HF Sinclair 10Q 2009 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2009


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.

Yesþ Noo

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yeso Noo

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 filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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

Yeso Noþ

50,244,495 shares of Common Stock, par value $.01 per share, were outstanding on July 31, 2009.

HOLLY CORPORATION
INDEX


	Page
PART I. FINANCIAL INFORMATION

Forward-Looking Statements		3

Definitions		4

Item 1. Financial Statements

Consolidated Balance Sheets June 30, 2009 (Unaudited) and December 31, 2008		6

Consolidated Statements of Income (Unaudited) Three and Six Months Ended June 30, 2009 and 2008		7

Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2009 and 2008		8

Consolidated Statements of Comprehensive Income (Unaudited) Three and Six Months Ended June 30, 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		31

Item 3. Quantitative and Qualitative Disclosures About Market Risk		50

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles		50

Item 4. Controls and Procedures		57

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		58

Item 6. Exhibits		61

Signatures		62
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 with certain exceptions. For periods prior to our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” exclude HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation. 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 successfully integrate the operations of the Tulsa Refinery 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.

“Lubricant”means a solvent neutral paraffinic product used in passenger and commercial vehicle engine oils, specialty products for metalworking or heat transfer applications and other industrial applications.

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

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

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

“PPM” means parts-per-million.

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

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

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

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

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

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

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Item 1.Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)


	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	108,688		$	40,805
Marketable securities		791			49,194

Accounts receivable: Product and transportation		240,644			128,337
Crude oil resales		364,056			161,427

		604,700			289,764

Inventories: Crude oil and refined products		238,405			107,811
Materials and supplies		25,643			17,924

		264,048			125,735

Income taxes receivable		5,841			6,350
Prepayments and other		26,389			18,775

Total current assets		1,010,457			530,623

Properties, plants and equipment, at cost		1,764,456			1,509,701
Less accumulated depreciation		(339,256	)		(304,379	)

		1,425,200			1,205,322

Marketable securities (long-term)		—			6,009

Other assets: Turnaround costs		59,913			34,309
Goodwill		27,542			27,542
Intangibles and other		98,329			70,420

		185,784			132,271


Total assets	$	2,621,441		$	1,874,225


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	804,619		$	391,142
Accrued liabilities		46,471			42,016
Short-term debt — Holly Energy Partners		—			29,000

Total current liabilities		851,090			462,158

Long-term debt — Holly Corporation		187,964			—
Long-term debt — Holly Energy Partners		390,056			341,914
Deferred income taxes		88,404			69,491
Other long-term liabilities		77,358			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; 73,569,851 and 73,543,873 shares issued as of June 30, 2009 and December 31, 2008, respectively		738			735
Additional capital		121,818			121,298
Retained earnings		1,166,883			1,145,388
Accumulated other comprehensive loss		(33,929	)		(35,081	)
Common stock held in treasury, at cost — 23,325,356 and 23,600,653 shares as of June 30, 2009 and December 31, 2008, respectively		(685,931	)		(690,800	)

Total Holly Corporation stockholders’ equity		569,579			541,540

Noncontrolling interest		456,990			394,792

Total equity		1,026,569			936,332

Total liabilities and equity	$	2,621,441		$	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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Sales and other revenues	$	1,038,381		$	1,743,822		$	1,689,204		$	3,223,806

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		879,926			1,620,550			1,391,580			3,003,987
Operating expenses (exclusive of depreciation and amortization)		78,508			74,175			145,710			134,883
General and administrative expenses (exclusive of depreciation and amortization)		15,108			12,942			26,855			25,879
Depreciation and amortization		25,500			15,929			45,821			29,238

Total operating costs and expenses		999,042			1,723,596			1,609,966			3,193,987


Income from operations		39,339			20,226			79,238			29,819

Other income (expense):
Equity in earnings of SLC Pipeline		488			—			663			—
Interest income		134			3,826			2,330			7,381
Interest expense		(7,205	)		(6,251	)		(13,444	)		(8,243	)
Tulsa Refinery acquisition costs		(1,610	)		—			(1,610	)		—
Equity in earnings of Holly Energy Partners		—			—			—			2,990

		(8,193	)		(2,425	)		(12,061	)		2,128

Income before income taxes		31,146			17,801			67,177			31,947

Income tax provision:
Current		(6,635	)		(877	)		3,525			5,441
Deferred		16,210			6,733			18,181			5,110

		9,575			5,856			21,706			10,551


Net income		21,571			11,945			45,471			21,396

Less net income attributable to noncontrolling interest		6,966			493			8,921			1,295


Net income attributable to Holly Corporation stockholders	$	14,605		$	11,452		$	36,550		$	20,101


Net income per share attributable to Holly Corporation stockholders — basic	$	0.29		$	0.23		$	0.73		$	0.40


Net income per share attributable to Holly Corporation stockholders — diluted	$	0.29		$	0.23		$	0.73		$	0.39


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


Average number of common shares outstanding:
Basic		50,170			50,158			50,106			50,654
Diluted		50,226			50,515			50,189			51,015

See accompanying notes.

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HOLLY CORPORATION

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


	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net income	$	45,471		$	21,396
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		45,821			29,238
Equity in earnings of SLC Pipeline		(598	)		—
Change in fair value — interest rate swaps		(628	)		—
Deferred income taxes		18,181			5,110
Equity based compensation expense		4,337			2,695
Distributions in excess of equity in earnings of Holly Energy Partners		—			3,067
(Increase) decrease in current assets:
Accounts receivable		(316,436	)		(221,285	)
Inventories		(39,579	)		(18,649	)
Income taxes receivable		509			6,323
Prepayments and other		(7,614	)		737
Increase (decrease) in current liabilities:
Accounts payable		413,420			296,611
Accrued liabilities		383			(8,107	)
Turnaround expenditures		(31,069	)		(3,390	)
Other, net		9,352			867

Net cash provided by operating activities		141,550			114,613

Cash flows from investing activities:
Additions to properties, plants and equipment — Holly Corporation		(127,367	)		(186,582	)
Additions to properties, plants and equipment — Holly Energy Partners		(56,026	)		(12,202	)
Acquisition of Tulsa Refinery — Holly Corporation		(157,814	)		—
Investment in SLC Pipeline — Holly Energy Partners		(25,500	)		—
Purchases of marketable securities		(165,892	)		(303,257	)
Sales and maturities of marketable securities		220,281			395,520
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		(312,318	)		71,484

Cash flows from financing activities:
Proceeds from issuance of senior notes — Holly Corporation		187,925			—
Proceeds from issuance of common units — Holly Energy Partners		58,355			—
Borrowings under credit agreement — Holly Corporation		94,000			—
Repayments under credit agreement — Holly Corporation		(94,000	)		—
Borrowings under credit agreement — Holly Energy Partners		99,000			40,000
Repayments under credit agreement — Holly Energy Partners		(81,000	)		(20,000	)
Dividends		(15,022	)		(14,055	)
Distributions to noncontrolling interest		(14,529	)		(7,577	)
Purchase of treasury stock		(1,214	)		(136,876	)
Contribution from joint venture partner		8,950			10,000
Excess tax benefit from equity based compensation		2,110			3,436
Deferred financing costs		(5,193	)		(365	)
Other		(731	)		(258	)

Net cash provided by (used for) financing activities		238,651			(125,695	)

Cash and cash equivalents:
Increase for the period		67,883			60,402
Beginning of period		40,805			94,369

End of period	$	108,688		$	154,771


Supplemental disclosure of cash flow information:
Cash paid during the period for
Interest	$	13,008		$	6,489
Income taxes	$	11,929		$	3,993

See accompanying notes.

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HOLLY CORPORATION

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009		2008			2009			2008
Net income	$	21,571	$	11,945		$	45,471		$	21,396
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain (loss) on available-for-sale securities		205		501			(258	)		1,327
Reclassification adjustment to net income on sale of marketable securities		—		(32	)		236			(1,339	)


Total unrealized gain (loss) on available-for-sale securities		205		469			(22	)		(12	)

Other comprehensive income of Holly Energy Partners:
Change in fair value of cash flow hedge		4,417		6,797			4,167			2,448


Other comprehensive income before income taxes		4,622		7,266			4,145			2,436
Income tax expense		866		1,273			733			388


Other comprehensive income		3,756		5,993			3,412			2,048


Total comprehensive income		25,327		17,938			48,883			23,444

Less comprehensive income attributable to noncontrolling interest		9,362		4,180			11,181			2,623


Comprehensive income attributable to Holly Corporation stockholders	$	15,965	$	13,758		$	37,702		$	20,821

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

As of the close of business on June 30, 2009, we:

	•		owned and operated three refineries consisting of our 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”), our refinery in Woods Cross, Utah (“Woods Cross Refinery”) and our refinery located in Tulsa, Oklahoma (“Tulsa Refinery”). See Note 2 for information on our Tulsa Refinery acquired on June 1, 2009;

	•		owned and operated Holly Asphalt Company which manufactures and markets asphalt products from various terminals in Arizona and New Mexico; and

	•		owned a 41% interest in HEP which includes our 2% general partner interest, which has logistic assets including approximately 2,700 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”). Additionally, HEP owns a 25% interest in SLC Pipeline LLC (“SLC Pipeline”).

We have prepared these consolidated financial statements without audit. In management’s opinion, these consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position as of June 30, 2009, the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2009 and 2008 and consolidated cash flows for the six months ended June 30, 2009 and 2008 in accordance with the rules and regulations of the SEC. Although certain notes and other information required by generally accepted accounting principles in the United States (“GAAP”) 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 consolidated financial statements under Exhibit 99.6 of our Form 8-K dated June 2, 2009 and our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the SEC.

These consolidated financial statements reflect management’s evaluation of subsequent events through the time of our filing of this Quarterly Report on Form 10-Q with the SEC on August 10, 2009.

Our results of operations for the first six months of 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 June 30, 2009 our allowance for doubtful accounts reserve was $2.5 million.

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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.

Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, interest rate swaps and debt. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments.

Debt consists of outstanding principle under the credit agreements and long-term senior notes. The carrying amounts of outstanding debt under the credit agreements approximate fair value as interest rates are reset frequently using current interest rates. The estimated fair values of the senior notes is based on market quotes provided from a third-party bank. See Note 9 for additional information on the senior notes, including fair value estimates.

We adopted SFAS No. 157 “Fair Value Measurements” effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that categorizes inputs used in fair value measurements into three broad levels as follows:

	•		(Level 1) Quoted prices in active markets for identical assets or liabilities.

	•		(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

	•		(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

Our investments in marketable securities are measured at fair value using quoted market prices, a Level 1 input. See Note 6 for additional information on our investments in marketable securities, including fair value measurements.

HEP has interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. With respect to these instruments, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreements. The measurements are computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 9 for additional information on the interest rate swaps, including fair value measurements.

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”

SFAS No. 160 became effective January 1, 2009, which changes the classification of noncontrolling interests, also referred to as minority interests, in the consolidated financial statements. As a result, all previous references to “minority interest” within this document have been replaced with “noncontrolling interest.” Additionally, net income attributable to the noncontrolling 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 applied this standard on a retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly Corporation stockholders.

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

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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. See Note 9 for disclosure of HEP’s derivative instruments and hedging activity.

Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) SFAS No. 107-1 and Accounting Principles Board (“APB”) No. 28-1 “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued FSP SFAS No, 107-1 and APB No. 28-1, which extends the annual financial statement disclosure requirements for financial instruments to interim reporting periods of publicly traded companies. We adopted this standard effective June 30, 2009.

SFAS No. 165 “Subsequent Events”

In May 2009, the FASB issued SFAS No. 165 which establishes general standards for accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard effective June 30, 2009. Although this standard requires disclosure of the date through which we have evaluated subsequent events, it did not affect our accounting and disclosure policies with respect to subsequent events.

SFAS No. 167 ”Amendments to FASB Interpretation (“FIN”) No. 46(R)”

In June 2009, the FASB issued SFAS No. 167 which replaces the previous quantitative-based risk and rewards calculation provided under FIN No. 46(R) with a quantitative approach in determining whether an entity is the primary beneficiary of a variable interest entity (“VIE”). Additionally, this standard requires an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhances disclosures requirements with respect to an entity’s involvement in a VIE. This standard is effective as of the beginning of an entity’s fiscal year beginning after November 15, 2009 including interim periods within that year. While we are currently evaluating the impact of this standard, we do not believe that it will have a material impact on our financial condition, results of operations and cash flows.

NOTE 2: Tulsa Refinery Acquisition

On June 1, 2009 we acquired the Tulsa Refinery, an 85,000 BPSD petroleum refinery located in Tulsa, Oklahoma, from Sunoco Inc. (“Sunoco”) for $157.8 million, including crude oil, refined product and other inventories totaling $92.8 million. The Tulsa Refinery is located on an approximate 750-acre site and has supporting infrastructure including approximately 3.2 million barrels of feedstock and product tankage and an additional 1.2 million barrels of tank capacity that is currently out of service. Additionally, supporting infrastructure includes nine truck racks and six rail racks that support product distribution at the refinery.

Distillates and gasolines are primarily delivered from the Tulsa Refinery to market via two pipelines owned and operated by Magellan Midstream Partners, L.P. These pipelines connect the refinery to distribution channels throughout the mid-continent region of the United States. Additionally, the Tulsa Refinery has a proprietary diesel transfer line to the local Burlington Northern Santa Fe Railroad depot, and the refinery’s truck and rail rack capability facilitates access to local refined product markets. The refinery also produces specialty lubricant products including agricultural oils, base oils, process oils and waxes that are marketed throughout North America and are distributed in Central and South America.

In accounting for this purchase, we recorded $5.9 million in materials and supplies, $92.8 million in crude oil and refined products inventory, $75.9 million in property, plants and equipment, $4.1 million in accrued liabilities and $12.7 in other long-term liabilities. The acquired liabilities primarily relate to environmental and asset retirement obligations. These amounts are based on management’s preliminary fair value estimates and are subject to change. Additionally, we incurred $1.6 million in costs related to our Tulsa Refinery purchase that were expensed as acquisition costs.

For the period from June 1, 2009 (date of acquisition) through June 30, 2009, our Tulsa Refinery generated revenues of $117.6 million and incurred a net loss of $3.7 million. We have not provided disclosure of pro forma revenues and earnings as if the Tulsa Refinery had been operating as a part of our refining business during all periods presented in these financial statements. Pro forma financial information specific to the Tulsa Refinery operations for periods prior to our acquisition is not available in GAAP form. The compilation of such financial information would entail an

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extremely manual process of “unwinding” significant volumes of intra-company transactions and obtaining a comprehensive understanding of accounting policies as well as estimates employed by Sunoco with respect to items including, but not limited to, inventory and depreciation. We would then need to recast historical financial information to reflect our own estimates and accounting policies. Therefore, we do not believe that it would be practical to produce this information, nor do we believe it would be representative or comparable with respect to our future operating results.

NOTE 3: Holly Energy Partners

HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. At June 30, 2009, we held 7,000,000 subordinated units and 290,000 common units of HEP, representing a 41% ownership interest in HEP, including our 2% general partner interest. The subordination period for the HEP subordinated units that we own extends until the first day of any quarter beginning after June 30, 2009 that certain conditions are met. After giving effect to the payment of HEP’s quarterly distribution for the quarter ended June 30, 2009, we expect that all of the conditions necessary to end the subordination period will be satisfied and the subordinated units will convert into 7,000,000 HEP common units two business days after the distribution is paid.

HEP is a variable interest entity as defined under FIN No. 46(R). Under the provisions of FIN No. 46(R), 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 June 1, 2009, HEP acquired our newly constructed 16-inch feedstock pipeline at our cost of $34.2 million. The pipeline runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to the Navajo petroleum refinery located in Artesia, New Mexico. HEP operates this pipeline as a component of its intermediate pipeline system that services the Navajo Refinery. Since HEP is a consolidated subsidiary, this transaction is eliminated and has no impact on our consolidated financial statements.

In May 2009, HEP closed a public offering of 2,192,400 of its common units priced at $27.80 per unit including 192,400 common units issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds of $58.4 million were used to repay bank debt and for general partnership purposes. In addition, we made a capital contribution to HEP of $1.2 million to maintain our 2% general partner interest. As a result of the issuance of additional HEP common units, our ownership interest in HEP was decreased from 46% to 41%. Additionally, this offering and the sale of our 16-inch feedstock pipeline to HEP (discussed above) qualified as reconsideration events whereby we have determined that HEP continues to qualify as a VIE and we remain HEP’s primary beneficiary.

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 currently serves our refineries in New Mexico and Utah under three long-term 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 2005 and in June 2009 and expires in 2024 (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 that 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 noncontrolling interest of $389.1 million and a decrease in distributions in excess of investment in HEP of $315.1 million.

NOTE 4: 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				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands, except per share data)
Net Income attributable to Holly Corporation stockholders	$	14,605	$	11,452	$	36,550	$	20,101

Average number of shares of common stock outstanding		50,170		50,158		50,106		50,654
Effect of dilutive stock options, variable restricted shares and performance share units		56		357		83		361

Average number of shares of common stock outstanding assuming dilution		50,226		50,515		50,189		51,015

Net income per share attributable to Holly Corporation stockholders — basic	$	0.29	$	0.23	$	0.73	$	0.40

Net income per share attributable to Holly Corporation stockholders — diluted	$	0.29	$	0.23	$	0.73	$	0.39

NOTE 5: Stock-Based Compensation

Holly Corporation

On June 30, 2009, we had three principal share-based compensation plans which are described below (collectively, the “Long-Term Incentive Compensation Plan”). The compensation cost that has been charged against income for these plans was $2.5 million and $1.9 million for the three months ended June 30, 2009 and 2008, respectively, and $3.8 million for each of the six months ended June 30, 2009 and 2008. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $1.0 million and $0.7 million for the three months ended June 30, 2009 and 2008, respectively, and $1.5 million for each of the six months ended June 30, 2009 and 2008. 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 June 30, 2009, 1,934,897 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.

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 June 30, 2009 and 2008 was $0.4 million and $0.5 million, respectively, and for the six months

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ended June 30, 2009 and 2008 was $0.9 million and $0.8 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 six months ended June 30, 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 June 30, 2009		70,200		$	2.98		1.7	$	1,053

The total intrinsic value of options exercised during the six months ended June 30, 2009 and 2008, was $0.3 million and $3.1 million, respectively.

Cash received from option exercises under the stock option plans was $45,000 and $0.3 million for the six months ended June 30, 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 six months ended June 30, 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 generally have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share targets being realized. The fair value of each share of restricted stock awarded, including the shares issued to the key executives, was measured based on the market price as of the date of grant and is being amortized over the respective vesting period.

A summary of restricted stock grant activity and changes during the six months ended June 30, 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		(139,312	)		27.77
Granted		184,182			23.08
Forfeited		(4,045	)		40.06

Outstanding at June 30, 2009 (nonvested)		276,135		$	31.36	$	4,965

The total fair value of restricted stock vested and transferred to recipients during the six months ended June 30, 2009 and 2008 was $3.9 million and $4.9 million, respectively. As of June 30, 2009, there was $4.4 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 1.1 years.

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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, the awards are subject to “financial performance” criteria.

During the six months ended June 30, 2009, we granted 122,555 performance share units with a fair value based on our grant date closing stock price of $22.94. 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 June 30, 2009, estimated share payouts for outstanding nonvested performance share unit awards ranged from 125% to 175%.

A summary of performance share unit activity and changes during the six months ended June 30, 2009 is presented below:


Performance Share Units	Grants
Outstanding at January 1, 2009 (non-vested)		169,669
Vesting and transfer of ownership to recipients		(72,059	)
Granted		122,555
Forfeited		(4,995	)

Outstanding at June 30, 2009 (non-vested)		215,170

For the six months ended June 30, 2009, we issued 110,971 shares of our common stock having a fair value of $2.2 million related to vested performance share units, representing a 154% payout. Based on the weighted average grant date fair value of $35.07, there was $5.7 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.3 years.

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

Our investment portfolio consists of cash and cash equivalents at June 30, 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 at times invest available cash 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 may include investments in variable rate demand notes (“VRDN”).

Our investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are generally considered temporary and are reported as a component of accumulated other comprehensive income. For investments in an unrealized loss position that are determined to be other than temporary, unrealized losses are reclassified out of accumulated other comprehensive income and into earnings as an impairment loss. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

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The following is a summary of our available-for-sale securities at June 30, 2009:

Available-for-Sale Securities

Estimated

Gross

Fair Value

Amortized

Unrealized

(Net Carrying

Cost

Gain

Amount)

(In thousands)

Equity securities

604

187

791

The following is a summary of our available-for-sale securities at December 31, 2008:


	Available-for-Sale Securities
								Estimated
			Gross		Recognized			Fair Value
	Amortized		Unrealized		Impairment			(Net Carrying
	Cost		Gain		Loss			Amount)
	(In thousands)
States and political subdivisions	$	54,389	$	210	$	—		$	54,599
Equity securities		4,328		—		(3,724	)		604

Total marketable securities	$	58,717	$	210	$	(3,724	)	$	55,203

For the six months ended June 30, 2009 and 2008 we received a total of $220.3 million and $395.5 million, respectively, related to sales and maturities of our marketable debt securities.

NOTE 7: Inventories

Inventory consists of the following components:


	June 30,		December 31,
	2009		2008
	(In thousands)
Crude oil	$	47,445	$	22,897
Other raw materials and unfinished products⁽¹⁾		22,789		12,286
Finished products⁽²⁾		168,170		72,628
Process chemicals⁽³⁾		3,607		3,800
Repairs and maintenance supplies and other		22,037		14,124

	$	264,048	$	125,735


(1)		Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.

(2)		Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and residual fuels.

(3)		Process chemicals include catalysts, additives and other chemicals.

During the three and six months ended June 30, 2009, we recognized a $1.0 million charge to cost of products sold resulting from the liquidation of certain LIFO quantities of inventory that were carried at higher costs as compared to current costs.

NOTE 8: Environmental

Consistent with our accounting policy for environmental remediation costs, we expensed $1.6 million and $0.4 million for the three months ended June 30, 2009 and 2008, respectively, and $4.1 million and $0.4 million for the six months ended June 30, 2009 and 2008, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $20.0 million and $7.3 million at June 30, 2009 and December 31, 2008, respectively, of which $13.8 million and $4.2 million, respectively,
were classified as

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other long-term liabilities. These liabilities include $10.0 million of environmental obligations that we assumed in connection with our Tulsa Refinery acquisition on June 1, 2009. Costs of future expenditures for environmental remediation are discounted to their present value.

NOTE 9: Debt

Credit Facilities

In April 2009, we entered into a second amended and restated $300.0 million senior secured revolving credit agreement (the “Holly Credit Agreement”) that amends and restates our previous credit agreement in its entirety with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. The credit agreement expires in March 2013 and may be used to fund working capital requirements, capital expenditures, permitted acquisitions or other general corporate purposes. We were in compliance with all covenants at June 30, 2009. At June 30, 2009, we had no outstanding borrowings and letters of credit totaling $61.8 million under the Holly Credit Agreement. At that level of usage, the unused commitment under the Holly Credit Agreement was $238.2 million at June 30, 2009.

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 for 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 June 30, 2009 consist of $4.2 million in cash and cash equivalents, $4.8 million in trade accounts receivable and other current assets, $398.8 million in property, plant and equipment, net and $107.0 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.

Holly Senior Notes Due 2017

On June 10, 2009, we issued $200 million in aggregate principal amount of 9.875% senior notes due 2017 (the “Holly Senior Notes”). A portion of the $188.0 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products from Sunoco following the closing of the Tulsa Refinery purchase on June 1, 2009. The remaining proceeds are available for general business purposes, including capital expenditures.

The Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%. The Holly Senior Notes are unsecured and impose certain restrictive covenants, including limitations on Holly’s ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. At any time when the Holly Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Holly Senior Notes.

HEP Senior Notes Due 2015

The HEP senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (the “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.

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The carrying amount of Holly’s long-term debt is as follows:


	June 30,			December 31,
	2009			2008
	(In thousands)
Holly Senior Notes
Principal	$	200,000		$	—
Unamortized discount		(12,036	)		—


Total long-term debt	$	187,964		$	—

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


	June 30,			December 31,
	2009			2008
	(In thousands)
HEP Credit Agreement	$	218,000		$	200,000

HEP Senior Notes
Principal		185,000			185,000
Unamortized discount		(14,908	)		(16,223	)
Unamortized premium – dedesignated fair value hedge		1,964			2,137

		172,056			170,914


Total debt		390,056			370,914
Less short-term borrowings under HEP Credit Agreement⁽¹⁾		—			29,000


Total long-term debt⁽¹⁾	$	390,056		$	341,914


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

At June 30, 2009, the estimated fair values of the Holly Senior Notes and the HEP Senior Notes were $195.0 million and $161.0 million, respectively.

Interest Rate Risk Management

HEP uses interest rate derivatives to manage its exposure to interest rate risk. As of June 30, 2009, HEP had three interest rate swap contracts.

HEP has an interest rate swap that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on its $171.0 million credit agreement advance that was used to finance its purchase of the Crude Pipelines and Tankage Assets in February 2008. This interest rate swap effectively converts its $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.00%, which equaled an effective interest rate of 5.74% as of June 30, 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.

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 the $171.0 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of June 30, 2009, HEP had no ineffectiveness on its cash flow hedge.

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HEP also has an interest rate swap contract that effectively converts interest expense associated with $60.0 million of the 6.25% HEP 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 1.83% as of June 30, 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 the 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 dedesignated 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 dedesignation 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 and six months ended June 30, 2009, HEP recognized a reduction of $0.8 million and $0.6 million, respectively, 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.

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 6.25% HEP Senior Notes	Other assets	$	2,751		Long-term debt - HEP	$	(1,964	)
					Equity		(1,942	)⁽¹⁾
					Interest expense		1,155	⁽²⁾

		$	2,751			$	(2,751	)

Liability
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	(8,700	)	Accumulated other comprehensive loss	$	8,700

					Equity		4,166	⁽¹⁾
Variable-to-fixed interest rate swap – $60 million	Other long-term liabilities		(2,209	)	Interest expense		(1,957	)

		$	(10,909	)		$	10,909


(1)		Represents prior year charges to interest expense.

(2)		Net of amortization of premium attributable to dedesignated hedge.

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NOTE 10: Equity

Changes to equity during the six months ended June 30, 2009 are presented below:


	Holly
	Corporation
	Stockholders’			Noncontrolling			Total
	Equity			Interest			Equity
Balance at December 31, 2008	$	541,540		$	394,792		$	936,332

Net income		36,550			8,921			45,471
Other comprehensive income		1,152			2,260			3,412
Dividends		(15,055	)		—			(15,055	)
Distributions to noncontrolling interest		—			(14,529	)		(14,529	)
Issuance of common stock upon exercise of stock options		45			—			45
Equity based compensation expense, net of forfeitures		3,920			417			4,337
Tax benefit from equity based compensation		2,110			—			2,110
Issuance of HEP common units, net of issuing costs		—			58,195			58,195
Contribution from joint venture partner		—			7,450			7,450
Purchase of treasury stock		(1,214	)		—			(1,214	)
Other		531			(516	)		15


Balance at December 31, 2008	$	569,579		$	456,990		$	1,026,569

During the six months ended June 30, 2009, we repurchased at current market prices 59,934 shares of our common stock at a cost of approximately $1.2 million from certain officers and key employees. 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 are as follows:


				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
For the three months ended June 30, 2009
Unrealized gain on available-for-sale securities	$	205		$	80		$	125
Unrealized gain on HEP cash flow hedge		4,417			786			3,631

Other comprehensive income		4,622			866			3,756
Less other comprehensive income attributable to noncontrolling interest		2,396			—			2,396

Other comprehensive income attributable to Holly Corporation stockholders	$	2,226		$	866		$	1,360


For the three months ended June 30, 2008
Unrealized gain on available-for-sale securities	$	469		$	182		$	287
Unrealized gain on HEP cash flow hedge		6,797			1,091			5,706

Other comprehensive income		7,266			1,273			5,993
Less other comprehensive income attributable to noncontrolling interest		3,687			—			3,687

Other comprehensive income attributable to Holly Corporation stockholders	$	3,579		$	1,273		$	2,306


For the six months ended June 30, 2009
Unrealized loss on available-for-sale securities	$	(22	)	$	(9	)	$	(13	)
Unrealized gain on HEP cash flow hedge		4,167			742			3,425

Other comprehensive income		4,145			733			3,412
Less other comprehensive income attributable to noncontrolling interest		2,260			—			2,260

Other comprehensive income attributable to Holly Corporation stockholders	$	1,885		$	733		$	1,152

- 21 -


				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
For the six months ended June 30, 2008
Unrealized loss on available-for-sale securities	$	(12	)	$	(5	)	$	(7	)
Unrealized gain on HEP cash flow hedge		2,448			393			2,055

Other comprehensive income		2,436			388			2,048
Less other comprehensive income attributable to noncontrolling interest		1,328			—			1,328

Other comprehensive income attributable to Holly Corporation stockholders	$	1,108		$	388		$	720

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

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


	June 30,			December 31,
	2009			2008
	(In thousands)
Pension obligation adjustment	$	(29,409	)	$	(29,409	)
Retiree medical obligation adjustment		(2,202	)		(2,202	)
Unrealized gain on available-for-sale securities		115			128
Unrealized loss on HEP cash flow hedge		(2,433	)		(3,598	)

Accumulated other comprehensive loss	$	(33,929	)	$	(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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands)
Service cost	$	990		$	1,090		$	2,079		$	2,180
Interest cost		1,189			1,193			2,420			2,386
Expected return on assets		(922	)		(1,143	)		(1,924	)		(2,287	)
Amortization of prior service cost		97			97			195			195
Amortization of net loss		1,818			351			1,837			702

Net periodic benefit cost	$	3,172		$	1,588		$	4,607		$	3,176

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 zero million and $10.0 million to the retirement plan in 2009.

NOTE 13: Contingencies

- 22 -

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 on SFPP’s East Line. 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 relating to East Line service 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 reduced SFPP’s current rates and required SFPP to make additional payments to us of approximately $2.9 million, which was received on May 18, 2009.

On June 2, 2009, SFPP notified us that it would terminate the October 2008 settlement, as provided under the settlement, effective August 31, 2009. On July 31, 2009, SFPP filed substantial rate increases for East Line service to become effective September 1, 2009. We intend to file a protest to this rate increase and to challenge it vigorously. We believe that other shippers will take similar action. We are not in a position to predict the ultimate outcome of the rate proceeding.

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, Woods Cross and Tulsa Refineries and Holly Asphalt Company. It involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel, jet fuel and specialty lubricant products. The petroleum products produced by the Refining segment are primarily marketed in the southwest, rocky mountain and mid-continent regions of the United States and northern Mexico. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. Holly Asphalt Company manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

HEP is a VIE as defined under FIN No. 46(R). Under the provisions of FIN No. 46(R), HEP’s purchase of the Crude Pipelines and Tankage Assets in 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.

- 23 -

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. Additionally, HEP owns a 25% interest in SLC Pipeline that services refiners in the Salt Lake City, Utah area. 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.

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.


								Consolidations
					Corporate			and			Consolidated
	Refining⁽¹⁾		HEP⁽²⁾		and Other			Eliminations			Total
	(In thousands)
Three Months Ended June 30, 2009
Sales and other revenues	$	1,019,919	$	40,602	$	2,979		$	(25,119	)	$	1,038,381
Depreciation and amortization	$	17,832	$	6,482	$	1,186		$	—		$	25,500
Income (loss) from operations	$	29,530	$	21,217	$	(11,408	)	$	—		$	39,339
Capital expenditures	$	38,229	$	45,456	$	480		$	—		$	84,165

Three Months Ended June 30, 2008
Sales and other revenues	$	1,736,201	$	26,774	$	886		$	(20,039	)	$	1,743,822
Depreciation and amortization	$	8,699	$	6,220	$	1,010		$	—		$	15,929
Income (loss) from operations	$	22,736	$	9,210	$	(11,720	)	$	—		$	20,226
Capital expenditures	$	116,509	$	8,950	$	564		$	—		$	126,023

Six Months Ended June 30, 2009
Sales and other revenues	$	1,656,829	$	72,727	$	3,078		$	(43,430	)	$	1,689,204
Depreciation and amortization	$	29,783	$	12,300	$	3,738		$	—		$	45,821
Income (loss) from operations	$	68,235	$	35,403	$	(24,400	)	$	—		$	79,238
Capital expenditures	$	126,467	$	56,026	$	900		$	—		$	183,393

Six Months Ended June 30, 2008
Sales and other revenues	$	3,213,577	$	36,716	$	1,287		$	(27,774	)	$	3,223,806
Depreciation and amortization	$	18,980	$	8,230	$	2,028		$	—		$	29,238
Income (loss) from operations	$	41,620	$	12,944	$	(24,745	)	$	—		$	29,819
Capital expenditures	$	185,325	$	12,202	$	1,257		$	—		$	198,784


(1)		The Refining segment reflects the operations of our Tulsa Refinery beginning June 1, 2009, our date of acquisition.

(2)		HEP segment revenues from external customers were $29.6 million and $6.7 million for the three months ended June 30, 2009 and 2008, respectively and $15.6 million and $8.9 million for the six months ended June 30, 2009 and 2008, respectively.

- 24 -


							Consolidations
					Corporate		and			Consolidated
	Refining		HEP		and Other		Eliminations			Total
	(In thousands)
June 30, 2009
Cash, cash equivalents and investments in marketable securities	$	—	$	4,195	$	105,284	$	—		$	109,479
Total assets	$	1,807,743	$	524,285	$	302,476	$	(13,063	)	$	2,621,441

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: Supplemental Guarantor/Non-Guarantor Financial Information

Our obligations under the Holly Senior Notes have been jointly and severally guaranteed by the substantial majority of our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”). These guarantees are full and unconditional. HEP in which we have a 41% ownership interest and its subsidiaries (collectively, “Non-Guarantor Non-Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed these obligations.

The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of Holly Corporation (the “Parent”), the Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor Restricted Subsidiaries are collectively the “Restricted Subsidiaries.”

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.

- 25 -

Condensed Consolidating Balance Sheet


							Non-
				Guarantor			Guarantor						Parent &		Non-Guarantor
				Restricted			Restricted						Restricted		Non-Restricted
June 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
										(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	99,383		$	(693	)		5,803		$	—		$	104,493	$	4,195	$	—		$	108,688
Marketable securities		—			791			—			—			791		—		—			791
Accounts receivable		987			600,871			38			—			601,896		13,480		(10,676	)		604,700
Intercompany accounts receivable (payable)		(1,223,417	)		916,505			306,912			—			—		—		—			—
Inventories		—			263,866			—			—			263,866		182		—			264,048
Income taxes receivable		5,841			—			—			—			5,841		—		—			5,841
Prepayments and other assets		21,449			7,826			—			—			29,275		645		(3,531	)		26,389

Total current assets		(1,095,757	)		1,789,166			312,753			—			1,006,162		18,502		(14,207	)		1,010,457

Properties and equipment, net		21,955			871,521			132,897			—			1,026,373		398,827		—			1,425,200
Investment in subsidiaries		1,995,838			408,085			(324,583	)		(2,079,340	)		—		26,098		(26,098	)		—
Intangibles and other assets		5,971			71,713			—			—			77,684		80,858		27,242			185,784

Total assets	$	928,007		$	3,140,485		$	121,067		$	(2,079,340	)	$	2,110,219	$	524,285	$	(13,063	)	$	2,621,441


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	16,862		$	786,516		$	2,796		$	—		$	806,174	$	9,120	$	(10,675	)	$	804,619
Accrued liabilities		19,915			13,684			460			—			34,059		15,944		(3,532	)		46,471

Total current liabilities		36,777			800,200			3,256			—			840,233		25,064		(14,207	)		851,090

Commitments and contingencies		—			65,876			—			—			65,876		—		(65,876	)		—
Long-term debt		187,964			(187,964	)		—			—			—		415,564		162,456			578,020
Deferred income taxes		87,987			60			357			—			88,404		—		—			88,404
Other long-term liabilities		46,070			141,894			—			—			187,964		11,482		(122,088	)		77,358
Distributions in excess of inv in HEP		—			324,581			—			—			324,581		—		(324,581	)		—
Equity — Holly Corporation		569,209			1,995,838			117,454			(2,113,292	)		569,209		61,635		(61,265	)		569,579
Equity — Noncontrolling interest		—			—			—			33,952			33,952		10,540		412,498			456,990

Total liabilities and equity	$	928,007		$	3,140,485		$	121,067		$	(2,079,340	)	$	2,110,219	$	524,285	$	(13,063	)	$	2,621,441

Condensed Consolidating Balance Sheet


							Non-
				Guarantor			Guarantor						Parent &		Non-Guarantor
				Restricted			Restricted						Restricted		Non-Restricted
December 31, 2008	Parent			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
										(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	33,316		$	(1,182	)	$	3,402		$	—		$	35,536	$	5,269	$	—		$	40,805
Marketable securities		48,590			604			—			—			49,194		—		—			49,194
Accounts receivable		1,734			283,480			1,524			—			286,738		14,477		(11,451	)		289,764
Intercompany accounts receivable (payable)		(1,419,212	)		1,134,118			285,094			—			—		—		—			—
Inventories		—			125,613			—			—			125,613		122		—			125,735
Income taxes receivable		6,350			—			—			—			6,350		—		—			6,350
Prepayments and other assets		13,814			6,842			—			—			20,656		471		(2,352	)		18,775

Total current assets		(1,315,408	)		1,549,475			290,020			—			524,087		20,339		(13,803	)		530,623

Properties and equipment, net		22,997			718,575			109,660			—			851,232		354,090		—			1,205,322
Marketable securities (long-term)		6,009			—			—			—			6,009		—		—			6,009
Investment in subsidiaries		1,911,613			371,964			(321,003	)		(1,962,574	)		—		—		—			—
Intangibles and other assets		—			48,651			—			—			48,651		83,620		—			132,271

Total assets	$	625,211		$	2,688,665		$	78,677		$	(1,962,574	)	$	1,429,979	$	458,049	$	(13,803	)	$	1,874,225


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	9,269		$	384,285		$	1,021		$	—		$	394,575	$	8,018	$	(11,451	)	$	391,142
Accrued liabilities		15,086			8,118			11			—			23,215		21,153		(2,352	)		42,016
Other liabilities		(8,130	)		8,130			—			—			—		—		—			—
Short-term debt		—			—			—			—			—		29,000		—			29,000

Total current liabilities		16,225			400,533			1,032			—			417,790		58,171		(13,803	)		462,158

Long-term debt		—			—			—			—			—		341,914		—			341,914
Non-current liabilities		41,693			5,033			—			—			46,726		17,604		—			64,330
Deferred income taxes		24,894			44,597			—			—			69,491		—		—			69,491
Distributions in excess of inv in HEP		—			326,889			—			—			326,889		—		(326,889	)		—
Equity — Holly Corporation		542,399			1,911,613			77,645			(1,989,258	)		542,399		30,142		(31,001	)		541,540
Equity — Noncontrolling interest		—			—			—			26,684			26,684		10,218		357,890			394,792

Total liabilities and equity	$	625,211		$	2,688,665		$	78,677		$	(1,962,574	)	$	1,429,979	$	458,049	$	(13,803	)	$	1,874,225

- 26 -

Condensed Consolidating Statement of Income


				Guarantor			Non-Guarantor						Parent &			Non-Guarantor
				Restricted			Restricted						Restricted			Non-Restricted
Three months ended June 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	97		$	1,022,772		$	29		$	—		$	1,022,898		$	40,602		$	(25,119	)	$	1,038,381

Operating costs and expenses:
Cost of products sold		—			904,786			131			—			904,917			—			(24,991	)		879,926
Operating expenses		—			67,648			—			—			67,648			11,086			(226	)		78,508
General and administrative expenses		12,643			550			—			—			13,193			1,817			98			15,108
Depreciation and amortization		965			17,736			317			—			19,018			6,482			—			25,500


Total operating costs and expenses		13,608			990,720			448			—			1,004,776			19,385			(25,119	)		999,042


Income (loss) from operations		(13,511	)		32,052			(419	)		—			18,122			21,217			—			39,339

Other income (expense):
Equity in earnings of subsidiaries		35,942			6,619			8,029			(42,561	)		8,029			488			(8,029	)		488
Interest income (expense)		(2,743	)		582			9			—			(2,152	)		(4,917	)		(2	)		(7,071	)
Tulsa Refinery acquisition costs		1,701			(3,311	)		—			—			(1,610	)		—			—			(1,610	)


		34,900			3,890			8,038			(42,561	)		4,267			(4,429	)		(8,031	)		(8,193	)


Income (loss) before income taxes		21,389			35,942			7,619			(42,561	)		22,389			16,677			(8,031	)		31,146

Income tax provision		9,464			—			—			—			9,464			111			—			9,575


Net income		11,925			35,942			7,619			(42,561	)		12,925			16,677			(8,031	)		21,571

Less net income attributable to noncontrolling interest		—			—			—			(104	)		(104	)		427			6,643			6,966


Net income attributable to Holly Corporation stockholders	$	11,925		$	35,942		$	7,619		$	(42,457	)	$	13,029		$	16,250		$	(14,674	)	$	14,605

Condensed Consolidating Statement of Income


						Non-
				Guarantor		Guarantor						Parent &		Non-Guarantor
				Restricted		Restricted						Restricted		Non-Restricted
Three months ended June 30, 2008	Parent			Subsidiaries		Subsidiaries			Eliminations			Subsidiaries		Subsidiaries			Eliminations			Consolidated
									(In thousands)
Sales and other revenues	$	467		$	1,736,620	$	—		$	—		$	1,737,087	$	26,774		$	(20,039	)	$	1,743,822

Operating costs and expenses:
Cost of products sold		—			1,640,579		10			—			1,640,589		—			(20,039	)		1,620,550
Operating expenses		—			64,200		(10	)		—			64,190		9,985			—			74,175
General and administrative expenses		8,683			2,900		—			—			11,583		1,359			—			12,942
Depreciation and amortization		789			8,920		—			—			9,709		6,220			—			15,929


Total operating costs and expenses		9,472			1,716,599		—			—			1,726,071		17,564			(20,039	)		1,723,596


Income (loss) from operations		(9,005	)		20,021		—			—			11,016		9,210			—			20,226

Other income (expense):
Equity in earnings of subsidiaries		32,235			3,205		3,073			(35,440	)		3,073		—			(3,073	)		—
Interest income (expense)		(5,652	)		9,009		132			—			3,489		(5,914	)		—			(2,425	)
Other Income		—			—		—			—			—		—			—			—


		26,583			12,214		3,205			(35,440	)		6,562		(5,914	)		(3,073	)		(2,425	)


Income (loss) before income taxes		17,578			32,235		3,205			(35,440	)		17,578		3,296			(3,073	)		17,801

Income tax provision		5,770			—		—			—			5,770		86			—			5,856


Net income		11,808			32,235		3,205			(35,440	)		11,808		3,210			(3,073	)		11,945

Less net income attributable to noncontrolling interest		—			—		—			31			31		264			198			493


Net income attributable to Holly Corporation stockholders	$	11,808		$	32,235	$	3,205		$	(35,471	)	$	11,777	$	2,946		$	(3,271	)	$	11,452

- 27 -

Condensed Consolidating Statement of Income


							Non-
				Guarantor			Guarantor						Parent &			Non-Guarantor
				Restricted			Restricted						Restricted			Non-Restricted
Six months ended June 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	195		$	1,659,654		$	58		$	—		$	1,659,907		$	72,727		$	(43,430	)	$	1,689,204

Operating costs and expenses:
Cost of products sold		—			1,434,502			254			—			1,434,756			—			(43,176	)		1,391,580
Operating expenses		—			124,082			—			—			124,082			21,882			(254	)		145,710
General and administrative expenses		22,599			1,114			—			—			23,713			3,142			—			26,855
Depreciation and amortization		1,937			30,950			634			—			33,521			12,300			—			45,821


Total operating costs and expenses		24,536			1,590,648			888			—			1,616,072			37,324			(43,430	)		1,609,966


Income (loss) from operations		(24,341	)		69,006			(830	)		—			43,835			35,403			—			79,238

Other income (expense):
Equity in earnings of subsidiaries		79,356			11,519			13,249			(90,875	)		13,249			663			(13,249	)		663
Interest income (expense)		(2,352	)		2,142			22			—			(188	)		(10,924	)		(2	)		(11,114	)
SLC Pipeline acquisition costs		—			—			—			—			—			(2,500	)		2,500			—
Tulsa Refinery acquisition costs		1,701			(3,311	)		—			—			(1,610	)		—			—			(1,610	)


		78,705			10,350			13,271			(90,875	)		11,451			(12,761	)		(10,751	)		(12,061	)


Income (loss) before income taxes		54,364			79,356			12,441			(90,875	)		55,286			22,642			(10,751	)		67,177

Income tax provision		21,503			—			—			—			21,503			203			—			21,706


Net income		32,861			79,356			12,441			(90,875	)		33,783			22,439			(10,751	)		45,471

Less net income attributable to noncontrolling interest		—			—			—			(182	)		(182	)		922			8,181			8,921


Net income attributable to Holly Corporation stockholders	$	32,861		$	79,356		$	12,441		$	(90,693	)	$	33,965		$	21,517		$	(18,932	)	$	36,550

Condensed Consolidating Statement of Income


						Non-
				Guarantor		Guarantor						Parent &		Non-Guarantor
				Restricted		Restricted						Restricted		Non-Restricted
Six months ended June 30, 2008	Parent			Subsidiaries		Subsidiaries			Eliminations			Subsidiaries		Subsidiaries			Eliminations			Consolidated
									(In thousands)
Sales and other revenues	$	1,772		$	3,213,092	$	—		$	—		$	3,214,864	$	36,716		$	(27,774	)	$	3,223,806

Operating costs and expenses:
Cost of products sold		—			3,031,230		347			—			3,031,577		—			(27,590	)		3,003,987
Operating expenses		—			121,353		53			—			121,406		13,661			(184	)		134,883
General and administrative expenses		22,254			1,744		—			—			23,998		1,881			—			25,879
Depreciation and amortization		1,584			19,424		—			—			21,008		8,230			—			29,238


Total operating costs and expenses		23,838			3,173,751		400			—			3,197,989		23,772			(27,774	)		3,193,987


Income (loss) from operations		(22,066	)		39,341		(400	)		—			16,875		12,944			—			29,819

Other income (expense):
Equity in earnings of subsidiaries		72,582			7,202		7,279			(79,784	)		7,279		—			(4,289	)		2,990
Interest income (expense)		(19,615	)		26,039		323			—			6,747		(7,609	)		—			(862	)


		52,967			33,241		7,602			(79,784	)		14,026		(7,609	)		(4,289	)		2,128


Income (loss) before income taxes		30,901			72,582		7,202			(79,784	)		30,901		5,335			(4,289	)		31,947

Income tax provision		10,444			—		—			—			10,444		107			—			10,551


Net income		20,457			72,582		7,202			(79,784	)		20,457		5,228			(4,289	)		21,396

Less net income attributable to noncontrolling interest		—			—		—			31			31		355			909			1,295


Net income attributable to Holly Corporation stockholders	$	20,457		$	72,582	$	7,202		$	(79,815	)	$	20,426	$	4,873		$	(5,198	)	$	20,101

- 28 -

Condensed Consolidating Statement of Cash Flows


							Non-
				Guarantor			Guarantor					Parent &			Non-Guarantor
				Restricted			Restricted					Restricted			Non-Restricted
Six months ended June 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Cash flows from operating activities	$	(195,175	)	$	317,535		$	979		$	—	$	123,339		$	32,250		$	(14,039	)	$	141,550

Cash flows from investing activities
Additions to properties, plants and equipment — Holly		34,200			(133,188	)		(28,379	)		—		(127,367	)		—			—			(127,367	)
Additions to properties, plants and equipment — HEP		—			—			—			—		—			(56,026	)		—			(56,026	)
Acquisition of Tulsa Refinery — Holly Corporation		—			(157,814	)		—			—		(157,814	)		—			—			(157,814	)
Investment in SLC Pipeline — Holly Energy Partners		—			—			—			—		—			(25,500	)		—			(25,500	)
Purchases of marketable securities		(165,892	)		—			—			—		(165,892	)		—			—			(165,892) -
Sales and maturities of marketable securities		220,281			—			—			—		220,281			—			—			220,281


Net cash provided by (used for) investing activities		88,589			(291,002	)		(28,379	)		—		(230,792	)		(81,526	)		—			(312,318	)


Cash flows from financing activities
Proceeds from issuance of senior notes, net of discounts — Holly Corporation		187,925			—			—			—		187,925			—			—			187,925
Proceeds from issuance of common units — Holly Energy Partners		—			—			—			—		—			58,355			—			58,355
Net Borrowings under credit agreement — Holly Energy Partners		—			—			—			—		—			18,000			—			18,000
Dividends		(15,022	)		—			—			—		(15,022	)		—			—			(15,022	)
Distributions to noncontrolling interest		—			—			—			—		—			(28,568	)		14,039			(14,529	)
Purchase of treasury stock		(1,214	)		—			—			—		(1,214	)		—			—			(1,214	)
Contribution from joint venture partner		—			(20,850	)		29,800			—		8,950			—			—			8,950
Excess tax benefit from equity based compensation		2,110			—			—			��		2,110			—			—			2,110
Deferred financing costs		(5,193	)		—			—			—		(5,193	)		—			—			(5,193	)
Other		(1,146	)		—			—			—		(1,146	)		415			—			(731	)


Net cash provided by (used for) financing activities		167,460			(20,850	)		29,800			—		176,410			48,202			14,039			238,651


Cash and cash equivalents
Increase (decrease) for the period		60,874			5,683			2,400			—		68,957			(1,074	)		—			67,883
Beginning of period		33,316			(1,182	)		3,402			—		35,536			5,269			—			40,805


End of period	$	94,190		$	4,501		$	5,802		$	—	$	104,493		$	4,195		$	—		$	108,688

- 29 -

Condensed Consolidating Statement of Cash Flows


							Non-
				Guarantor			Guarantor					Parent &			Non-Guarantor
				Restricted			Restricted					Restricted			Non-Restricted
Six months ended June 30, 2008	Parent			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Cash flows from operating activities	$	85,458		$	9,980		$	19,441		$	—	$	114,879		$	6,089		$	(6,355	)	$	114,613

Cash flows from investing activities
Additions to properties, plants and equipment — Holly		—			(123,727	)		(62,855	)		—		(186,582	)		—			—			(186,582	)
Additions to properties, plants and equipment — HEP		—			—			—			—		—			(12,202	)		—			(12,202	)
Purchases of marketable securities		(303,257	)		—			—			—		(303,257	)		—			—			(303,257	)
Sales and maturities of marketable securities		395,520			—			—			—		395,520			—			—			395,520
Proceeds from sale of crude pipeline and tankage assets		—			171,000			—			—		171,000			—			—			171,000
Increase in cash due to consolidation of HEP		—			—			—			—		—			—			7,295			7,295
Investment in HEP		—			(290	)		—			—		(290	)		—			—			(290	)


Net cash provided by (used for) investing activities		92,263			46,983			(62,855	)		—		76,391			(12,202	)		7,295			71,484


Cash flows from financing activities
Net borrowings under credit agreements		—			—			—			—		—			20,000			—			20,000
Dividends		(14,055	)		—			—			—		(14,055	)		—			—			(14,055	)
Distributions to noncontrolling interest		—			—			—			—		—			(13,933	)		6,356			(7,577	)
Purchase of treasury stock		(136,876	)		—			—			—		(136,876	)		—			—			(136,876	)
Contribution from joint venture partner		10,000			(40,000	)		40,000			—		10,000			—			—			10,000
Excess tax benefit from equity based compensation		3,436			—			—			—		3,436			—			—			3,436
Deferred financing costs		—			—			—			—		—			(365	)		—			(365	)
Other		256			—			—			—		256			(224	)		(290	)		(258	)


Net cash provided by (used for) financing activities		(137,239	)		(40,000	)		40,000			—		(137,239	)		5,478			6,066			(125,695	)


Cash and cash equivalents

Increase (decrease) for the period		40,482			16,963			(3,414	)		—		54,031			(635	)		7,006			60,402
Beginning of period		97,953			(17,912	)		14,328			—		94,369			7,006			(7,006	)		94,369


End of period	$	138,435		$	(949	)	$	10,914		$	—	$	148,400		$	6,371		$	—		$	154,771

Note 16: Subsequent Event

On August 1, 2009, we announced the sale of our truck and rail loading facilities at our Tulsa Refinery to HEP for $17.5 million. In connection with this transaction, we have also entered into a 15-year equipment and throughput agreement with HEP for usage of the facilities to load or unload products via tanker truck and / or rail car. Since HEP is a consolidated subsidiary, the effects of this transaction will be eliminated in our consolidated financial statements.

- 30 -

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 with certain exceptions. For periods prior to our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” exclude HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation. 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 three refineries in Artesia and Lovington, New Mexico (operated as one refinery and collectively known as the “Navajo Refinery”), Woods Cross, Utah (the “Woods Cross Refinery”) and Tulsa, Oklahoma (the “Tulsa Refinery”). As of June 30, 2009, our refineries had a combined crude capacity of 216,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At June 30, 2009, we also owned a 41% interest in HEP, which owns and operates pipeline and terminalling assets, and owns a 70% interest in Rio Grande Pipeline Company (“Rio Grande”) and a 25% interest in SLC Pipeline LLC (“SLC Pipeline”).

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel, jet fuel and specialty lubricant products in markets in the southwest, rocky mountain and mid-continent regions of the United States and in northern Mexico. For the six months ended June 30, 2009, sales and other revenues were $1,689.2 million and net income attributable to Holly Corporation stockholders was $36.6 million. For the six months ended June 30, 2008, sales and other revenues were $3,223.8 million and net income attributable to Holly Corporation stockholders was $20.1 million. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the six months ended June 30, 2009 were $1,610.0 million compared to $3,194.0 million for the six months ended June 30, 2008.

On June 1, 2009, we acquired the Tulsa Refinery from Sunoco, Inc. (“Sunoco”) for $157.8 million, including crude oil, refined product and other inventories totaling $92.8 million. The Tulsa Refinery is located on a 750-acre site in Tulsa, Oklahoma and has a total crude oil throughput capacity of approximately 85,000 BPSD. The refinery produces fuel products including gasoline, diesel fuel and jet fuel and serves markets in the mid-continent region of the United States and also produces specialty lubricant products that are marketed throughout North America and are distributed in Central and South America.

HEP is a variable interest entity (“VIE”) as defined under Financial Accounting Standards Board Interpretation (“FIN”) No. 46(R). Under the provisions of FIN No. 46(R), HEP’s purchase of our crude pipelines and tankage assets in 2008 (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.

- 31 -

RESULTS OF OPERATIONS

Financial Data (Unaudited)


	Three Months Ended
	June 30,						Change from 2008
	2009			2008			Change			Percent
				(In thousands, except per share data)
Sales and other revenues	$	1,038,381		$	1,743,822		$	(705,441	)		(40.5	)%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		879,926			1,620,550			(740,624	)		(45.7	)
Operating expenses (exclusive of depreciation and amortization)		78,508			74,175			4,333			5.8
General and administrative expenses (exclusive of depreciation and amortization)		15,108			12,942			2,166			16.7
Depreciation and amortization		25,500			15,929			9,571			60.1

Total operating costs and expenses		999,042			1,723,596			(724,554	)		(42.0	)


Income from operations		39,339			20,226			19,113			94.5
Other income (expense):
Equity in earnings of SLC Pipeline		488			—			488			—
Interest income		134			3,826			(3,692	)		(96.5	)
Interest expense		(7,205	)		(6,251	)		(954	)		15.3
Tulsa Refinery acquisition costs		(1,610	)		—			(1,610	)		—

		(8,193	)		(2,425	)		(5,768	)		237.9

Income before income taxes		31,146			17,801			13,345			75.0
Income tax provision		9,575			5,856			3,719			63.5

Net income⁽¹⁾		21,571			11,945			9,626			80.6
Less noncontrolling interest in net income⁽¹⁾		6,966			493			6,473			1,313.0


Net income attributable to Holly Corporation stockholders⁽¹⁾	$	14,605		$	11,452		$	3,153			27.5	%


Net income per share attributable to Holly Corporation stockholders – basic	$	0.29		$	0.23		$	0.06			26.1	%


Net income per share attributable to Holly Corporation stockholders – diluted	$	0.29		$	0.23		$	0.06			26.1	%


Cash dividends declared per common share	$	0.15		$	0.15		$	—			—	%

Average number of common shares outstanding:
Basic		50,170			50,158			12			—	%
Diluted		50,226			50,515			(289	)		(0.6	)%

- 32 -


	Six Months Ended
	June 30,						Change from 2008
	2009			2008			Change			Percent
				(In thousands, except per share data)
Sales and other revenues	$	1,689,204		$	3,223,806		$	(1,534,602	)		(47.6	)%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		1,391,580			3,003,987			(1,612,407	)		(53.7	)
Operating expenses (exclusive of depreciation and amortization)		145,710			134,883			10,827			8.0
General and administrative expenses (exclusive of depreciation and amortization)		26,855			25,879			976			3.8
Depreciation and amortization		45,821			29,238			16,583			56.7

Total operating costs and expenses		1,609,966			3,193,987			(1,584,021	)		(49.6	)


Income from operations		79,238			29,819			49,419			165.7
Other income (expense):
Equity in earnings of SLC Pipeline		663			—			663			—
Interest income		2,330			7,381			(5,051	)		(68.4	)
Interest expense		(13,444	)		(8,243	)		(5,201	)		63.1
Tulsa Refinery acquisition costs		(1,610	)		—			(1,610	)		—
Equity in earnings of HEP		—			2,990			(2,990	)		(100.0	)

		(12,061	)		2,128			(14,189	)		(666.8	)

Income before income taxes		67,177			31,947			35,230			110.3
Income tax provision		21,706			10,551			11,155			105.7

Net income⁽¹⁾		45,471			21,396			24,075			112.5
Less noncontrolling interest in net income⁽¹⁾		8,921			1,295			7,626			588.9

Net income attributable to Holly Corporation stockholders⁽¹⁾	$	36,550		$	20,101		$	16,449			81.8	%


Net income per share attributable to Holly Corporation stockholders – basic	$	0.73		$	0.40		$	0.33			82.5	%


Net income per share attributable to Holly Corporation stockholders – diluted	$	0.73		$	0.39		$	0.34			87.2	%


Cash dividends declared per common share	$	0.30		$	0.30		$	—			—	%

Average number of common shares outstanding:
Basic		50,106			50,654			(548	)		(1.1	)%
Diluted		50,189			51,015			(826	)		(1.6	)%

Balance Sheet Data (Unaudited)


	June 30,		December 31,
	2009		2008
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	109,479	$	96,008
Working capital	$	159,367	$	68,465
Total assets	$	2,621,441	$	1,874,225
Long-term debt – Holly Corporation	$	187,964	$	—
Long-term debt – Holly Energy Partners	$	390,056	$	341,914
Total equity⁽¹⁾	$	1,026,569	$	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 noncontrolling 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 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 retrospective basis. While this presentation differs from previous GAAP requirements, this standard did not affect our net income and equity attributable to Holly Corporation stockholders.

- 33 -

Other Financial Data (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(In thousands)
Net cash provided by operating activities	$	143,865		$	15,763		$	141,550		$	114,613
Net cash provided by (used for) investing activities	$	(241,979	)	$	(11,975	)	$	(312,318	)	$	71,484
Net cash provided by (used for) financing activities	$	152,924		$	(29,568	)	$	238,651		$	(125,695	)
Capital expenditures	$	84,165		$	126,023		$	183,393		$	198,784
EBITDA⁽¹⁾	$	56,751		$	35,662		$	115,191		$	60,752


(1)		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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(In thousands)
Sales and other revenues
Refining⁽¹⁾	$	1,019,919		$	1,736,201		$	1,656,829		$	3,213,577
HEP⁽²⁾		40,602			26,774			72,727			36,716
Corporate and Other		2,979			886			3,078			1,287
Consolidations and Eliminations		(25,119	)		(20,039	)		(43,430	)		(27,774	)

Consolidated	$	1,038,381		$	1,743,822		$	1,689,204		$	3,223,806


Operating Income (loss)
Refining⁽¹⁾	$	29,530		$	22,736		$	68,235		$	41,620
HEP⁽²⁾		21,217			9,210			35,403			12,944
Corporate and Other		(11,408	)		(11,720	)		(24,400	)		(24,745	)
Consolidations and Eliminations		—			—			—			—

Consolidated	$	39,339		$	20,226		$	79,238		$	29,819


(1)		The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries 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, jet fuel and specialty lubricant products. The petroleum products produced by the Refining segment are primarily marketed in the southwest, rocky mountain and mid-continent regions of the United States and northern Mexico. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. Holly Asphalt Company manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

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(2)

The HEP segment involves all of the operations of HEP effective March 1, 2008 (date of reconsolidation). HEP owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico and Utah. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through 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. Additionally, HEP owns a 25% interest in the SLC Pipeline that services refineries in the Salt lake City, Utah area. 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, Woods Cross and Tulsa Refineries. The following tables set forth information, including non-GAAP performance 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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Navajo Refinery*
Crude charge (BPD)⁽¹⁾		85,760			72,800			71,800			78,000
Refinery production (BPD)⁽²⁾		96,670			76,960			79,960			85,800
Sales of produced refined products (BPD)		95,810			79,910			79,070			86,980
Sales of refined products (BPD)⁽³⁾		96,340			88,720			83,810			97,070

Refinery utilization⁽⁴⁾		85.8	%		85.6	%		71.8	%		91.8	%

Average per produced barrel⁽⁵⁾
Net sales	$	67.93		$	133.89		$	63.80		$	117.33
Cost of products⁽⁶⁾		59.54			125.82			53.83			110.15

Refinery gross margin		8.39			8.07			9.97			7.18
Refinery operating expenses⁽⁷⁾		4.56			5.68			5.19			4.98

Net operating margin	$	3.83		$	2.39		$	4.78		$	2.20


Feedstocks:
Sour crude oil		83	%		83	%		83	%		81	%
Sweet crude oil		6	%		10	%		7	%		9	%
Other feedstocks and blends		11	%		7	%		10	%		10	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		57	%		55	%		58	%		57	%
Diesel fuels		34	%		34	%		33	%		33	%
Jet fuels		1	%		1	%		1	%		1	%
Fuel oil		3	%		3	%		3	%		3	%
Asphalt		3	%		4	%		3	%		3	%
LPG and other		2	%		3	%		2	%		3	%

Total		100	%		100	%		100	%		100	%

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Woods Cross Refinery*
Crude charge (BPD)⁽¹⁾		25,940			23,980			24,630			24,470
Refinery production (BPD)⁽²⁾		27,700			23,540			25,510			24,490
Sales of produced refined products (BPD)		27,060			23,790			27,040			24,550
Sales of refined products (BPD)⁽³⁾		27,750			24,490			27,710			26,010

Refinery utilization⁽⁴⁾		83.7	%		92.2	%		79.5	%		94.1	%

Average per produced barrel⁽⁵⁾
Net sales	$	69.05		$	133.09		$	59.74		$	117.56
Cost of products⁽⁶⁾		60.10			120.60			49.90			105.05

Refinery gross margin		8.95			12.49			9.84			12.51
Refinery operating expenses⁽⁷⁾		5.98			8.13			6.45			7.17

Net operating margin	$	2.97		$	4.36		$	3.39		$	5.34


Feedstocks:
Sour crude oil		3	%		—	%		3	%		2	%
Sweet crude oil		62	%		76	%		64	%		75	%
Black wax crude oil		27	%		22	%		27	%		19	%
Other feedstocks and blends		8	%		2	%		6	%		4	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		66	%		62	%		67	%		65	%
Diesel fuels		28	%		29	%		26	%		26	%
Jet fuels		—	%		—	%		—	%		—	%
Fuel oil		3	%		6	%		4	%		5	%
Asphalt		2	%		2	%		1	%		1	%
LPG and other		1	%		1	%		2	%		3	%

Total		100	%		100	%		100	%		100	%


*Tulsa Refinery*⁽⁸⁾
Crude charge (BPD)⁽¹⁾		17,930			—			9,010			—
Refinery production (BPD)⁽²⁾		17,280			—			9,690			—
Sales of produced refined products (BPD)		16,970			—			8,530			—
Sales of refined products (BPD)⁽³⁾		17,250			—			8,670			—

Refinery utilization⁽⁴⁾		64.0	%		—	%		64.0	%		—	%

Average per produced barrel⁽⁵⁾
Net sales	$	76.14		$	—		$	76.14		$	—
Cost of products⁽⁶⁾		73.31			—			73.31			—

Refinery gross margin		2.83			—			2.83			—
Refinery operating expenses⁽⁷⁾		5.21			—			5.21			—

Net operating margin	$	(2.38	)	$	—		$	(2.38	)	$	—


Feedstocks:									��
Sour crude oil		—	%		—	%		—	%		—	%
Sweet crude oil		100	%		—	%		100	%		—	%
Other feedstocks and blends		—	%		—	%		—	%		—	%

Total		100	%		—	%		100	%		—	%


Sales of produced refined products:
Gasolines		23	%		—	%		23	%		—	%
Diesel fuels		28	%		—	%		28	%		—	%
Jet fuels		9	%		—	%		9	%		—	%
Lubricants		22	%		—	%		22	%		—	%
Gas oil / intermediates		16	%		—	%		16	%		—	%
LPG and other		2	%		—	%		2	%		—	%

Total		100	%		—	%		100	%		—	%

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Consolidated*
Crude charge (BPD)⁽¹⁾		129,620			96,780			105,440			102,470
Refinery production (BPD)⁽²⁾		141,650			100,500			115,150			110,290
Sales of produced refined products (BPD)		139,840			103,700			114,650			111,530
Sales of refined products (BPD)⁽³⁾		141,340			113,210			120,190			123,080

Refinery utilization⁽⁴⁾		81.5	%		87.2	%		77.0	%		92.3	%

Average per produced barrel⁽⁵⁾
Net sales	$	69.14		$	133.71		$	63.76		$	117.38
Cost of products⁽⁶⁾		61.32			124.62			54.35			109.03

Refinery gross margin		7.82			9.09			9.41			8.35
Refinery operating expenses⁽⁷⁾		4.91			6.24			5.49			5.46

Net operating margin	$	2.91		$	2.85		$	3.92		$	2.89


Feedstocks:
Sour crude oil		56	%		63	%		59	%		63	%
Sweet crude oil		29	%		26	%		27	%		24	%
Black wax crude oil		5	%		5	%		6	%		4	%
Other feedstocks and blends		10	%		6	%		8	%		9	%

Total		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		54	%		56	%		58	%		58	%
Diesel fuels		32	%		32	%		31	%		31	%
Jet fuels		1	%		1	%		1	%		1	%
Fuel oil		3	%		4	%		3	%		4	%
Asphalt		3	%		4	%		2	%		3	%
Lubricants		3	%		—	%		2	%		—	%
Gas oil / intermediates		2	%		—	%		1	%		—	%
LPG and other		2	%		3	%		2	%		3	%

Total		100	%		100	%		100	%		100	%


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

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

(3)		Includes refined products purchased for resale.

(4)		Represents crude charge divided by total crude capacity (BPSD). Our consolidated crude capacity was increased by 5,000 BPSD effective January 1, 2009 (our Woods Cross Refinery expansion), 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion) and 85,000 BPSD effective June 1, 2009 (our Tulsa Refinery acquisition), increasing our consolidated crude capacity to 216,000 BPSD.

(5)		Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

(6)		Transportation costs billed from HEP are included in cost of products.

(7)		Represents operating expenses of our refineries, exclusive of depreciation and amortization.

(8)		The amounts reported for the Tulsa Refinery for the three and six months ended June 30, 2009 include crude oil processed and products yielded from the refinery for the period from June 1, 2009 through June 30, 2009 only, and averaged over the number of days in the period (91 days and 182 days for the three and six months ended, respectively). Operating data for the period from June 1, 2009 through June 30, 2009 is as follows:


Tulsa Refinery
Crude charge (BPD)	54,390
Refinery production (BPD)	52,400
Sales of produced refined products (BPD)	51,480
Sales of refined products (BPD)	52,310

Refinery utilization	64.0	%

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Results of Operations — Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Summary

Net income attributable to Holly Corporation stockholders for the three months ended June 30, 2009 was $14.6 million ($0.29 per basic and diluted share), a $3.2 million increase compared to $11.5 million ($0.23 per basic and diluted share) for the three months ended June 30, 2008. Net income increased due to the effects of increased refining production, partially offset by an overall decrease in refinery gross margins. Overall refinery gross margins for the three months ended June 30, 2009 were $7.82 per produced barrel compared to $9.09 for the three months ended June 30, 2008.

Overall production levels for the three months ended June 30, 2009 increased by 41% over the same period of 2008 due to incremental production attributable to the operations of our newly acquired Tulsa Refinery and production gains resulting from our recent Navajo and Woods Cross Refinery capacity expansions. Also contributing to the year-over-year increase in second quarter production levels were the effects of reduced production during the second quarter of 2008 as a result of a fluid catalytic cracking unit (“FCC”) outage that resulted in downtime at our Navajo Refinery.

Sales and Other Revenues

Sales and other revenues decreased 41% from $1,743.8 million for the three months ended June 30, 2008 to $1,038.4 million for the three months ended June 30, 2009, due principally to the effects of an overall decline in year-over-year second quarter sales prices of produced refined products sold, partially offset by a 25% increase in volumes of refined products sold. The average sales price we received per produced barrel sold decreased 48% from $133.71 for the three months ended June 30, 2008 to $69.14 for the three months ended June 30, 2009. Additionally, direct sales of excess crude oil also decreased in the current year. Sales and other revenues for the three months ended June 30, 2009 and 2008, includes $15.6 million and $6.7 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold decreased 46% from $1,620.6 million for the three months ended June 30, 2008 to $879.9 million for the three months ended June 30, 2009, due principally to significantly lower crude oil costs, partially offset by a 25% increase in volumes of refined products sold. 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 51% from $124.62 for the three months ended June 30, 2008 to $61.32 for the three months ended June 30, 2009. Also during the three months ended June 30, 2009, we recognized a $1.0 million charge to cost of products sold resulting from the liquidation of certain last-in, first-out (“LIFO”) quantities of inventory that were carried at higher costs as compared to current costs.

Gross Refinery Margins

Gross refining margin per produced barrel decreased 14% from $9.09 for the three months ended June 30, 2008 to $7.82 for the three months ended June 30, 2009 due to the effects of a decrease in the average sales price we received per produced barrel sold, partially offset a decrease in the average price we paid per barrel of crude oil and feedstocks. Gross refinery margin does not include the effects of depreciation 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 6% from $74.2 million for the three months ended June 30, 2008 to $78.5 million for the three months ended June 30, 2009, due principally to the inclusion of costs attributable to the operations of our Tulsa Refinery commencing June 1, 2009. This was partially offset by a decrease in utility costs.

- 38 -

General and Administrative Expenses

General and administrative expenses increased 17% from $12.9 million for the three months ended June 30, 2008 to $15.1 million for the three months ended June 30, 2009, due principally to increased professional fees and services.

Depreciation and Amortization Expenses

Depreciation and amortization increased 60% from $15.9 million for the three months ended June 30, 2008 to $25.5 million for the three months ended June 30, 2009. The increase was due principally to depreciation and amortization attributable to capitalized refinery improvement projects in 2008 and early 2009.

Interest Expense

Interest expense was $7.2 million for the three months ended June 30, 2009 compared to $6.3 million for the three months ended June 30, 2008. The increase was due principally to interest attributable to increased long-term debt, including the Holly Senior Notes. For the three months ended June 30, 2009 and 2008, interest expense included $4.7 million and $6.0 million, respectively, in costs attributable to HEP operations. Fair value adjustments to HEP’s interest rate swaps resulted in a $0.8 million non-cash reduction in interest expense for the three months ended June 30, 2009.

Income Taxes

Income taxes for the three months ended June 30, 2009 were $9.6 million compared to $5.9 million for the three months ended June 30, 2008. Our effective tax rate, before consideration of earnings attributable to noncontrolling interest, was 30.7% and 32.9% for the three months ended June 30, 2009 and 2008, respectively.

Results of Operations — Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Summary

Net income attributable to Holly Corporation stockholders for the six months ended June 30, 2009 was $36.6 million ($0.73 per basic and diluted share), a $16.5 million increase compared to $20.1 million ($0.40 per basic and $0.39 per diluted share) for the six months ended June 30, 2008. Net income increased due principally to higher year-over-year refined product margins combined with a slight increase in year-to-date production levels. Overall refinery gross margins for the six months ended June 30, 2009 were $9.41 per produced barrel compared to $8.35 for the six months ended June 30, 2008.

Overall production levels for the six months ended June 30, 2009 increased by 4% due principally to the effects of incremental production attributable to our Tulsa Refinery operations, production gains resulting from our recent Navajo and Woods Cross Refinery capacity expansions and production downtime during the second quarter of 2008. These factors were largely offset by the effects of production downtime during the first quarter of 2009. During the first quarter of 2009, we timed our scheduled major maintenance turnaround at the Navajo Refinery to coincide with the completion of its 15,000 BPSD capacity expansion, increasing refining capacity to 100,000 BPSD.

Sales and Other Revenues

Sales and other revenues decreased 48% from $3,223.8 million for the six months ended June 30, 2008 to $1,689.2 million for the six months ended June 30, 2009, due principally to significantly lower refined product sales prices combined with the effects of a 2% decrease in volumes of refined products sold. The average sales price we received per produced barrel sold decreased 46% from $117.38 for the six months ended June 30, 2008 to $63.76 for the six months ended June 30, 2009. Additionally, direct sales of excess crude oil also decreased in the current year. Sales and other revenues for the six months ended June 30, 2009 and 2008, includes $29.6 million and $8.9 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold decreased 54% from $3,004.0 million for the six months ended June 30, 2008 to $1,392.6 million for the six months ended June 30, 2009, due principally to the effects of significantly lower crude oil costs combined with a 2% decline in volumes of refined products sold. 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 50% from $109.03 for the six months ended June 30, 2008 to $54.35 for the six months ended June 30, 2009.

- 39 -

Also during the six months ended June 30, 2009, we recognized a $1.0 million charge to cost of products sold resulting from the liquidation of certain LIFO quantities of inventory that were carried at higher costs as compared to current costs.

Gross Refinery Margins

Gross refining margin per produced barrel increased 13% from $8.35 for the six months ended June 30, 2008 to $9.41 for the six months ended June 30, 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 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 8% from $134.9 million for the six months ended June 30, 2008 to $145.7 million for the six months ended June 30, 2009, due principally to costs attributable to the operations of our Tulsa Refinery commencing June 1, 2009 and the inclusion of HEP operating expense for a full six month period during the six months ended June 30, 2009 compared to four months in 2008 due to our reconsolidation of HEP effective March 1, 2008. These factors were partially offset by a decrease in utility costs. For the six months ended June 30, 2009 and 2008, operating expenses included $21.6 million and $13.5 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses

General and administrative expenses increased 4% from $25.9 million for the six months ended June 30, 2008 to $26.9 million for the six months ended June 30, 2009, due principally to increased professional fees and services. For the six months ended June 30, 2009 and 2008, general and administrative expenses included $2.0 million and $1.8 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses

Depreciation and amortization increased 57% from $29.2 million for the six months ended June 30, 2008 to $45.8 million for the six months ended June 30, 2009. The increase was due principally to depreciation and amortization attributable to the capitalized refinery improvement projects in 2008 and early 2009, and the inclusion of HEP depreciation expense for a full six month period during the six months ended June 30, 2009 compared to four months in 2008. For the six months ended June 30, 2009 and 2008, depreciation and amortization expenses included $12.3 million and $8.2 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 six months ended June 30, 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 $13.4 million for the six months ended June 30, 2009 compared to $8.2 million for the six months ended June 30, 2008. The increase was due principally to interest attributable to increased long-term debt, including the Holly Senior Notes, and the inclusion of HEP interest expense for a full six month period during the six months ended June 30, 2009 compared to four months in 2008. For the six months ended June 30, 2009 and 2008, interest expense included $10.9 million and $7.7 million, respectively, in costs attributable to HEP operations. Fair value adjustments to HEP’s interest rate swaps resulted in a $0.6 million non-cash reduction in interest expense for the six months ended June 30, 2009.

Income Taxes

Income taxes for the six months ended June 30, 2009 were $21.7 million compared to $10.6 million for the six months ended June 30, 2008. Our effective tax rate, before consideration of earnings attributable to noncontrolling interest, was 32.3% and 33.0% for the six months ended June 30, 2009 and 2008, 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. As of June 30, 2009, we had cash and cash equivalents of $108.7 million.

Cash and cash equivalents increased by $67.9 million during the six months ended June 30, 2009. Net cash provided by operating activities and financing activities of $141.6 million and $238.7 million, respectively, exceeded cash used for investing activities of $312.3 million. Working capital increased by $90.9 million during the six months ended June 30, 2009.

There are currently a total of twelve lenders under the Holly 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 June 30, 2009 consist of $4.2 million in cash and cash equivalents, $4.8 million in trade accounts receivable and other current assets, $398.8 million in property, plant and equipment, net and $107.0 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.

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 its credit agreement, which was $82.0 million as of June 30, 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.

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On June 10, 2009, we issued $200 million in aggregate principal amount of 9.875% senior notes due 2017, the Holly Senior Notes. A portion of the $188.0 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products from Sunoco following the closing of the Tulsa Refinery purchase on June 1, 2009. The remaining proceeds are available for general business purposes, including capital expenditures.

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

We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities provide sufficient resources to fund currently planned capital projects, including planned capital expenditures at our recently acquired Tulsa Refinery and our liquidity needs for the foreseeable future. In addition, components of our growth strategy may include construction of new refinery processing units and the expansion of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase earnings and cash flow. Our ability to acquire complementary assets will be dependent upon several factors, including our ability to identify attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth, and many other factors beyond our control.

Cash Flows — Operating Activities

Net cash flows provided by operating activities were $141.6 million for the six months ended June 30, 2009 compared to $114.6 million for the six months ended June 30, 2008, an increase of $27.0 million. Net income for the six months ended June 30, 2009 was $45.5 million, an increase of $24.1 million compared to the six months ended June 30, 2008. Non-cash adjustments consisting of depreciation and amortization, equity in earnings of SLC Pipeline, interest rate swap adjustments, deferred income taxes and equity-based compensation expense resulted in an increase to operating cash flows of $67.1 million for the six months ended June 30, 2009 compared to $37.0 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 increased cash flows by $50.7 million for the six months ended June 30, 2009 compared to $55.6 million for the six months ended June 30, 2008. Additionally, for the six months ended June 30, 2009, turnaround expenditures increased to $31.1 million from $3.4 million in 2008 due to the planned major maintenance turnaround at our Navajo Refinery in the first quarter of 2009.

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Cash Flows — Investing Activities and Planned Capital Expenditures

Net cash flows used for investing activities were $312.3 million for the six months ended June 30, 2009 compared to net cash flows provided by investing activities of $71.5 million for the six months ended June 30, 2008, a change of $383.8 million. Cash expenditures for property, plant and equipment for the first six months of 2009 decreased to $183.4 million from $198.8 million for the same period in 2008. These include HEP capital expenditures of $56.0 million and $12.2 million for the six months ended June 30, 2009 and 2008, respectively. During the six months ended June 30, 2009, we acquired the Tulsa Refinery for $157.8 million and HEP purchased a 25% joint venture interest in the SLC Pipeline for $25.5 million. Additionally we invested $165.9 million in marketable securities and received proceeds of $220.3 million from the sale or maturity of marketable securities. For the six months ended June 30, 2008, we received $171.0 million in proceeds from our sale of the Crude Pipelines and Tankage Assets to HEP. 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 a cash inflow. Additionally for the six months ended June 30, 2008, we invested $303.3 million in marketable securities and received proceeds of $395.5 million from the sale or maturity of marketable securities.

Planned Capital Expenditures

Holly Corporation

Each year our Board of Directors approves in our annual capital budget capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, other or special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. Our total capital budget for 2009 is now $25.4 million, not including the capital projects approved in prior years, our expansion / feedstock flexibility projects at the Navajo and Woods Cross Refineries or the capital projects at the Tulsa Refinery 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, $5.6 million for projects at the Tulsa 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, phase I of our major capital projects was mechanically completed in March 2009 increasing refinery capacity to 100,000 BPSD effective April 1, 2009. Phase I required the installation of a new 15,000 BPSD mild hydrocracker, 28 MMSCFSD hydrogen plant and the expansion of our Lovington crude and vacuum units at a cost of approximately $187.4 million.

We are currently proceeding with phase II of the major capital projects at the Navajo Refinery that will provide the capability to run up to 40,000 BPSD of heavy type crudes. 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 of 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 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 completed the installation of a new 100 ton per day sulfur recovery unit at a cost of approximately $31.0 million.

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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. 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. We sold the 65-mile Lovington to Artesia, New Mexico pipeline to HEP on June 1, 2009 for $34.2 million. Under the provisions of the Omnibus Agreement with HEP, HEP will have an option to purchase the remaining transportation assets described above upon our completion of these projects. We expect to complete these projects in the fourth quarter of 2009. We plan to grant HEP the option to purchase these transportation assets upon our completion of the project.

The Navajo Refinery and pipeline projects discussed above 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. These improvements will also provide the necessary infrastructure for future expansions of crude capacity and enable the refinery to meet new low sulfur gasoline 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, with our share of this cost totaling $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. We expect the project will be ready to commence operations in
the fall of 2010.

On June 1, 2009, we acquired our 85,000 BPSD Tulsa Refinery from Sunoco for $65.0 million. We plan to construct a new diesel hydrotreater and to expand sulfur recovery capacity, which, once complete, will allow all diesel produced at the Tulsa Refinery to be produced as ULSD. Additionally, this project will allow the Tulsa Refinery to upgrade coker distillate and extracts to ULSD. Although this project has not been approved by the Holly Board, schedule A engineering is underway to define the scope and cost of the project. We expect this project will also satisfy several consent decree requirements around sulfur levels in refinery fuel gas. This project is expected to be mechanically complete in mid-2011 and is currently estimated to cost up to $150.0 million. Separately, in connection with the modified consent decree that we have assumed with respect to the Tulsa Refinery, we will be required to make certain capital expenditures in order to satisfy obligations under the consent decree, including requirements for the reduction of nitrogen and nitrous oxide from the refinery’s heaters and boilers and requirements to reduce sulfur

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levels in the refinery’s fuel gas loop.

In 2009, we expect to spend approximately $285.0 million on 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 our approved capital projects.

In October 2004, the American Jobs Creation Act of 2004 (“2004 Act”) was signed into law. Among other things, the 2004 Act creates tax incentives for small business refiners incurring costs to produce ULSD. The 2004 Act 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 qualify for this deduction.

Regulatory compliance items, such as the ULSD and LSG requirements mentioned above, or other presently existing or future environmental regulations / consent decrees 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 its 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 HEP’s pipeline between Artesia, New Mexico and El Paso, Texas (the “South System”) and the Plains joint venture discussed below.

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.

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

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be $51.0 million. Construction of the South System pipe replacement and storage tankage is complete and improvements to Kinder Morgan’s El Paso pump station are expected to be completed by August 2009.

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 as a result of our recent capacity expansion at the Navajo Refinery. This project is expected to be completed in the third quarter of 2009 at an estimated cost of $7.0 million.

Cash Flows — Financing Activities

Net cash flows provided by financing activities were $238.7 million for the six months ended June 30, 2009 compared to net cash used for financing activities of $125.7 million for the six months ended June 30, 2008, a change of $364.3 million. During the six months ended June 30, 2009, we received $188.0 million in proceeds upon the issuance of the Holly Senior Notes, received and repaid $94.0 million in advances under the Holly Credit agreement, paid $15.0 million in dividends, 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, received a $9.0 million contribution from our UNEV Pipeline joint venture partner and recognized $2.1 million in excess tax benefits on our equity based compensation. Also during this period, HEP received proceeds of $58.4 million upon the issuance of additional common units, received $99.0 million and repaid $81.0 million in advances under the HEP Credit Agreement, paid distributions of $14.5 million to noncontrolling interest holders. Additionally, we paid $5.2 million and $0.4 million in deferred financing costs during the six months ended June 30, 2009 and 2008, respectively. The increased deferred financing costs relate to the Holly Senior Notes issued in June 2009. For the six months ended June 30, 2008, we purchased $136.9 million in treasury stock, paid $14.1 million in dividends, received a $10.0 million contribution from our UNEV Pipeline joint venture partner and recognized $3.4 million in excess tax benefits on our equity based compensation. For this same period, HEP received $40.0 million and repaid $20.0 million in advances under the HEP Credit Agreement and paid $7.6 million in distributions to noncontrolling interest holders.

Contractual Obligations and Commitments

On June 10, 2009, we issued $200 million in aggregate principal amount of senior notes due 2017, the Holly Senior Notes. The Holly Senior Notes mature on June 15, 2017 and bear interest at 9.875%.

With respect to the acquired Tulsa Refinery, we have assumed a Recovery Conservation and Recovery Act (“RCRA”) Post Closure and Corrective Permit that requires the remediation of contaminated areas at our Tulsa location. Under this permit, we expect to expend approximately $10.0 million (present value) through 2038 for remediation projects. In accounting for the Tulsa acquisition, we recorded this obligation as an environmental liability.

Capital expenditure obligations that pertain to the Tulsa Refinery, including those under a modified consent decree, are discussed under “Planned Capital Expenditures” above.

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 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.

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HEP is a variable interest entity VIE as defined under FIN No. 46(R). Under the provisions of FIN No. 46(R), 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 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.

Our purchase accounting for the Tulsa Refinery acquisition is based on management’s preliminary fair value estimates and is subject to change.

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”

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

SFAS No. 161 became effective January 1, 2009, which amends and expands the disclosure requirements of SFAS No. 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. See risk management below for disclosure of HEP’s derivative instruments and hedging activity.

SFAS No. 165 “Subsequent Events”

SFAS No. 167 ”Amendments to FIN No. 46(R)”

In June 2009, the FASB issued SFAS No. 167 which replaces the previous quantitative-based risk and rewards calculation provided under FIN No. 46(R) with a quantitative approach in determining whether an entity is the primary beneficiary of a VIE. Additionally, this standard requires an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhances disclosures requirements with respect to an entity’s involvement in a VIE. This standard is effective as of the beginning of an entity’s fiscal year beginning after November 15, 2009 including interim periods within that year. While we are currently evaluating the impact of this standard, we do not believe that it will have a material impact on our financial condition, results of operations and cash flows.

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RISK MANAGEMENT

We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position, capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit.

HEP uses interest rate derivatives to manage its exposure to interest rate risk. As of June 30, 2009, HEP had three interest rate swap contracts.

HEP has an interest rate swap that hedges its exposure to the cash flow risk caused by the effects of changes in the London Interbank Offered Rate (“LIBOR”) on their $171.0 million credit agreement advance that was used to finance its purchase of the Crude Pipelines and Tankage Assets in February 2008. This interest rate swap effectively converts its $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 2.00%, which equaled an effective interest rate of 5.74% as of June 30, 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.

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 1.83% as of June 30, 2009. The maturity of the swap contract is March 1, 2015, matching the maturity of the HEP Senior Notes.

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 dedesignated 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 six months ended June 30, 2009, HEP recognized $0.6 million reduction 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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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 6.25% HEP Senior Notes	Other assets	$	2,751		Long-term debt - HEP	$	(1,964	)
					Equity		(1,942	)⁽¹⁾
					Interest expense		1,155	⁽²⁾

		$	2,751			$	(2,751	)

Liability
Cash flow hedge — $171 million LIBOR based debt	Other long-term liabilities	$	(8,700	)	Accumulated other comprehensive loss	$	8,700

					Equity		4,166	⁽¹⁾
Variable-to-fixed interest rate swap – $60 million	Other long-term liabilities		(2,209	)	Interest expense		(1,957	)

		$	(10,909	)		$	10,909


(1)		Represents prior year charges to interest expense.

(2)		Net of amortization of premium attributable to dedesignated 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.

For the fixed rate Holly and HEP Senior Notes, changes in interest rates would generally affect fair value of the debt, but not our earnings or cash flows. At June 30, 2009, the estimated fair value of the Holly Senior Notes and the HEP Senior Notes were $195.0 million and $161.0 million, respectively. We estimate that a hypothetical 10% change in the yield-to-maturity rates applicable to the senior notes would result in an approximate fair value change of $10.6 million to the Holly Senior Notes and a $9.6 million change to the HEP Senior Notes.

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.Quantitative and Qualitative Disclosures About Market Risk

See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.

Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants.

Set forth below is our calculation of EBITDA.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(In thousands)
Net income attributable to Holly Corporation stockholders	$	14,605		$	11,452		$	36,550		$	20,101
Add provision for income tax		9,575			5,856			21,706			10,551
Add interest expense		7,205			6,251			13,444			8,243
Subtract interest income		(134	)		(3,826	)		(2,330	)		(7,381	)
Add depreciation and amortization		25,500			15,929			45,821			29,238

EBITDA	$	56,751		$	35,662		$	115,191		$	60,752

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

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Average per produced barrel:

*Navajo Refinery*
Net sales	$	67.93	$	133.89	$	63.80	$	117.33
Less cost of products		59.54		125.82		53.83		110.15

Refinery gross margin	$	8.39	$	8.07	$	9.97	$	7.18


*Woods Cross Refinery*
Net sales	$	69.05	$	133.09	$	59.74	$	117.56
Less cost of products		60.10		120.60		49.90		105.05

Refinery gross margin	$	8.95	$	12.49	$	9.84	$	12.51


*Tulsa Refinery*
Net sales	$	76.14	$	—	$	76.14	$	—
Less cost of products		73.31		—		73.31		—

Refinery gross margin	$	2.83	$	—	$	2.83	$	—


*Consolidated*
Net sales	$	69.14	$	133.71	$	63.76	$	117.38
Less cost of products		61.32		124.62		54.35		109.03

Refinery gross margin	$	7.82	$	9.09	$	9.41	$	8.35

Net Operating Margin

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
Average per produced barrel:

*Navajo Refinery*
Refinery gross margin	$	8.39		$	8.07	$	9.97		$	7.18
Less refinery operating expenses		4.56			5.68		5.19			4.98

Net operating margin	$	3.83		$	2.39	$	4.78		$	2.20


*Woods Cross Refinery*
Refinery gross margin	$	8.95		$	12.49	$	9.84		$	12.51
Less refinery operating expenses		5.98			8.13		6.45			7.17

Net operating margin	$	2.97		$	4.36	$	3.39		$	5.34


*Tulsa Refinery*
Refinery gross margin	$	2.83		$	—	$	2.83		$	—
Less refinery operating expenses		5.21			—		5.21			—

Net operating margin	$	(2.38	)	$	—	$	(2.38	)	$	—


*Consolidated*
Refinery gross margin	$	7.82		$	9.09	$	9.41		$	8.35
Less refinery operating expenses		4.91			6.24		5.49			5.46

Net operating margin	$	2.91		$	2.85	$	3.92		$	2.89

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

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Navajo Refinery*
Average sales price per produced barrel sold	$	67.93		$	133.89		$	63.80		$	117.33
Times sales of produced refined products sold (BPD)		95,812			79,910			79,072			86,980
Times number of days in period		91			91			181			182

Refined product sales from produced products sold	$	592,274		$	973,623		$	913,108		$	1,857,376


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	69.05		$	133.09		$	59.74		$	117.56
Times sales of produced refined products sold (BPD)		27,059			23,790			27,042			24,550
Times number of days in period		91			91			181			182

Refined product sales from produced products sold	$	170,027		$	288,125		$	292,404		$	525,270


*Tulsa Refinery*
Average sales price per produced barrel sold	$	76.14		$	—		$	76.14		$	—
Times sales of produced refined products sold (BPD)		16,971			—			8,532			—
Times number of days in period		91			—			181			—

Refined product sales from produced products sold	$	117,588		$	—		$	117,582		$	—


Sum of refined products sales from produced products sold from our three refineries⁽⁴⁾	$	879,889		$	1,261,748		$	1,323,094		$	2,382,646
Add refined product sales from purchased products and rounding⁽¹⁾		8,303			120,310			61,984			255,556

Total refined products sales		888,192			1,382,058			1,385,078			2,638,202
Add direct sales of excess crude oil⁽²⁾		100,621			314,486			221,876			517,437
Add other refining segment revenue⁽³⁾		31,106			39,657			49,875			57,938

Total refining segment revenue		1,019,919			1,736,201			1,656,829			3,213,577
Add HEP segment sales and other revenues		40,602			26,774			72,727			36,716
Add corporate and other revenues		2,979			886			3,078			1,287
Subtract consolidations and eliminations		(25,119	)		(20,039	)		(43,430	)		(27,774	)

Sales and other revenues	$	1,038,381		$	1,743,822		$	1,689,204		$	3,223,806


(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.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Average sales price per produced barrel sold	$	69.14	$	133.71	$	63.76	$	117.38
Times sales of produced refined products sold (BPD)		139,842		103,700		114,646		111,530
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	879,889	$	1,261,748	$	1,323,094	$	2,382,646

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Navajo Refinery*
Average cost of products per produced barrel sold	$	59.54		$	125.82		$	53.83		$	110.15
Times sales of produced refined products sold (BPD)		95,812			79,910			79,072			86,980
Times number of days in period		91			91			181			182

Cost of products for produced products sold	$	519,123		$	914,939		$	770,417		$	1,743,714


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	60.10		$	120.60		$	49.90		$	105.05
Times sales of produced refined products sold (BPD)		27,059			23,790			27,042			24,550
Times number of days in period		91			91			181			182

Cost of products for produced products sold	$	147,988		$	261,086		$	244,241		$	469,374


*Tulsa Refinery*
Average cost of products per produced barrel sold	$	73.31		$	—		$	73.31		$	—
Times sales of produced refined products sold (BPD)		16,971			—			8,532			—
Times number of days in period		91			—			181			—

Cost of products for produced products sold	$	113,217		$	—		$	113,212		$	—


Sum of cost of products for produced products sold from our three refineries⁽⁴⁾	$	780,328		$	1,176,025		$	1,127,870		$	2,213,088
Add refined product costs from purchased products sold and rounding⁽¹⁾		9,180			123,226			66,859			258,415

Total refined cost of products sold		789,508			1,299,251			1,194,729			2,471,503
Add crude oil cost of direct sales of excess crude oil⁽²⁾		99,872			311,963			220,554			514,176
Add other refining segment cost of products sold⁽³⁾		15,537			29,375			19,473			45,898

Total refining segment cost of products sold		904,917			1,640,589			1,434,756			3,031,577
Subtract consolidations and eliminations		(24,991	)		(20,039	)		(43,176	)		(27,590	)

Costs of products sold (exclusive of depreciation and amortization)	$	879,926		$	1,620,550		$	1,391,580		$	3,003,987


(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.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Average cost of products per produced barrel sold	$	61.32	$	124.62	$	54.35	$	109.03
Times sales of produced refined products sold (BPD)		139,842		103,700		114,646		111,530
Times number of days in period		91		91		181		182

Cost of products for produced products sold	$	780,328	$	1,176,025	$	1,127,870	$	2,213,088

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	4.56		$	5.68	$	5.19		$	4.98
Times sales of produced refined products sold (BPD)		95,812			79,910		79,072			86,980
Times number of days in period		91			91		181			182

Refinery operating expenses for produced products sold	$	39,758		$	41,304	$	74,279		$	78,835


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	5.98		$	8.13	$	6.45		$	7.17
Times sales of produced refined products sold (BPD)		27,059			23,790		27,042			24,550
Times number of days in period		91			91		181			182

Refinery operating expenses for produced products sold	$	14,725		$	17,601	$	31,570		$	32,036


*Tulsa Refinery*
Average refinery operating expenses per produced barrel sold	$	5.21		$	—	$	5.21		$	—
Times sales of produced refined products sold (BPD)		16,971			—		8,532			—
Times number of days in period		91			—		181			—

Refinery operating expenses for produced products sold	$	8,046		$	—	$	8,046		$	—


Sum of refinery operating expenses per produced products sold from our three refineries⁽²⁾	$	62,529		$	58,905	$	113,895		$	110,871
Add other refining segment operating expenses and rounding⁽¹⁾		5,111			5,278		10,160			10,528

Total refining segment operating expenses		67,640			64,183		124,055			121,399
Add HEP segment operating expenses		11,086			9,985		21,882			13,661
Add corporate and other costs		8			7		27			7
Subtract consolidations and eliminations		(226	)		—		(254	)		(184	)

Operating expenses (exclusive of depreciation and amortization)	$	78,508		$	74,175	$	145,710		$	134,883


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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Average refinery operating expenses per produced barrel sold	$	4.91	$	6.24	$	5.49	$	5.46
Times sales of produced refined products sold (BPD)		139,842		103,700		114,646		111,530
Times number of days in period		91		91		181		182

Refinery operating expenses for produced products sold	$	62,529	$	58,905	$	113,895	$	110,871

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
*Navajo Refinery*
Net operating margin per barrel	$	3.83		$	2.39		$	4.78		$	2.20
Add average refinery operating expenses per produced barrel		4.56			5.68			5.19			4.98

Refinery gross margin per barrel		8.39			8.07			9.97			7.18
Add average cost of products per produced barrel sold		59.54			125.82			53.83			110.15

Average sales price per produced barrel sold	$	67.93		$	133.89		$	63.80		$	117.33
Times sales of produced refined products sold (BPD)		95,812			79,910			79,072			86,980
Times number of days in period		91			91			181			182

Refined products sales from produced products sold	$	592,274		$	973,623		$	913,108		$	1,857,376


*Woods Cross Refinery*
Net operating margin per barrel	$	2.97		$	4.36		$	3.39		$	5.34
Add average refinery operating expenses per produced barrel		5.98			8.13			6.45			7.17

Refinery gross margin per barrel		8.95			12.49			9.84			12.51
Add average cost of products per produced barrel sold		60.10			120.60			49.90			105.05

Average sales price per produced barrel sold	$	69.05		$	133.09		$	59.74		$	117.56
Times sales of produced refined products sold (BPD)		27,059			23,790			27,042			24,550
Times number of days in period		91			91			181			182

Refined products sales from produced products sold	$	170,027		$	288,125		$	292,404		$	525,270


*Tulsa Refinery*
Net operating margin per barrel	$	(2.38	)	$	—		$	(2.38	)	$	—
Add average refinery operating expenses per produced barrel		5.21			—			5.21			—

Refinery gross margin per barrel		2.83			—			2.83			—
Add average cost of products per produced barrel sold		73.31			—			73.31			—

Average sales price per produced barrel sold	$	76.14		$	—		$	76.14		$	—
Times sales of produced refined products sold (BPD)		16,971			—			8,532			—
Times number of days in period		91			—			181			—

Refined products sales from produced products sold	$	117,588		$	—		$	117,582		$	—


Sum of refined products sales from produced products sold from our three refineries⁽⁴⁾	$	879,889		$	1,261,748		$	1,323,094		$	2,382,646
Add refined product sales from purchased products and rounding⁽¹⁾		8,303			120,310			61,984			255,556

Total refined products sales		888,192			1,382,058			1,385,078			2,638,202
Add direct sales of excess crude oil⁽²⁾		100,621			314,486			221,876			517,437
Add other refining segment revenue⁽³⁾		31,106			39,657			49,875			57,938

Total refining segment revenue		1,019,919			1,736,201			1,656,829			3,213,577
Add HEP segment sales and other revenues		40,602			26,774			72,727			36,716
Add corporate and other revenues		2,979			886			3,078			1,287
Subtract consolidations and eliminations		(25,119	)		(20,039	)		(43,430	)		(27,774	)

Sales and other revenues	$	1,038,381		$	1,743,822		$	1,689,204		$	3,223,806


(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.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Net operating margin per barrel	$	2.91	$	2.85	$	3.92	$	2.89
Add average refinery operating expenses per produced barrel		4.91		6.24		5.49		5.46

Refinery gross margin per barrel		7.82		9.09		9.41		8.35
Add average cost of products per produced barrel sold		61.32		124.62		54.35		109.03

Average sales price per produced barrel sold	$	69.14	$	133.71	$	63.76	$	117.38
Times sales of produced refined products sold (BPD)		139,842		103,700		114,646		111,530
Times number of days in period		91		91		181		182

Refined product sales from produced products sold	$	879,889	$	1,261,748	$	1,323,094	$	2,382,646

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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

SFPP Litigation

a.The Early Complaint Cases

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 on SFPP’s East Line. 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.

b.Settlements

c.The Latest Rate Proceeding

MTBE Litigation

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

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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.

NMED NOV

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 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.

Woods Cross Construction Dispute 1

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.

Woods Cross Construction Dispute 2

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 on April 22, 2009 by Brahma Group, Inc. in state district court in Davis County, Utah involving a construction 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. Our subsidiaries have answered the complaint and denied any liability. The plaintiff and the general contractor have agreed to arbitrate their dispute, and the claims against our subsidiaries have been stayed pending the outcome of that arbitration. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.

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Cut Bank Hill Environmental Claims

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 approximately $150,000 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.

OSHA Inspection

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
October 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.

Unclaimed Property Audit

A multi-state audit of our unclaimed property compliance and reporting is being conducted by Kelmar Associates, LLC on behalf of eleven states. We are still reviewing records in order to determine whether there are any errors in reporting and expect for this process to take several years to be resolved due to the lengthy period covered by the audit (1981 — 2004). It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states since only preliminary investigation has occurred to date.

Other

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.

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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 Form 8-K Current Report dated April 16, 2009, File No. 1-03876).

10.1		Purchase Agreement, dated June 5, 2009, among Holly Corporation, the subsidiary guarantors named therein and UBS Securities LLC, as representative of the several initial purchasers named therein, relating to the sale of Holly Corporation’s 9.875% Senior Notes due 2017 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated June 11, 2009, File No. 1-03876).

10.2		Amended and Restated Intermediate Pipelines Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Refining Company, L.L.C., Holly Energy Partners, L.P., Holly Energy Partners — Operating, L.P., HEP Pipeline, L.L.C., Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistic Services, L.L.C. and HEP Logistics GP, L.L.C. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-03876).

10.3		Amended and Restated Omnibus Agreement, dated as of June 1, 2009, by and among Holly Corporation, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners — Operating, L.P. (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated June 5, 2009, File No. 1-03876).

10.4		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. (incorporated by reference to Exhibit 10.1 of Registrant’s Form 10-Q Quarterly Report for the period ended March 31, 2009, File No. 1-03876).

10.5+		First Amendment to Guarantee and Collateral Agreement and Reaffirmation and Assumption Agreement, dated April 7, 2009, by and among Holly Corporation and certain of its subsidiaries, in favor of Bank of America, N.A., as administrative agent, for certain other lenders from time to time party to the Second Amended and Restated Credit Agreement dated April 7, 2009.

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

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

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

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


+		Filed herewith.

++		Furnished herewith.

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SIGNATURES

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


	HOLLY CORPORATION (Registrant)
Date: August 10, 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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HF Sinclair 10-Q2009 Q2 Quarterly report

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