuel oil		3	%		—	%
Asphalt		3	%		1	%
LPG and other		3	%		6	%
Total		100	%		100	%

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	Three Months Ended
	March 31,
	2007			2006
Woods Cross Refinery
Crude charge (BPD)(1)		24,650			22,730
Refinery production (BPD)(2)		26,570			24,010
Sales of produced refined products (BPD)		28,120			23,290
Sales of refined products (BPD)(3)		28,550			24,490
Refinery utilization(4)		94.8	%		87.4	%
Average per produced barrel(5)
Net sales	$	71.61		$	69.64
Cost of products(6)		56.87			60.19
Refinery gross margin		14.74			9.45
Refinery operating expenses(7)		4.76			5.73
Net operating margin	$	9.98		$	3.72
Feedstocks:
Sour crude oil		—	%		6	%
Sweet crude oil		91	%		86	%
Other feedstocks and blends		9	%		8	%
Total		100	%		100	%
Sales of produced refined products:
Gasolines		63	%		61	%
Diesel fuels		25	%		26	%
Jet fuels		2	%		3	%
Fuel oil		6	%		6	%
LPG and other		4	%		4	%
Total		100	%		100	%
Consolidated
Crude charge (BPD)(1)		101,470			95,250
Refinery production (BPD)(2)		112,670			105,120
Sales of produced refined products (BPD)		113,510			103,050
Sales of refined products (BPD)(3)		124,910			115,270
Refinery utilization (4)		93.1	%		94.3	%
Average per produced barrel (5)
Net sales	$	74.59		$	74.21
Cost of products (6)		58.50			62.25
Refinery gross margin		16.09			11.96
Refinery operating expenses (7)		4.32			4.70
Net operating margin	$	11.77		$	7.26
Feedstocks:
Sour crude oil		58	%		64	%
Sweet crude oil		28	%		24	%
Other feedstocks and blends		14	%		12	%
Total		100	%		100	%

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Sales of produced refined products:
Gasolines	61	%	62	%
Diesel fuels	27	%	26	%
Jet fuels	3	%	4	%
Fuel oil	4	%	2	%
Asphalt	2	%	1	%
LPG and other	3	%	5	%
Total	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 amount for produced refined products sold, which is a non-GAAP measure. 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.

Results of Operations — Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

Summary

Income from continuing operations was $67.5 million ($1.22 per basic and $1.20 per diluted share) for the three months ended March 31, 2007, compared to income from continuing operations of $31.2 million ($.53 per basic and $.52 per diluted share) for the three months ended March 31, 2006. Income from continuing operations increased $36.4 million for the first quarter of 2007, an increase of 117%, as compared to the first quarter of 2006 principally due to improved refined product margins experienced in the current year’s first quarter and an increase in volume of produced refined products sold. These favorable factors were partially offset by the effects of higher depreciation, depletion and amortization costs and general and administrative expenses incurred in the first quarter of 2007, partially offset by a decrease in operating expenses. Overall refinery production levels from continuing operations increased by 7% for the first quarter of 2007 as compared to the same period in 2006 primarily due to increased production following the completion of our Navajo Refinery’s 8,000 BPSD capacity expansion in the latter half of 2006, partially offset by the effects of unplanned downtime of certain units at our Navajo Refinery in the first quarter of 2007. Overall refinery gross margins from continuing operations were $16.09 per produced barrel for the first quarter of 2007 compared to refinery gross margins from continuing operations of $11.96 per produced barrel for the first quarter of 2006.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 17% from $791.6 million for the three months ended March 31, 2006 to $925.9 million for the three months ended March 31, 2007 due principally to an increase in volumes of produced refined products sold. The total volume of refined products sold increased 8% for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006. Additionally, the first quarter of 2007 included $61.7 million of revenues attributable to certain direct crude oil sales that were previously netted against the corresponding purchases and presented in cost of products sold prior to our adoption of new accounting guidance effective April 1, 2006.

Cost of Products Sold

Cost of products sold increased 11% from $675.5 million in the first quarter of 2006 to $751.7 million in the first quarter of 2007 due principally to an increase in volumes of produced refined products sold and the inclusion of $61.9 million of costs attributable to direct crude oil sales, partially offset by a per unit decrease in cost of produced refined products sold. The total volume of refined products sold increased 8% for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006. The average price we paid per barrel of crude oil and

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feedstocks purchased and the transportation costs of moving the finished products to the market place decreased 6% from $62.25 in the first quarter of 2006 to $58.50 in the first quarter of 2007.

Gross Refinery Margins

Gross refining margin per produced barrel increased 35% from $11.96 in the first quarter of 2006 to $16.09 in the first quarter of 2007. Gross refinery margin does not include the effects of depreciation, depletion and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part 1 of this Form 10-Q for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.

Operating Expenses

Operating expenses, exclusive of depreciation, depletion and amortization, decreased 5% from $52.5 million in the first quarter of 2006 to $50.1 million in the first quarter of 2007 due principally to lower utility and environmental costs, partially offset by higher refinery maintenance costs.

General and Administrative Expenses

General and administrative expenses increased 17% from $13.5 million in the first quarter of 2006 to $15.8 million in the first quarter of 2007 due primarily to increased equity-based incentive compensation expense which is affected by increases in our stock price.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 43% from $8.0 million in the first quarter of 2006 to $11.5 million in the first quarter of 2007 due to capitalized refinery improvement projects in 2006.

Equity in Earnings of HEP

Our equity in earnings of HEP was $3.3 million for the three months ended March 31, 2007 as compared to $3.2 million for the three months ended March 31, 2006.

Interest Income

Interest income for the first quarter of 2007 was $2.6 million compared to $1.7 million for the first quarter of 2006. The increase in interest income was principally due to a higher interest rate environment.

Interest Expense

Interest expense was $0.3 million for the first quarter of 2007 and 2006.

Income Taxes

Income taxes increased 124% from $15.5 million for the first quarter of 2006 to $34.7 million for the first quarter of 2007 due to significantly higher pre-tax earnings during the 2007 first quarter as compared to the 2006 first quarter. The effective tax rate for the first quarter of 2007 was 33.9%, as compared to 33.2% for the first quarter of 2006. The slight increase in our effective tax rate was principally due to an increase in our pre-tax income for the first quarter of 2007 as compared to the first quarter of 2006.

Discontinued Operations

We had no income from discontinued operations for the first quarter of 2007 as our Montana Refinery operations have ceased. Income from discontinued operations was $15.6 million for the first quarter of 2006 which included the gain on the sale of the Montana Refinery of $14.3 million, net of $8.4 million in income taxes. The Montana Refinery generated operating income of $1.3 million for the first quarter of 2006.

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LIQUIDITY AND CAPITAL RESOURCES

We consider all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued by financial institutions or government entities with strong credit standings. We also invest available cash in highly-rated marketable debt securities primarily issued by government entities that have maturities greater than three months. These securities include investments in variable rate demand notes (“VRDN”) and auction rate securities (“ARS”). Although VRDN and ARS may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. Rates on ARS are reset through a Dutch auction process at intervals between 35 and 90 days, depending on the terms of the security. VRDN and ARS may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of March 31, 2007, we had cash and cash equivalents of $151.2 million, marketable securities with maturities under one year of $119.5 million and marketable securities with maturities greater than one year, but less than two years, of $9.7 million.

Cash and cash equivalents decreased by $2.9 million during the three months ended March 31, 2007. The combined cash used for investing activities of $53.8 million and for financing activities of $35.4 million exceeded cash provided by operating activities of $86.3 million. Working capital increased during the three months ended March 31, 2007 by $17.1 million.

We have a $175.0 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 $225.0 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 March 31, 2007, 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 March 31, 2007.

Under our $300.0 million common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the three months ended March 31, 2007, we repurchased under this repurchase initiative 545,439 shares at a cost of approximately $29.2 million (of which $0.6 million of the cash settlement was after March 31, 2007) or an average of $53.56 per share. Since inception of this repurchase initiative in November 2005 through March 31, 2007, we have repurchased 5,991,646 shares at a cost of approximately $236.2 million or an average of $39.42 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 projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and the repurchase of additional common stock under our common stock repurchase program. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

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Cash Flows — Operating Activities

Net cash flows provided by operating activities were $86.3 million for the three months ended March 31, 2007 compared to cash used of $18.3 million for the three months ended March 31, 2006, an increase of $104.6 million. Net income for the three months ended March 31, 2007 was $67.5 million, an increase of $20.7 million from net income of $46.8 million for the three months ended March 31, 2006. Additionally, the non-cash adjustments to net income of depreciation and amortization, deferred taxes, equity-based compensation and gain on an asset sale resulted in an increase of cash flows of $27.7 million for the 2007 first quarter over the 2006 first quarter. Distributions in excess of equity in earnings of HEP increased by $0.5 million for the three months ended March 31, 2007 from the three months ended March 31, 2006. Changes in working capital items increased cash flows by $4.4 million during the three months ended March 31, 2007, as compared to a decrease of $48.6 million for the three months ended March 31, 2006, resulting mainly from an increase in inventories during the first quarter of 2006. For the first three months of 2007, inventories increased by only $15.8 million, as compared to an increase of $53.4 million for the first three months of 2006. Also impacting the working capital items was a $23.7 decrease in net assets of discontinued operations during the first quarter of 2006, due to the sale of the Montana Refinery assets on March 31, 2006. Additionally, in the first three months of 2007, turnaround expenditures amounted to $0.2 million, as opposed to $4.0 million in the first three months of 2006.

Cash Flows — Investing Activities and Capital Projects

Net cash flows used for investing activities were $53.8 million for the three months ended March 31, 2007, as compared to net cash flows provided by investing activities of $119.9 million for the three months ended March 31, 2006, a net change of $173.7 million. Cash expenditures for property, plant and equipment for the first three months of 2007 totaled $26.8 million as compared to $32.2 million for the same period of 2006. On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery were $48.9 million, net of transaction fees and expenses. We also invested $89.2 million in marketable securities and received proceeds of $62.1 million from the sale or maturity of marketable securities during the three months ended March 31, 2007. For the three months ended March 31, 2006, we invested $51.4 million in marketable securities and received proceeds of $154.7 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 special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total capital budget for 2007 is approximately $42.1 million, not including the capital projects approved in prior years, and our expansion and feedstock flexibility projects at the Navajo and Woods Cross refineries, as described below. The 2007 capital budget is comprised of $24.7 million for refining improvement projects for the Navajo Refinery, $9.7 million for projects at the Woods Cross Refinery, $3.2 million for transportation projects, $0.5 million for marketing-related projects, $2.8 million for asphalt plant projects and $1.2 million for information technology and other miscellaneous projects.

As announced in December 2006, we will be installing at the Navajo Refinery a new 15,000 BPD hydrocracker and a new 28 mmscf hydrogen plant at a budgeted cost of approximately $125.0 million. The addition of these units is expected to increase liquid volume recovery, increase the refinery’s capacity to process outside feedstocks, and increase yields of high-valued products, as well as enabling the refinery to meet the EPA’s new low sulfur gasoline specifications. The hydrocracker and hydrogen plant projects will provide improved heavy crude oil processing flexibility.

As announced in February 2007, we will be revamping an existing crude unit at the Navajo Refinery which will increase crude capacity at the Navajo Refinery to approximately 100,000 BPD. Additionally, our Board of Directors

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has approved a revamp of the refinery’s second crude unit and a new solvent de-asphalter unit. The newly approved components combined with the components approved in December bring the total budgeted amount for this expansion and heavy crude oil processing project to $225.0 million. It is currently anticipated that the expansion portion of the overall project consisting of the initial crude unit revamp, the new hydrocracker and the new hydrogen plant will be completed and operational by the fourth quarter of 2008. The completion of the heavy crude oil processing portion of the overall project, including the second crude unit revamp and the installation of the new solvent de-asphalter, will be targeted to coincide with development of future pipeline access to the Navajo Refinery for heavy Canadian crude oil and other foreign heavy crude oils transported from the Cushing, Oklahoma area. We plan to explore with HEP the most economical manner to obtain this needed pipeline access.

Also at the Navajo Refinery, a project to install an additional 100 ton per day sulfur recovery unit included in the 2006 capital budget is currently underway at an estimated cost of $26.0 million. Approximately $2.0 million was spent on this project in 2006. This new sulfur recovery unit will permit Navajo to process 100% sour crude and is planned for start-up in the third quarter of 2008.

It is anticipated that these projects will also enable the Navajo Refinery to comply with LSG specifications required by the end of 2010.

Also as announced in December 2006, we will be adding at the Woods Cross Refinery a new 15,000 BPD hydrocracker along with sulfur recovery and desalting equipment. The budgeted cost of these additions is approximately $100.0 million. These additions will expand the Woods Cross Refinery’s crude processing capabilities from 26,000 BPD to 31,000 BPD while enabling the refinery to process up to 10,000 BPD of high-value low-priced black wax crude oil and up to 5,000 BPD of low-priced heavy Canadian crude oils. The Woods Cross Refinery expansion project as approved involves a higher capital investment than had originally been estimated, principally because of the substitution of a complex hydrocracker in place of certain desulfurization and expanded bottoms-processing modifications that had been included in preliminary planning. The substitution of the complex hydrocracker is expected to provide increased capabilities to process significantly more black wax crude oils, which have recently been priced at substantial discounts to West Texas Intermediate crude oil, while yielding substantially higher value products than the discounted heavy Canadian crudes that were a more significant part of the original plan. These additions would also increase the refinery’s capacity to process low-cost feedstocks and provide the necessary infrastructure for future expansions of crude oil refining capacity at the Woods Cross Refinery. The approved projects for the Woods Cross Refinery are expected to be completed during the fourth quarter of 2008.

In 2007 we expect to expend a total of approximately $179.0 million on currently approved capital projects, which amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved capital projects.

To fully take advantage of the economics on the Woods Cross expansion project, additional crude pipeline capacity will be required to move Canadian crude to the Woods Cross Refinery. In February 2007, HEP entered into a letter of intent with Plains All American Pipeline, L.P. (“Plains”) under which HEP will own a 25% interest in a new 95 mile intrastate pipeline system, now being constructed by Plains, capable of shipping up to 120,000 BPD of crude oil into the Salt Lake City area.

Additionally, we are also working with HEP to evaluate construction of a refined products pipeline from Salt Lake City to Las Vegas. The current estimated cost of this pipeline is expected to be approximately $235.0 million, and the total cost of the project including terminals is expected to be approximately $300.0 million.

In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act 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 derive from planned capital expenditures associated with the 2004 Act will result in a reduction in our income tax expense of approximately $15.0 million in 2007, representing the difference between the value of allowed credits under the 2004 Act as compared to the value of depreciating the investments. In August 2005, the Energy Policy Act of 2005

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(“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 expansion assets are placed in service. We believe the capacity expansions under the new Navajo and Woods Cross capital projects will qualify for this deduction.

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

Cash Flows — Financing Activities

Net cash flows used for financing activities were $35.5 million for the three months ended March 31, 2007, as compared to $56.0 million for the three months ended March 31, 2006, a decrease of $20.5 million. Under our common stock repurchase program, we purchased treasury stock of $35.8 million during the three months ended March 31, 2007 and $59.3 million during the three months ended March 31, 2006. Our treasury stock purchases for the three months ended March 31, 2007 and 2006, include $4.2 million and $1.4 million, respectively, in common stock purchased from certain executives, at market prices, 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 three months ended March 31, 2007, we paid $4.5 million in dividends, received $0.3 million for common stock issued upon exercise of stock options, and recognized $4.6 million in excess tax benefits on our equity based compensation. During the three months ended March 31, 2006, we paid $3.0 million in dividends, received $1.4 million for common stock issued upon exercise of stock options and recognized $4.8 million in excess tax benefits on our equity based compensation.

Contractual Obligations and Commitments

During the three months ended March 31, 2007, there were no significant changes to our contractual obligations for our agreements with HEP and operating leases, other than the regular payments made under the existing pipelines and terminals agreements with HEP and operating leases.

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 $38.5 million. 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 $12.4 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 $15.0 million relates solely to the intermediate pipelines.

HEP financed the Alon transaction through a private offering of $150.0 million principal amount of HEP Senior Notes. HEP increased these notes to $185.0 million as part of the purchase of our intermediate pipelines. The $185.0 million HEP Senior Notes are not recorded on our accompanying consolidated balance sheets at March 31, 2007 or December 31, 2006. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s general partner to the extent it makes any payment in satisfaction of $35.0 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 CAA 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

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put into a final written agreement, includes proposed obligations for us to make specified additional capital investments expected to total up to approximately $10.0 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 Condition and Results of Operations — Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2006. 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 2007.

We use the last-in, first-out (“LIFO”) method of valuing inventory. Under the LIFO method, an actual valuation of inventory can only be made 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 are subject to the final year-end LIFO inventory valuation.

New Accounting Pronouncements

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No 115. SFAS No. 159, which amends SFAS No. 115, allows certain financial assets and liabilities to be recognized, at a company’s election, at fair market value, with any gains or losses for the period recorded in the statement of income. SFAS No. 159 includes available-for-sale securities in the assets eligible for this treatment. Currently, we record the gains or losses for the period as a component of comprehensive income and in the equity section of the balance sheet. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years. While we are currently evaluating the provisions of SFAS No. 159, we do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.

Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and

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transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits.

We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.

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

SFAS No. 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We do not anticipate that the adoption of this interpretation will have a material effect on our financial condition, results of operations and cash flows.

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.

We periodically utilize petroleum commodity futures contracts to reduce our exposure to price fluctuations associated with crude oil and refined products. Such contracts historically have been used principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. We have not had any open positions since 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 March 31, 2007, 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 March 31, 2007. We invest a substantial portion of available cash in investment grade, highly liquid investments with maturities of three months or less and hence the interest rate market risk implicit in these cash investments is low. We also invest the remainder of

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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 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.

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

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Income from continuing operations	$	67,542		$	31,160
Add provision for income tax		34,686			15,487
Add interest expense		252			275
Subtract interest income		(2,560	)		(1,735	)
Add depreciation, depletion and amortization		11,451			8,024
EBITDA from continuing operations	$	111,371		$	53,211

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

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

We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation, depletion and amortization. Each of these component performance measures can be reconciled directly to our Consolidated 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
	March 31,
	2007		2006
Average per produced barrel:
Navajo Refinery
Net sales	$	75.58	$	75.54
Less cost of products		59.04		62.85
Refinery gross margin	$	16.54	$	12.69
Woods Cross Refinery
Net sales	$	71.61	$	69.64
Less cost of products		56.87		60.19
Refinery gross margin	$	14.74	$	9.45
Consolidated
Net sales	$	74.59	$	74.21
Less cost of products		58.50		62.25
Refinery gross margin	$	16.09	$	11.96

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

	Three Months Ended
	March 31,
	2007		2006
Average per produced barrel:
Navajo Refinery
Refinery gross margin	$	16.54	$	12.69
Less refinery operating expenses		4.18		4.39
Net operating margin	$	12.36	$	8.30
Woods Cross Refinery
Refinery gross margin	$	14.74	$	9.45
Less refinery operating expenses		4.76		5.73
Net operating margin	$	9.98	$	3.72
Consolidated
Refinery gross margin	$	16.09	$	11.96
Less refinery operating expenses		4.32		4.70
Net operating margin	$	11.77	$	7.26

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.

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

	Three Months Ended
	March 31,
	2007			2006
Navajo Refinery
Average sales price per produced barrel sold	$	75.58		$	75.54
Times sales of produced refined products sold (BPD)		85,390			79,760
Times number of days in period		90			90
Refined product sales from produced products sold	$	580,840		$	542,256
Woods Cross Refinery
Average sales price per produced barrel sold	$	71.61		$	69.64
Times sales of produced refined products sold (BPD)		28,120			23,290
Times number of days in period		90			90
Refined product sales from produced products sold	$	181,231		$	145,972
Sum of refined products sales from produced products sold from our two refineries(4)	$	762,071		$	688,228
Add refined product sales from purchased products and rounding(1)		79,225			84,542
Total refined products sales		841,296			772,770
Add direct sales of excess crude oil(2)		61,680			—
Add other refining segment revenue(3)		22,606			18,578
Total refining segment revenue		925,582			791,348
Add corporate and other revenues		391			381
Subtract consolidations and eliminations		(106	)		(135	)
Sales and other revenues	$	925,867		$	791,594

(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 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
	March 31,
	2007		2006
Average sales price per produced barrel sold	$	74.59	$	74.21
Times sales of produced refined products sold (BPD)		113,510		103,050
Times number of days in period		90		90
Refined product sales from produced products sold	$	762,071	$	688,228

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

	Three Months Ended
	March 31,
	2007		2006
Navajo Refinery
Average cost of products per produced barrel sold	$	59.04	$	62.85
Times sales of produced refined products sold (BPD)		85,390		79,760
Times number of days in period		90		90
Cost of products for produced products sold	$	453,728	$	451,162

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	Three Months Ended
	March 31,
	2007			2006
Woods Cross Refinery
Average cost of products per produced barrel sold	$	56.87		$	60.19
Times sales of produced refined products sold (BPD)		28,120			23,290
Times number of days in period		90			90
Cost of products for produced products sold	$	143,927		$	126,164
Sum of cost of products for produced products sold from our two refineries(4)	$	597,655		$	577,326
Add refined product costs from purchased products sold and rounding(1)		82,044			85,582
Total refined cost of products sold		679,699			662,908
Add crude oil cost of direct sales of excess crude oil(2)		61,852			—
Add other refining segment cost of products sold(3)		10,269			12,712
Total refining segment cost of products sold		751,820			675,620
Subtract consolidations and eliminations		(106	)		(135	)
Costs of products sold (exclusive of depreciation, depletion and amortization)	$	751,714		$	675,485

(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 cost of products sold includes the cost of products for NK Asphalt Partners and costs attributable to 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
	March 31,
	2007		2006
Average cost of products per produced barrel sold	$	58.50	$	62.25
Times sales of produced refined products sold (BPD)		113,510		103,050
Times number of days in period		90		90
Cost of products for produced products sold	$	597,655	$	577,326

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

	Three Months Ended
	March 31,
	2007		2006
Navajo Refinery
Average refinery operating expenses per produced barrel sold	$	4.18	$	4.39
Times sales of produced refined products sold (BPD)		85,390		79,760
Times number of days in period		90		90
Refinery operating expenses for produced products sold	$	32,124	$	31,513
Woods Cross Refinery
Average refinery operating expenses per produced barrel sold	$	4.76	$	5.73
Times sales of produced refined products sold (BPD)		28,120		23,290
Times number of days in period		90		90
Refinery operating expenses for produced products sold	$	12,047	$	12,011

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Sum of refinery operating expenses per produced products sold from our two refineries(2)	$	44,171	$	43,524
Add other refining segment operating expenses and rounding(1)		5,947		8,909
Total refining segment operating expenses		50,118		52,433
Add corporate and other costs		11		34
Operating expenses (exclusive of depreciation, depletion and amortization)	$	50,129	$	52,467

(1)	Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt Partners.
(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
	March 31,
	2007		2006
Average refinery operating expenses per produced barrel sold	$	4.32	$	4.70
Times sales of produced refined products sold (BPD)		113,510		103,050
Times number of days in period		90		90
Refinery operating expenses for produced products sold	$	44,171	$	43,524

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

	Three Months Ended
	March 31,
	2007			2006
Navajo Refinery
Net operating margin per barrel	$	12.36		$	8.30
Add average refinery operating expenses per produced barrel		4.18			4.39
Refinery gross margin per barrel		16.54			12.69
Add average cost of products per produced barrel sold		59.04			62.85
Average sales price per produced barrel sold	$	75.58		$	75.54
Times sales of produced refined products sold (BPD)		85,390			79,760
Times number of days in period		90			90
Refined products sales from produced products sold	$	580,840		$	542,256
Woods Cross Refinery
Net operating margin per barrel	$	9.98		$	3.72
Add average refinery operating expenses per produced barrel		4.76			5.73
Refinery gross margin per barrel		14.74			9.45
Add average cost of products per produced barrel sold		56.87			60.19
Average sales price per produced barrel sold	$	71.61		$	69.64
Times sales of produced refined products sold (BPD)		28,120			23,290
Times number of days in period		90			90
Refined products sales from produced products sold	$	181,231		$	145,972
Sum of refined products sales from produced products sold from our two refineries(4)	$	762,071		$	688,228
Add refined product sales from purchased products and rounding(1)		79,225			84,542
Total refined products sales		841,296			772,770
Add direct sales of excess crude oil(2)		61,680			—
Add other refining segment revenue(3)		22,606			18,578
Total refining segment revenue		925,582			791,348
Add corporate and other revenues		391			381
Subtract consolidations and eliminations		(106	)		(135	)
Sales and other revenues	$	925,867		$	791,594

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

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(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 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
	March 31,
	2007		2006
Net operating margin per barrel	$	11.77	$	7.26
Add average refinery operating expenses per produced barrel		4.32		4.70
Refinery gross margin per barrel		16.09		11.96
Add average cost of products per produced barrel sold		58.50		62.25
Average sales price per produced barrel sold	$	74.59	$	74.21
Times sales of produced refined products sold (BPD)		113,510		103,050
Times number of days in period		90		90
Refined product sales from produced products sold	$	762,071	$	688,228

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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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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 Federal Energy Regulatory Commission (“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 $3.0 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 $3.0 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 $299.0 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 that have also been 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. In August and September 2006, three judges of the United States Court of Federal Claims issued rulings adverse to three other refining companies on issues that are also involved in our case. The refining companies that received these adverse rulings filed appeals of the adverse rulings to the United States Court of Appeals for the Federal Circuit in the fall of 2006. At the date of this report, it is not possible to predict the outcome of further proceedings with respect to 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 Refinery and previously-owned Montana Refinery. The tentative

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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 $10.0 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.

Our Navajo Refining Company subsidiary is named as a defendant, along with approximately 40 other companies involved in oil refining and marketing and related businesses, in a lawsuit originally filed in May 2006 by the State of New Mexico in the U.S. District Court for the District of New Mexico. The lawsuit, as amended in October 2006 through the filing of a second amended complaint in the U.S. District Court for the Southern District of New York under multidistrict procedures, alleges that the defendants are liable for contaminating the waters of New Mexico through producing and/or supplying 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 second amended complaint also contains a claim, which is asserted in the complaint only against certain other defendants but which appears to be similar to a claim that has been threatened in a mailing to Navajo by law firms representing the plaintiff in this case, alleging violations of certain provisions of the Toxic Substances Control Act. The lawsuit 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. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

On December 6, 2006, the Montana Department of Environmental Quality (“MDEQ”) filed in state district court in Great Falls, Montana a Complaint and Application for Preliminary Injunction (the “Complaint”) naming as defendants Montana Refining Company (“MRC”), our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser on March 31, 2006, and the unrelated company that purchased the refinery from MRC. The MDEQ asserts in the Complaint that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The Complaint seeks penalties under applicable law of up to $10,000 per violation and an order enjoining MRC and the current owner of the refinery from further violations. While we do not agree with a number of the violations asserted in the Complaint, we and the current owner of the Great Falls refinery have been in negotiations with the MDEQ both before and after the filing of the Complaint to attempt to settle the issues raised on a compromise basis. At the date of this report, 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 either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.

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

     (c) Common Stock Repurchases Made in the Quarter

Under our $300 million common stock repurchase program (announced in November 2005 and increased from $200 million to $300 million in October 2006), 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 repurchases made under this program during the first quarter of 2007.

							Maximum Dollar
					Total Number of		Value of Shares Yet
					Shares Purchased as		to be Purchased as
	Total Number of		Average price Paid		Part of $300 Million		Part of the $300
Period	Shares Purchased		Per Share		Program		Million Program
January 2007		260,507	$	49.94		260,507	$	80,021,206
February 2007		—	$	—		—	$	80,021,206
March 2007		284,932	$	56.87		284,932	$	63,818,189
Total for January to March 2007		545,439	$	53.56		545,439

The total shares purchased during the first quarter of 2007 reflected herein include 10,075 shares at a total cost of $0.6 million that were not settled until April 2007, and therefore are not included on our cash flow statement for the three months ended March 31, 2007.

Additionally, during the three months ended March 31, 2007, we repurchased at current market price from certain executives 80,704 shares of our common stock at a cost of approximately $4.2 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.

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Item 6.Exhibits

     (a) Exhibits

10.1*+	Agreement Concerning Payment of Benefits Under Holly Corporation Retirement Restoration Plan, effective April 1, 2007, between Jack P. Reid and Holly Corporation
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.

*	Constitutes management contracts or compensatory plans or arrangements.
+	Filed herewith.

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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: May 8, 2007	/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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