Edgar Filing: HOLLY CORP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2008


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

For the transition period from to

Commission File Number 1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		75-1056913

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

100 Crescent Court, Suite 1600
Dallas, Texas		75201-6915

(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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

49,607,009 shares of Common Stock, par value $.01 per share, were outstanding on July 31, 2008.

HOLLY CORPORATION
INDEX


	Page
PART I. FINANCIAL INFORMATION

Forward-Looking Statements		3

Definitions		4

Item 1. Financial Statements

Consolidated Balance Sheets June 30, 2008 (Unaudited) and December 31, 2007		6

Consolidated Statements of Income (Unaudited) Three and Six Months Ended June 30, 2008 and 2007		7

Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2008 and 2007		8

Consolidated Statements of Comprehensive Income (Unaudited) Three and Six Months Ended June 30, 2008 and 2007		9

Notes to Consolidated Financial Statements (Unaudited)		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25

Item 3. Quantitative and Qualitative Disclosures About Market Risk		43

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles		43

Item 4. Controls and Procedures		49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		51

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

Item 6. Exhibits		52

Signatures		53
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. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we”, “our”, “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions. Our consolidated financial statements contain certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

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 “Risk Management” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I and those in Item 1 “Legal Proceedings” in Part II, are forward-looking statements. These statements are based on management’s beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

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

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

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

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

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

	•		effects of governmental regulations and policies;

	•		the availability and cost of our financing;

	•		the effectiveness of our capital investments and marketing strategies;

	•		our efficiency in carrying out construction projects;

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

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

	•		general economic conditions; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation in conjunction with the forward-looking statements included in this Form 10-Q that are referred to above. This summary discussion should be read in conjunction with the discussion of risk factors and other cautionary statements under the heading “Risk Factors” included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007 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 heading “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 to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is the primary 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.

“MMSCFD” means one million standard cubic feet per day.

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

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

“PPM” means parts-per-million.

“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)


	June 30,			December 31,
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	154,771		$	94,369
Marketable securities		116,310			158,233

Accounts receivable: Product and transportation		263,025			242,392
Crude oil resales		578,502			366,226
Related party receivable		—			6,151

		841,527			614,769

Inventories: Crude oil and refined products		143,271			118,308
Materials and supplies		16,119			22,322

		159,390			140,630

Income taxes receivable		10,033			16,356
Prepayments and other		9,825			10,264

Total current assets		1,291,856			1,034,621

Properties, plants and equipment, at cost		1,326,085			802,820
Less accumulated depreciation, depletion and amortization		(279,352	)		(271,970	)

		1,046,733			530,850

Marketable securities (long-term)		26,831			77,182

Other assets: Turnaround costs (long-term)		9,167			8,705
Intangibles and other		68,284			12,587

		77,451			21,292


Total assets	$	2,442,871		$	1,663,945


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,079,193		$	782,976
Accrued liabilities		36,058			35,104
Short-term debt — Holly Energy Partners		20,000			—

Total current liabilities		1,135,251			818,080

Long-term debt — Holly Corporation		—			—
Long-term debt — Holly Energy Partners		339,909			—
Deferred income taxes		44,432			38,933
Other long-term liabilities		37,819			36,712
Distributions in excess of investment in Holly Energy Partners		—			168,093
Minority interest		405,087			8,333

Stockholders’ equity:
Preferred stock, $1.00 par value — 1,000,000 shares authorized; none issued		—			—
Common stock $.01 par value — 160,000,000 shares authorized; 73,544,063 and 73,269,219 shares issued as of June 30, 2008 and December 31, 2007, respectively		736			733
Additional capital		114,809			109,125
Retained earnings		1,059,905			1,054,974
Accumulated other comprehensive loss		(18,356	)		(19,076	)
Common stock held in treasury, at cost - 23,437,054 and 20,653,050 shares as of June 30, 2008 and December 31, 2007, respectively		(676,721	)		(551,962	)

Total stockholders’ equity		480,373			593,794


Total liabilities and stockholders’ equity	$	2,442,871		$	1,663,945

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In thousands, except per share data)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Sales and other revenues	$	1,743,822		$	1,216,997		$	3,223,806		$	2,142,864

Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion, and amortization)		1,620,550			897,237			3,003,987			1,648,951
Operating expenses (exclusive of depreciation, depletion, and amortization)		74,175			51,116			134,883			101,245
General and administrative expenses (exclusive of depreciation, depletion, and amortization)		12,832			21,348			25,664			37,195
Depreciation, depletion and amortization		15,929			10,641			29,238			22,092
Exploration expenses, including dry holes		110			105			215			257

Total operating costs and expenses		1,723,596			980,447			3,193,987			1,809,740

Income from operations		20,226			236,550			29,819			333,124

Other income (expense):
Equity in earnings of Holly Energy Partners		—			4,954			2,990			8,300
Minority interest in earnings of Holly Energy Partners		(493	)		—			(1,295	)		—
Interest income		3,826			3,550			7,381			6,110
Interest expense		(6,251	)		(291	)		(8,243	)		(543	)

		(2,918	)		8,213			833			13,867


Income from operations before income taxes		17,308			244,763			30,652			346,991

Income tax provision:
Current		(877	)		85,189			5,441			119,947
Deferred		6,733			947			5,110			875

		5,856			86,136			10,551			120,822


Income from operations		11,452			158,627			20,101			226,169

Net income	$	11,452		$	158,627		$	20,101		$	226,169


Net income per share-basic	$	0.23		$	2.89		$	0.40		$	4.11


Net income per share-diluted	$	0.23		$	2.84		$	0.39		$	4.03


Cash dividends declared per common share	$	0.15		$	0.12		$	0.30		$	0.22


Average number of common shares outstanding:
Basic		50,158			54,959			50,654			55,073
Diluted		50,515			55,953			51,015			56,079

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended
	June 30,
	2008			2007
Cash flows from operating activities:
Net income	$	20,101		$	226,169
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		29,238			22,092
Deferred income taxes		5,110			875
Minority interest in earnings of Holly Energy Partners		1,295			—
Equity based compensation expense		2,695			1,446
Distributions in excess of equity in earnings in Holly Energy Partners		3,067			2,756
(Increase) decrease in current assets:
Accounts receivable		(221,285	)		(5,862	)
Inventories		(18,649	)		(14,022	)
Income taxes receivable		6,323			9,055
Prepayments and other		737			(3,306	)
Increase (decrease) in current liabilities:
Accounts payable		296,611			9,136
Accrued liabilities		(8,107	)		(3,789	)
Income taxes payable		—			34,767
Turnaround expenditures		(3,390	)		(202	)
Other, net		867			1,469

Net cash provided by operating activities		114,613			280,584

Cash flows from investing activities:
Additions to properties, plants and equipment		(198,784	)		(72,531	)
Investment in Holly Energy Partners		(290	)		—
Purchases of marketable securities		(303,257	)		(360,040	)
Sales and maturities of marketable securities		395,520			158,150
Proceeds from sale of crude pipeline and tankage assets		171,000			—
Increase in cash due to consolidation of Holly Energy Partners		7,295			—

Net cash provided by (used for) investing activities		71,484			(274,421	)

Cash flows from financing activities:
Net borrowings under credit agreement — Holly Energy Partners		20,000			—
Deferred financing costs — Holly Energy Partners		(365	)		—
Purchase of treasury stock		(136,876	)		(51,097	)
Cash dividends		(14,055	)		(10,050	)
Cash distributions to minority interests		(7,577	)		—
Contribution from joint venture partner		10,000			—
Issuance of common stock upon exercise of options		256			547
Excess tax benefit from equity based compensation		3,436			7,457
Purchase of units for restricted grants — Holly Energy Partners		(514	)		—

Net cash used for financing activities		(125,695	)		(53,143	)

Cash and cash equivalents:

Increase (decrease) for the period		60,402			(46,980	)
Beginning of period		94,369			154,117

End of period	$	154,771		$	107,137


Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	6,489		$	313
Income taxes	$	3,993		$	68,668

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
Net income	$	11,452		$	158,627	$	20,101		$	226,169
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain on available for sale securities		501			50		1,327			428
Reclassification adjustment to net income on sale of equity securities		(32	)		16		(1,339	)		(5	)

Total unrealized gain (loss) on available for sale securities		469			66		(12	)		423

Retirement medical obligation adjustment		—			—		—			(2,792	)

Other comprehensive income of Holly Energy Partners
Change in fair value of cash flow hedge		6,797			—		2,448			—
Less minority interest in other comprehensive income		(3,687	)		—		(1,328	)		—

Other comprehensive income of Holly Energy Partners, net of minority interest		3,110			—		1,120			—


Other comprehensive income (loss) before income taxes		3,579			66		1,108			(2,369	)
Income tax expense (benefit)		1,273			28		388			(921	)

Other comprehensive income (loss)		2,306			38		720			(1,448	)

Total comprehensive income	$	13,758		$	158,665	$	20,821		$	224,721

See accompanying notes.

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HOLLY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

As of the close of business on June 30, 2008, 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 and operated Holly Asphalt Company (formerly, NK Asphalt Partners) which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and

	•		owned a 46% interest in HEP which includes our 2% general partner interest, which has logistic assets including approximately 2,500 miles of petroleum product pipelines located in Texas, New Mexico, Oklahoma and Utah (including 340 miles of leased pipeline); ten 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 February 29, 2008, HEP acquired certain crude pipelines and tankage assets from us that also service our Navajo and Woods Cross Refineries.

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of June 30, 2008, the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2008 and 2007 and consolidated cash flows for the six months ended June 30, 2008 and 2007 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, 2007 filed with the SEC.

Our results of operations for the first six months of 2008 are not necessarily indicative of the results to be expected for the full year.

On February 29, 2008, we closed on the sale of certain crude pipelines and tankage assets (the “Crude Pipelines and Tankage Assets”) to HEP for $180.0 million. See Note 2 for a description of this transaction.

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

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Our accounts receivable consist of amounts due from customers which are primarily companies in the petroleum industry. Credit is extended based on our evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal. At June 30, 2008 our allowance for doubtful accounts reserve was $2.0 million.

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.

During the three and six months ended June 30, 2008 we recognized a $4.1 million reduction in cost of products sold resulting from the liquidation of certain LIFO quantities of asphalt inventory that were carried at lower costs as compared to current.

New Accounting Pronouncements

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

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. We will adopt this standard effective January 1, 2009. We are currently evaluating the impact of this standard on our financial condition, results of operations and cash flows.

Emerging Issues Task Force (“EITF”) No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”

In June 2007, the FASB ratified EITF No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. EITF No. 06-11 requires that tax benefits generated by dividends paid during the vesting period on certain equity-classified share-based compensation awards be classified as additional paid-in capital and included in a pool of excess tax benefits available to absorb tax deficiencies from share-based payment awards. EITF No. 06-11 is effective for fiscal years beginning after December 15, 2007. We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of Financial Accounting Standards Board (“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 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years. We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

SFAS No. 157 “Fair Value Measurements”

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considered the most reliable evidence of fair value and are given the highest priority level (level 1). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3). We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows. We have investments in marketable debt and equity securities that are valued on a recurring basis using level 1 inputs (See Note 5). Additionally, HEP has interest rate swaps that are measured at fair value on a recurring basis using level 2 inputs (See Note 7).

NOTE 2: 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. At June 30, 2008, we held 7,000,000 subordinated units and 290,000 common units of HEP, representing a 46% ownership interest in HEP, including our 2% general partner interest.

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

In connection with this transaction, we entered into a 15-year crude pipelines and tankage agreement with HEP (the “HEP CPTA”). Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, will initially result in minimum annual payments to HEP of $25.3 million. The agreed upon tariffs on the crude pipelines will be adjusted each year at a rate equal to the percentage change in the producer price index (“PPI”), but will not decrease as a result of a decrease in the PPI. Additionally, we amended our omnibus agreement (the “Omnibus Agreement”) to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.

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

HEP is a variable interest entity as defined under FIN No. 46. Under the provisions of FIN No. 46, HEP’s acquisition of our crude pipelines and tankage assets qualifies as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transfer, we determined that our beneficial interest in HEP exceeds 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting.

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


	(In thousands)
Investment in HEP balance at December 31, 2007		$	(168,093	)
Equity in the earnings of HEP			2,990
Regular quarterly distributions from HEP			(6,057	)
Consideration received in excess of basis in Crude Pipeline and Tankage Assets			(153,355	)
HEP common units received			9,000
Purchase of additional HEP common units			104
Contribution made to maintain 2% general partner interest			186

Investment in HEP balance at February 29, 2008		$	(315,225	)

As of March 1, 2008, the impact of the reconsolidation of HEP was an increase in cash of $7.3 million, an increase in other current assets of $5.9 million, an increase in property, plant and equipment of $368.7 million, an increase in intangibles and other assets of $56.3 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $341.4 million, an increase in other long-term liabilities of $0.3 million, an increase in minority interest of $391.7 million and a decrease in distributions in excess of investment in HEP of $315.2 million. These amounts are based on management’s preliminary fair value estimates.

The following tables provide summary financial results for HEP through February 29, 2008, prior to our reconsolidation effective March 1, 2008.


	February 29,		December 31,
	2008		2007
	(In thousands)
Current assets	$	13,177	$	23,178
Properties and equipment, net		272,370		158,600
Transportation agreements and other		129,022		57,126

Total assets	$	414,569	$	238,904


Current liabilities	$	19,561	$	17,732
Long-term liabilities		353,684		182,616
Minority interest		11,055		10,740
Partners’ equity		30,269		27,816

Total liabilities and partners’ equity	$	414,569	$	238,904


	Period From
	January 1, 2008			Three Months			Six Months
	Through			Ended			Ended
	February 29, 2008			June 30, 2007			June 30, 2007
				(In thousands)
Revenues	$	17,334		$	27,131		$	51,003
Operating costs and expenses		(9,172	)		(12,681	)		(25,757	)

Operating income		8,162			14,450			25,246
Other expenses, net		(2,344	)		(3,444	)		(6,806	)

Net income	$	5,818		$	11,006		$	18,440

We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under the HEP PTA, HEP IPA, HEP CPTA and an Omnibus Agreement. Related party transactions prior to our reconsolidation of HEP effective March 1, 2008 are as follows:

	•		Pipeline and terminal expenses paid to HEP were $10.6 million for the period from January 1, 2008 through February 29, 2008 and $16.4 million and $30.1 million for the three and six months ended June 30, 2007, respectively.

	•		We charged HEP $0.4 million for the period from January 1, 2008 through February 29, 2008 and $0.5 million and $1.0 million for the three and six months ended June 30, 2007, respectively, for general and administrative services under the Omnibus Agreement which we recorded as a reduction in expenses.

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	•		HEP reimbursed us for costs of employees supporting their operations $2.1 million for the period from January 1, 2008 through February 29, 2008 and $2.3 million and $4.6 million for the three and six months ended June 30 2007, respectively, which we recorded as a reduction in expenses.

	•		We reimbursed HEP $24,000 and $98,000 for the three and six months ended June 30, 2007, respectively, for certain costs paid on our behalf.

	•		We received as regular distributions on our subordinated units, common units and general partner interest $6.1 million for the period from January 1, 2008 through February 29, 2008 and $5.6 million and $11.1 million for the three and six months ended June 30, 2007, respectively. Our distributions included $0.7 million for the period from January 1, 2008 through February 29, 2008 and $0.5 million and $1.0 million for the three and six months ending June 30, 2007, respectively, in incentive distributions with respect to our general partner interest.

	•		We had a related party receivable from HEP of $6.0 million at February 29, 2008 and December 31, 2007, respectively.

	•		We had accounts payable to HEP of zero and $5.7 million at February 29, 2008 and December 31, 2007, respectively.

NOTE 3: Earnings Per Share

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
			(In thousands, except per share data)
Net Income	$	11,452	$	158,627	$	20,101	$	226,169

Average number of shares of common stock outstanding		50,158		54,959		50,654		55,073
Effect of dilutive stock options, variable restricted shares and performance share units		357		994		361		1,006

Average number of shares of common stock outstanding assuming dilution		50,515		55,953		51,015		56,079


Net income per share-basic	$	0.23	$	2.89	$	0.40	$	4.11


Net income per share-diluted	$	0.23	$	2.84	$	0.39	$	4.03

NOTE 4: Stock-Based Compensation

Holly Corporation

On June 30, 2008 Holly had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for those plans was $1.9 million and $4.7 million for the three months ended June 30, 2008 and 2007, respectively, and $3.8 million and $9.1 million for the six months ended June 30, 2008 and 2007, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $0.7 million and $1.8 million for the three months ended June 30, 2008 and 2007, respectively, and $1.5 million and $3.2 million for the six months ended June 30, 2008 and 2007, respectively. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods, which results in a higher expense in the earlier periods of the grants. At June 30, 2008, 2,405,610 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.

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

A summary of option activity and changes during the six months ended June 30, 2008 is presented below:


						Weighted-
				Weighted-		Average		Aggregate
				Average		Remaining		Intrinsic
				Exercise		Contractual		Value
Options	Shares			Price		Term		($000)
Outstanding at January 1, 2008		491,200		$	2.56
Exercised		(76,000	)		3.34

Outstanding at June 30, 2008		415,200		$	2.42		2.5	$	14,326

Exercisable at June 30, 2008		415,200		$	2.42		2.5	$	14,326

The total intrinsic value of options exercised during the six months ended June 30, 2008 and 2007, was $3.1 million and $11.1 million, respectively.

Cash received from option exercises under the stock option plans was $0.3 million and $0.5 million for the six months ended June 30, 2008 and 2007, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $1.2 million and $4.3 million for the six months ended June 30, 2008 and 2007, 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 six months ended June 30, 2008 is presented below:


				Weighted-
				Average
				Grant-Date		Aggregate Intrinsic
Restricted Stock	Grants			Fair Value		Value ($000)
Outstanding at January 1, 2008 (non-vested)		298,565		$	27.22
Vesting and transfer of ownership to recipients		(131,993	)		23.81
Granted		86,409			45.91
Forfeited		(1,868	)		39.05

Outstanding at June 30, 2008 (non-vested)		251,113		$	35.35	$	9,271

The total intrinsic value of restricted stock vested and transferred to recipients during the six months ended June 30, 2008 and 2007 was $4.9 million and $15.1 million, respectively. As of June 30, 2008, there was $4.2 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be

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recognized over a weighted-average period of 1.1 years. The total fair value of shares vested during the six months ended June 30, 2008 and 2007 was $3.1 million and $3.4 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 six months ended June 30, 2008, we granted 60,605 performance share units with a fair value based on our grant date closing stock price of $47.47. 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 June 30, 2008, estimated share payouts for outstanding non-vested performance share unit awards ranged from 100% to 175%.

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.

All outstanding performance share unit awards that were payable in cash vested in January 2008.

A summary of performance share unit activity and changes during the six months ended June 30, 2008 is presented below:


							Financial
	Market Performance						Performance
	Payable in			Stock			Stock			Total
	Cash			Settled			Settled			Performance
Performance Share Units	Grants			Grants			Grants			Share Units
Outstanding at January 1, 2008 (non-vested)		81,450			42,474			116,156			240,080
Vesting and payment of benefit to recipients		(81,450	)		(42,474	)		—			(123,924	)
Granted		—			—			60,605			60,605
Forfeited		—			—			(1,578	)		(1,578	)

Outstanding at June 30, 2008 (non-vested)		—			—			175,183			175,183

For the six months ended June 30, 2008 we paid $6.0 million and issued 84,948 shares of our common stock (representing a 200% share payout) having a fair value of $1.3 million related to vested performance share units. Based on the weighted average grant date fair value of $42.64, there was $3.2 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

HEP

On June 30, 2008, HEP had two types of equity-based compensation. The compensation cost charged against HEP’s income for these plans was $0.6 million for the period from March 1, 2008 through June 30, 2008.

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Restricted Units

A summary of restricted unit activity and changes during the six months ended June 30, 2008, is presented below:


						Weighted
				Weighted		Average		Aggregate
				Average		Remaining		Intrinsic
				Grant Date		Contractual		Value
Restricted Units	Grants			Fair Value		Term		($000)
Outstanding January 1, 2008 (not vested)		44,711		$	44.77
Granted		18,902			40.30
Forfeited		(303	)		44.62
Vesting and transfer of full ownership to recipients		(11,486	)		43.53


Outstanding at June 30, 2008 (not vested)		51,824		$	43.42		1.1	$	2,021

There were 11,486 restricted units having an intrinsic value of $0.4 million and a fair value of $0.5 million that were vested and transferred to recipients during the six months ended June 30, 2008. As of June 30, 2008, there was $0.9 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 1.1 years.

Performance Units

A summary of performance units activity and changes during the six months ended June 30, 2008 is presented below:


	Payable
Performance Units	In Units
Outstanding at January 1, 2008 (not vested)		24,148
Granted		14,337
Forfeited		—
Vesting and transfer of full ownership to recipients		(1,514	)

Outstanding at June 30, 2008 (not vested)		36,971

There were 1,514 performance units having an intrinsic value of $0.1 million and a fair value of $0.1 million that were vested and transferred to recipients during the six months ended June 30, 2008. Based on the weighted average fair value at June 30, 2008 of $42.10 there was $1.1 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

NOTE 5: Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, we own 1,000,000 shares of Connacher Oil and Gas Limited 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”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments

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including investments in equity securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. 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.

The following is a summary of our available-for-sale securities at June 30, 2008:


	Available-for-Sale Securities
						Estimated
			Gross			Fair Value
			Unrealized			(Net Carrying
	Amortized Cost		Gain (Loss)			Amount)
	(In thousands)
States and political subdivisions	$	138,446	$	475		$	138,921
Equity securities		4,328		(108	)		4,220

Total marketable securities	$	142,774	$	367		$	143,141

Interest income on our marketable debt securities for the six months ended June 30, 2008 and 2007 included $3.9 million and $3.5 million, respectively, of interest earned, $1.3 million and $5,000, respectively, in realized gains and amortization of $0.8 million and $0.4 million, respectively, in net premiums paid related to our marketable debt securities. For the six months ended June 30, 2008 and 2007 we received a total of $395.5 million and $158.2 million, respectively, related to sales and maturities of our marketable debt securities. Realized gains and losses represent the difference between the purchase price, as amortized, and the market value on the maturity or sales date.

NOTE 6: Environmental Costs

Consistent with our accounting policy for environmental remediation costs, we expensed $0.4 million and $2.2 million for the three months ended June 30, 2008 and 2007, respectively, and $0.4 million and $2.3 million for the six months ended June 30, 2008 and 2007, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $8.1 million and $8.6 million at June 30, 2008 and December 31, 2007, respectively, of which $2.8 million and $5.3 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 7: Debt

Credit Facilities

In March 2008, we entered into an amended and restated $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America as administrative agent and lender. The Credit Agreement has a term of five years and an option to increase the facility to $300.0 million subject to certain conditions. This credit facility expires in 2013 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. We were in compliance with all covenants at June 30, 2008. At June 30, 2008, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our credit facility was $172.5 million at June 30, 2008.

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Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement. HEP's obligations under the HEP Credit Agreement are collateralized by substantially all of HEP's assets. HEP assets that are included in our Consolidated Balance Sheets at June 30, 2008 consist of $6.4 million in cash and cash equivalents, $15.9 million in trade accounts receivable, $0.1 million in inventory, $0.6 million in prepayments and other, $373.5 million in property, plant and equipment, net and $55.5 million in intangible and other assets.

HEP Senior Notes Due 2015

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of $35.0 million of the principal amount of the HEP Senior Notes.

At June 30, 2008, the carrying amount of HEP’s long-term debt was as follows:


	(In thousands)
HEP Credit Agreement	$	191,000

HEP Senior Notes
Principal		185,000
Unamortized discount		(16,738	)
Fair value hedge — interest rate swap		647

		168,909


Total debt		359,909
Less short-term borrowings under HEP Credit Agreement		20,000


Total long-term debt	$	339,909

Interest Rate Risk Management

As of June 30, 2008, HEP had two interest rate swap contracts.

HEP entered into an interest rate swap to hedge their exposure to the cash flow risk caused by the effects of LIBOR changes on their $171.0 million credit agreement advance that was used to finance their purchase of the Crude Pipelines and Tankage Assets. This interest rate swap effectively converts their $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, that results in a June 30, 2008 effective interest rate of 5.49%. The maturity of this swap contract is February 28, 2013. HEP intends to renew the Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

Under the provisions of SFAS No. 133, HEP designated this interest rate swap as a cash flow hedge. Based on their assessment of effectiveness using the change in variable cash flows method, they determined that the interest rate swap is effective in offsetting the variability in interest payments on their $171.0 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, HEP adjusts the cash flow hedge on a quarterly basis to its fair value with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, HEP measures hedge effectiveness by comparing the present value of the cumulative change in the expected future interest payments on the variable leg of their swap against the expected future interest payments on their $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of June 30, 2008, HEP had no ineffectiveness on our cash flow hedge.

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HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of their 6.25% senior notes from a fixed to a variable rate. Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus an applicable margin of 1.1575%, which equaled an effective interest rate of 3.84% at June 30, 2008. The maturity of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.

This interest rate swap has been designated as a fair value hedge and meets the requirements to assume no ineffectiveness under the provisions of SFAS No. 133. Accordingly, HEP uses the “shortcut” method of accounting as prescribed under SFAS No. 133. Under this method, HEP adjusts the carrying value of the swap to its fair value on a quarterly basis, with an offsetting entry to their senior notes, effectively adjusting the carrying value of $60.0 million of principal on the HEP Senior Notes to its fair value.

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


		Fair Value		Location of Offsetting
Interest Rate Swaps	Balance Sheet Location	(In thousands)		Balance
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	2,448	Accumulated other comprehensive loss

Fair value hedge — $60 million of 6.25% Senior Notes	Other assets	$	647	Long-term debt

NOTE 8: Income Taxes

Our effective tax rates for the first six months of 2008 and 2007 were 34.4% and 34.8%, respectively. We realized a lower effective tax rate during the first six months of 2008 due principally to lower pre-tax earnings.

NOTE 9: Stockholders’ Equity

Common Stock Repurchases: Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2008, we repurchased 2,728,489 shares at a cost of $122.9 million or an average of $45.05 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through June 30, 2008, we have repurchased 16,259,395 shares at a cost of approximately $641.0 million or an average of $39.42 per share.

During the six months ended June 30, 2008, we repurchased at current market price from certain officers and key employees 55,515 shares of our common stock at a cost of approximately $2.0 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

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NOTE 10: Other Comprehensive Income

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


				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
For the three months ended June 30, 2008
Unrealized gain on available-for-sale securities	$	469		$	182		$	287
Unrealized gain on HEP cash flow hedge, net of minority interest		3,110			1,091			2,019

Other comprehensive income	$	3,579		$	1,273		$	2,306


For the three months ended June 30, 2007
Unrealized gain on available-for-sale securities	$	66		$	28		$	38

Other comprehensive income	$	66		$	28		$	38


For the six months ended June 30, 2008
Unrealized loss on available-for-sale securities	$	(12	)	$	(5	)	$	(7	)
Unrealized gain on HEP cash flow hedge, net of minority interest		1,120			393			727

Other comprehensive income	$	1,108		$	388		$	720


For the six months ended June 30, 2007
Retirement medical obligation adjustment	$	(2,792	)	$	(1,086	)	$	(1,706	)
Unrealized gain on available-for-sale securities		423			165			258

Other comprehensive loss	$	(2,369	)	$	(921	)	$	(1,448	)

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

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


	June 30,			December 31,
	2008			2007
	(In thousands)
Pension obligation adjustment	$	(16,228	)	$	(16,228	)
Retiree medical obligation adjustment		(3,078	)		(3,078	)
Unrealized gain on available-for-sale securities		223			230
Unrealized gain on HEP cash flow hedge, net of minority interest		727			—

Accumulated other comprehensive loss	$	(18,356	)	$	(19,076	)

NOTE 11: 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.

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

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The net periodic pension expense consisted of the following components:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
				(In thousands)
Service cost	$	1,090		$	465		$	2,180		$	2,055
Interest cost		1,193			633			2,386			2,037
Expected return on assets		(1,143	)		(473	)		(2,287	)		(2,039	)
Amortization of prior service cost		97			132			195			195
Amortization of net loss		351			171			702			454

Net periodic benefit cost	$	1,588		$	928		$	3,176		$	2,702

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2008 and 2007 net periodic benefit cost. We expect to contribute $10.0 million to the retirement plan during 2008. No contributions were made during the six months ended June 30, 2008.

NOTE 12: Contingencies

In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the 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 the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 2007 decision approved a FERC position, which is adverse to us, on the treatment of income taxes in the calculation of allowable rates for pipelines operated by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. The income tax issue and the other remaining issues relating to SFPP’s obligations to shippers are being handled by the FERC in a single compliance proceeding covering the period from 1992 through May 2006. We currently estimate that, as a result of the May 2007 Court of Appeals decision and prior rulings by the Court of Appeals and the FERC in these proceedings, a net amount will be due from SFPP to us for the period January 1992 through May 2006 in addition to the $15.3 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. A partial settlement covering the period June 2006 through November 2007, which became final in February 2008, resulted in a payment from SFPP to us of approximately $1.3 million in April 2008. Discussions concerning a possible settlement with SFPP for periods after November 2007 have taken place but no additional agreements have been reached as of the date of this report.

On July 2, 2008, the United States District Court for the District of Utah entered a Consent Decree approving the terms of an agreement that had been entered into in April 2008 by the EPA, the State of Utah and us concerning alleged Federal CAA liabilities relating to our Woods Cross Refinery and arising from actions taken or not taken by prior owners of the refinery. The Consent Decree includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The Consent Decree also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit to the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips, the prior owner of the refinery, 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 is approximately $1.4 million with respect to the Consent Decree.

- 22 -

In May 2008, Montana Refining Company (“MRC”), our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC, entered into a Notice Of Violation And Administrative Order On Consent (“AOC”) with the Montana Department of Environmental Quality (“MDEQ”). The AOC relates to assertions by the MDEQ 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 AOC requires certain actions to be taken by the refinery and payment of a $105,000 penalty. Pursuant to the terms of the AOC, a lawsuit on this matter brought by the MDEQ in Montana state court was dismissed with prejudice in late May 2008. We expect to pay to the current owner of the Great Falls refinery our appropriate share, which has not yet been finally agreed, of penalty and related amounts with respect to 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.

NOTE 13: Segment Information

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segments are included in Corporate and Other and includes the operations of Holly Corporation, our parent company, and a small-scale oil and gas exploration and production program.

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

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

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

- 23 -

The accounting policies for our segments are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2008.


						Corporate						Consolidated
	Refining			HEP⁽¹⁾		and Other			Eliminations			Total
	(In thousands)
Three Months Ended June 30, 2008
Sales and other revenues	$	1,736,201		$	26,774	$	886		$	(20,039	)	$	1,743,822
Operating expenses	$	64,183		$	9,985	$	7		$	—		$	74,175
General and administrative expenses	$	(6	)	$	1,359	$	11,479		$	—		$	12,832
Depreciation and amortization	$	8,699		$	6,220	$	1,010		$	—		$	15,929
Income (loss) from operations	$	22,736		$	9,210	$	(11,720	)	$	—		$	20,226

Three Months Ended June 30, 2007
Sales and other revenues	$	1,216,777		$	—	$	114		$	106		$	1,216,997
Operating expenses	$	51,113		$	—	$	3		$	—		$	51,116
General and administrative expenses	$	(3	)	$	—	$	21,351		$	—		$	21,348
Depreciation and amortization	$	9,904		$	—	$	737		$	—		$	10,641
Income (loss) from operations	$	258,632		$	—	$	(22,082	)	$	—		$	236,550

Six Months Ended June 30, 2008
Sales and other revenues	$	3,213,577		$	36,716	$	1,287		$	(27,774	)	$	3,223,806
Operating expenses	$	121,399		$	13,661	$	7		$	(184	)	$	134,883
General and administrative expenses	$	1		$	1,881	$	23,782		$	—		$	25,664
Depreciation and amortization	$	18,980		$	8,230	$	2,028		$	—		$	29,238
Income (loss) from operations	$	41,620		$	12,944	$	(24,745	)	$	—		$	29,819

Six Months Ended June 30, 2007
Sales and other revenues	$	2,142,359		$	—	$	505		$	—		$	2,142,864
Operating expenses	$	101,231		$	—	$	14		$	—		$	101,245
General and administrative expenses	$	—		$	—	$	37,195		$	—		$	37,195
Depreciation and amortization	$	20,930		$	—	$	1,162		$	—		$	22,092
Income (loss) from operations	$	371,247		$	—	$	(38,123	)	$	—		$	333,124


(1)		HEP segment revenues from external customers were $6.7 million and $8.9 million for the three and six months ended June 30, 2008, respectively.


					Corporate					Consolidated
	Refining		HEP		and Other		Eliminations			Total
	(In thousands)
June 30, 2008
Cash, cash equivalents and investments in marketable securities	$	—	$	6,371	$	291,541	$	—		$	297,912
Total assets	$	1,671,633	$	451,937	$	331,841	$	(12,540	)	$	2,442,871
Total debt	$	—	$	359,909	$	—	$	—		$	359,909

December 31, 2007
Cash, cash equivalents and investments in marketable securities	$	—	$	—	$	329,784	$	—		$	329,784
Total assets	$	1,271,163	$	—	$	392,782	$	—		$	1,663,945

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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 June 30, 2008, we also owned a 46% 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 six months ended June 30, 2008 were $3,223.8 million and our net income for the six months ended June 30, 2008 was $20.1 million. Our sales and other revenues and net income for the six months ended June 30, 2007 were $2,142.9 million and $226.2 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the six months ended June 30, 2008 were $3,194.0 million, an increase from $1,809.7 million for the six months ended June 30, 2007.

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

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

Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2008, we repurchased 2,728,489 shares at a cost of $122.9 million or an average of $45.05 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through June 30, 2008, we have repurchased 16,259,395 shares at a cost of approximately $641.0 million or an average of $39.42 per share.

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RESULTS OF OPERATIONS

Financial Data (Unaudited)


	Three Months Ended
	June 30,						Change from 2007
	2008			2007			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	1,743,822		$	1,216,997		$	526,825			43.3	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		1,620,550			897,237			723,313			80.6
Operating expenses (exclusive of depreciation, depletion and amortization)		74,175			51,116			23,059			45.1
General and administrative expenses (exclusive of depreciation, depletion and amortization)		12,832			21,348			(8,516	)		(39.9	)
Depreciation, depletion and amortization		15,929			10,641			5,288			49.7
Exploration expenses, including dry holes		110			105			5			4.8

Total operating costs and expenses		1,723,596			980,447			743,149			75.8


Income from operations		20,226			236,550			(216,324	)		(91.4	)
Other income (expense):
Equity in earnings of HEP		—			4,954			(4,954	)		(100.0	)
Minority interest in earnings of HEP		(493	)		—			(493	)		—
Interest income		3,826			3,550			276			7.8
Interest expense		(6,251	)		(291	)		(5,960	)		2,048.1

		(2,918	)		8,213			(11,131	)		(135.5	)

Income from operations before income taxes		17,308			244,763			(227,455	)		(92.9	)
Income tax provision		5,856			86,136			(80,280	)		(93.2	)

Net income	$	11,452		$	158,627		$	(147,175	)		(92.8	)%


Net income per share — basic	$	0.23		$	2.89		$	(2.66	)		(92.0	)%


Net income per share — diluted	$	0.23		$	2.84		$	(2.61	)		(91.9	)%


Cash dividends declared per common share	$	0.15		$	0.12		$	0.03			25.0	%

Average number of common shares outstanding:
Basic		50,158			54,959			(4,801	)		(8.7	)%
Diluted		50,515			55,953			(5,438	)		(9.7	)%

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	Six Months Ended
	June 30,						Change from 2007
	2008			2007			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	3,223,806		$	2,142,864		$	1,080,942			50.4	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		3,003,987			1,648,951			1,355,036			82.2
Operating expenses (exclusive of depreciation, depletion and amortization)		134,883			101,245			33,638			33.2
General and administrative expenses (exclusive of depreciation, depletion and amortization)		25,664			37,195			(11,531	)		(31.0	)
Depreciation, depletion and amortization		29,238			22,092			7,146			32.3
Exploration expenses, including dry holes		215			257			(42	)		(16.3	)

Total operating costs and expenses		3,193,987			1,809,740			1,384,247			76.5


Income from operations		29,819			333,124			(303,305	)		(91.0	)
Other income (expense):
Equity in earnings of HEP		2,990			8,300			(5,310	)		(64.0	)
Minority interest in earnings of HEP		(1,295	)		—			(1,295	)		(100.0	)
Interest income		7,381			6,110			1,271			20.8
Interest expense		(8,243	)		(543	)		(7,700	)		1,418.0

		833			13,867			(13,034	)		(94.0	)

Income from operations before income taxes		30,652			346,991			(316,339	)		(91.2	)
Income tax provision		10,551			120,822			(110,271	)		(91.3	)

Net income	$	20,101		$	226,169		$	(206,068	)		(91.1	)%


Net income per share — basic	$	0.40		$	4.11		$	(3.71	)		(90.3	)%


Net income per share — diluted	$	0.39		$	4.03		$	(3.64	)		(90.3	)%


Cash dividends declared per common share	$	0.30		$	0.22		$	0.08			36.4	%

Average number of common shares outstanding:
Basic		50,654			55,073			(4,419	)		(8.0	)%
Diluted		51,015			56,079			(5,064	)		(9.0	)%

Balance Sheet Data (Unaudited)


	June 30,		December 31,
	2008		2007
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	297,912	$	329,784
Working capital	$	156,605	$	216,541
Total assets	$	2,442,871	$	1,663,945
Long-term debt — HEP	$	339,909	$	—
Stockholders’ equity	$	480,373	$	593,794

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Other Financial Data (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
Net cash provided by operating activities	$	15,763		$	194,283		$	114,613		$	280,584
Net cash provided by (used for) investing activities	$	(11,975	)	$	(220,646	)	$	71,484		$	(274,421	)
Net cash used for financing activities	$	(29,568	)	$	(17,679	)	$	(125,695	)	$	(53,143	)
Capital expenditures	$	126,023		$	45,781		$	198,784		$	72,531
EBITDA ⁽¹⁾	$	35,662		$	252,145		$	60,752		$	363,516


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

Our operations are currently organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining and HEP segment are included in Corporate and Other and includes the operations of Holly Corporation, our parent company, and a small-scale oil and gas exploration and production program.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
Sales and other revenues
Refining⁽¹⁾	$	1,736,201		$	1,216,777		$	3,213,577		$	2,142,359
HEP⁽²⁾		26,774			—			36,716			—
Corporate and Other		886			114			1,287			505
Eliminations		(20,039	)		106			(27,774	)		—

Consolidated	$	1,743,822		$	1,216,997		$	3,223,806		$	2,142,864


Operating Income (loss)
Refining⁽¹⁾	$	22,736		$	258,632		$	41,620		$	371,247
HEP⁽²⁾		9,210			—			12,944			—
Corporate and Other		(11,720	)		(22,082	)		(24,745	)		(38,123	)
Eliminations		—			—			—			—

Consolidated	$	20,226		$	236,550		$	29,819		$	333,124


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

- 28 -


(2)		The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through their pipelines and by charging fees for terminalling petroleum products and other hydrocarbons, and storing and providing other services at their storage tanks and terminals. The HEP segment also includes a 70% interest in Rio Grande which provides petroleum products transportation services. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations and from HEP’s interest in Rio Grande.

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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
*Navajo Refinery*
Crude charge (BPD) ⁽¹⁾		72,800			82,730			78,000			79,790
Refinery production (BPD) ⁽²⁾		76,960			90,940			85,800			88,540
Sales of produced refined products (BPD)		79,910			90,660			86,980			88,040
Sales of refined products (BPD) ⁽³⁾		88,720			100,840			97,070			98,610

Refinery utilization ⁽⁴⁾		85.6	%		99.7	%		91.8	%		96.1	%

Average per produced barrel ⁽⁵⁾
Net sales	$	133.89		$	93.17		$	117.33		$	84.69
Cost of products ⁽⁶⁾		125.82			65.63			110.15			62.45

Refinery gross margin		8.07			27.54			7.18			22.24
Refinery operating expenses ⁽⁷⁾		5.68			4.26			4.98			4.22

Net operating margin	$	2.39		$	23.28		$	2.20		$	18.02


Feedstocks:
Sour crude oil		83	%		78	%		81	%		76	%
Sweet crude oil		10	%		10	%		9	%		10	%
Other feedstocks and blends		7	%		12	%		10	%		14	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		55	%		58	%		57	%		59	%
Diesel fuels		34	%		30	%		33	%		29	%
Jet fuels		1	%		3	%		1	%		3	%
Fuel oil		3	%		3	%		3	%		3	%
Asphalt		4	%		3	%		3	%		3	%
LPG and other		3	%		3	%		3	%		3	%

Total		100	%		100	%		100	%		100	%

- 29 -


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
*Woods Cross Refinery*
Crude charge (BPD) ⁽¹⁾		23,980			25,800			24,470			25,230
Refinery production (BPD) ⁽²⁾		23,540			27,280			24,490			26,920
Sales of produced refined products (BPD)		23,790			26,130			24,550			27,120
Sales of refined products (BPD) ⁽³⁾		24,490			26,230			26,010			27,390

Refinery utilization ⁽⁴⁾		92.2	%		99.2	%		94.1	%		97.0	%

Average per produced barrel ⁽⁵⁾
Net sales	$	133.09		$	96.51		$	117.56		$	83.67
Cost of products ⁽⁶⁾		120.60			65.29			105.05			60.95

Refinery gross margin		12.49			31.22			12.51			22.72
Refinery operating expenses ⁽⁷⁾		8.13			4.22			7.17			4.50

Net operating margin	$	4.36		$	27.00		$	5.34		$	18.22


Feedstocks:
Sour crude oil		—	%		2	%		2	%		1	%
Sweet crude oil		98	%		90	%		94	%		90	%
Other feedstocks and blends		2	%		8	%		4	%		9	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		62	%		58	%		65	%		61	%
Diesel fuels		29	%		31	%		26	%		28	%
Jet fuels		—	%		3	%		—	%		2	%
Fuel oil		6	%		7	%		5	%		7	%
Asphalt		2	%		—	%		1	%		—	%
LPG and other		1	%		1	%		3	%		2	%

Total		100	%		100	%		100	%		100	%


*Consolidated*
Crude charge (BPD) ⁽¹⁾		96,780			108,530			102,470			105,020
Refinery production (BPD) ⁽²⁾		100,500			118,220			110,290			115,460
Sales of produced refined products (BPD)		103,700			116,790			111,530			115,160
Sales of refined products (BPD) ⁽³⁾		113,210			127,070			123,080			126,000

Refinery utilization ⁽⁴⁾		87.2	%		99.6	%		92.3	%		96.3	%

Average per produced barrel ⁽⁵⁾
Net sales	$	133.71		$	93.92		$	117.38		$	84.45
Cost of products ⁽⁶⁾		124.62			65.56			109.03			62.10

Refinery gross margin		9.09			28.36			8.35			22.35
Refinery operating expenses ⁽⁷⁾		6.24			4.25			5.46			4.29

Net operating margin	$	2.85		$	24.11		$	2.89		$	18.06


Feedstocks:
Sour crude oil		63	%		60	%		63	%		59	%
Sweet crude oil		31	%		28	%		28	%		29	%
Other feedstocks and blends		6	%		12	%		9	%		12	%

Total		100	%		100	%		100	%		100	%

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Sales of produced refined products:
Gasolines		56	%		58	%		58	%		59	%
Diesel fuels		32	%		30	%		31	%		29	%
Jet fuels		1	%		3	%		1	%		3	%
Fuel oil		4	%		4	%		4	%		4	%
Asphalt		4	%		2	%		3	%		2	%
LPG and other		3	%		3	%		3	%		3	%

Total		100	%		100	%		100	%		100	%


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

(2)		Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 109,000 BPSD to 111,000 BPSD in mid-year 2007.

(5)		Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “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 refineries, exclusive of depreciation, depletion and amortization.

Results of Operations — Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007

Summary

Net income for the three months ended June 30, 2008 was $11.5 million ($0.23 per basic diluted share) compared to net income of $158.6 million ($2.89 per basic and $2.84 per diluted share) for the three months ended June 30, 2007. Net income decreased $147.1 million for the second quarter of 2008 compared to the second quarter of 2007, due principally to a decline in refined product margins during the current year’s second quarter, a decrease in volumes of produced refined products sold and an increase in operating expenses. Overall refinery gross margins for the three months ended June 30, 2008 were $9.09 per produced barrel compared to $28.36 for the three months ended June 30, 2007. The total volume of refined products sold for the three months ended June 30, 2008 decreased 11% compared to the second quarter of 2007.

Overall refinery production levels decreased 15% for the three months ended June 30, 2008 compared to the same period in 2007 due primarily to the effects of unplanned downtime of our fluid catalytic cracking (“FCC”) unit at our Navajo Refinery in May 2008 and power failures at our Woods Cross Refinery during the second quarter of 2008.

Sales and Other Revenues

Sales and other revenues increased 43% from $1,217.0 million for the three months ended June 30, 2007 to $1,743.8 million for the three months ended June 30, 2008, due principally to higher refined product sales prices. The average sales price we received per produced barrel sold increased 42% from $93.92 for the three months ended June 30, 2007 to $133.71 for the three months ended June 30, 2008. Additionally, sales and other revenues for the three months ended June 30, 2008, includes $6.7 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. The total volume of refined products sold decreased 11% for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Cost of Products Sold

Cost of products sold increased 81% from $897.2 million for the three months ended June 30, 2007 to $1,620.6 million the three months ended June 30, 2008, due principally to significantly higher crude oil. The average price we paid per produced barrel sold for crude oil and feedstocks and the transportation costs of moving the finished

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products to the market place increased 90% from $65.56 for the three months ended June 30, 2007 to $124.62 for the three months ended June 30, 2008. The total volume of refined products sold decreased 11% for the three months ended June 30, 2008 compared to the three months ended June 30 2007. Also during the three months ended June 30, 2008 we recognized a $4.1 million reduction in cost of products sold resulting from the liquidation of certain LIFO quantities of asphalt inventory that were carried at lower costs as compared to current.

Gross Refinery Margins

Gross refining margin per produced barrel decreased 68% from $28.36 for the three months ended June 30, 2007 to $9.09 for the three months ended June 30, 2008 due to an increase in the average price we paid per barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross 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, increased 45% from $51.1 million for the three months ended June 30, 2007 to $74.2 million for the three months ended June 30, 2008, due principally to the inclusion of $10.0 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008, higher utility and increased maintenance costs associated with unplanned downtime.

General and Administrative Expenses

General and administrative expenses decreased 40% from $21.3 million for the three months ended June 30, 2007 to $12.8 million for the three months ended June 30, 2008, due principally to a decrease in equity-based compensation expense and software implementation costs. Equity based compensation is to some extent affected by our stock price. Additionally, general and administrative expenses for the three months ended June 30, 2008, includes $1.4 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 50% from $10.6 million for the three months ended June 30, 2007 to $15.9 million for the three months ended June 30, 2008, due principally to the inclusion of $6.2 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 combined with increased depreciation attributable to capitalized refinery improvement projects in 2007.

Equity in Earnings of HEP

Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting. Our equity in earnings of HEP for the three months ended June 30, 2007 was $5.0 million.

Minority Interests

Minority interests in income for the three months ended June 30, 2008 reduced our income by $0.5 million and represents the noncontrolling interest in HEP’s earnings.

Interest Income

Interest income was $3.8 million for the three months ended June 30, 2008 compared to $3.6 million for the three months ended June 30, 2007.

Interest Expense

Interest expense was $6.3 million for the three months ended June 30, 2008 compared to $0.3 million for the three months ended June 30, 2007. The increase in interest expense was due to the inclusion of $6.0 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Income Taxes

Income taxes decreased 93% from $86.1 million for the three months ended June 30, 2007 to $5.9 million for the three months ended June 30, 2008 due to lower pre-tax earnings during the three months ended June 30, 2008 as

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compared to the three months ended June 30, 2007. Our effective tax rate for the three months ended June 30, 2008 was 33.8% compared to 35.2% for the three months ended June 30, 2007. We realized a lower effective tax rate during the second quarter of 2008 due principally to lower pre-tax earnings.

Results of Operations — Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Summary

Net income for the six months ended June 30, 2008 was $20.1 million ($0.40 per basic and $0.39 per diluted share) compared to net income of $226.2 million ($4.11 per basic and $4.03 per diluted share) for the six months ended June 30, 2007. Net income for the first six months of 2008 decreased $206.1 million compared to the first six months of 2007, due principally to a decline in refined product margins during the current year, a decrease in volumes of produced refined products sold and an increase in operating expenses. Overall refinery gross margins for the six months ended June 30, 2008 were $8.35 per produced barrel compared $22.35 for the six months ended June 30, 2007. The total volume of refined products sold for the six months ended June 30, 2008 decreased 2% compared to the first six months of 2007.

Overall refinery production levels decreased 4% for the six months ended June 30, 2008 compared to the same period in 2007 due primarily to the effects of unplanned downtime of the FCC unit at our Navajo Refinery in May 2008, partially offset by the effects of our 2,000 BPSD Navajo Refinery capacity expansion in mid-year 2007.

Sales and Other Revenues

Sales and other revenues increased 50% from $2,142.9 million for the six months ended June 30, 2007 to $3,223.8 million for the six months ended June 30, 2008, due principally to higher refined product sales prices. The average sales price we received per produced barrel sold increased 39% from $84.45 for the six months ended June 30, 2007 to $117.38 for the six months ended June 30, 2008. Additionally, sales and other revenues for the six months ended June 30, 2008, includes $8.9 million in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties due to our reconsolidation of HEP effective March 1, 2008. The total volume of refined products sold decreased 2% for the six months ended June 30, 2008, as compared to the six months ended June 30, 2007.

Cost of Products Sold

Cost of products sold increased 82% from $1,649.0 million for the six months ended June 30, 2007 to $3,004.0 million the six months ended June 30, 2008, due principally to significantly higher crude oil costs. The average price we paid per produced barrel sold for crude oil and feedstocks and the transportation costs of moving the finished products to the market place increased 76% from $62.10 for the six months ended June 30, 2007 to $109.03 for the six months ended June 30, 2008. The total volume of refined products sold decreased 2% for the six months ended June 30, 2008, as compared to the six months ended June 30, 2007. Also during the six months ended June 30, 2008 we recognized a $4.1 million reduction in cost of products sold resulting from the liquidation of certain LIFO quantities of asphalt inventory that were carried at lower costs as compared to current.

Gross Refinery Margins

Gross refining margin per produced barrel decreased 63% from $22.35 for the six months ended June 30, 2007 to $8.35 for the six months ended June 30, 2008 due to the effects of an increase in the average price we paid per barrel of crude oil and feedstocks, partially offset by the effects of an increase in the average sales price we received per produced barrel sold. Gross 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, increased 33% from $101.2 million for the six months ended June 30, 2007 to $134.9 million for the six months ended June 30, 2008, due principally to the inclusion of $13.7 million in operating costs attributable to HEP as a result of our reconsolidation effective March 1, 2008, higher utility costs and increased maintenance costs associated with unplanned downtime.

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General and Administrative Expenses

General and administrative expenses decreased 31% from $37.2 million for the six months ended June 30, 2007 to $25.7 million for the six months ended June 30, 2008, due principally to a decrease in equity-based compensation expense which is to some extent affected by our stock price. Additionally, general and administrative expenses for the six months ended June 30, 2008, includes $1.8 million in expenses related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization increased 32% from $22.1 million for the six months ended June 30, 2007 to $29.2 million for the six months ended June 30, 2008, due principally to the inclusion of $8.2 million in depreciation and amortization related to HEP operations following our reconsolidation of HEP effective March 1, 2008 combined with increased depreciation attributable to capitalized refinery improvement projects in 2007.

Equity in Earnings of HEP

Our equity in earnings of HEP was $3.0 million for the six months ended June 30, 2008 compared to $8.3 million for the six months ended June 30, 2007. Our equity in earnings of HEP for the six months ended June 30, 2008 represents our interest in HEP’s earnings through February 29, 2008. Effective March 1, 2008, we reconsolidated HEP and no longer account for our investment in HEP under the equity method of accounting.

Minority Interests

Minority interests in income for the six months ended June 30, 2008 reduced our income by $1.3 million and represents the noncontrolling interest in HEP’s earnings for the period from March 1, 2008 through June 30, 2008.

Interest Income

Interest income was $7.4 million for the six months ended June 30, 2008 compared to $6.1 million for the six months ended June 30, 2007. The increase in interest income was due principally to an overall increase in our investments in marketable debt securities during the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

Interest Expense

Interest expense was $8.2 million for the six months ended June 30, 2008 compared to $0.5 million for the six months ended June 30, 2007. The increase in interest expense was due to the inclusion of $7.7 million in interest expense related to HEP operations following our reconsolidation of HEP effective March 1, 2008.

Income Taxes

Income taxes decreased 91% from $120.8 million for the six months ended June 30, 2007 to $10.6 million for the six months ended June 30, 2008 due to lower pre-tax earnings during the six months ended June 30, 2008 compared to the six months ended June 30, 2007. Our effective tax rate for the six months ended June 30, 2008 was 34.4% compared to 34.8% for the six months ended June 30, 2007. We realized a lower effective tax rate during the first six months of 2008 due principally to lower pre-tax earnings.

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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”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of June 30, 2008, we had cash and cash equivalents of $154.8 million, marketable securities with maturities under one year of $116.3 million and marketable securities with maturities greater than one year, but less than two years, of $26.8 million.

Cash and cash equivalents increased by $60.4 million during the six months ended June 30, 2008. The combined cash provided by operating and investing activities of $114.6 million and $71.5 million, respectively, exceeded cash used for financing activities of $125.7 million. Working capital decreased by $59.9 million during the six months ended June 30, 2008.

HEP has a $300.0 million senior secured revolving credit agreement (the “HEP Credit Agreement”) with Union Bank of California, N.A. as one of the lenders and as administrative agent and an option to increase the facility to $370.0 million subject to certain conditions. The HEP Credit Facility expires in August 2011 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general partnership purposes. Navajo Pipeline Co., L.P., Navajo Refining Company, L.L.C. and Woods Cross Refining Company, L.L.C., three of our subsidiaries, have agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171.0 million aggregate principal amount of borrowings under the HEP Credit Agreement. HEP's obligations under the HEP Credit Agreement are collateralized by substantially all of HEP's assets. HEP assets that are included in our Consolidated Balance Sheets at June 30, 2008 consist of $6.4 million in cash and cash equivalents, $15.9 million in trade accounts receivable, $0.1 million in inventory, $0.6 million in prepayments and other, $373.5 million in property, plant and equipment, net and $55.5 million in intangible and other assets.

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (“HEP Senior Notes”). The HEP Senior Notes are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. Navajo Pipeline Co., L.P., one of our subsidiaries, has agreed to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on $35.0 million of the principal amount of the HEP Senior Notes.

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At June 30, 2008, the carrying amount of HEP’s long-term debt was as follows:


	(In thousands)
HEP Credit Agreement	$	191,000

HEP Senior Notes
Principal		185,000
Unamortized discount		(16,738	)
Fair value hedge — interest rate swap		647

		168,909


Total debt		359,909
Less short-term borrowings under HEP Credit Agreement		20,000


Total long-term debt	$	339,909

See “Risk Management” for a discussion of HEP’s interest rate swaps.

Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. Under our common stock repurchase program, common stock repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. During the six months ended June 30, 2008, we repurchased 2,728,489 shares at a cost of $122.9 million or an average of $45.05 per share. Since inception of our common stock repurchase initiative beginning in May 2005 through June 30, 2008, we have repurchased 16,259,395 shares at a cost of approximately $641.0 million or an average of $39.42 per share. At June 30, 2008, we had $59.0 million of authorized repurchases remaining under our program.

We believe our current cash, cash equivalents and marketable securities, along with future internally generated cash flow and funds available under our credit facilities provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends, the repurchase of additional common stock under our common stock repurchase program and distributions by HEP to its minority interest partners. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

Cash Flows — Operating Activities

Net cash flows provided by operating activities were $114.6 million for the six months ended June 30, 2008 compared to $280.6 million for the six months ended June 30, 2007, a decrease of $166.0 million. Net income for the six months ended June 30, 2008 was $20.1 million, a decrease of $206.1 million from net income of $226.2 million for the six months ended June 30, 2007. Additionally, the non-cash adjustments to net income of depreciation and amortization, deferred taxes, minority interest in earnings of HEP and equity-based compensation resulted in an increase to operating cash flows of $38.3 million for the six months ended June 30, 2008 as compared to $24.4 million for the six months ended June 30, 2007. Distributions in excess of equity in earnings of HEP for the six months ended June 30, 2008 increased to $3.1 million compared to $2.8 million for the six months ended June 30, 2007. Changes in working capital items increased cash flows by $55.6 million during the six months ended June 30, 2008 compared to $26.0 million for the six months ended June 30, 2007, resulting mainly from an increase in accounts payable that was partially offset by an increase in accounts receivable. For the six months ended June 30, 2008, accounts receivable increased by $221.3 million compared to an increase of $5.9 million for the six months ended June 30, 2007 and accounts payable increased by $296.6 million compared to an increase of $9.1 million for the six months ended June 30, 2007. Also for the six months ended June 30, 2008, inventories increased by $18.6 million as compared to an increase of $14.0 million for the six months ended June 30, 2007. Additionally, for the six months ended June 30, 2008, turnaround expenditures amounted to $3.4 million as compared to $0.2 million for the six months ended June 30, 2007.

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Cash Flows — Investing Activities and Capital Projects

Net cash flows provided by investing activities were $71.5 million for the six months ended June 30, 2008 compared to net cash flows used of $274.4 million for the six months ended June 30, 2007, a net change of $345.9 million. Cash expenditures for property, plant and equipment for the six months ended June 30, 2008 totaled $198.8 million compared to $72.5 million for the same period in 2007. Capital expenditures for the six months ended June 30, 2008 include $12.2 million attributable to HEP. We also invested $303.3 million in marketable securities and received proceeds of $395.5 million from the sale or maturity of marketable securities during the six months ended June 30, 2008. Additionally for the six months ended June 30, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP on February 29, 2008. We are also presenting HEP’s March 1, 2008 cash balance as an inflow as a result of our reconsolidation of HEP effective March 1, 2008. For the six months ended June 30, 2008, we invested $360.0 million in marketable securities and received proceeds of $158.2 million from the sale or maturity of marketable securities.

Planned Capital Expenditures

Holly Corporation

Each year our Board of Directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total new capital budget for 2008 is approximately $37.5 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 2008 capital budget is comprised of $21.0 million for refining improvement projects for the Navajo Refinery, $7.7 million for projects at the Woods Cross Refinery, $1.6 million for marketing-related projects, $2.0 million for asphalt plant projects and $5.2 million for other miscellaneous projects.

At the Navajo Refinery, we will be installing a new 15,000 BPD hydrocracker and a new 28 MMSCFD 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 new low sulfur gasoline specifications required by the Environmental Protection Agency (“EPA”). The hydrocracker and hydrogen plant projects will provide improved heavy crude oil processing flexibility.

Additionally, we are revamping existing crude units and a solvent de-asphalter unit that will increase the crude capacity at the Navajo Refinery to approximately 100,000 BPD. The total budgeted amount for this expansion and heavy crude oil processing project is $245.0 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 in the first quarter of 2009. 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 is planned for the fourth quarter of 2009.

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. This new sulfur recovery unit will permit our Navajo Refinery to process 100% sour crude and is planned for start-up in the first quarter of 2009.

At the Woods Cross Refinery, we will be adding a new 15,000 BPD hydrocracker along with sulfur recovery and desalting equipment at our Woods Cross Refinery. The budgeted cost of these additions is approximately $105.0 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

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and up to 5,000 BPD of low-priced heavy Canadian crude oils. This 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 will 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, 2008.

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. HEP’s joint venture pipeline with Plains All American Pipeline, L.P. (“Plains”) will allow our Woods Cross Refinery to ship crude oil into the Salt Lake City area. HEP’s joint venture project with Plains is further described under the HEP section of this discussion of planned capital expenditures.

In December 2007, we entered into a definitive agreement with Sinclair to jointly build a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair will own the remaining 25% interest. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project including terminals is expected to be $300.0 million. Holly’s share of this cost is $225.0 million. Construction of this project is currently expected to be completed and operational in early 2010. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. On January 31, 2008, we entered into an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum. In July 2008, we purchased a terminal and rail facility located near Cedar City, Utah that will serve as a key component of our UNEV joint venture pipeline. We expect this acquisition to result in reduced construction costs.

On July 22, 2008, we announced an agreement by one of our subsidiaries to transport crude oil on Centurion Pipeline L.P.’s pipeline from Cushing, Oklahoma to Slaughter, Texas. Our Board of Directors has approved capital expenditures of up to $90.0 million to build the necessary infrastructure including a 70-mile pipeline from Slaughter, Texas to Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. We plan to grant HEP the option to purchase these transportation assets upon our completion of the project in 2009.

In 2008, we expect to expend approximately $390.0 million on currently approved capital projects, including sustaining capital and turnaround costs. This amount consists of certain carryovers of capital projects from previous years, less carryovers to subsequent years of certain of the currently approved capital projects.

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 $1.3 million in 2008, 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 (“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.

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

HEP

Each year the Holly Logistic Services, L.L.C. (“HLS”) board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in their current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. HEP’s total capital budget for 2008 is $53.7 million. This consists of budgeted costs for their south system expansion discussed below and other capital expansion and maintenance projects.

In October 2007, we entered into an agreement with HEP that amends the 15-year pipelines and terminals agreement (“HEP PTA”) under which HEP has agreed to expand their South System between Artesia, New Mexico and El Paso, Texas. The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be $48.3 million. Currently, HEP is expecting to complete this project by January 2009.

In November 2007, HEP executed a definitive agreement with Plains to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under construction by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the “SLC Pipeline”). Under the agreement, the SLC Pipeline will be owned by a joint venture company which will be owned 75% by Plains and 25% by HEP. Subject to the actual cost of the SLC Pipeline, HEP will purchase their 25% interest in the joint venture in late 2008, when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming and Utah, which is currently flowing on Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5 million finder’s fee that is payable to us upon the closing of their investment in the SLC Pipeline.

HEP is also studying several other projects, which are in various stages of analysis.

Cash Flows — Financing Activities

Net cash flows used for financing activities were $125.7 million for the six months ended June 30, 2008 compared $53.1 million for the six months ended June 30, 2007, an increase of $72.6 million. For the period from March 1, 2008 through June 30, 2008, HEP had net short-term borrowing of $20.0 million under the HEP Credit Agreement, paid $0.4 million in deferred financing costs and purchased $0.5 million in HEP common units in the open market for restricted unit grants. Under our common stock repurchase program, we purchased treasury stock of $136.9 million during the six months ended June 30, 2008 and $51.1 million during the six months ended June 30, 2007. Our treasury stock purchases for the six months ended June 30, 2008 and 2007, include $2.0 million and $6.7 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 six months ended June 30, 2008, we paid $14.1 million in dividends, received $0.3 million for common stock issued upon exercise of stock options, and recognized $3.4 million in excess tax benefits on our equity based compensation. During the six months ended June 30, 2007, we paid $10.1 million in dividends, received $0.5 million for common stock issued upon exercise of stock options and recognized $7.5 million in excess tax benefits on our equity based compensation.

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Contractual Obligations and Commitments

Holly Corporation

In connection with HEP’s purchase of the Crude Pipelines and Tankage Assets, we entered into a 15-year crude pipelines and tankage agreement with HEP. Under the HEP CPTA, we agreed to transport and store volumes of crude oil on HEP’s crude pipelines and tankage facilities that, at the agreed rates, will initially result in minimum annual payments to HEP of $25.3 million. The agreed upon tariffs on the crude pipelines will be adjusted each year at a rate equal to the percentage change in the PPI, but will not decrease as a result of a decrease in the PPI. Additionally, we amended the Omnibus Agreement to provide $7.5 million of indemnification for environmental noncompliance and remediation liabilities associated with the Crude Pipelines and Tankage Assets that occurred or existed prior to our sale to HEP for a period of up to fifteen years.

Other than the HEP CPTA discussed above, there were no other significant changes to our contractual obligations and commitments during the six months ended June 30, 2008.

HEP

We reconsolidated HEP effective March 1, 2008. During the three months ended June 30, 2008, HEP borrowed $10.0 million under the HEP Credit Agreement. HEP’s long-term contractual obligations as of June 30, 2008 are presented below:


			Payments Due by Period
			Less than						Over 5
	Total		1 Year		2-3 Years		4-5 Years		Years
	(In thousands)
HEP Senior Notes — principal	$	185,000	$	—	$	—	$	—	$	185,000
HEP Credit Agreement — principal		191,000		20,000		—		171,000		—
Interest on debt		112,299		20,523		41,046		27,605		23,125
Pipeline operating lease		54,161		5,855		11,711		11,711		24,884
Right of way leases		1,522		402		144		296		680
Other		23,102		5,066		4,806		4,305		8,925


Total	$	567,084	$	51,846	$	57,707	$	214,917	$	242,614

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, 2007. 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 2008.

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.

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New Accounting Pronouncements

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

Emerging Issues Task Force (“EITF”) No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of Financial Accounting Standards Board (“FASB”) Statement No. 115”

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, prescribes expanded disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels. Under this hierarchy, quoted prices in active markets for identical assets or liabilities are considered the most reliable evidence of fair value and are given the highest priority level (level 1). Unobservable inputs are considered the least reliable and are given the lowest priority level (level 3). We adopted this standard effective January 1, 2008. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows. We have investments in marketable debt and equity securities that are valued on a recurring basis using level 1 inputs. See Note 5 of the Consolidated Financial Statements for additional information. Additionally, HEP has interest rate swaps that are measured at fair value on a recurring basis using level 2 inputs. See Risk Management below for additional information on these swaps.

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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.

As of June 30, 2008, HEP had two interest rate swap contracts.

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


		Fair Value	Location of Offsetting
Interest Rate Swaps	Balance Sheet Location	(In thousands)	Balance
Cash flow hedge — $171 million LIBOR based debt	Other assets	$2,448	Accumulated other comprehensive loss

Fair value hedge — $60 million of 6.25% Senior Notes	Other assets	$647	Long-term debt

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

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

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have formed a risk management oversight committee that is made up of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.

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.

Set forth below is our calculation of EBITDA.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
Income	$	11,452		$	158,627		$	20,101		$	226,169
Add provision for income tax		5,856			86,136			10,551			120,822
Add interest expense		6,251			291			8,243			543
Subtract interest income		(3,826	)		(3,550	)		(7,381	)		(6,110	)
Add depreciation, depletion and amortization		15,929			10,641			29,238			22,092

EBITDA	$	35,662		$	252,145		$	60,752		$	363,516

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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.

Refinery Gross Margin

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Average per produced barrel:

*Navajo Refinery*
Net sales	$	133.89	$	93.17	$	117.33	$	84.69
Less cost of products		125.82		65.63		110.15		62.45

Refinery gross margin	$	8.07	$	27.54	$	7.18	$	22.24


*Woods Cross Refinery*
Net sales	$	133.09	$	96.51	$	117.56	$	83.67
Less cost of products		120.60		65.29		105.05		60.95

Refinery gross margin	$	12.49	$	31.22	$	12.51	$	22.72


*Consolidated*
Net sales	$	133.71	$	93.92	$	117.38	$	84.45
Less cost of products		124.62		65.56		109.03		62.10

Refinery gross margin	$	9.09	$	28.36	$	8.35	$	22.35

Net Operating Margin

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Average per produced barrel:

*Navajo Refinery*
Refinery gross margin	$	8.07	$	27.54	$	7.18	$	22.24
Less refinery operating expenses		5.68		4.26		4.98		4.22

Net operating margin	$	2.39	$	23.28	$	2.20	$	18.02

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
*Woods Cross Refinery*
Refinery gross margin	$	12.49	$	31.22	$	12.51	$	22.72
Less refinery operating expenses		8.13		4.22		7.17		4.50

Net operating margin	$	4.36	$	27.00	$	5.34	$	18.22


*Consolidated*
Refinery gross margin	$	9.09	$	28.36	$	8.35	$	22.35
Less refinery operating expenses		6.24		4.25		5.46		4.29

Net operating margin	$	2.85	$	24.11	$	2.89	$	18.06

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

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
*Navajo Refinery*
Average sales price per produced barrel sold	$	133.89		$	93.17	$	117.33		$	84.69
Times sales of produced refined products sold (BPD)		79,910			90,660		86,980			88,040
Times number of days in period		91			91		182			181

Refined product sales from produced products sold	$	973,623		$	768,658	$	1,857,376		$	1,349,555


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	133.09		$	96.51	$	117.56		$	83.67
Times sales of produced refined products sold (BPD)		23,790			26,130		24,550			27,120
Times number of days in period		91			91		182			181

Refined product sales from produced products sold	$	288,125		$	229,484	$	525,270		$	410,713


Sum of refined products sales from produced products sold from our two refineries ⁽⁴⁾	$	1,261,748		$	998,142	$	2,382,646		$	1,760,268
Add refined product sales from purchased products and rounding ⁽¹⁾		120,310			91,747		255,556			171,093

Total refined products sales		1,382,058			1,089,889		2,638,202			1,931,361
Add direct sales of excess crude oil⁽²⁾		314,486			91,843		517,437			153,523
Add other refining segment revenue⁽³⁾		39,657			35,045		57,938			57,475

Total refining segment revenue		1,736,201			1,216,777		3,213,577			2,142,359
Add HEP segment sales and other revenues		26,774			—		36,716			—
Add corporate and other revenues		886			114		1,287			505
Add (subtract) consolidations and eliminations		(20,039	)		106		(27,774	)		—

Sales and other revenues	$	1,743,822		$	1,216,997	$	3,223,806		$	2,142,864


(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 that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.

(3)		Other refining segment revenue includes the revenues associated with Holly Asphalt Company 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.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Average sales price per produced barrel sold	$	133.71	$	93.92	$	117.38	$	84.45
Times sales of produced refined products sold (BPD)		103,700		116,790		111,530		115,160
Times number of days in period		91		91		182		181

Refined product sales from produced products sold	$	1,261,748	$	998,142	$	2,382,646	$	1,760,268

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
*Navajo Refinery*
Average cost of products per produced barrel sold	$	125.82		$	65.63	$	110.15		$	62.45
Times sales of produced refined products sold (BPD)		79,910			90,660		86,980			88,040
Times number of days in period		91			91		182			181

Cost of products for produced products sold	$	914,939		$	541,451	$	1,743,714		$	995,156


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	120.60		$	65.29	$	105.05		$	60.95
Times sales of produced refined products sold (BPD)		23,790			26,130		24,550			27,120
Times number of days in period		91			91		182			181

Cost of products for produced products sold	$	261,086		$	155,249	$	469,374		$	299,186


Sum of cost of products for produced products sold from our two refineries ⁽⁴⁾	$	1,176,025		$	696,700	$	2,213,088		$	1,294,342
Add refined product costs from purchased products sold and rounding ⁽¹⁾		123,226			86,404		258,415			168,556

Total refined cost of products sold		1,299,251			783,104		2,471,503			1,462,898
Add crude oil cost of direct sales of excess crude oil⁽²⁾		311,963			92,054		514,176			153,906
Add other refining segment cost of products sold⁽³⁾		29,375			21,973		45,898			32,147

Total refining segment cost of products sold		1,640,589			897,131		3,031,577			1,648,951
Add (subtract) consolidations and eliminations		(20,039	)		106		(27,590	)		—

Costs of products sold (exclusive of depreciation, depletion and amortization)	$	1,620,550		$	897,237	$	3,003,987		$	1,648,951


(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 that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.

(3)		Other refining segment cost of products sold includes the cost of products for Holly Asphalt Company and costs attributable to sulfur credit sales.

(4)		The above calculations of costs of products for produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Average cost of products per produced barrel sold	$	124.62	$	65.56	$	109.03	$	62.10
Times sales of produced refined products sold (BPD)		103,700		116,790		111,530		115,160
Times number of days in period		91		91		182		181

Cost of products for produced products sold	$	1,176,025	$	696,700	$	2,213,088	$	1,294,342

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008			2007
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	5.68	$	4.26	$	4.98		$	4.22
Times sales of produced refined products sold (BPD)		79,910		90,660		86,980			88,040
Times number of days in period		91		91		182			181

Refinery operating expenses for produced products sold	$	41,304	$	35,145	$	78,835		$	67,247


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	8.13	$	4.22	$	7.17		$	4.50
Times sales of produced refined products sold (BPD)		23,790		26,130		24,550			27,120
Times number of days in period		91		91		182			181

Refinery operating expenses for produced products sold	$	17,601	$	10,034	$	32,036		$	22,089


Sum of refinery operating expenses per produced products sold from our two refineries ⁽²⁾	$	58,905	$	45,179	$	110,871		$	89,336
Add other refining segment operating expenses and rounding ⁽¹⁾		5,278		5,934		10,528			11,895

Total refining segment operating expenses		64,183		51,113		121,399			101,231
Add HEP segment operating expenses		9,985		—		13,661			—
Add corporate and other costs		7		3		7			14
Add (subtract) consolidations and eliminations		—		—		(184	)		—

Operating expenses (exclusive of depreciation, depletion and amortization)	$	74,175	$	51,116	$	134,883		$	101,245


(1)		Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of Holly Asphalt Company.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Average refinery operating expenses per produced barrel sold	$	6.24	$	4.25	$	5.46	$	4.29
Times sales of produced refined products sold (BPD)		103,700		116,790		111,530		115,160
Times number of days in period		91		91		182		181

Refinery operating expenses for produced products sold	$	58,905	$	45,179	$	110,871	$	89,336

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
*Navajo Refinery*
Net operating margin per barrel	$	2.39	$	23.28	$	2.20	$	18.02
Add average refinery operating expenses per produced barrel		5.68		4.26		4.98		4.22

Refinery gross margin per barrel		8.07		27.54		7.18		22.24
Add average cost of products per produced barrel sold		125.82		65.63		110.15		62.45

Average sales price per produced barrel sold	$	133.89	$	93.17	$	117.33	$	84.69
Times sales of produced refined products sold (BPD)		79,910		90,660		86,980		88,040
Times number of days in period		91		91		182		181

Refined products sales from produced products sold	$	973,623	$	768,658	$	1,857,376	$	1,349,555

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	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
*Woods Cross Refinery*
Net operating margin per barrel	$	4.36		$	27.00	$	5.34		$	18.22
Add average refinery operating expenses per produced barrel		8.13			4.22		7.17			4.50

Refinery gross margin per barrel		12.49			31.22		12.51			22.72
Add average cost of products per produced barrel sold		120.60			65.29		105.05			60.95

Average sales price per produced barrel sold	$	133.09		$	96.51	$	117.56		$	83.67
Times sales of produced refined products sold (BPD)		23,790			26,130		24,550			27,120
Times number of days in period		91			91		182			181

Refined products sales from produced products sold	$	288,125		$	229,484	$	525,270		$	410,713


Sum of refined products sales from produced products sold from our two refineries ⁽⁴⁾	$	1,261,748		$	998,142	$	2,382,646		$	1,760,268
Add refined product sales from purchased products and rounding ⁽¹⁾		120,310			91,747		255,556			171,093

Total refined products sales		1,382,058			1,089,889		2,638,202			1,931,361
Add direct sales of excess crude oil ⁽²⁾		314,486			91,843		517,437			153,523
Add other refining segment revenue ⁽³⁾		39,657			35,045		57,938			57,475

Total refining segment revenue		1,736,201			1,216,777		3,213,577			2,142,359
Add HEP segment sales and other revenues		26,774			—		36,716			—
Add corporate and other revenues		886			114		1,287			505
Add (subtract) consolidations and eliminations		(20,039	)		106		(27,774	)		—

Sales and other revenues	$	1,743,822		$	1,216,997	$	3,223,806		$	2,142,864


(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 that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding acquisition cost as inventory and then upon sale as cost of products sold. Additionally, we enter into buy/sell exchanges of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.

(3)		Other refining segment revenue includes the revenues associated with Holly Asphalt Company and revenue derived from sulfur credit sales.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Net operating margin per barrel	$	2.85	$	24.11	$	2.89	$	18.06
Add average refinery operating expenses per produced barrel		6.24		4.25		5.46		4.29

Refinery gross margin per barrel		9.09		28.36		8.35		22.35
Add average cost of products per produced barrel sold		124.62		65.56		109.03		62.10

Average sales price per produced barrel sold	$	133.71	$	93.92	$	117.38	$	84.45
Times sales of produced refined products sold (BPD)		103,700		116,790		111,530		115,160
Times number of days in period		91		91		182		181

Refined product sales from produced products sold	$	1,261,748	$	998,142	$	2,382,646	$	1,760,268

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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

On July 2, 2008, the United States District Court for the District of Utah entered a Consent Decree approving the terms of an agreement that had been entered into in April 2008 by the EPA, the State of Utah and us concerning alleged Federal CAA liabilities relating to our Woods Cross Refinery and arising from actions taken or not taken by prior owners of the refinery. The Consent Decree includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The Consent Decree also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips, the prior owner of the refinery, 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 is approximately $1.4 million with respect to the Consent Decree.

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.

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

Under our common stock repurchase program, 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 second quarter of 2008.


							Maximum Dollar
					Total Number of		Value of Shares Yet
					Shares Purchased		to be Purchased
					under Approved		under Approved
	Total Number of		Average price		Stock Repurchase		Stock Repurchase
Period	Shares Purchased		Paid Per Share		Program		Program
April 2008		602,862	$	46.48		602,862	$	58,994,269
May 2008		—	$	—		—	$	58,994,269
June 2008		—	$	—		—	$	58,994,269

Total for April to June 2008		602,862	$	46.48		602,862

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

At the annual meeting of stockholders on May 8, 2008, all seven of the nominees for directors as listed in the proxy statement were elected.

Election of Directors


	Total Votes		Total Votes
	“For”		“Withheld”
Buford P. Berry		44,872,451		366,835
Matthew P. Clifton		44,755,027		484,259
Marcus R. Hickerson		37,597,095		7,642,191
Thomas K. Matthews, II		44,763,367		475,919
Robert G. McKenzie		44,796,243		443,043
Jack P. Reid		44,754,075		485,211
Paul T. Stoffel		44,875,831		363,455

Our stockholders approved the ratification of the Board’s selection of Ernst & Young LLP as the Company’s auditor for 2008.

Total Votes

Broker

“For”

“Withheld”

Abstentions

Non-Votes

44,398,933

821,146

19,207

—

Item 6. Exhibits

(a) Exhibits


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

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

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

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


+		Filed herewith.

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SIGNATURES

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


	HOLLY CORPORATION (Registrant)
Date: August 8, 2008	/s/ Bruce R. Shaw
	Bruce R. Shaw
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)


	/s/ Scott C. Surplus
	Scott C. Surplus
	Vice President and Controller (Principal Accounting Officer)

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