HF Sinclair 10-Q 2009 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period endedMarch 31, 2009

OR

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

For the transition period from                     to                     

Commission File Number1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	75-1056913
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

100 Crescent Court, Suite 1600 Dallas, Texas	75201-6915
(Address of principal executive offices)	(Zip Code)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes o No o

The registrant has not yet been phased in to the Interactive Data File requirements.

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
(Do not check if a smaller reporting company) Smaller reporting company o

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

50,101,768 shares of Common Stock, par value $.01 per share, were outstanding on April 30, 2009.

HOLLY CORPORATION
INDEX

		Page
PART I.	FINANCIAL INFORMATION
Forward-Looking Statements			3
Definitions			4
Item 1.	Financial Statements		6
	Consolidated Balance Sheets March 31, 2009 (Unaudited) and December 31, 2008		6
	Consolidated Statements of Income (Unaudited) Three Months Ended March 31, 2009 and 2008		7
	Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2009 and 2008		8
	Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, 2009 and 2008		9
	Notes to Consolidated Financial Statements (Unaudited)		10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		38
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles			38
Item 4.	Controls and Procedures		44
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		45
Item 6.	Exhibits		47
Signatures			49
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 and environmental 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;

• our ability to complete the acquisition of the Tulsa refinery and successfully integrate its operations into our business;

• 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, 2008 and in conjunction with the discussion in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the headings “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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DEFINITIONS

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

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

     “BPD” means the number of barrels per calendar 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.

     “Black wax crude oil”is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain characteristics that require specific facilities to transport, store and refine into transportation fuels.

     “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 main source of hydrogen for the refinery.

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

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

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

     “FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.

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

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

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

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

     “Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.

     “LPG” means liquid petroleum gases.

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

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

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

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

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

     “PPM” means parts-per-million.

     “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 and amortization costs.

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

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

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

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

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

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Item 1.Financial Statements

HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

	March 31,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	53,878		$	40,805
Marketable securities		587			49,194
Accounts receivable: Product and transportation		133,489			128,337
Crude oil resales		170,198			161,427
		303,687			289,764
Inventories:                Crude oil and refined products		145,513			107,811
Materials and supplies		17,411			17,924
		162,924			125,735
Income taxes receivable		5,841			6,350
Prepayments and other		18,281			18,775
Total current assets		545,198			530,623
Properties, plants and equipment, at cost		1,604,508			1,509,701
Less accumulated depreciation		(319,263	)		(304,379	)
		1,285,245			1,205,322
Marketable securities (long-term)		—			6,009
Other assets:                   Turnaround costs		60,277			34,309
Goodwill		27,542			27,542
Intangibles and other		95,605			70,420
		183,424			132,271
Total assets	$	2,013,867		$	1,874,225
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	415,592		$	391,142
Accrued liabilities		41,987			42,016
Short-term debt — Holly Corporation		55,000			—
Short-term debt — Holly Energy Partners		—			29,000
Total current liabilities		512,579			462,158
Long-term debt — Holly Energy Partners		411,485			341,914
Deferred income taxes		71,328			69,491
Other long-term liabilities		67,391			64,330
Equity:
Holly Corporation 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; 73,543,873 and 73,543,873 shares issued as of March 31, 2009 and December 31, 2008, respectively		735			735
Additional capital		119,365			121,298
Retained earnings		1,159,881			1,145,388
Accumulated other comprehensive loss		(35,289	)		(35,081	)
Common stock held in treasury, at cost — 23,442,105 and 23,600,653 shares as of March 31, 2009 and December 31, 2008, respectively		(685,931	)		(690,800	)
Total Holly Corporation stockholders’ equity		558,761			541,540
Noncontrolling interest		392,323			394,792
Total equity		951,084			936,332
Total liabilities and equity	$	2,013,867		$	1,874,225

     See accompanying notes.

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

	Three Months Ended
	March 31,
	2009			2008
Sales and other revenues	$	650,823		$	1,479,984
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		511,654			1,383,437
Operating expenses (exclusive of depreciation and amortization)		67,202			60,708
General and administrative expenses (exclusive of depreciation and amortization)		11,747			12,937
Depreciation and amortization		20,321			13,309
Total operating costs and expenses		610,924			1,470,391
Income from operations		39,899			9,593
Other income (expense):
Equity in earnings of SLC Pipeline		175			—
Interest income		2,196			3,555
Interest expense		(6,239	)		(1,992	)
Equity in earnings of Holly Energy Partners		—	��		2,990
		(3,868	)		4,553
Income from operations before income taxes		36,031			14,146
Income tax provision:
Current		10,160			6,318
Deferred		1,971			(1,623	)
		12,131			4,695
Net income		23,900			9,451
Less net income attributable to noncontrolling interest		1,955			802
Net income attributable to Holly Corporation stockholders	$	21,945		$	8,649
Net income per share attributable to Holly Corporation stockholders — basic	$	0.44		$	0.17
Net income per share attributable to Holly Corporation stockholders — diluted	$	0.44		$	0.17
Cash dividends declared per common share	$	0.15		$	0.15
Average number of common shares outstanding:
Basic		50,042			51,165
Diluted		50,171			51,515

See accompanying notes.

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

	Three Months Ended
	March 31,
	2009			2008
Cash flows from operating activities:
Net income	$	23,900		$	9,451
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,321			13,309
Deferred income taxes		1,971			(1,623	)
Equity based compensation expense		1,447			178
Equity in earnings of SLC Pipeline		(175	)		—
Distributions in excess of equity in earnings in Holly Energy Partners		—			3,067
Change in fair value — interest rate swaps		216			—
(Increase) decrease in current assets:
Accounts receivable		(15,423	)		(49,717	)
Inventories		(37,189	)		5,626
Income taxes receivable		509			2,905
Prepayments and other		494			1,855
Increase (decrease) in current liabilities:
Accounts payable		9,597			125,125
Accrued liabilities		14,797			(9,989	)
Turnaround expenditures		(26,983	)		(1,398	)
Other, net		4,203			61
Net cash provided by (used for) operating activities		(2,315	)		98,850
Cash flows from investing activities:
Additions to properties, plants and equipment — Holly Corporation		(88,658	)		(69,508	)
Additions to properties, plants and equipment — Holly Energy Partners		(10,570	)		(3,253	)
Investment in joint venture — Holly Energy Partners		(25,500	)		—
Purchases of marketable securities		(128,707	)		(207,557	)
Sales and maturities of marketable securities		183,096			185,772
Proceeds from sale of crude pipeline and tankage assets		—			171,000
Increase in cash due to consolidation of Holly Energy Partners		—			7,295
Investment in Holly Energy Partners		—			(290	)
Net cash provided by (used for) investing activities		(70,339	)		83,459
Cash flows from financing activities:
Net borrowings under credit agreement — Holly Corporation		55,000			—
Net borrowings under credit agreement — Holly Energy Partners		40,000			10,000
Purchase of treasury stock		(1,214	)		(102,850	)
Dividends		(7,502	)		(6,410	)
Distributions to noncontrolling interest		(6,916	)		—
Contribution from joint venture partner		4,750			19
Issuance of common stock upon exercise of options		45			254
Excess tax benefit from equity based compensation		2,180			3,225
Purchase of units for restricted grants — Holly Energy Partners		(616	)		—
Deferred financing costs		—			(365	)
Net cash provided by (used for) financing activities		85,727			(96,127	)
Cash and cash equivalents:
Increase (decrease) for the period		13,073			86,182
Beginning of period		40,805			94,369
End of period	$	53,878		$	180,551
Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	8,774		$	5,080
Income taxes	$	3,457		$	298

See accompanying notes.

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

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Net income	$	23,900		$	9,451
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain (loss) on available-for-sale securities		(463	)		826
Reclassification adjustment to net income on sale of marketable securities		236			(1,307	)
Total unrealized gain (loss) on available-for-sale securities		(227	)		(481	)
Other comprehensive loss of Holly Energy Partners:
Change in fair value of cash flow hedge		(250	)		(4,349	)
Other comprehensive loss before income taxes		(477	)		(4,830	)
Income tax benefit		(133	)		(885	)
Other comprehensive loss		(344	)		(3,945	)
Total comprehensive income		23,556			5,506
Less comprehensive income (loss) attributable to noncontrolling interest		1,819			(1,557	)
Comprehensive income attributable to Holly Corporation stockholders	$	21,737		$	7,063

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

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

     As of the close of business on March 31, 2009, 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 which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and

• owned a 46% interest in Holly Energy Partners, L.P. (“HEP”) which includes our 2% general partner interest, which has logistic assets including approximately 2,600 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; two refinery truck rack facilities; a refined products tank farm facility; on-site crude oil tankage at both our Navajo and Woods Cross Refineries and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”).

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of March 31, 2009, the consolidated results of operations and comprehensive income for the three months ended March 31, 2009 and 2008 and consolidated cash flows for the three months ended March 31, 2009 and 2008 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, 2008 filed with the SEC.

Our results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year.

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 March 31, 2009 our allowance for doubtful accounts reserve was $2.5 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 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"
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160 which changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. We adopted this standard effective January 1, 2009. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the non-controlling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interests in earnings of Holly Energy Partners,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retroactive basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”In March 2008, the FASB issued SFAS No. 161 which amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. We adopted this standard effective as of January 1, 2009. See Note 8 for disclosure of HEP’s derivative instruments and hedging activity.

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 March 31, 2009, 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.

HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standards Board Interpretation (“FIN”) No. 46R. Under the provisions of FIN No. 46R, HEP’s acquisition of the Crude Pipelines and Tankage Assets (discussed below) qualified as a reconsideration event whereby we reassessed whether HEP continued to qualify as a VIE. Following this transfer, we determined that HEP continued to qualify as a VIE, and furthermore, we determined that our beneficial interest in HEP exceeded 50%. Accordingly, we reconsolidated HEP effective March 1, 2008 and no longer account for our investment in HEP under the equity method of accounting. As a result, our consolidated financial statements include the results of HEP.

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 between Artesia and Roswell, New Mexico, a leased jet fuel terminal in 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 serves our refineries in New Mexico and Utah under three 15-year pipeline, terminal and tankage agreements. The majority of HEP’s business is devoted to providing transportation, storage and terminalling services to us. We have an agreement that relates to the pipelines and terminals contributed to HEP by us at the time of their initial public offering in 2004 and expires in 2019 (the “HEP PTA”). Our second agreement relates to the intermediate pipelines sold to HEP in July 2005 and expires in 2020 (the “HEP IPA”). Our third agreement relates to the Crude Pipelines and Tankage Assets sold to HEP as discussed above and expires in February 2023 (the “HEP CPTA”).

Under these agreements, we agreed to transport and store volumes of refined product and crude oil on HEP’s pipelines and terminal and tankage facilities that result in minimum annual payments to HEP. These minimum

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annual payments are adjusted each year at a percentage change equal to the change in the producer price index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the percentage change in the PPI or the Federal Energy Regulatory Commission (“FERC”) index, but generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically.

The balance sheet impact of our reconsolidation of HEP on March 1, 2008 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 $336.9 million, an increase in goodwill, intangibles and other assets of $81.5 million, an increase in current liabilities of $19.6 million, an increase in long-term debt of $338.5 million, a decrease in other long-term liabilities of $0.5 million, an increase in minority interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.

HEP closed on a public offering of 2,000,000 common units priced at $27.80 per common unit on May 8, 2009. In connection with the offering, HEP granted the underwriters a 30-day option to purchase up to 300,000 additional common units. Proceeds from the offering will be used to repay bank debt and for general partnership purposes. In addition, we made a capital contribution to HEP to maintain our 2% general partner interest.

NOTE 3: Earnings Per Share

Basic earnings per share attributable to Holly Corporation stockholders is calculated as net income attributable to Holly Corporation stockholders 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
	March 31,
	2009		2008
	(In thousands, except per share data)
Net Income attributable to Holly Corporation stockholders	$	21,945	$	8,649
Average number of shares of common stock outstanding		50,042		51,165
Effect of dilutive stock options, variable restricted shares and performance share units		129		350
Average number of shares of common stock outstanding assuming dilution		50,171		51,515
Net income per share attributable to Holly Corporation stockholders — basic	$	0.44	$	0.17
Net income per share attributable to Holly Corporation stockholders — diluted	$	0.44	$	0.17

NOTE 4: Stock-Based Compensation

Holly Corporation

On March 31, 2009, we had three principal share-based compensation plans (“Long-Term Incentive Compensation Plan”) which are described below. The compensation cost that has been charged against income for these plans was $1.3 million and $1.9 million for the three months ended March 31, 2009 and 2008, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $0.5 million and $0.7 million for the three months ended March 31, 2009 and 2008, 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. At March 31, 2009, 2,158,118 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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Additionally, HEP maintains share-based compensation plans for HEP directors and select Holly Logistic Services, L.L.C. executives and employees. Compensation cost attributable to HEP’s share-based compensation plans for the three months ended March 31, 2009 and 2008 was $0.4 million and $0.1 million, respectively.

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 following the grant date. There have been no options granted since December 2001. The fair value on the date of grant of each option awarded was estimated using the Black-Scholes option pricing model.

A summary of option activity and changes during the three months ended March 31, 2009 is presented below:

						Weighted-
				Weighted		Average		Aggregate
				Average		Remaining		Intrinsic
				Exercise		Contractual		Value
Options	Shares			Price		Term		($000)
Outstanding at January 1, 2009		85,200		$	2.98
Exercised		(15,000	)		2.98
Outstanding and exercisable at March 31, 2009		70,200		$	2.98		1.9	$	1,279

The total intrinsic value of options exercised during the three months ended March 31, 2009 and 2008, was $0.3 million and $3.1 million, respectively.

Cash received from option exercises under the stock option plans was zero and $0.3 million for the three months ended March 31, 2009 and 2008, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $0.1 million and $1.2 million for the three months ended March 31, 2009 and 2008, respectively.

Restricted Stock

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

A summary of restricted stock grant activity and changes during the three months ended March 31, 2009 is presented below:

				Weighted
				Average		Aggregate
				Grant-Date		Intrinsic Value
Restricted Stock	Grants			Fair Value		($000)
Outstanding at January 1, 2009 (nonvested)		235,310		$	35.86
Vesting and transfer of ownership to recipients		(127,252	)		26.63
Granted		142,473			22.71
Forfeited		(2,412	)		35.04
Outstanding at March 31, 2009 (nonvested)		248,119		$	33.06	$	5,260

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The total fair value of restricted stock vested and transferred to recipients during the three months ended March 31, 2009 and 2008 was $3.4 million and $2.7 million, respectively. As of March 31, 2009, there was $4.3 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.2 years.

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 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 “financial performance” criteria.

During the three months ended March 31, 2009, we granted 115,356 performance share units with a fair value based on our grant date closing stock price of $22.86. These units are payable in stock and are subject to certain financial performance criteria.

The fair value of each performance share unit award is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of March 31, 2009, estimated share payouts for outstanding nonvested performance share unit awards ranged from 120% to 170%.

A summary of performance share unit activity and changes during the three months ended March 31, 2009 is presented below:

Performance Share Units	Grants
Outstanding at January 1, 2009 (non-vested)		169,669
Vesting and payment of benefit to recipients		(72,059	)
Granted		115,356
Forfeited		(4,995	)
Outstanding at March 31, 2009 (non-vested)		207,971

For the three months ended March 31, 2009, we issued 110,971 shares of our common stock (representing a 154% share payout) having a fair value of $2.2 million related to vested performance share units. Based on the weighted average grant date fair value of $35.44, there was $3.1 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 1.4 years.

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

Our investment portfolio consists of cash and cash equivalents at March 31, 2009. In addition, we own 1,000,000 shares of Connacher Oil and Gas Limited common stock that was received as partial consideration upon the sale of our Montana Refinery in 2006.

We also 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 including investments in equity securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices (level 1 inputs). Interest income is recorded as earned. Unrealized gains and losses, net

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of related income taxes, are considered temporary and are 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 March 31, 2009:

	Available-for-Sale Securities
			Gross			Estimated
			Unrealized			Fair Value
	Amortized		Gain			(Net Carrying
	Cost		(Loss)			Amount)
	(In thousands)
Equity securities	$	604	$	(17	)	$	587

For the three months ended March 31, 2009 and 2008 we received a total of $183.1 million and $185.8 million, respectively, related to sales and maturities of our marketable debt securities.

NOTE 6: Inventories

Inventory consists of the following components:

	March 31,		December 31,
	2009		2008
	(In thousands)
Crude oil	$	27,977	$	22,897
Other raw materials and unfinished products(1)		23,706		12,286
Finished products(2)		93,830		72,628
Process chemicals(3)		3,634		3,800
Repairs and maintenance supplies and other		13,777		14,124
	$	162,924	$	125,735

(1)	Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
(2)	Finished products include gasolines, jet fuels, diesels, asphalts, LPG’s and residual fuels.
(3)	Process chemicals include catalysts, additives and other chemicals.

NOTE 7: Environmental

Consistent with our accounting policy for environmental remediation costs, we expensed $2.6 million and zero for the three months ended March 31, 2009 and 2008, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $9.4 million and $7.3 million at March 31, 2009 and December 31, 2008, respectively, of which $5.9 million and $4.2 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.

NOTE 8: Debt

Credit Facility

At March 31, 2009, we had a $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) 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 March 31, 2009. At March 31, 2009, we had outstanding

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borrowings of $55.0 million and letters of credit totaling $9.8 million under the Credit Agreement. At that level of usage, the unused commitment under the Credit Agreement was $110.2 million at March 31, 2009.

In April 2009, we amended the Credit Agreement increasing the size from $175.0 million to $300.0 million (the “Amended Credit Agreement”). The Amended Credit Agreement expires in March 2013 and has an option to increase the facility to $450.0 million subject to certain conditions. The general terms of the Amended Credit Agreement did not change.

HEP has a $300.0 million senior secured revolving credit agreement expiring in August 2011 (the “HEP Credit Agreement”). The HEP Credit Agreement is available to fund capital expenditures, acquisitions and working capital and or other general partnership purposes. 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 March 31, 2009 consist of $4.3 million in cash and cash equivalents, $4.1 million in trade accounts receivable and other current assets, $359.3 million in property, plant and equipment, net and $108.5 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. 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 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. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. 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 on up to $35.0 million of the principal amount of the HEP Senior Notes.

The carrying amounts of HEP’s long-term debt are as follows:

	March 31,			December 31,
	2009			2008
	(In thousands)
HEP Credit Agreement	$	240,000		$	200,000
HEP Senior Notes
Principal		185,000			185,000
Unamortized discount		(15,566	)		(16,223	)
Unamortized premium — de-designated fair value hedge		2,051			2,137
		171,485			170,914
Total debt		411,485			370,914
Less short-term borrowings under HEP Credit Agreement(1)		—			29,000
Total long-term debt(1)	$	411,485		$	341,914

(1) HEP is currently classifying all borrowings under the HEP Credit Agreement as long-term. At December 31, 2008, certain borrowings under the HEP Credit Agreement were classified as short-term.

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Interest Rate Risk Management

HEP uses interest rate derivatives to manage their exposure to interest rate risk. As of March 31, 2009, HEP had three interest rate swap contracts.

HEP has an interest rate swap that hedges 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 in February 2008. 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%, which equaled an effective interest rate of 5.49% as of March 31, 2009. The maturity of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

HEP has designated this interest rate swap as a cash flow hedge. Based on their assessment of effectiveness using the change in variable cash flows method, HEP determined that the interest rate swap is effective in offsetting the variability in interest payments on the $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 the offsetting fair value adjustment 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 to be paid or received 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 March 31, 2009, HEP had no ineffectiveness on their cash flow hedge.

HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 2.42% as of March 31, 2009. The maturity of the swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.

In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of their hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three months ended March 31, 2009, HEP recognized $0.2 million in interest expense attributable to fair value adjustments to its interest rate swaps.

HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction to interest expense.

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The interest rate swaps are valued using level 2 inputs. Additional information on HEP’s interest rate swaps is as follows:

	Balance Sheet				Location of
Interest Rate Swaps	Location	Fair Value			Offsetting Balance	Offsetting Amount
					(In thousands)
Asset
Fixed-to-variable interest rate swap — $60 million of HEP 6.25% Senior Notes	Other assets	$	3,762		Long-term debt - HEP	$	(2,051	)
					Equity		(1,942	)(1)
					Interest expense		231	(2)
		$	3,762			$	(3,762	)
Liability
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	(13,117	)	Accumulated other comprehensive loss	$	13,117
Variable-to-fixed interest rate swap — $60 million	Other long-term liabilities				Equity		4,166	(1)
			(4,064	)	Interest expense		(102	)
		$	(17,181	)		$	17,181

(1)	Represents prior year charges to interest expense.
(2)	Net of amortization of premium attributable to de-designated hedge.

NOTE 9: Income Taxes

Our effective tax rate for the first quarter of 2009 and 2008 was 33.7% and 33.2%, respectively.

NOTE 10: Stockholders’ Equity

During the three months ended March 31, 2009, we repurchased at current market price from certain officers and key employees 59,934 shares of our common stock at a cost of approximately $1.2 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

NOTE 11: Other Comprehensive Income

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

				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
For the three months ended March 31, 2009
Unrealized loss on available-for-sale securities	$	(227	)	$	(89	)	$	(138	)
Unrealized loss on HEP cash flow hedge		(250	)		(44	)		(206	)
Other comprehensive loss		(477	)		(133	)		(344	)
Less other comprehensive loss attributable to noncontrolling interest		(136	)		—			(136	)
Other comprehensive loss attributable to Holly Corporation stockholders	$	(341	)	$	(133	)	$	(208	)
For the three months ended March 31, 2008
Unrealized loss on available-for-sale securities	$	(481	)	$	(187	)	$	(294	)
Unrealized loss on HEP cash flow hedge		(4,349	)		(698	)		(3,651	)
Other comprehensive loss		(4,830	)		(885	)		(3,945	)
Less other comprehensive loss attributable to noncontrolling interest		(2,359	)		—			(2,359	)
Other comprehensive loss attributable to Holly Corporation stockholders	$	(2,471	)	$	(885	)	$	(1,586	)

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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:

	March 31,			December 31,
	2009			2008
	(In thousands)
Pension obligation adjustment	$	(29,409	)	$	(29,409	)
Retiree medical obligation adjustment		(2,202	)		(2,202	)
Unrealized loss on available-for-sale securities		(10	)		128
Unrealized loss on HEP cash flow hedge		(3,668	)		(3,598	)
Accumulated other comprehensive loss	$	(35,289	)	$	(35,081	)

NOTE 12: Retirement Plan

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

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.

The net periodic pension expense consisted of the following components:

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Service cost	$	1,088		$	1,090
Interest cost		1,231			1,193
Expected return on assets		(1,002	)		(1,144	)
Amortization of prior service cost		98			98
Amortization of net loss		19			351
Net periodic benefit cost	$	1,434		$	1,588

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2009 and 2008 net periodic benefit cost. We expect to contribute between $5.0 million and $15.0 million to the retirement plan in 2009.

NOTE 13: 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 FERC in proceedings brought by us and other parties against SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize 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

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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. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million. On May 1, 2009, SFPP notified us that it may seek to invoke its rights to terminate the October 22, 2008, settlement rates and to file higher prospective rates. We and other shippers have begun discussions with SFPP to discuss its notification and possible alternatives to the termination of the settlement. We are not in a position to predict the outcome of these negotiations.

We are a party to various other litigation and proceedings 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 14: 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. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

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 and Woods Cross Refineries. 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. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 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 its pipelines, by leasing certain pipeline capacity to Alon USA, Inc., by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its 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 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.

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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			Consolidations
					and			and
	Refining		HEP(1)		Other			Eliminations			Consolidated Total
	(In thousands)
Three Months Ended March 31, 2009
Sales and other revenues	$	636,910	$	32,125	$	99		$	(18,311	)	$	650,823
Depreciation and amortization	$	11,951	$	7,174	$	1,196		$	—		$	20,321
Income (loss) from operations	$	38,705	$	12,830	$	(11,636	)	$	—		$	39,899
Capital expenditures	$	88,238	$	10,570	$	420		$	—		$	99,228
Three Months Ended March 31, 2008
Sales and other revenues	$	1,477,376	$	9,942	$	401		$	(7,735	)	$	1,479,984
Depreciation and amortization	$	10,281	$	2,010	$	1,018		$	—		$	13,309
Income (loss) from operations	$	18,884	$	3,734	$	(13,025	)	$	—		$	9,593
Capital expenditures	$	68,816	$	3,252	$	693		$	—		$	72,761

(1) HEP segment revenues from external customers were $13.9 million and $2.2 million for the three months ended March 31, 2009 and 2008, respectively.

					Corporate		Consolidations
					and		and
	Refining		HEP		Other		Eliminations			Consolidated Total
	(In thousands)
March 31, 2009
Cash, cash equivalents and investments in marketable securities	$	—	$	4,321	$	50,144	$	—		$	54,465
Total assets	$	1,447,571	$	488,311	$	96,543	$	(18,558	)	$	2,013,867
December 31, 2008
Cash, cash equivalents and investments in marketable securities	$	—	$	5,269	$	90,739	$	—		$	96,008
Total assets	$	1,288,211	$	458,049	$	141,768	$	(13,803	)	$	1,874,225

Note 15: Subsequent Event

On April 16, 2009, we entered into a definitive agreement with Sunoco Inc. (R&M) (“Sunoco”) to acquire their 85,000 barrel per day (“bpd”) refinery located in Tulsa, Oklahoma and associated businesses (the “Tulsa Refinery”) for $65.0 million. Under the terms of the agreement, we will also purchase related inventory which will be valued at market prices at closing. Additionally, we will receive an assignment of the Sunoco specialty lubricant product trademarks in North America and a license to use the same in Central and South America. The transaction, which is expected to close by June 1, 2009, is subject to approval by certain regulatory agencies as well as other usual and customary closing conditions.

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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,” “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. This Quarterly Report on Form 10-Q contains 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.

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”). As of March 31, 2009, our refineries had a combined crude capacity of 131,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At March 31, 2009, we also owned a 46% interest in 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. For the three months ended March 31, 2009, sales and other revenues were $650.8 million and net income attributable to Holly Corporation stockholders was $21.9 million. For the three months ended March 31, 2008, sales and other revenues were $1,480.0 million and net income attributable to Holly corporation stockholders was $8.6 million. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the three months ended March 31, 2009 were $610.9 million, a decrease from $1,470.4 million for the three months ended March 31, 2008.

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 between Artesia and Roswell, New Mexico and a jet fuel terminal in Roswell, New Mexico. 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. 46R. Under the provisions of FIN No. 46R, HEP’s purchase of the Crude Pipelines and Tankage Assets qualified as a reconsideration event whereby we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded 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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RESULTS OF OPERATIONS

Financial Data (Unaudited)

	Three Months Ended
	March 31,						Change from 2008
	2009			2008			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	650,823		$	1,479,984		$	(829,161	)		(56.0	)%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation, depletion and amortization)		511,654			1,383,437			(871,783	)		(63.0	)
Operating expenses (exclusive of depreciation, depletion and amortization)		67,202			60,708			6,494			10.7
General and administrative expenses (exclusive of depreciation, depletion and amortization)		11,747			12,937			(1,190	)		(9.2	)
Depreciation, depletion and amortization		20,321			13,309			7,012			52.7
Total operating costs and expenses		610,924			1,470,391			(859,467	)		(58.5	)
Income from operations		39,899			9,593			30,306			315.9
Other income (expense):
Equity in earnings of SLC Pipeline		175			—			175			—
Interest income		2,196			3,555			(1,359	)		(38.2	)
Interest expense		(6,239	)		(1,992	)		(4,247	)		213.2
Equity in earnings of HEP		—			2,990			(2,990	)		(100.0	)
		(3,868	)		4,553			(8,421	)		(185.0	)
Income from operations before income taxes		36,031			14,146			21,885			154.7
Income tax provision		12,131			4,695			7,436			158.4
Net income(1)		23,900			9,451			14,449			152.9	%
Less noncontrolling interest in net income(1)		1,955			802			1,153			143.8
Net income attributable to Holly Corporation stockholders(1)	$	21,945		$	8,649		$	13,296			153.7	%
Net income per share attributable to Holly Corporation stockholders — basic	$	0.44		$	0.17		$	0.27			158.8	%
Net income per share attributable to Holly Corporation stockholders — diluted	$	0.44		$	0.17		$	0.27			158.8	%
Cash dividends declared per common share	$	0.15		$	0.15		$	—			—	%
Average number of common shares outstanding:
Basic		50,042			51,165			(1,123	)		(2.2	)%
Diluted		50,171			51,515			(1,344	)		(2.6	)%

Balance Sheet Data (Unaudited)

	March 31,		December 31,
	2009		2008
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	54,465	$	96,008
Working capital	$	32,619	$	68,465
Total assets	$	2,013,867	$	1,874,225
Long-term debt — HEP	$	411,485	$	341,914
Total equity(1)	$	951,084	$	936,332

(1) During the first quarter of 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” As a result, net income attributable to the non-controlling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly

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Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interest in earnings of HEP,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retroactive basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

Other Financial Data (Unaudited)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Net cash provided by (used for) operating activities	$	(2,315	)	$	98,850
Net cash provided by (used for) investing activities	$	(70,339	)	$	83,459
Net cash provided by (used for) financing activities	$	85,727		$	(96,127	)
Capital expenditures	$	99,228		$	72,761
EBITDA(2)	$	58,440		$	25,090

(2) Earnings before interest, taxes, depreciation and amortization, which we refer to as (“EBITDA”), is calculated as net income attributable to Holly Corporation stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation 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. Intersegment transactions are eliminated in our consolidated financial statements and are included in Consolidations and Eliminations.

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Sales and other revenues
Refining(3)	$	636,910		$	1,477,376
HEP(4)		32,125			9,942
Corporate and Other		99			401
Consolidations and Eliminations		(18,311	)		(7,735	)
Consolidated	$	650,823		$	1,479,984
Operating Income (loss)
Refining(3)	$	38,705		$	18,884
HEP(4)		12,830			3,788
Corporate and Other		(11,636	)		(13,025	)
Consolidations and Eliminations		—			(54	)
Consolidated	$	39,899		$	9,593

(3) 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

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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.

(4)

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 its 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 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 and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

	Three Months Ended
	March 31,
	2009			2008
Navajo Refinery
Crude charge (BPD)(1)		57,685			83,200
Refinery production (BPD)(2)		63,061			94,640
Sales of produced refined products (BPD)		62,147			94,050
Sales of refined products (BPD)(3)		71,138			105,410
Refinery utilization(4)		67.9	%		97.9	%
Average per produced barrel(5)
Net sales	$	57.37		$	103.26
Cost of products(6)		44.92			96.83
Refinery gross margin		12.45			6.43
Refinery operating expenses(7).		6.17			4.39
Net operating margin	$	6.28		$	2.04
Feedstocks:
Sour crude oil		87	%		80	%
Sweet crude oil		8	%		8	%
Other feedstocks and blends		5	%		12	%
Total		100	%		100	%
Sales of produced refined products:
Gasolines		61	%		58	%
Diesel fuels		31	%		32	%
Jet fuels		1	%		1	%
Fuel oil		1	%		3	%
Asphalt		3	%		3	%
LPG and other		3	%		3	%
Total		100	%		100	%

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	Three Months Ended
	March 31,
	2009			2008
Woods Cross Refinery
Crude charge (BPD)(1)		23,309			24,960
Refinery production (BPD)(2)		23,286			25,440
Sales of produced refined products (BPD)		27,024			25,300
Sales of refined products (BPD)(3)		27,664			27,530
Refinery utilization(4)		75.2	%		96.0	%
Average per produced barrel(5)
Net sales	$	50.31		$	102.96
Cost of products(6)		39.57			90.42
Refinery gross margin		10.74			12.54
Refinery operating expenses(7)		6.92			6.26
Net operating margin	$	3.82		$	6.28
Feedstocks:
Sour crude oil		3	%		3	%
Sweet crude oil		66	%		76	%
Black wax crude oil		29	%		16	%
Other feedstocks and blends		2	%		5	%
Total		100	%		100	%
Sales of produced refined products:
Gasolines		68	%		68	%
Diesel fuels		23	%		23	%
Jet fuels		1	%		—	%
Fuel oil		4	%		5	%
Asphalt		1	%		—	%
LPG and other		3	%		4	%
Total		100	%		100	%
Consolidated
Crude charge (BPD)(1)		80,994			108,160
Refinery production (BPD)(2)		86,347			120,080
Sales of produced refined products (BPD)		89,171			119,350
Sales of refined products (BPD)(3)		98,802			132,940
Refinery utilization(4)		69.8	%		97.4	%
Average per produced barrel(5)
Net sales	$	55.23		$	103.20
Cost of products(6)		43.30			95.48
Refinery gross margin		11.93			7.72
Refinery operating expenses(7)		6.40			4.78
Net operating margin	$	5.53		$	2.94
Feedstocks:
Sour crude oil		64	%		63	%
Sweet crude oil		24	%		23	%
Black wax crude oil		8	%		4	%
Other feedstocks and blends		4	%		10	%
Total		100	%		100	%

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	Three Months Ended
	March 31,
	2009			2008
Sales of produced refined products:
Gasolines		63	%		60	%
Diesel fuels		29	%		30	%
Jet fuels		1	%		1	%
Fuel oil		2	%		3	%
Asphalt		2	%		3	%
LPG and other		3	%		3	%
Total		100	%		100	%

(1)	Crude charge represents the barrels per day of crude oil processed at the crude units at our refineries.
(2)	Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
(3)	Includes refined products purchased for resale.
(4)	Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased from 111,000 BPSD to 116,000 BPSD in the fourth quarter of 2008.
(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 refinery, exclusive of depreciation and amortization.

Results of Operations — Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

Summary

Net income attributable to Holly Corporation stockholders for the three months ended March 31, 2009 was $21.9 million ($0.44 per basic and diluted share), a $13.3 million increase compared to $8.6 million ($0.17 per basic and diluted share) for the three months ended March 31, 2008. Net income increased due principally to higher year-over-year refined product margins for the first quarter, partially offset by the effects of an overall decrease in refining production during the three months ended March 31, 2009 due to planned downtime. Overall refinery gross margins for the three months ended March 31, 2009 were $11.93 per produced barrel compared to $7.72 for the three months ended March 31, 2008. Additionally contributing to the increase in net income for the current quarter were improved results from our asphalt marketing business and an increase in sulfur credit sales.

Overall production levels for the three months ended March 31, 2009 decreased by 28% due principally to reduced production attributable to our planned major maintenance turnaround at the Navajo Refinery during the first quarter of 2009. We timed this turnaround with the completion of phase I of our major capital projects initiative at the Navajo Refinery, increasing the refinery’s production capacity from 85,000 bpd to 100,000 bpd effective April 1, 2009.

Sales and Other Revenues

Sales and other revenues decreased 56% from $1,480.0 million for the three months ended March 31, 2008 to $650.8 million for the three months ended March 31, 2009, due principally to significantly lower refined product sales prices combined with the effects of a 26% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold decreased 46% from $103.20 for the first quarter of 2008 to $55.23 for the first quarter of 2009. The total volume of refined products sold for the three months ended March 31, 2009 decreased due to the effects of reduced production resulting from our Navajo Refinery’s planned major maintenance turnaround during the first quarter of 2009. Sales and other revenues for the three months ended March 31, 2009 and 2008, includes $13.8 million and $2.2 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties. Additionally, revenues for the three months ended March 31, 2009 include sulfur credit sales of $4.5 million compared to $0.9 million for the three months ended March 31, 2008.

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Cost of Products Sold

Cost of products sold decreased 63% from $1,383.4 million for the three months ended March 31, 2008 to $511.7 million for the three months ended March 31, 2009, due principally to significantly lower 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 decreased 55% from $95.48 for the first quarter of 2008 to $43.30 for the first quarter of 2009. Also contributing to this decrease was the effects of a 26% decrease in first quarter year-over-year volumes of refined products sold.

Gross Refinery Margins

Gross refining margin per produced barrel increased 55% from $7.72 for the three months ended March 31, 2008 to $11.93 for the three months ended March 31, 2009 due to the effects of a decrease in the average price we paid per barrel of crude oil and feedstocks partially offset by a decrease 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 and amortization, increased 11% from $60.7 million for the three months ended March 31, 2008 to $67.2 million for the three months ended March 31, 2009, due principally to the inclusion of HEP costs for a full three month period during the first quarter of 2009 compared to one month during the first quarter of 2008. For the three months ended March 31, 2009 and 2008, operating expenses included $10.8 million and $3.5 million, respectively, in costs attributable to HEP operations. Excluding HEP, operating expenses decreased by $0.8 million due principally to lower utility costs, partially offset by higher maintenance costs.

General and Administrative Expenses

General and administrative expenses decreased 9% from $12.9 million for the three months ended March 31, 2008 to $11.7 million for the three months ended March 31, 2009, due principally to a decrease in professional fees and services. For the three months ended March 31, 2009 and 2008, general and administrative expenses included $0.7 million and $0.5 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 53% from $13.3 million for the three months ended March 31, 2008 to $20.3 million for the three months ended March 31, 2009. The increase was due principally to depreciation attributable to capitalized refinery improvement projects in 2008 and the inclusion of HEP depreciation expense. For the three months ended March 31, 2009 and 2008, depreciation and amortization expenses included $7.2 million and $2.0 million, respectively, in costs attributable to HEP operations.

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. Equity in earnings of HEP for the three months ended March 31, 2008 was $3.0 million, representing our pro-rata share of earnings in HEP from January 1 through February 29, 2008.

Interest Expense

Interest expense was $6.2 million for the three months ended March 31, 2009 compared to $2.0 million for the three months ended March 31, 2008. The increase was due principally to the inclusion of HEP interest expense. For the three months ended March 31, 2009 and 2008, interest expense included $6.0 million and $1.7 million, respectively, in costs attributable to HEP operations.

Income Taxes

Income taxes for the three months ended March 31, 2009 were $12.1 million compared to $4.7 million for the three months ended March 31, 2008. Our effective tax rate for the first quarter of 2009 and 2008 was 33.7% and 33.2%, respectively.

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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 and may be liquidated at par on the rate reset date. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income or loss. As of March 31, 2009, we had cash and cash equivalents of $53.9 million.

Cash and cash equivalents increased by $13.1 million during the three months ended March 31, 2009. Net cash provided by financing activities of $85.7 million exceeded the combined cash used for operating activities of $2.3 million and investing activities of $70.3 million. Working capital decreased by $35.8 million during the three months ended March 31, 2009.

At March 31, 2009, we had a $175.0 million senior secured revolving credit agreement (the “Credit Agreement”) with Bank of America, N.A. as administrative agent and lender. We were in compliance with all covenants at March 31, 2009. This credit facility expires in March 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 March 31, 2009. At March 31, 2009, we had outstanding borrowings of $55.0 million and letters of credit totaling $9.8 million under the Credit Agreement. At that level of usage, the unused commitment under the Credit Agreement was $110.2 million at March 31, 2009.

In April 2009, we amended our $175.0 million senior secured revolving credit agreement increasing the size to $300.0 million (the “Amended Credit Agreement”). The Amended Credit Agreement expires in March 2013 and has an option to increase the facility to $450.0 million subject to certain conditions. The general terms of the Amended Credit Agreement did not change.

There are currently a total of twelve lenders under our $300.0 million Amended Credit Agreement with individual commitments ranging from $15.0 million to $46.0 million. If any particular lender could not honor its commitment, we believe the unused capacity would be available to meet our borrowing needs. Additionally, we have reviewed publicly available information on our lenders in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We have not experienced, nor do we expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

HEP has a $300.0 million senior secured revolving credit agreement expiring in August 2011 (the “HEP Credit Agreement”). The HEP Credit Agreement is available to fund capital expenditures, acquisitions and working capital and or other general partnership purposes. 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 March 31, 2009 consist of $4.3 million in cash and cash equivalents, $4.1 million in trade accounts receivable and other current assets, $359.3 million in property, plant and equipment, net and $108.5 million in intangible and other assets. Indebtedness under the HEP Credit Agreement is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. 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.

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There are currently a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15.0 million to $40.0 million. If any particular lender could not honor its commitment, HEP has unused capacity available under their credit agreement, which was $60.0 million as of March 31, 2009, to meet their borrowing needs. Additionally, publicly available information on these lenders is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the HEP Credit Agreement. HEP has not experienced, nor do they expect to experience, any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, HEP believes there would be alternative lenders or options available.

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. Indebtedness under the HEP Senior Notes is recourse to HEP Logistics Holdings, L.P., its general partner, and guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. 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 on up to $35.0 million of the principal amount of the HEP Senior Notes.

HEP closed on a public offering of 2,000,000 common units priced at $27.80 per common unit on May 8, 2009. In connection with the offering, HEP granted the underwriters a 30-day option to purchase up to 300,000 additional common units. Proceeds from the offering will be used to repay bank debt and for general partnership purposes. In addition, we made a capital contribution to HEP to maintain our 2% general partner interest.

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

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, including our planned acquisition of Sunoco Inc.’s Tulsa refinery (see discussion under “planned capital expenditures”) and our liquidity needs for the foreseeable future as well as allow us to continue payment of quarterly dividends and distributions by HEP to its noncontrolling interest holders. 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 used for operating activities were $2.3 million for the three months ended March 31, 2009 compared to net cash provided of $98.9 million for the three months ended March 31, 2008, a net change of $101.2 million. Net income for the first quarter of 2009 was $23.9 million, an increase of $14.4 million compared to net income of $9.5 million for the first quarter of 2008. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense, equity in earnings of SLC Pipeline and interest rate swap adjustments resulted in an increase to operating cash flows of $23.8 million for the three months ended March 31, 2009 compared to $11.9 million for the same period in 2008. Additionally, distributions in excess of equity in earnings of HEP increased 2008 operating cash flows by $3.1 million. Changes in working capital items decreased cash flows by $27.2 million for the three months ended March 31, 2009 compared to an increase of $75.8 million for the three months ended March 31, 2008. Additionally, for the three months ended March 31, 2009, turnaround expenditures increased to $27.0 million from $1.4 million in 2008 due to a planned major maintenance turnaround at our Navajo Refinery in the first quarter of 2009.

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Cash Flows — Investing Activities and Capital Projects

Net cash flows used for investing activities were $70.3 million for the three months ended March 31, 2009 compared to net cash flows provided by investing activities of $83.5 million for the three months ended March 31, 2008, a net change of $153.8 million. Cash expenditures for property, plant and equipment for the first three months of 2009 increased to $99.2 million from $72.8 million for the same period in 2008. These include HEP capital expenditures of $10.6 million and $3.3 million for the three months ended March 31, 2009 and 2008, respectively. During the three months ended March 31, 2009, HEP purchased a 25% joint venture interest in the SLC Pipeline for $25.5 million. Additionally we invested $128.7 million in marketable securities and received proceeds of $183.1 million from the sale or maturity of marketable securities. For the three months ended March 31, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP. Also, as a result of our reconsolidation of HEP effective March 1, 2008, our investing activities reflect HEP’s March 1, 2008 cash balance of $7.3 million as cash inflow. Additionally for the three months ended March 31, 2008, we invested $207.6 million in marketable securities and received proceeds of $185.8 million from the sale or maturity of marketable securities.

Planned Capital Expenditures

Holly Corporation

On April 16, 2009, we entered into a definitive agreement with Sunoco Inc. (R&M) (“Sunoco”) to acquire their 85,000 barrel per day (“bpd”) refinery located in Tulsa, Oklahoma and associated businesses (the “Tulsa Refinery”) for $65.0 million. Under the terms of the agreement, we will also purchase related inventory (estimated to cost approximately $100.0 million) which will be valued at market prices at closing. Additionally, we will receive an assignment of the Sunoco specialty lubricant product trademarks in North America and a license to use the same in Central and South America. The transaction which is expected to close by June 1, 2009 is subject to approval by certain regulatory agencies as well as other usual and customary closing conditions. We expect to incurr approximately $150.0 million in capital improvements to the refinery in order to meet regulatory requirements by November 2011.

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 capital budget for 2009 is $19.8 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 2009 capital budget is comprised of $11.4 million for refining improvement projects for the Navajo Refinery, $5.3 million for projects at the Woods Cross Refinery, $0.4 million for marketing-related projects, $1.4 million for asphalt plant projects and $1.3 million for other miscellaneous projects.

At the Navajo Refinery, we are proceeding with major capital projects including expanding refinery capacity to 100,000 BPSD in phase I and then in phase II, developing the capability to run up to 40,000 BPSD of heavy type crudes. Phase I requires the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units. As of March 31, 2009, phase I is mechanically complete. The total cost of phase I is now expected to be $187.4 million.

Phase II involves the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units. Phase II is expected to be mechanically complete in the fourth quarter of 2009 at a cost approximately $98.0 million.

We are also proceeding with a project to add asphalt tankage at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico to enhance asphalt economics by storing asphalt during the winter months when asphalt

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prices are generally lower. These asphalt tank additions and an approved upgrade of our rail loading facilities at the Artesia refinery are estimated to cost approximately $21.0 million and are expected to be completed at the same time as the phase II project.

During the first quarter of 2009, the Navajo Refinery also installed a new 100 ton per day sulfur recovery unit at a cost of approximately $31.0 million.

The Navajo projects discussed above are currently in the process of start-up and will enable the Navajo Refinery to process 100,000 BPSD of crude with up to 40% of that crude being lower cost heavy crude oil. The projects will also increase the yield of diesel, supply Holly Asphalt with all of its performance grade asphalt requirements, increase refinery liquid volume yield, increase the refinery’s capacity to process outside feedstocks, and enable the refinery to meet new low sulfur gasoline specifications required by the EPA.

At the Woods Cross Refinery, we have increased the refinery’s capacity from 26,000 BPSD to 31,000 BPSD while increasing its ability to process lower cost crude. The project involved installing a new 15,000 BPSD mild hydrocracker, sulfur recovery facilities, black wax desalting equipment and black wax unloading systems. The total cost of this project was approximately $122.0 million. The projects were mechanically complete in the fourth quarter of 2008 and are in the start-up phase. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new LSG specifications as required by the EPA.

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 permit the transportation of additional 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 Transportation Company (“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. 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. We have 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.

The UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is anticipated that the permit to proceed will now be received during the second quarter of 2009, we are currently evaluating whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it would be better to delay completion until the fall of 2010.

In July 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 $97.0 million to build the necessary infrastructure including a 70-mile pipeline from Centurion’s Slaughter Station to Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. It also includes a 37-mile pipeline project that connects HEP’s Artesia gathering system to our Lovington facility for processing. This will permit the segregation of heavy crude oil for our crude / vacuum unit in Artesia and provide Artesia area crude oil producers additional access to markets. Under the provisions of the Omnibus Agreement with HEP, HEP will have an option to purchase these transportation assets upon our completion of these projects. We plan to grant HEP the option to purchase these transportation assets upon our completion of the project. We expect to complete these projects in the fourth quarter of 2009.

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In 2009, we expect to spend approximately $275.0 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. This amount does not include costs of our planned Tulsa refinery acquisition including expected improvement costs.

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 provided 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. In August 2005, the Energy Policy Act of 2005 (“2005 Act”) was signed into law. Among other things, the 2005 Act created 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 expansion projects at the Navajo and Woods Cross Refineries will qualify for this deduction.

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

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 several 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. The 2009 HEP capital budget is comprised of $3.7 million for maintenance capital expenditures and $2.2 million for expansion capital expenditures. Additionally, capital expenditures planned in 2009 include approximately $43.0 million for capital projects approved in prior years, most of which relate to the expansion of the HEP’s pipeline between Artesia, New Mexico and El Paso, Texas (the “South System”) and the joint venture with Plains discussed below.

In October 2007, we amended the HEP PTA under which HEP has agreed to expand the South System. The expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at HEP’ 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. Construction of the South System pipe replacement and storage tankage is substantially complete. The improvements to Kinder Morgan’s El Paso pump station are expected to be completed by July 2009.

In March 2009, HEP acquired a 25% joint venture interest in a new 95-mile intrastate pipeline system (the “SLC Pipeline”) jointly owned by Plains All American Pipeline, L.P. (“Plains”) and HEP. The SLC Pipeline allows various refiners in the Salt Lake City area, including our Woods Cross refinery, to ship up to 120,000 bpd of crude oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil flowing from Wyoming and Utah via Plains’ Rocky Mountain Pipeline. The total cost of HEP’s investment in the SLC Pipeline was $25.5 million.

HEP is currently working on a capital improvement project that will provide increased flexibility and capacity to its intermediate pipelines enabling it to accommodate increased volumes following the completion of our Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009 at an estimated cost of $6.4 million.

Also during the first quarter of 2009, HEP completed the conversion an existing 12-mile crude oil pipeline to a natural gas pipeline at a cost of approximately $1.0 million. This pipeline will supply natural gas to our Navajo Refinery. The pipeline is currently awaiting the tie-in to our natural gas supplier.

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Cash Flows — Financing Activities

Net cash flows provided by financing activities were $85.7 million for the three months ended March 31, 2009 compared to net cash used for financing activities of $96.1 million for the three months ended March 31, 2008, a net change of $181.8 million. During the three months ended March 31, 2009, we received advances under the Credit Agreement of $55.0 million, purchased $1.2 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $7.5 million in dividends, received a $4.8 million contribution from our UNEV Pipeline joint venture partner and recognized $2.2 million in excess tax benefits on our equity based compensation. Also during this period, HEP received net advances of $40.0 million under the HEP Credit Agreement, paid distributions of $6.9 million to noncontrolling interests and purchased $0.6 million in HEP common units in the open market for recipients of its 2009 restricted unit grants. For the three months ended March 31, 2008, we purchased $102.9 million in treasury stock, paid $6.4 million in dividends, received $0.3 million for common stock issued upon the exercise of stock options, recognized $3.2 million in excess tax benefits on our equity based compensation and incurred $0.4 million in deferred financing costs. For this same period, HEP received advances of $10.0 million under the HEP Credit Agreement.

Contractual Obligations and Commitments

Holly Corporation

During the three months ended March 31, 2009, we received advances of $55.0 million under the Credit Agreement that were classified as short term borrowings.

On April 16, 2009, we entered into a definitive agreement with Sunoco to acquire their 85,000 bpd refinery located in Tulsa, Oklahoma and associated businesses (the “Tulsa Refinery”) for $65.0 million. Under the terms of the agreement, we will also purchase related inventory which will be valued at market prices at closing. Additionally, we will receive an assignment of the Sunoco specialty lubricant product trademarks in North America and a license to use the same in Central and South America. The transaction, which is expected to close by June 1, 2009, is subject to approval by certain regulatory agencies as well as other usual and customary closing conditions.

There were no other significant changes to our contractual obligations and commitments during the three months ended March 31, 2009.

HEP

During the three months ended March 31, 2009, HEP received net advances of $40.0 million under the HEP Credit Agreement resulting in a March 31, 2009 principal balance of $240.0 million that was classified as long-term debt.

There were no significant changes to HEP’s other contractual obligations during the three months ended March 31, 2009.

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, 2008. Certain critical accounting policies that materially affect the amounts recorded in our

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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 2009.

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

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. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.

New Accounting Pronouncements

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 Financial Accounting Standards Board (“FASB”) issued SFAS No. 160 which changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. We adopted this standard effective January 1, 2009. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the non-controlling interest in our HEP subsidiary is now presented as an adjustment to net income to arrive at “Net income attributable to Holly Corporation stockholders” in our Consolidated Statements of Income. Prior to our adoption of this standard, this amount was presented as “Minority interests in earnings of Holly Energy Partners,” a non-operating expense item before “Income before income taxes.” Additionally, equity attributable to noncontrolling interests is now presented as a separate component of total equity in our Consolidated Financial Statements. We have adopted this standard on a retroactive basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly stockholders.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133”

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure requirements of SFAS 133 to include disclosure of the objectives and strategies related to an entity’s use of derivative instruments, disclosure of how an entity accounts for its derivative instruments and disclosure of the financial impact including effect on cash flows associated with derivative activity. We adopted this standard effective as of January 1, 2009. See risk management below for disclosure of our derivative instruments and hedging activity.

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.

HEP uses interest rate derivatives to manage its exposure to interest rate risk. As of March 31, 2009, HEP had three interest rate swap contracts.

HEP has an interest rate swap that hedges 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 in February 2008. This interest rate swap effectively converts their $171.0 million

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LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of March 31, 2009. The maturity of this swap contract is February 28, 2013. HEP intends to renew the HEP Credit Agreement prior to its expiration in August 2011 and continue to finance the $171.0 million balance until the swap matures.

HEP has designated this interest rate swap as a cash flow hedge. Based on its assessment of effectiveness using the change in variable cash flows method, HEP determined that the interest rate swap is effective in offsetting the variability in interest payments on the $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 the offsetting fair value adjustment 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 to be paid or received 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 March 31, 2009, HEP had no ineffectiveness on their cash flow hedge.

HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). Under this swap contract, interest on the $60.0 million notional amount is computed using the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 2.42% as of March 31, 2009. The maturity of the swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.

In October 2008, HEP entered into an additional interest rate swap contract, effective December 1, 2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting $60.0 million of their hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”). Under the Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of 3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is December 1, 2013.

Prior to the execution of HEP’s Fixed Rate Swap, the Variable Rate Swap was designated as a fair value hedge of $60.0 million in outstanding principal under the HEP Senior Notes. HEP de-designated this hedge in October 2008. At this time, the carrying balance of the HEP Senior Notes included a $2.2 million premium due to the application of hedge accounting until the de-designation date. This premium is being amortized as a reduction to interest expense over the remaining term of the Variable Rate Swap.

HEP’s interest rate swaps not having a “hedge” designation are measured quarterly at fair value either as an asset or a liability in the consolidated balance sheets with the offsetting fair value adjustment to interest expense. For the three months ended March 31, 2009, HEP recognized $0.2 million in interest expense attributable to fair value adjustments to its interest rate swaps.

HEP records interest expense equal to the variable rate payments under the swaps. Receipts under the swap agreements are recorded as a reduction to interest expense.

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The interest rate swaps are valued using level 2 inputs. Additional information on HEP’s interest rate swaps is as follows:

	Balance Sheet				Location of Offsetting	Offsetting
Interest Rate Swaps	Location	Fair Value			Balance	Amount
					(In thousands)
Asset
Fixed-to-variable interest rate swap — $60 million of HEP 6.25% Senior Notes	Other assets	$	3,762		Long-term debt — HEP	$	(2,051	)
					Equity	(1,942		)(1)
					Interest expense	231		(2)
		$	3,762			$	(3,762	)
Liability
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	(13,117	)	Accumulated other comprehensive loss	$	13,117
Variable-to-fixed interest rate swap — $60 million	Other long-term liabilities				Equity	4,166		(1)
			(4,064	)	Interest expense	(102		)
		$	(17,181	)		$	17,181

(1)	Represents prior year charges to interest expense.
(2)	Net of amortization of premium attributable to de-designated hedge.

We have reviewed publicly available information on our counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. We have not, nor do we expect to experience any difficulty in the counterparties honoring their respective commitments.

We invest a substantial portion of available cash in investment grade, highly liquid investments with maturities of three months or less and hence the interest rate market risk implicit in these cash investments is low. We also invest the remainder of 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 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.

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Item 3. Qantitative 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 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
	March 31,
	2009			2008
	(In thousands)
Net Income attributable to Holly Corporation stockholders	$	21,945		$	8,649
Add provision for income tax		12,131			4,695
Add interest expense		6,239			1,992
Subtract interest income		(2,196	)		(3,555	)
Add depreciation and amortization		20,321			13,309
EBITDA	$	58,440		$	25,090

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 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.

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	Three Months Ended
	March 31,
	2009		2008
Average per produced barrel:
Navajo Refinery
Net sales	$	57.37	$	103.26
Less cost of products		44.92		96.83
Refinery gross margin	$	12.45	$	6.43
Woods Cross Refinery
Net sales	$	50.31	$	102.96
Less cost of products		39.57		90.42
Refinery gross margin	$	10.74	$	12.54
Consolidated
Net sales	$	55.23	$	103.20
Less cost of products		43.30		95.48
Refinery gross margin	$	11.93	$	7.72

Net Operating Margin

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

	Three Months Ended
	March 31,
	2009		2008
Average per produced barrel:
Navajo Refinery
Refinery gross margin	$	12.45	$	6.43
Less refinery operating expenses		6.17		4.39
Net operating margin	$	6.28	$	2.04
Woods Cross Refinery
Refinery gross margin	$	10.74	$	12.54
Less refinery operating expenses		6.92		6.26
Net operating margin	$	3.82	$	6.28
Consolidated
Refinery gross margin	$	11.93	$	7.72
Less refinery operating expenses		6.40		4.78
Net operating margin	$	5.53	$	2.94

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

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

	Three Months Ended
	March 31,
	2009			2008
Navajo Refinery
Average sales price per produced barrel sold	$	57.37		$	103.26
Times sales of produced refined products sold (BPD)		62,147			94,050
Times number of days in period		90			91
Refined product sales from produced products sold	$	320,884		$	883,756
Woods Cross Refinery
Average sales price per produced barrel sold	$	50.31		$	102.96
Times sales of produced refined products sold (BPD)		27,024			25,300
Times number of days in period		90			91
Refined product sales from produced products sold	$	122,362		$	237,045
Sum of refined product sales from produced products sold from our two refineries(4)	$	443,246		$	1,120,801
Add refined product sales from purchased products and rounding(1)		53,646			135,209
Total refined products sales		496,892			1,256,010
Add direct sales of excess crude oil(2)		121,255			202,951
Add other refining segment revenue(3)		18,763			18,415
Total refining segment revenue		636,910			1,477,376
Add HEP segment sales and other revenues		32,125			9,942
Add corporate and other revenues		99			401
Subtract consolidations and eliminations		(18,311	)		(7,735	)
Sales and other revenues	$	650,823		$	1,479,984

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

	Three Months Ended
	March 31,
	2009		2008
Average sales price per produced barrel sold	$	55.23	$	103.20
Times sales of produced refined products sold (BPD)		89,171		119,350
Times number of days in period		90		91
Refined product sales from produced products sold	$	443,246	$	1,120,801

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

	Three Months Ended
	March 31,
	2009		2008
Navajo Refinery
Average cost of products per produced barrel sold	$	44.92	$	96.83
Times sales of produced refined products sold (BPD)		62,147		94,050
Times number of days in period		90		91
Cost of products for produced products sold	$	251,248	$	828,724

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	Three Months Ended
	March 31,
	2009			2008
Woods Cross Refinery
Average cost of products per produced barrel sold	$	39.57		$	90.42
Times sales of produced refined products sold (BPD)		27,024			25,300
Times number of days in period		90			91
Cost of products for produced products sold	$	96,241		$	208,174
Sum of cost of products for produced products sold from our two refineries(4)	$	347,489		$	1,036,898
Add refined product costs from purchased products sold and rounding(1)		57,760			135,164
Total refined cost of products sold		405,249			1,172,062
Add crude oil cost of direct sales of excess crude oil(2)		120,682			202,213
Add other refining segment cost of products sold(3)		3,908			16,713
Total refining segment cost of products sold		529,839			1,390,988
Subtract consolidations and eliminations		(18,185	)		(7,551	)
Costs of products sold (exclusive of depreciation and amortization)	$	511,654		$	1,383,437

(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 feedstock and sulfur credit sales.
(4)	The above calculations of cost 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
	March 31,
	2009		2008
Average cost of products per produced barrel sold	$	43.30	$	95.48
Times sales of produced refined products sold (BPD)		89,171		119,350
Times number of days in period		90		91
Cost of products for produced products sold	$	347,489	$	1,036,898

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

	Three Months Ended
	March 31,
	2009		2008
Navajo Refinery
Average refinery operating expenses per produced barrel sold	$	6.17	$	4.39
Times sales of produced refined products sold (BPD)		62,147		94,050
Times number of days in period		90		91
Refinery operating expenses for produced products sold	$	34,510	$	37,572
Woods Cross Refinery
Average refinery operating expenses per produced barrel sold	$	6.92	$	6.26
Times sales of produced refined products sold (BPD)		27,024		25,300
Times number of days in period		90		91
Refinery operating expenses for produced products sold	$	16,831	$	14,412

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	Three Months Ended
	March 31,
	2009			2008
Sum of refinery operating expenses per produced products sold from our two refineries(2)	$	51,341		$	51,984
Add other refining segment operating expenses and rounding(1)		5,074			5,232
Total refining segment operating expenses		56,415			57,216
Add HEP segment operating expenses		10,796			3,676
Add corporate and other costs		( 9	)		(184	)
Operating expenses (exclusive of depreciation and amortization)	$	67,202		$	60,708

(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
	March 31,
	2009		2008
Average refinery operating expenses per produced barrel sold	$	6.40	$	4.78
Times sales of produced refined products sold (BPD)		89,171		119,350
Times number of days in period		90		91
Refinery operating expenses for produced products sold	$	51,341	$	51,984

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

	Three Months Ended
	March 31,
	2009			2008
Navajo Refinery
Net operating margin per barrel	$	6.28		$	2.04
Add average refinery operating expenses per produced barrel		6.17			4.39
Refinery gross margin per barrel		12.45			6.43
Add average cost of products per produced barrel sold		44.92			96.83
Average net sales per produced barrel sold	$	57.37		$	103.26
Times sales of produced refined products sold (BPD)		62,147			94,050
Times number of days in period		90			91
Refined products sales from produced products sold	$	320,884		$	883,756
Woods Cross Refinery
Net operating margin per barrel	$	3.82		$	6.28
Add average refinery operating expenses per produced barrel		6.92			6.26
Refinery gross margin per barrel		10.74			12.54
Add average cost of products per produced barrel sold		39.57			90.42
Average net sales per produced barrel sold	$	50.31		$	102.96
Times sales of produced refined products sold (BPD)		27,024			25,300
Times number of days in period		90			91
Refined products sales from produced products sold	$	122,362		$	237,045
Sum of refined products sales from produced products sold from our two refineries(4)	$	443,246		$	1,120,801
Add refined product sales from purchased products and rounding(1)		53,646			135,209
Total refined products sales		496,892			1,256,010
Add direct sales of excess crude oil(2)		121,255			202,951
Add other refining segment revenue(3)		18,763			18,415
Total refining segment revenue		636,910			1,477,376
Add HEP segment sales and other revenues		32,125			9,942
Add corporate and other revenues		99			401
Subtract consolidations and eliminations		(18,311	)		(7,735	)
Sales and other revenues	$	650,823		$	1,479,984

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

	Three Months Ended
	March 31,
	2009		2008
Net operating margin per barrel	$	5.53	$	2.94
Add average refinery operating expenses per produced barrel		6.40		4.78
Refinery gross margin per barrel		11.93		7.72
Add average cost of products per produced barrel sold		43.30		95.48
Average sales price per produced barrel sold	$	55.23	$	103.20
Times sales of produced refined products sold (BPD)		89,171		119,350
Times number of days in period		90		91
Refined product sales from produced products sold	$	443,246	$	1,120,801

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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 been 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

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, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize 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. On October 22, 2008, we and other shippers jointly filed at the FERC with SFPP a settlement covering the period from December 2008 through November 2010. The Commission approved the settlement on January 29, 2009. The settlement will reduce SFPP’s current rates and require SFPP to make additional payments to us of approximately $2.0 million. On May 1, 2009, SFPP notified us that it may seek to invoke its rights to terminate the October 22, 2008, settlement rates and to file higher prospective rates. We and other shippers have begun discussions with SFPP to discuss its notification and possible alternatives to the termination of the settlement. We are not in a position to predict the outcome of these negotiations.

Our Navajo Refining Company subsidiary was 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 and subsequently transferred to the U.S. District Court for the Southern District of New York under multidistrict procedures along with approximately 100 similar cases, in which Navajo is not named, brought by other governmental entities and private parties in other states. The lawsuit, in which Navajo is named, as amended in October 2006 through the filing of a second amended complaint, 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 lawsuit asserts claims for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy, and seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. The second amended complaint also contains a claim, asserted against certain other defendants but not against Navajo, alleging violations of certain provisions of the Toxic Substances Control Act, which appears to be similar to a claim previously threatened in a mailing to Navajo and other defendants by law firms representing the plaintiffs. Most other defendants have been dismissed from this lawsuit as a result of settlements. As of the close of business on the day prior to the date of this report, Navajo has not been served in this lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

In October 2008, the New Mexico Environment Department (“NMED”) issued an Amended Notice of Violation and Proposed Penalties (“Amended NOV”) to Navajo Refining Company, amending an NOV issued in February 2007. The NOV is a preliminary enforcement document issued by NMED and usually is the predicate to formal administrative or judicial enforcement. The February 2007 NOV was issued following two hazardous waste

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compliance evaluation inspections at the Artesia, New Mexico refinery that were conducted in April and November 2006 and alleged violations of the New Mexico Hazardous Waste Management Regulations and Navajo’s Hazardous Waste Permit. NMED proposed a civil penalty of approximately $0.1 million for the February 2007 NOV. The Amended NOV includes additional alleged violations concerning post-closure care of a hazardous waste land treatment unit and the construction of a tank on the land treatment area. The Amended NOV also proposes an additional civil penalty of $0.3 million. Navajo has submitted responses to the February 2007 NOV and the Amended NOV, challenging certain alleged violations and proposed penalty amounts and is continuing negotiations with the NMED to resolve these matters expeditiously.

Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in state district court in Davis County, Utah involving a construction dispute regarding the installation of improvements known as a crude desalter, crude unloader, and west tank farm at our Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the construction of those improvements for which the plaintiff was not paid. The claims made against our subsidiaries are for breach of contract, lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the amount of $2.3 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the Refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Triad Engineers Limited d/b/a Triad Project Corporation, answered the complaint denying any liability, and asserted counterclaims. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

Our Holly Refining & Marketing Company — Woods Cross and Woods Cross Refining Company, LLC subsidiaries are named, along with other parties, as defendants in a lawsuit filed in December 2008 by Brahma Group, Inc. in the U.S. District Court for the Central District of Utah involving a construction related dispute over the installation of an oil gas hydrocracker at the Woods Cross, Utah refinery. The lawsuit alleges that the defendants caused delays, additional work and increased costs in the installation of the oil gas hydrocracker for which the plaintiff was not paid. The claims made against our subsidiaries are for lien foreclosure, failure to obtain a payment bond, and implied contract. The lawsuit seeks compensatory damages in the approximate amount of $12.0 million, costs, attorney’s fees allowed by law, and interest allowed by law. A lien has also been filed in the county records against the refinery property in that amount. Our subsidiaries have tendered defense of the complaint to the general contractor, Benham Constructors, LLC, and have filed an answer to the complaint denying any liability. Holly Refining & Marketing Company — Woods Cross has been dismissed from this suit on the basis of subject matter jurisdiction. The Brahma Group, Inc.’s claims against Benham Constructors, LLC have been dismissed based on a forum selection clause in the subcontract. The claims against Woods Cross Refinery, LLC remain. Based on the dismissal of its claims against the general contractor, Brahma Group, Inc. has filed a new legal action against Holly Refining & Marketing Company — Woods Cross, Woods Cross Refining Company, LLC, and Benham Constructors, LLC in the Second Judicial District Court for the State of Utah in April 2009 alleging the same claims that were previously dismissed from the federal action. We intend to vigorously defend against the claims asserted in the lawsuit. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

On February 17, 2009, our Holly Refining & Marketing Company filed a complaint with the FERC against Plains and Rocky Mountain Pipeline LLC (“Rocky Mountain”). Plains and Rocky Mountain are affiliated companies which operate an interstate crude oil pipeline system from origin points in the Rocky Mountain region to destination points in the Rocky Mountain region. The Holly refinery at Salt Lake City uses that pipeline system to supply between 15,000 to 17,000 barrels per day of its crude oil requirements. Holly’s complaint alleged that the proposed reversal of flow on the segment of the pipeline system from Ft. Laramie, Wyoming, to Wamsutter, Wyoming, would provide an undue and unjust preference for affiliates of Plains and Rocky Mountain and would be unduly and unjustly prejudicial and discriminatory against Holly in violation of the Interstate Commerce Act. On April 23, 2009, the FERC dismissed Holly’s complaint for lack of jurisdiction without addressing the merits of the complaint.

On March 16, 2009, Holly filed a protest with the FERC against a tariff filing of Rocky Mountain which proposed to discontinue crude oil transportation service from Guernsey, Wyoming, and Ft. Laramie, Wyoming, to Wamsutter,

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Wyoming as part of the proposed reversal on the pipeline segment from Ft. Laramie to Wamsutter. Holly’s protest was based on the same grounds as Holly’s earlier complaint against Plains and Rocky Mountain. On March 31, 2009, the FERC rejected Holly’s protest for lack of jurisdiction without addressing the merits of the protest.

Prior to the sale by Holly Corporation of the Montana Refining Company assets in 2006, MRC, along with other companies was the subject of several environmental claims at the Cut Bank Hill site in Montana. These claims include: (1) a U.S. Environmental Protection Agency administrative order requiring Montana Refining and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against Montana Refining and other companies for response costs of $298,500 in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality directing Montana Refining and other companies to complete a remedial investigation and a request by the MDEQ that Montana Refining and other companies pay $147,500 to reimburse the State’s costs for remedial actions. Montana Refining Company has denied responsibility for the requested EPA and the Montana Department of Environmental Quality (“MDEQ”) cleanup actions and the MDEQ and Coast Guard response costs.

In June 2007, the Federal Occupational Safety and Health Administration (“OSHA”) announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As a part of the NEP, OSHA encouraged the State Plan States such as Utah to initiate their own version of the NEP. Beginning on May 1, 2008, the Utah Labor Commission, Occupational Safety and Health Division (“UOSH”) began an inspection of the refinery which is operated by Holly Refining and Marketing Company — Woods Cross and is located in Woods Cross, Utah. The inspection ended on September 18 and on October 23, 2008, UOSH issued one citation alleging 33 violations of various safety standards including the Process Safety Management Standard and proposing a penalty of $91,750. We filed a notice of contest with the Adjudicative Division, Utah Labor Commission, in Salt Lake City, Utah. On February 18, 2009, the initial status conference for this matter was held and a scheduling order was issued. Our answer was filed and served on March 4th and discovery will continue until July 6, 2009. No hearing date has been set. We intend to vigorously defend this citation and believe that we have strong defenses on the merits.

We are a party to various other litigation and proceedings that 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.

Item 6. Exhibits

(a) Exhibits

2.1	Asset Sale and Purchase Agreement dated as of April 15, 2009 by and between Holly Refining & Marketing-Midcon, L.L.C. and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 2.1 of Registrant’s Current Report on Form 8-K filed April 16, 2009, File No. 1-3876).
10.1+	Second Amended and Restated Credit Agreement dated April 7, 2009 by and among Holly Corporation and Bank of America, N.A., as administrative agent, swing line lender, and L/C issuer, UBS Loan Finance LLC and U.S. Bank National Association, as co-documentation agents, Union Bank of California, N.A. and Compass Bank, as syndication agents, and certain other lenders from time to time party thereto.
10.2*+	Form of Executive Restricted Stock Agreement.
10.3*+	Form of Employee Restricted Stock Agreement.
10.4*+	Form of Director Restricted Stock Unit Agreement.
10.5*+	Form of Performance Share Unit Agreement.
31.1+	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

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SIGNATURES

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

	HOLLY CORPORATION
	(Registrant)
Date: May 8, 2009	/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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