10-Q

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 September 30, 2010

OR

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

For the transition period from ______________ to ______________

Commission File Number 1-3876

HOLLY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	75-1056913
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
100 Crescent Court, Suite 1600 Dallas, Texas	75201-6915
(Address of principal executive offices)	(Zip Code)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ          No o

Indicate by check mark whether the registrant 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).

Yes þ          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.

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

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

Yes o          No þ

53,210,016 shares of Common Stock, par value $.01 per share, were outstanding on October 29, 2010.

HOLLY CORPORATION
INDEX

		Page
PART I.	FINANCIAL INFORMATION
Forward-Looking Statements			3
Definitions			4
Item 1.	Financial Statements
	Consolidated Balance Sheets September 30, 2010 (Unaudited) and December 31, 2009		6
	Consolidated Statements of Income (Unaudited) Three and Nine Months Ended September 30, 2010 and 2009		7
	Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2010 and 2009		8
	Consolidated Statements of Comprehensive Income (Unaudited) Three and Nine Months Ended September 30, 2010 and 2009		9
	Notes to Consolidated Financial Statements (Unaudited)		10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		52
	Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles		52
Item 4.	Controls and Procedures		59
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		60
Item 6.	Exhibits		63
Signatures			64
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly Report on Form 10-Q has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation or its other subsidiaries. This document 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.

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 existing or future acquired operations;

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

• general economic conditions; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, 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, 2009 and in conjunction with the discussion in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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DEFINITIONS

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

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

     “Aromatic oil” is long chain oil that is highly aromatic in nature that is used to manufacture tires and in the production of asphalt.

     “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 primary source of hydrogen for the refinery.

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

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

     “Delayed coker unit” is a refinery unit that removes carbon from the bottom cuts of crude oil to produce unfinished light transportation fuels and petroleum coke.

     “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.

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     “Lube extraction unit” is a unit used in the lube process that separates aromatic oils from paraffinic oils using furfural as a solvent.

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

     “MEK” means a lube process that separates waxy oil from non-waxy oils using methyl ethyl ketone as a solvent.

     “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.

     “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.

     “Parafinnic oil” is a high paraffinic, high gravity oil produced by extracting aromatic oil and waxes from gas oil and is used in producing high-grade lubricating oils.

     “Refinery gross margin” means the difference between average net sales price and average product costs per produced barrel of refined products sold. 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.

     “Roofing flux” is produced from the bottom cut of crude oil and is the base oil used to make roofing shingles for the housing industry.

     “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.

     “Scanfiner” is a refinery unit that removes sulfur from gasoline to produce low sulfur gasoline blendstock.

     “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)

	September 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents (HEP: $706 and $2,508, respectively)	$	271,920		$	124,596
Marketable securities		1,171			1,223
Accounts receivable: Product and transportation (HEP: $21,319 and $18,767, respectively)		250,098			292,310
Crude oil resales		468,373			470,145
		718,471			762,455
Inventories:                Crude oil and refined products		368,260			259,582
Materials and supplies (HEP: $197 and $165, respectively )		45,755			43,931
		414,015			303,513
Income taxes receivable		26,269			38,072
Prepayments and other (HEP: $924 and $574, respectively)		43,261			50,957
Current assets of discontinued operations (HEP: $2,195)		—			2,195
Total current assets		1,475,107			1,283,011
Properties, plants and equipment, at cost (HEP: $535,464 and $491,999, respectively)		2,130,680			2,001,855
Less accumulated depreciation (HEP: $(52,678) and $(33,478), respectively)		(433,297	)		(371,885	)
		1,697,383			1,629,970
Other assets:                   Turnaround costs		50,948			53,463
Goodwill (HEP: $81,602 and $81,602)		81,602			81,602
Intangibles and other (HEP: $73,192 and $77,443, respectively)		92,339			97,893
		224,889			232,958
Total assets	$	3,397,379		$	3,145,939
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $5,786 and $6,211, respectively)	$	1,044,277		$	975,155
Accrued liabilities (HEP: $15,752 and $13,594, respectively)		69,072			49,957
Credit agreement borrowings (HEP: $157,000)		157,000			—
Total current liabilities		1,270,349			1,025,112
Long-term debt (HEP: $322,623 and $379,198, respectively)		650,906			707,458
Deferred income taxes		129,677			124,585
Other long-term liabilities (HEP: $12,534 and $12,349, respectively)		80,970			81,003
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; 76,346,432 and 76,359,006 shares issued as of September 30, 2010 and December 31, 2009, respectively		764			764
Additional capital		191,030			195,565
Retained earnings		1,199,605			1,134,341
Accumulated other comprehensive loss		(26,360	)		(25,700	)
Common stock held in treasury, at cost — 23,136,416 and 23,292,737 shares as of September 30, 2010 and December 31, 2009, respectively		(677,912	)		(685,931	)
Total Holly Corporation stockholders’ equity		687,127			619,039
Noncontrolling interest		578,350			588,742
Total equity		1,265,477			1,207,781
Total liabilities and equity	$	3,397,379		$	3,145,939

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of September 30, 2010 and December 31, 2009. HEP is a consolidated variable interest entity.

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Sales and other revenues	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		1,807,044			1,295,438			5,379,120			2,687,018
Operating expenses (exclusive of depreciation and amortization)		130,263			96,717			378,638			241,518
General and administrative expenses (exclusive of depreciation and amortization)		16,925			16,728			50,623			43,572
Depreciation and amortization		29,138			24,026			85,719			69,367
Total operating costs and expenses		1,983,370			1,432,909			5,894,100			3,041,475
Income from operations		107,618			55,582			217,038			130,824
Other income (expense):
Equity in earnings of SLC Pipeline		570			646			1,595			1,309
Interest income		64			231			758			2,561
Interest expense		(17,368	)		(12,407	)		(56,113	)		(25,849	)
Tulsa Refinery acquisition costs		—			(378	)		—			(1,988	)
		(16,734	)		(11,908	)		(53,760	)		(23,967	)
Income from continuing operations before income taxes		90,884			43,674			163,278			106,857
Income tax provision:
Current		9,042			6,085			48,964			9,075
Deferred		22,452			7,412			5,512			25,593
		31,494			13,497			54,476			34,668
Income from continuing operations		59,390			30,177			108,802			72,189
Income from discontinued operations, net of taxes of $182 and $718, respectively		—			901			—			3,438
Net income		59,390			31,078			108,802			75,627
Less net income attributable to noncontrolling interest		8,213			7,594			19,557			15,593
Net income attributable to Holly Corporation stockholders	$	51,177		$	23,484		$	89,245		$	60,034
Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	51,177		$	23,213		$	89,245		$	59,014
Income from discontinued operations		—			271			—			1,020
Net income	$	51,177		$	23,484		$	89,245		$	60,034
Earnings per share attributable to Holly Corporation stockholders — basic:
Income from continuing operations	$	0.96		$	0.46		$	1.68		$	1.18
Income from discontinued operations		—			0.01			—			0.02
Net income	$	0.96		$	0.47		$	1.68		$	1.20
Earnings per share attributable to Holly Corporation stockholders — diluted:
Income from continuing operations	$	0.96		$	0.46		$	1.67		$	1.17
Income from discontinued operations		—			0.01			—			0.02
Net income	$	0.96		$	0.47		$	1.67		$	1.19
Cash dividends declared per common share	$	0.15		$	0.15		$	0.45		$	0.45
Average number of common shares outstanding:
Basic		53,210			50,244			53,172			50,153
Diluted		53,567			50,327			53,531			50,272

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended
	September 30,
	2010			2009(1)
Cash flows from operating activities:
Net income	$	108,802		$	75,627
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		85,719			70,088
SLC Pipeline earnings, net of distributions		406			(1,309	)
Deferred income taxes		5,512			25,593
Equity based compensation expense		7,814			6,579
Change in fair value — interest rate swaps		1,464			300
Noncontrolling interest in earnings of Rio Grande Pipeline Company		—			1,191
(Increase) decrease in current assets:
Accounts receivable		43,984			(327,568	)
Inventories		(110,502	)		(73,813	)
Income taxes receivable		11,803			966
Prepayments and other		(304	)		(7,987	)
Current assets of discontinued operations		2,195			—
Increase (decrease) in current liabilities:
Accounts payable		69,030			429,465
Accrued liabilities		17,971			1,225
Turnaround expenditures		(11,453	)		(33,112	)
Other, net		3,527			12,407
Net cash provided by operating activities		235,968			179,652
Cash flows from investing activities:
Additions to properties, plants and equipment — Holly Corporation		(119,885	)		(218,543	)
Additions to properties, plants and equipment — Holly Energy Partners		(8,054	)		(27,478	)
Acquisition of Tulsa Refinery west facility — Holly Corporation		—			(157,814	)
Investment in SLC Pipeline — Holly Energy Partners		—			(25,500	)
Purchases of marketable securities		—			(165,892	)
Sales and maturities of marketable securities		—			220,281
Net cash used for investing activities		(127,939	)		(374,946	)
Cash flows from financing activities:
Borrowings under credit agreement — Holly Corporation		310,000			94,000
Repayments under credit agreement — Holly Corporation		(310,000	)		(94,000	)
Borrowings under credit agreement — Holly Energy Partners		52,000			197,000
Repayments under credit agreement — Holly Energy Partners		(101,000	)		(152,000	)
Proceeds from issuance of senior notes — Holly Corporation		—			187,925
Proceeds from issuance of senior notes — Holly Energy Partners		147,540			—
Proceeds from issuance of common units — Holly Energy Partners		—			58,355
Repayments under financing obligation — Holly Corporation		(760	)		—
Purchase of treasury stock		(1,308	)		(1,214	)
Contribution from joint venture partner		9,500			13,650
Dividends		(23,889	)		(22,569	)
Distributions to noncontrolling interest		(36,139	)		(23,359	)
Excess tax benefit (expense) from equity based compensation		(1,313	)		2,140
Purchase of units for restricted grants — Holly Energy Partners		(2,276	)		(616	)
Deferred financing costs		(3,121	)		(6,356	)
Issuance of common stock upon exercise of options		61			60
Net cash provided by financing activities		39,295			253,016
Cash and cash equivalents:
Increase for the period		147,324			57,722
Beginning of period		124,596			40,805
End of period	$	271,920		$	98,527
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	49,051		$	20,555
Income taxes	$	45,040		$	18,219

(1) Includes cash flows attributable to discontinued operations.

See accompanying notes.

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HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net income	$	59,390		$	31,078		$	108,802		$	75,627
Other comprehensive income (loss):
Securities available for sale:
Unrealized gain (loss) on available-for-sale securities		(51	)		234			(58	)		(24	)
Reclassification adjustment to net income on sale of marketable securities		—			—			—			236
Total unrealized gain (loss) on available-for-sale securities		(51	)		234			(58	)		212
Hedging instruments:
Change in fair value of cash flow hedging instruments		(1,780	)		(1,482	)		(4,837	)		2,685
Reclassification adjustment to net income on maturity / settlement of cash flow hedging instruments		(65	)		—			1,011			—
Total unrealized gain (loss) on hedging instruments		(1,845	)		(1,482	)		(3,826	)		2,685
Other comprehensive income (loss) before income taxes		(1,896	)		(1,248	)		(3,884	)		2,897
Income tax expense (benefit)		(558	)		(173	)		(420	)		560
Other comprehensive income (loss)		(1,338	)		(1,075	)		(3,464	)		2,337
Total comprehensive income		58,052			30,003			105,338			77,964
Less noncontrolling interest in comprehensive income		7,752			6,790			16,753			17,049
Comprehensive income attributable to Holly Corporation stockholders	$	50,300		$	23,213		$	88,585		$	60,915

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

References herein to Holly Corporation include Holly Corporation and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this Quarterly Report on Form 10-Q has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation or its other subsidiaries. These financial statements contain certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of Holly Corporation. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

As of September 30, 2010, we:

• owned and operated three refineries consisting of a petroleum refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery in Woods Cross, Utah (the “Woods Cross Refinery”) and our two refinery facilities located in Tulsa, Oklahoma (collectively, operated as the “Tulsa Refinery”);

• owned and operated Holly Asphalt Company (“Holly Asphalt”) which manufactures and markets asphalt products from various terminals in Arizona, New Mexico and Texas;

• owned a 75% interest in a 12-inch refined products pipeline project from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”); and

• owned a 34% interest in HEP (which includes our 2% general partnership interest), which owns and operates logistics assets including approximately 2,500 miles of petroleum product and crude oil pipelines located principally in west Texas and New Mexico; ten refined product terminals; a jet fuel terminal; eight refinery loading rack facilities; a refined products tank farm facility; on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries, on-site refined product tankage at our Tulsa Refinery and a 25% interest in a 95-mile, crude oil pipeline joint venture (the “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 September 30, 2010, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2010 and 2009 and consolidated cash flows for the nine months ended September 30, 2010 and 2009 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 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC.

Our results of operations for the first nine months of 2010 are not necessarily indicative of the results to be expected for the full year.

Accounts Receivable

Our accounts receivable consist of amounts due from customers that 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 a letter of credit or guarantee, is required. Credit losses are charged to income

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when accounts are deemed uncollectible and historically have been minimal. At September 30, 2010, our allowance for doubtful accounts reserve was $1.9 million.

Inventories

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.

New Accounting Pronouncements

Variable Interest Entities

On January 1, 2010, new accounting standards became effective that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in determining whether an entity is the primary beneficiary of a variable interest entity (“VIE”). Additionally, these standards require an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhance disclosure requirements with respect to an entity’s involvement in a VIE. See Note 3 for additional information on our involvement with HEP, a consolidated VIE.

NOTE 2: Tulsa Refinery Acquisition

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”) for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. The refinery produces fuel products including gasoline, diesel fuel and jet fuel, 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. On October 20, 2009, we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities that were acquired as part of the refinery assets for $40 million. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing transaction. See Note 10 for additional information.

On December 1, 2009, we acquired a 75,000 BPSD refinery that is also in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) from an affiliate of Sinclair Oil Company (“Sinclair”) for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The total purchase price consisted of $109.3 million in cash and 2,789,155 shares of our common stock having a value of $74 million. Additionally, we reimbursed Sinclair $8.4 million upon their completion of certain environmental projects at the refinery in July 2010. The refinery produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities. This will result in the Tulsa Refinery having an integrated crude processing rate of 125,000 BPSD.

In accounting for these combined acquisitions, we recorded $20.6 million in materials and supplies, $139.2 million in crude oil and refined products inventory, $203.8 million in property, plants and equipment, $8.2 million in prepayments and other, $6.3 million in accrued liabilities and $24.4 million in other long-term liabilities. The acquired liabilities primarily relate to environmental and asset retirement obligations. Additionally, we incurred $3.1 million in costs directly related to these acquisitions that were expensed as acquisition costs in 2009.

NOTE 3: Holly Energy Partners

HEP, a VIE, is a publicly held master limited partnership that was formed to acquire, own and operate the petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support our refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. HEP also

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owns and operates refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas.

As of September 30, 2010, we owned a 34% interest in HEP, including the 2% general partner interest. As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP’s economic performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are HEP’s primary beneficiary and therefore we consolidate HEP. See Note 17 for supplemental guarantor/non-guarantor financial information, including HEP balances included in these consolidated financial statements. All intercompany transactions with HEP are eliminated in our consolidated balances.

HEP has two primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further below), we accounted for 81% of HEP’s total revenues for the nine months ended September 30, 2010. We do not provide financial or equity support through any liquidity arrangements and /or guarantees to HEP.

HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. With the exception of the assets of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse to our assets. Any recourse to HEP’s 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. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 10 for a description of HEP’s debt obligations.

HEP has risk associated with its operations. If a major shipper of HEP were to terminate its contracts or fail to meet desired shipping levels for an extended period time, revenue would be reduced and HEP could suffer substantial losses to the extent that a new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss, net of intercompany eliminations, to the extent of our ownership interest in HEP at that point in time.

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, HEP acquired from us certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa Refinery east facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.

2009 Acquisitions

Sinclair Logistics and Storage Assets Transaction

On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of HEP’s common units having a fair value of $53.5 million.

With respect to this purchase, HEP recorded $30.2 million in properties and equipment, $49.1 million in goodwill and $0.2 million in other long-term liabilities.

Roadrunner / Beeson Pipelines Transaction

Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery Lovington facility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects HEP’s New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).

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Tulsa West Loading Racks Transaction

On August 1, 2009, HEP acquired from us certain truck and rail loading/unloading facilities located at our Tulsa Refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa Refinery onto rail cars and/or tanker trucks.

Lovington-Artesia Pipeline Transaction

On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from our Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.

SLC Pipeline Joint Venture Interest

On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. HEP’s capitalized joint venture contribution was $25.5 million.

Discontinued Operations

On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande are presented in discontinued operations.

In accounting for the sale, HEP recorded a gain of $14.5 million and a receivable of $2.2 million representing its final distribution from Rio Grande. The recorded net asset balance of Rio Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.

Cash flows from discontinued operations have been combined with cash flows from continuing operations for presentation purposes in the Consolidated Statements of Cash Flows. For the nine months ended September 30, 2009, net cash flows provided by discontinued Rio Grande operations were $5.7 million.

Transportation Agreements

HEP serves our refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

• HEP PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets that we contributed to HEP upon its initial public offering in 2004);

• HEP IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines sold to HEP in 2005 and 2009);

• HEP CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets sold to HEP in 2008);

• HEP PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired in 2009 and 2010);

• HEP RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline sold to HEP in 2009);

• HEP ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities sold to HEP in 2009);

• HEP NPA (natural gas pipeline throughput agreement expiring in 2024); and

• HEP ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility sold to HEP in March 2010).

Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP’s pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP. These minimum annual payments are adjusted each year at a percentage change based upon 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 based upon the percentage

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change in PPI or Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the HEP IPA, 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. Following the July 1, 2010 PPI adjustment, these agreements will result in minimum annualized payments to HEP of $133 million.

HEP Equity Offerings

In November 2009, HEP issued 2,185,000 of its common units priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under HEP’s credit agreement and for general partnership purposes.

Additionally in May 2009, HEP issued 2,192,400 of its common units priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under HEP’s credit agreement and for general partnership purposes.

NOTE 4: Financial Instruments

Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts payable, debt and derivative instruments. 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 principal under HEP’s revolving credit agreement, our 9.875% senior notes due 2017 (the “Holly 9.875% Senior Notes”), HEP’s 6.25% senior notes due 2015 (the “HEP 6.25% Senior Notes”) and HEP’s 8.25% senior notes due 2018 (the “HEP 8.25% Senior Notes”). The $157 million carrying amount of outstanding debt under HEP’s credit agreement approximates fair value as interest rates are reset frequently using current interest rates. At September 30, 2010, the estimated fair value of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $324 million, $183.2 million and $156.8 million, respectively. These fair value estimates are based on market quotes provided from a third-party bank. See Note 10 for additional information on these debt instruments.

Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability, including assumptions about risk). GAAP 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, quoted prices for similar assets and liabilities in markets that are not active or inputs that 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 7 for additional information on our investments in marketable securities, including fair value measurements.

We have commodity price swaps and HEP has an interest rate swap 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 the respective swap agreements. The measurements are computed using market-based observable inputs, quoted forward commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield curve with respect to HEP’s interest rate swap. See Note 11 for additional information on these swap contracts, including fair value measurements.

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NOTE 5: Earnings Per Share

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands, except per share data)
Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	51,177	$	23,213	$	89,245	$	59,014
Average number of shares of common stock outstanding		53,210		50,244		53,172		50,153
Effect of dilutive stock options, variable restricted shares and performance share units		357		83		359		119
Average number of shares of common stock outstanding assuming dilution		53,567		50,327		53,531		50,272
Basic earnings per share from continuing operations	$	0.96	$	0.46	$	1.68	$	1.18
Diluted earnings per share from continuing operations	$	0.96	$	0.46	$	1.67	$	1.17

NOTE 6: Stock-Based Compensation

On September 30, 2010, we had three principal share-based compensation plans that are described below (collectively, the “Long-Term Incentive Compensation Plan”). The compensation cost that has been charged against income for these plans was $2.1 million and $2 million for the three months ended September 30, 2010 and 2009, respectively, and $6.2 million and $5.5 million for the nine months ended September 30, 2010 and 2009, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $0.8 million for the three months ended September 30, 2010 and 2009, and $2.4 million and $2.1 million for the nine months ended September 30, 2010 and 2009, respectively. Our current accounting policy for the recognition of compensation expense for awards with pro-rata vesting (substantially all of our awards) is to expense the costs pro-rata over the vesting periods. At September 30, 2010, 1,585,756 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 was $0.4 million and $0.2 million for the three months ended September 30, 2010 and 2009, respectively, and $1.8 million and $1.1 million for the nine months ended September 30, 2010 and 2009, 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 after the grant date. There have been no options granted since December 2001. The fair value on the date of grant for each option awarded was estimated using the Black-Scholes option pricing model.

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A summary of option activity and changes during the nine months ended September 30, 2010 is presented below:

						Weighted-
				Weighted-		Average	Aggregate
				Average		Remaining	Intrinsic
				Exercise		Contractual	Value
Options	Shares			Price		Term	($000)
Outstanding and exercisable at January 1, 2010		40,200		$	2.98
Exercised		(20,700	)		2.98
Outstanding and exercisable at September 30, 2010		19,500		$	2.98	6 months	$	503

The total intrinsic value of options exercised during the nine months ended September 30, 2010 and 2009, was $0.5 million and $0.4 million, respectively.

Cash received from option exercises under the stock option plans was $0.1 million for the nine months ended September 30, 2010 and 2009. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $0.2 million for the nine months ended September 30, 2010 and 2009.

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 performance 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 activity and changes during the nine months ended September 30, 2010 is presented below:

				Weighted-
				Average Grant		Aggregate
				Date Fair		Intrinsic
Restricted Stock	Grants			Value		Value ($000)
Outstanding at January 1, 2010 (non-vested)		284,450		$	31.82
Vesting and transfer of ownership to recipients		(123,307	)		33.84
Granted		192,248			28.44
Forfeited		(2,714	)		28.38
Outstanding at September 30, 2010 (non-vested)		350,677		$	29.29	$	10,082

The total fair value of restricted stock vested and transferred to recipients during the nine months ended September 30, 2010 and 2009 was $4.2 million and $3.9 million, respectively. As of September 30, 2010, there was $3.3 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1 year.

Performance Share Units

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

During the nine months ended September 30, 2010, we granted 110,489 performance share units having a fair value based on our grant date closing stock price of $29.17. These units are payable in stock and are subject to certain financial performance criteria.

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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 September 30, 2010, estimated share payouts for outstanding non-vested performance share unit awards ranged from 125% to 130%.

A summary of performance share unit activity and changes during the nine months ended September 30, 2010 is presented below:

Performance Share Units	Grants
Outstanding at January 1, 2010 (non-vested)		215,170
Vesting and transfer of ownership to recipients		(38,653	)
Granted		110,489
Forfeited		(3,720	)
Outstanding at September 30, 2010 (non-vested)		283,286

For the nine months ended September 30, 2010, we issued 66,483 shares of our common stock having a fair value of $2.2 million related to vested performance share units, representing a 172% payout. Based on the weighted average grant date fair value of $3.2 million, there was $4.7 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 1.4 years.

NOTE 7: Cash and Cash Equivalents and Investments in Marketable Securities

Our investment portfolio consisted of cash and cash equivalents at September 30, 2010. In addition, we own 1,000,000 shares of Connacher Oil and Gas Limited common stock that were received as partial consideration upon our sale of our Montana refinery in 2006.

At times we also 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.

Our investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. Unrealized gains and losses, net of related income taxes, are 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.

The following is a summary of our available-for-sale securities:

	Available-for-Sale Securities
					Estimated Fair
			Gross		Value
			Unrealized		(Net Carrying
	Amortized Cost		Gain		Amount)
	(In thousands)
September 30, 2010
Equity securities	$	610	$	561	$	1,171
December 31, 2009
Equity securities	$	604	$	619	$	1,223

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There were no sales or maturities of marketable securities for the nine months ended September 30, 2010. For the nine months ended September 30, 2009, we received $220.3 million related to sales and maturities of marketable debt securities.

NOTE 8: Inventories

Inventory consists of the following components:

	September 30,		December 31,
	2010		2009
	(In thousands)
Crude oil	$	96,706	$	60,874
Other raw materials and unfinished products (1)		48,521		42,783
Finished products (2)		223,033		155,925
Process chemicals (3)		22,492		22,823
Repairs and maintenance supplies and other		23,263		21,108
Total inventory	$	414,015	$	303,513

(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.

NOTE 9: Environmental

Consistent with our accounting policy for environmental remediation costs, we expensed $1.5 million and $4.2 million for the nine months ended September 30, 2010 and 2009, respectively for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheets was $29.2 million and $30.4 million at September 30, 2010 and December 31, 2009, respectively, of which $22.8 million and $24.2 million, respectively, were classified as other long-term liabilities. These liabilities include $22.3 million of environmental obligations that we assumed in connection with our Tulsa Refinery west facility acquired on June 1, 2009 and our Tulsa Refinery east facility acquired on December 1, 2009. Costs of future expenditures for environmental remediation that are expected to be incurred over the next several years are not discounted to their present value.

NOTE 10: Debt

Credit Facilities

We have a $400 million senior secured credit agreement expiring in March 2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. In June 2010, the agreement was upsized by $30 million pursuant to the accordion feature. The Holly Credit Agreement 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 September 30, 2010. At September 30, 2010, we had no outstanding borrowings and outstanding letters of credit totaling $84.3 million under the Holly Credit Agreement. At that level of usage, the unused commitment was $315.7 million at September 30, 2010. We entered into an amendment to the Holly Credit Agreement on May 6, 2010 that changed certain financial covenants and provided other enhancements to the agreement.

HEP has a $300 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. At September 30, 2010, HEP had outstanding borrowings totaling $157 million under the HEP Credit Agreement, with unused borrowing capacity of $143 million. The HEP Credit Agreement expires in August 2011, therefore, outstanding borrowings all of which were previously classified as long-term liabilities are currently classified as current liabilities. HEP intends to renew the HEP

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Credit Agreement prior to expiration and to continue to finance outstanding borrowings. Upon renewal, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt.

HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our Consolidated Balance Sheets). 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. During the first quarter of 2010, our previous agreements to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement were terminated.

Holly Senior Notes Due 2017

In June 2009, we issued $200 million in aggregate principal amount of the Holly 9.875% Senior Notes. A portion of the $187.9 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly 9.875% Senior Notes that was used to fund the cash portion of our acquisition of Sinclair’s 75,000 BPSD refinery located in Tulsa, Oklahoma.

The $300 million aggregate principal amount of Holly 9.875% Senior Notes mature on June 15, 2017. The Holly 9.875% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our 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 9.875% 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 9.875% Senior Notes.

HEP Senior Notes Due 2018 and 2015

In March 2010, HEP issued $150 million in aggregate principal amount of HEP 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund HEP’s $93 million purchase of certain storage assets at our Tulsa Refinery east facility and Navajo Refinery Lovington facility on March 31, 2010. Additionally, HEP used a portion to repay $42 million in outstanding HEP Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

The HEP 6.25% Senior Notes having an aggregate principal amount of $185 million mature March 1, 2015 and are registered with the SEC. The HEP 6.25% Senior Notes and HEP 8.25% Senior Notes (collectively, 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. However, 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. During the first quarter of 2010, our previous agreement to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $35 million of the principal amount of the HEP 6.25% Senior Notes was terminated.

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Holly Financing Obligation

In October 2009, we sold to Plains a portion of the crude oil petroleum storage, and certain refining-related crude oil receiving pipeline facilities located at our Tulsa Refinery east facility. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing obligation. As a result, we retained these assets on our books and recorded a liability representing the $40 million in proceeds received.

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

	September 30,			December 31,
	2010			2009
	(In thousands)
Holly 9.875% Senior Notes
Principal	$	300,000		$	300,000
Unamortized discount		(10,767	)		(11,549	)
		289,233			288,451
Holly financing obligation
Principal		39,050			39,809
Total Holly long-term debt		328,283			328,260
HEP Credit Agreement		157,000			206,000
HEP 6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(11,620	)		(13,593	)
Unamortized premium – dedesignated fair value hedge		1,531			1,791
		174,911			173,198
HEP 8.25% Senior Notes
Principal		150,000			—
Unamortized discount		(2,288	)		—
		147,712			—
Total HEP debt		479,623			379,198
Less Credit Agreement borrowings classified as current liabilities		157,000			—
Total HEP long-term debt		322,623			379,198
Total long-term debt	$	650,906		$	707,458

NOTE 11: Derivative Instruments and Hedging Activities

Commodity Price Risk Management

During the third quarter of 2010, we entered into two types of hedging transactions.

We entered into multiple gasoline price swap contracts relating to forecasted sales transactions of unleaded 87 gasoline produced at our Tulsa Refinery facilities in order to protect margins on winter grade gasoline. Winter grade gasoline specifications allow for the blending of butane as an additive. Since the cost of butane is subject to price risk (fluctuating prices), our refined product margins are exposed to the adverse affects of higher butane costs during winter months when demand for butane is generally higher and lower gasoline sales prices when demand for finished gasoline products is generally lower. To mitigate the effects of higher butane costs during

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winter months, we regularly purchase volumes of butane at more favorable prices during the summer season. Furthermore, in order to maintain a favorable spread between the cost of this butane and the ultimate sales price we receive on quantities of produced winter grade gasoline, we have entered into gasoline price swaps that effectively fix the sales price on forecasted sales totaling 135,000 barrels of unleaded 87 gasoline at a weighted average price of $81.61 per barrel. These barrels will be ratably sold between September and December 2010, matching the terms of the swap contracts maturing between September and December 2010.

Additionally, we entered into natural gas price swap contracts relating to forecasted purchases of natural gas to be used in production at our refining facilities during the 2010-2011 winter season. Natural gas prices are subject to price risk (fluctuating prices), therefore, the profitability of our refinery operations is exposed to the adverse affects of higher natural gas prices during winter months when demand for natural gas is generally higher. In order to mitigate the effects of higher natural gas prices, we have entered into natural gas price swaps that effectively fix our purchase price on forecasted natural gas purchases aggregating 2,500,000 million British thermal units (“MMBTU”) (approximately 30% of our refineries’ projected winter season consumption) to be ratably purchased between November 2010 and March 2011 at a weighted-average cost of $4.20 per MMBTU.

We have designated these commodity price swaps as cash flow hedges. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that our gasoline price swaps are effective in offsetting the variability in sales prices to be received on forecasted sales of finished gasoline inventory resulting from changes in gasoline reference prices. We have also determined that our natural gas price swaps are effective in offsetting the variability in prices to be paid on forecasted natural gas purchases resulting from changes in natural gas reference prices. Under hedge accounting, we adjust our cash flow hedges on a quarterly basis to fair value with offsetting fair value adjustments to accumulated other comprehensive income. Hedge effectiveness is measured by comparing the combined effects of amounts expected to be received or paid under these price swap contracts and prices to be received and paid under the forecasted transactions as discussed above against prestablished fixed prices. Any ineffectiveness is reclassified from accumulated other comprehensive income to cost of products sold. As of September 30, 2010, we have had no ineffectiveness on these cash flow hedges.

Interest Rate Risk Management

HEP uses interest rate swaps to manage its exposure to interest rate risk.

As of September 30, 2010, HEP has an interest rate swap that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of September 30, 2010. The maturity date of this swap contract is February 28, 2013.

HEP 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 this interest rate swap is effective in offsetting the variability in interest payments on the $155 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 the swap against the expected future interest payments on the $155 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of September 30, 2010, HEP had no ineffectiveness on its cash flow hedge.

In May 2010, HEP repaid $16 million of the HEP Credit Agreement debt and also settled a corresponding portion of its interest rate swap agreement having a notional amount of $16 million for $1.1 million. Upon payment, HEP reduced its swap liability and reclassified a $1.1 million charge from accumulated other comprehensive loss to interest expense, representing the application of hedge accounting prior to settlement.

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Additionally, HEP settled two interest rate swaps in the first quarter of 2010. HEP had an interest rate swap contract that effectively converted interest expense associated with $60 million of the HEP 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). HEP had an additional interest rate swap contract that effectively unwound the effects of the Variable Rate Swap, converting $60 million of the previously hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”), effectively fixing interest at a 4.75% rate. Upon settlement of the Variable Rate and Fixed Rate Swaps, HEP received $1.9 million and paid $3.6 million, respectively.

For the nine months ended September 30, 2010, HEP recognized a $1.5 million charge to interest expense as a result of fair value adjustments prior to settlement of these interest rate swaps in the first quarter of 2010. For the nine months ended September 30, 2009, fair value adjustments resulted in a $0.3 million increase in interest expense.

HEP has a deferred hedge premium that relates to the application of hedge accounting to the Variable Rate Swap prior to its hedge dedesignation in 2008. This deferred hedge premium having a balance of $1.5 million at September 30, 2010, is being amortized as a reduction to interest expense over the remaining term of the HEP 6.25% Senior Notes.

The following table presents balance sheet locations and related fair values of outstanding derivative instruments.

				Location of
	Balance Sheet			Offsetting	Offsetting
Derivative Instruments	Location	Fair Value		Balance	Amount
		(Dollars in thousands)
September 30, 2010
Derivatives designated as cash flow hedging instruments:
Variable-to-fixed commodity price swap contracts				Accumulated other
(forecasted volumes of gasoline sales)	Accrued liabilities	$	406	comprehensive loss	$	406
Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)	Accrued liabilities		738	Accumulated other    comprehensive loss		738
		$	1,144		$	1,144
Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	11,825	Accumulated other    comprehensive loss	$	11,825
December 31, 2009
Derivative designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments)	Other long-term liabilities	$	9,141	Accumulated other    comprehensive loss	$	9,141
Derivatives not designated as hedging instruments:
Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other assets	$	2,294	Long-term debt	$	1,791	(1)
				Equity		503	(2)
		$	2,294		$	2,294
Variable-to-fixed interest rate swap contract	Other long-term
($60 million of HEP 6.25% Senior Notes)	liabilities	$	2,555	Equity	$	2,555	(2)

(1)	Represents unamortized balance of dedesignated hedge premium.
(2)	Represents prior year charges to interest expense.

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NOTE 12: Equity

Changes to equity during the nine months ended September 30, 2010 are presented below:

	Holly Corporation
	Stockholders’			Noncontrolling			Total
	Equity			Interest			Equity
				(In thousands)
Balance at December 31, 2009	$	619,039		$	588,742		$	1,207,781
Net income		89,245			19,557			108,802
Dividends		(23,981	)		—			(23,981	)
Distributions to noncontrolling interest holders		—			(36,139	)		(36,139	)
Other comprehensive loss		(660	)		(2,804	)		(3,464	)
Contribution from joint venture partner		—			9,500			9,500
Issuance of common stock upon exercise of stock options		61			—			61
Tax benefit from stock options		199			—			199
Equity based compensation		6,044			1,770			7,814
Tax expense from equity based compensation arrangements		(1,512	)		—			(1,512	)
Purchase of HEP units for restricted grants		—			(2,276	)		(2,276	)
Purchase of treasury stock (1)		(1,308	)		—			(1,308	)
Balance at September 30, 2010	$	687,127		$	578,350		$	1,265,477

(1) Represents shares purchased under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock.

During the nine months ended September 30, 2010, we repurchased at market price from certain executives and employees 44,475 shares of our common stock at a cost of $1.2 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

NOTE 13: Other Comprehensive Income (Loss)

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

				Tax Expense
	Before-Tax			(Benefit)			After-Tax
	(In thousands)
Three Months Ended September 30, 2010
Unrealized loss on available-for-sale securities	$	(51	)	$	(20	)	$	(31	)
Unrealized loss on hedging activities		(1,845	)		(538	)		(1,307	)
Other comprehensive loss		(1,896	)		(558	)		(1,338	)
Less other comprehensive loss attributable to noncontrolling interest		(461	)		—			(461	)
Other comprehensive loss attributable to Holly stockholders	$	(1,435	)	$	(558	)	$	(877	)
Three Months Ended September 30, 2009
Unrealized gain on available-for-sale securities	$	234		$	91		$	143
Unrealized loss on hedging activities		(1,482	)		(264	)		(1,218	)
Other comprehensive loss		(1,248	)		(173	)		(1,075	)
Less other comprehensive loss attributable to noncontrolling interest		(804	)		—			(804	)
Other comprehensive loss attributable to Holly stockholders	$	(444	)	$	(173	)	$	(271	)
Nine Months Ended September 30, 2010
Unrealized loss on available-for-sale securities	$	(58	)	$	(24	)	$	(34	)
Unrealized loss on hedging activities		(3,826	)		(396	)		(3,430	)
Other comprehensive loss		(3,884	)		(420	)		(3,464	)
Less other comprehensive loss attributable to noncontrolling interest		(2,804	)		—			(2,804	)
Other comprehensive loss attributable to Holly stockholders	$	(1,080	)	$	(420	)	$	(660	)

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			Tax Expense
	Before-Tax		(Benefit)		After-Tax
	(In thousands)
Nine Months Ended September 30, 2009
Unrealized gain on available-for-sale securities	$	212	$	82	$	130
Unrealized gain on hedging activities		2,685		478		2,207
Other comprehensive income		2,897		560		2,337
Less other comprehensive income attributable to noncontrolling interest		1,456		—		1,456
Other comprehensive income attributable to Holly stockholders	$	1,441	$	560	$	881

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:

	September 30,			December 31,
	2010			2009
	(In thousands)
Pension obligation adjustment	$	(21,774	)	$	(21,774	)
Retiree medical obligation adjustment		(1,749	)		(1,749	)
Unrealized gain on available-for-sale securities		345			379
Unrealized loss on hedging activities, net of noncontrolling interest		(3,182	)		(2,556	)
Accumulated other comprehensive loss	$	(26,360	)	$	(25,700	)

NOTE 14: Retirement Plan

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

The retirement plan is closed to employees hired subsequent to 2006 and not covered by collective bargaining agreements with labor unions. To the extent a non-union 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.

Effective July 1, 2010, the retirement plan was closed to all new employees covered by collective bargaining agreements with labor unions. To the extent a union employee was hired prior to July 1, 2010, the employee may elect to continue their participation in the retirement plan or to participate in our defined contribution plan whereby their participation in future benefits of the retirement plan will be frozen.

The net periodic pension expense consisted of the following components:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
				(In thousands)
Service cost – benefit earned during the period	$	1,149		$	1,158		$	3,446		$	3,236
Interest cost on projected benefit obligations		1,288			1,287			3,865			3,707
Expected return on plan assets		(1,144	)		(959	)		(3,432	)		(2,883	)
Amortization of prior service cost		98			98			293			293
Amortization of net loss		549			1,024			1,647			2,861
Net periodic pension expense	$	1,940		$	2,608		$	5,819		$	7,214

The expected long-term annual rate of return on plan assets is 8.5%. This rate was used in measuring 2010 and 2009 net periodic benefit cost. We contributed $5.4 million to the retirement plan in July 2010.

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NOTE 15: Contingencies

In May 2007, the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”) issued its decision on petitions for review, brought by us and other parties, concerning rulings by the FERC in proceedings brought by us and other parties against SFPP, L.P. (“SFPP”). These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona 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 case was remanded to FERC and consolidated with other cases that together addressed SFPP’s rates for the period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP owes us for the period January 1992 through May 2006.

We and other shippers also engaged in settlement discussions with SFPP relating to East Line service in the FERC proceedings that address periods after May 2006. 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 $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 FERC approved the settlement on January 29, 2009. The settlement reduced SFPP’s current rates and required SFPP to make additional payments to us of $2.9 million, which were received on May 18, 2009.

On June 2, 2009, SFPP notified us that it would terminate the October 22, 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 and several other shippers filed protests at the FERC challenging the rate increase and asking the FERC to suspend the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect subject to refund, and setting the rate increase for a full evidentiary hearing to be held in 2010. SFPP subsequently reduced its rates for the East Line service, effective September 1, 2010. The rates placed in effect on January 1, 2010, and the lower rates put into effect on September 1, 2010, remain subject to refund subject to the outcome of the evidentiary hearing. 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 16: 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 and involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum products 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

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throughout North America and are distributed in Central and South America. Holly Asphalt manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

HEP, a consolidated VIE, 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, Utah and Oklahoma. 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 25% interest in SLC Pipeline that services refineries 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. 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, 2009.

								Consolidations and
	Refining		HEP(1)		Corporate and Other			Eliminations			Consolidated Total
					(In thousands)
Three Months Ended September 30, 2010
Sales and other revenues	$	2,081,709	$	46,558	$	100		$	(37,379	)	$	2,090,988
Depreciation and amortization	$	21,274	$	6,830	$	1,329		$	(295	)	$	29,138
Income (loss) from operations	$	100,111	$	24,588	$	(16,652	)	$	(429	)	$	107,618
Capital expenditures	$	47,623	$	3,567	$	219		$	—		$	51,409
Three Months Ended September 30, 2009
Sales and other revenues	$	1,476,304	$	40,805	$	229		$	(28,847	)	$	1,488,491
Depreciation and amortization	$	16,527	$	5,974	$	1,525		$	—		$	24,026
Income (loss) from operations	$	50,584	$	21,880	$	(16,183	)	$	(699	)	$	55,582
Capital expenditures	$	54,946	$	5,652	$	2,030		$	—		$	62,628
Nine Months Ended September 30, 2010
Sales and other revenues	$	6,086,243	$	132,730	$	317		$	(108,152	)	$	6,111,138
Depreciation and amortization	$	62,599	$	20,822	$	3,183		$	(885	)	$	85,719
Income (loss) from operations	$	200,080	$	65,737	$	(47,529	)	$	(1,250	)	$	217,038
Capital expenditures	$	118,387	$	8,054	$	1,498		$	—		$	127,939
Nine Months Ended September 30, 2009
Sales and other revenues	$	3,136,017	$	108,136	$	423		$	(72,277	)	$	3,172,299
Depreciation and amortization	$	46,310	$	17,794	$	5,263		$	—		$	69,367
Income (loss) from operations	$	121,703	$	53,287	$	(43,467	)	$	(699	)	$	130,824
Capital expenditures	$	215,613	$	27,478	$	2,930		$	—		$	246,021
September 30, 2010
Cash, cash equivalents and investments in marketable securities	$	—	$	706	$	272,385		$	—		$	273,091
Total assets	$	2,210,374	$	660,727	$	555,419		$	(29,141	)	$	3,397,379
December 31, 2009
Cash, cash equivalents and investments in marketable securities	$	—	$	2,508	$	123,311		$	—		$	125,819
Total assets	$	2,142,317	$	641,775	$	392,007		$	(30,160	)	$	3,145,939

(1) HEP segment revenues from external customers were $9.2 million and $12.4 million for the three months ended September 30, 2010 and 2009, respectively, and $24.7 million and $36.4 million for the nine months ended September 30, 2010 and 2009, respectively.

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NOTE 17: Supplemental Guarantor/Non-Guarantor Financial Information

Our obligations under the Holly 9.875% 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 34% 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.

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Condensed Consolidating Balance Sheet

							Non-								Non-Guarantor
							Guarantor						Holly Corp. Before		Non-Restricted
				Guarantor Restricted			Restricted						Consolidation of		Subsidiaries
September 30, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP		(HEP Segment)		Eliminations			Consolidated
										(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	265,969		$	(1,557	)	$	6,802		$	—		$	271,214	$	706	$	—		$	271,920
Marketable securities		—			1,171			—			—			1,171		—		—			1,171
Accounts receivable		(6,957	)		724,081			—			—			717,124		21,319		(19,972	)		718,471
Intercompany accounts receivable (payable)		(1,385,596	)		988,726			396,870			—			—		—		—			—
Inventories		—			413,818			—			—			413,818		197		—			414,015
Income taxes receivable		26,269			—			—			—			26,269		—		—			26,269
Prepayments and other assets		26,704			19,040			—			—			45,744		924		(3,407	)		43,261
Total current assets		(1,073,611	)		2,145,279			403,672			—			1,475,340		23,146		(23,379	)		1,475,107
Properties and equipment, net		17,971			1,004,329			199,203			—			1,221,503		482,786		(6,906	)		1,697,383
Investment in subsidiaries		2,227,676			545,056			(393,379	)		(2,379,353	)		—		—		—			—
Intangibles and other assets		9,352			59,599			—			—			68,951		154,794		1,144			224,889
Total assets	$	1,181,388		$	3,754,263		$	209,496		$	(2,379,353	)	$	2,765,794	$	660,726	$	(29,141	)	$	3,397,379
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,348		$	1,043,545		$	7,570		$	—		$	1,058,463	$	5,786	$	(19,972	)	$	1,044,277
Accrued liabilities		33,644			22,591			492			—			56,727		15,752		(3,407	)		69,072
Credit agreement borrowings		—			—			—			—			—		157,000		—			157,000
Total current liabilities		40,992			1,066,136			8,062			—			1,115,190		178,538		(23,379	)		1,270,349
Long-term debt		289,233			56,085			—			—			345,318		322,623		(17,035	)		650,906
Non-current liabilities		38,098			30,338			—			—			68,436		12,534		—			80,970
Deferred income taxes		124,640			(239	)		325			—			124,726		—		4,951			129,677
Distributions in excess of inv in HEP		—			374,267			—			—			374,267		—		(374,267	)		—
Equity — Holly Corporation		688,425			2,227,676			201,109			(2,428,785	)		688,425		147,031		(148,329	)		687,127
Equity — noncontrolling interest		—			—			—			49,432			49,432		—		528,918			578,350
Total liabilities and equity	$	1,181,388		$	3,754,263		$	209,496		$	(2,379,353	)	$	2,765,794	$	660,726	$	(29,141	)	$	3,397,379

Condensed Consolidating Balance Sheet

							Non-								Non-Guarantor
							Guarantor						Holly Corp. Before		Non-Restricted
				Guarantor Restricted			Restricted						Consolidation of		Subsidiaries
December 31, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP		(HEP Segment)		Eliminations			Consolidated
										(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	127,560		$	(12,477	)	$	7,005		$	—		$	122,088	$	2,508	$	—		$	124,596
Marketable securities		—			1,223			—			—			1,223		—		—			1,223
Accounts receivable		973			759,140			—			—			760,113		18,767		(16,425	)		762,455
Intercompany accounts receivable (payable)		(1,134,296	)		817,647			316,649			—			—		—		—			—
Inventories		—			303,348			—			—			303,348		165		—			303,513
Income taxes receivable		38,071			1			—			—			38,072		—		—			38,072
Prepayments and other assets		24,940			29,018			—			—			53,958		574		(3,575	)		50,957
Current assets of discontinued ops		—			—			—			—			—		2,195		—			2,195
Total current assets		(942,752	)		1,897,900			323,654			—			1,278,802		24,209		(20,000	)		1,283,011
Properties and equipment, net		21,918			1,005,422			155,413			—			1,182,753		458,521		(11,304	)		1,629,970
Investment in subsidiaries		2,010,510			435,970			(314,973	)		(2,131,507	)		—		—		—			—
Intangibles and other assets		8,752			64,017			—			—			72,769		159,045		1,144			232,958
Total assets	$	1,098,428		$	3,403,309		$	164,094		$	(2,131,507	)	$	2,534,324	$	641,775	$	(30,160	)	$	3,145,939
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,968		$	974,177		$	2,224		$	—		$	985,369	$	6,211	$	(16,425	)	$	975,155
Accrued liabilities		23,752			15,477			709			—			39,938		13,594		(3,575	)		49,957
Total current liabilities		32,720			989,654			2,933			—			1,025,307		19,805		(20,000	)		1,025,112
Long-term debt		288,451			39,809			—			—			328,260		379,198		—			707,458
Non-current liabilities		37,859			48,137			—			—			85,996		12,349		(17,342	)		81,003
Deferred income taxes		119,127			229			278			—			119,634		—		4,951			124,585
Distributions in excess of inv in HEP		—			314,970			—			—			314,970		—		(314,970	)		—
Equity — Holly Corporation		620,271			2,010,510			160,883			(2,171,393	)		620,271		230,423		(231,655	)		619,039
Equity — noncontrolling interest		—			—			—			39,886			39,886		—		548,856			588,742
Total liabilities and equity	$	1,098,428		$	3,403,309		$	164,094		$	(2,131,507	)	$	2,534,324	$	641,775	$	(30,160	)	$	3,145,939

- 28 -

Condensed Consolidating Statement of Income

																Non-Guarantor
							Non-Guarantor						Holly Corp. Before			Non-Restricted
Three Months Ended				Guarantor Restricted				Restricted					Consolidation of			Subsidiaries
September 30, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	100		$	2,081,707		$	2		$	—		$	2,081,809		$	46,558		$	(37,379	)	$	2,090,988
Operating costs and expenses:
Cost of products sold		—			1,843,464			103			—			1,843,567			—			(36,523	)		1,807,044
Operating expenses		—			116,763			—			—			116,763			13,632			(132	)		130,263
General and administrative expenses		15,538			(121	)		—			—			15,417			1,508			—			16,925
Depreciation and amortization		925			21,499			179			—			22,603			6,830			(295	)		29,138
Total operating costs and expenses		16,463			1,981,605			282			—			1,998,350			21,970			(36,950	)		1,983,370
Income (loss) from operations		(16,363	)		100,102			(280	)		—			83,459			24,588			(429	)		107,618
Other income (expense):
Equity in earnings of subsidiaries and joint venture		106,360			7,918			8,117			(114,278	)		8,117			570			(8,117	)		570
Interest income (expense)		(7,294	)		(1,660	)		11			—			(8,943	)		(8,979	)		618			(17,304	)
		99,066			6,258			8,128			(114,278	)		(826	)		(8,409	)		(7,499	)		(16,734	)
Income from continuing operations before income taxes		82,703			106,360			7,848			(114,278	)		82,633			16,179			(7,928	)		90,884
Income tax provision		31,418			—			—			—			31,418			76			—			31,494
Net income		51,285			106,360			7,848			(114,278	)		51,215			16,103			(7,928	)		59,390
Less net income attributable to noncontrolling interest		—			—			—			(70	)		(70	)		—			8,283			8,213
Net income attributable to Holly Corporation stockholders	$	51,285		$	106,360		$	7,848		$	(114,208	)	$	51,285		$	16,103		$	(16,211	)	$	51,177

Condensed Consolidating Statement of Income

																Non-Guarantor
							Non-Guarantor						Holly Corp. Before			Non-Restricted
Three Months Ended				Guarantor Restricted				Restricted					Consolidation of			Subsidiaries
September 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	229		$	1,476,304		$	—		$	—		$	1,476,533		$	40,805		$	(28,847	)	$	1,488,491
Operating costs and expenses:
Cost of products sold		—			1,323,329			129			—			1,323,458			—			(28,020	)		1,295,438
Operating expenses		—			85,742			—			—			85,742			11,103			(128	)		96,717
General and administrative expenses		15,056			(241	)		65			—			14,880			1,848			—			16,728
Depreciation and amortization		987			16,748			317			—			18,052			5,974			—			24,026
Total operating costs and expenses		16,043			1,425,578			511			—			1,442,132			18,925			(28,148	)		1,432,909
Income (loss) from operations		(15,814	)		50,726			(511	)		—			34,401			21,880			(699	)		55,582
Other income (expense):
Equity in earnings of subsidiaries and joint venture		59,968			7,744			8,118			(67,712	)		8,118			646			(8,118	)		646
Interest income (expense)		(5,802	)		175			11			—			(5,616	)		(6,979	)		419			(12,176	)
SLC Pipeline acquisition costs		—			—			—			—			—			1,144			(1,144	)		—
Tulsa Refinery acquisition costs		(1,701	)		1,323			—			—			(378	)		—			—			(378	)
		52,465			9,242			8,129			(67,712	)		2,124			(5,124	)		(8,908	)		(11,908	)
Income from continuing operations before income taxes		36,651			59,968			7,618			(67,712	)		36,525			16,756			(9,607	)		43,674
Income tax provision		13,566			—			—			—			13,566			100			(169	)		13,497
Income from continuing operations		23,085			59,968			7,618			(67,712	)		22,959			16,656			(9,438	)		30,177
Income from discontinued operations		—			—			—			—			—			1,070			(169	)		901
Net income		23,085			59,968			7,618			(67,712	)		22,959			17,726			(9,607	)		31,078
Less net income attributable to noncontrolling interest		—			—			—			(126	)		(126	)		—			7,720			7,594
Net income attributable to Holly Corporation stockholders	$	23,085		$	59,968		$	7,618		$	(67,586	)	$	23,085		$	17,726		$	(17,327	)	$	23,484

- 29 -

Condensed Consolidating Statement of Income

																Non-Guarantor
							Non-Guarantor						Holly Corp. Before			Non-Restricted
Nine Months Ended				Guarantor Restricted				Restricted					Consolidation of			Subsidiaries
September 30, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	317		$	6,086,241		$	2		$	—		$	6,086,560		$	132,730		$	(108,152	)	$	6,111,138
Operating costs and expenses:
Cost of products sold		—			5,484,647			115			—			5,484,762			—			(105,642	)		5,379,120
Operating expenses		—			338,826			—			—			338,826			40,187			(375	)		378,638
General and administrative expenses		44,339			300			—			—			44,639			5,984			—			50,623
Depreciation and amortization		2,796			63,278			(292	)		—			65,782			20,822			(885	)		85,719
Total operating costs and expenses		47,135			5,887,051			(177	)		—			5,934,009			66,993			(106,902	)		5,894,100
Income (loss) from operations		(46,818	)		199,190			179			—			152,551			65,737			(1,250	)		217,038
Other income (expense):
Equity in earnings of subsidiaries and joint venture		216,349			21,217			21,053			(237,566	)		21,053			1,595			(21,053	)		1,595
Interest income (expense)		(25,964	)		(4,058	)		31			—			(29,991	)		(27,192	)		1,828			(55,355	)
		190,385			17,159			21,084			(237,566	)		(8,938	)		(25,597	)		(19,225	)		(53,760	)
Income from continuing operations before income taxes		143,567			216,349			21,263			(237,566	)		143,613			40,140			(20,475	)		163,278
Income tax provision		54,260			—			—			—			54,260			216			—			54,476
Net income		89,307			216,349			21,263			(237,566	)		89,353			39,924			(20,475	)		108,802
Less net income attributable to noncontrolling interest		—			—			—			46			46			—			19,511			19,557
Net income attributable to Holly Corporation stockholders	$	89,307		$	216,349		$	21,263		$	(237,612	)	$	89,307		$	39,924		$	(39,986	)	$	89,245

Condensed Consolidating Statement of Income

																Non-Guarantor
							Non-Guarantor						Holly Corp. Before			Non-Restricted
Nine Months Ended				Guarantor Restricted				Restricted					Consolidation of			Subsidiaries
September 30, 2009	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
										(In thousands)
Sales and other revenues	$	423		$	3,135,959		$	58		$	—		$	3,136,440		$	108,136		$	(72,277	)	$	3,172,299
Operating costs and expenses:
Cost of products sold		—			2,757,831			383			—			2,758,214			—			(71,196	)		2,687,018
Operating expenses		—			209,824			—			—			209,824			32,076			(382	)		241,518
General and administrative expenses		37,655			873			65			—			38,593			4,979						43,572
Depreciation and amortization		2,924			47,698			951			—			51,573			17,794			—			69,367
Total operating costs and expenses		40,579			3,016,226			1,399			—			3,058,204			54,849			(71,578	)		3,041,475
Income (loss) from operations		(40,156	)		119,733			(1,341	)		—			78,236			53,287			(699	)		130,824
Other income (expense):
Equity in earnings of subsidiaries and joint venture		140,429			20,367			21,367			(160,796	)		21,367			1,374			(21,432	)		1,309
Interest income (expense)		(8,154	)		2,317			33			—			(5,804	)		(17,903	)		419			(23,288	)
SLC Pipeline acquisition costs		—			—			—			—			—			(1,356	)		1,356			—
Tulsa Refinery acquisition costs		—			(1,988	)		—			—			(1,988	)		—			—			(1,988	)
		132,275			20,696			21,400			(160,796	)		13,575			(17,885	)		(19,657	)		(23,967	)
Income from continuing operations before income taxes		92,119			140,429			20,059			(160,796	)		91,811			35,402			(20,356	)		106,857
Income tax provision		35,069			—			—			—			35,069			266			(667	)		34,668
Income from continuing operations		57,050			140,429			20,059			(160,796	)		56,742			35,136			(19,689	)		72,189
Income from discontinued operations		—			—			—			—			—			4,105			(667	)		3,438
Net income		57,050			140,429			20,059			(160,796	)		56,742			39,241			(20,356	)		75,627
Less net income attributable to noncontrolling interest		—			—			—			(308	)		(308	)		—			15,901			15,593
Net income attributable to Holly Corporation stockholders	$	57,050		$	140,429		$	20,059		$	(160,488	)	$	57,050		$	39,241		$	(36,257	)	$	60,034

- 30 -

Condensed Consolidating Statement of Cash Flows

													Non-Guarantor
							Non-Guarantor			Holly Corp. Before			Non-Restricted
				Guarantor Restricted			Restricted			Consolidation of			Subsidiaries
Nine Months Ended September 30, 2010	Parent			Subsidiaries			Subsidiaries			HEP			(HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	168,984		$	22,377		$	5,294		$	196,655		$	66,129		$	(26,816	)	$	235,968
Cash flows from investing activities
Additions to properties, plants and equipment — Holly		(1,498	)		(74,890	)		(43,497	)		(119,885	)		—			—			(119,885	)
Additions to properties, plants and equipment — HEP		—			—			—			—			(43,580	)		35,526			(8,054	)
Proceeds from sale of assets		—			39,040			—			39,040			—			(39,040	)		—
		(1,498	)		(35,850	)		(43,497	)		(80,845	)		(43,580	)		(3,514	)		(127,939	)
Cash flows from financing activities
Net repayments under credit agreements — HEP		—			—			—			—			(49,000	)		—			(49,000	)
Proceeds from issuance of senior notes — HEP		—			—			—			—			147,540			—			147,540
Repayments under financing obligation — Holly		—			(1,067	)		—			(1,067	)		—			307			(760	)
Purchase of treasury stock		(1,308	)		—			—			(1,308	)		—			—			(1,308	)
Contribution from joint venture partner		—			(28,500	)		38,000			9,500			—			—			9,500
Dividends		(23,889	)		—			—			(23,889	)		—			—			(23,889	)
Purchase price in excess of transferred basis in assets		—			53,960			—			53,960			(57,474	)		3,514			—
Distributions to noncontrolling interest		—			—			—			—			(62,648	)		26,509			(36,139	)
Excess tax expense from equity based compensation		(1,313	)		—			—			(1,313	)		—			—			(1,313	)
Deferred financing costs		(2,628	)		—			—			(2,628	)		(493	)		—			(3,121	)
Purchase of units for HEP restricted grants		—			—			—			—			(2,276	)		—			(2,276	)
Other		61			—			—			61			—			—			61
		(29,077	)		24,393			38,000			33,316			(24,351	)		30,330			39,295
Cash and cash equivalents
Increase (decrease) for the period		138,409			10,920			(203	)		149,126			(1,802	)		—			147,324
Beginning of period		127,560			(12,477	)		7,005			122,088			2,508			—			124,596
End of period	$	265,969		$	(1,557	)	$	6,802		$	271,214		$	706		$	—		$	271,920

Condensed Consolidating Statement of Cash Flows

							Non-						Non-Guarantor
							Guarantor			Holly Corp. Before			Non-Restricted
				Guarantor Restricted			Restricted			Consolidation of			Subsidiaries
Nine Months Ended September 30, 2009	Parent			Subsidiaries			Subsidiaries			HEP			(HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	(158,881	)	$	314,740		$	967		$	156,826		$	44,788		$	(21,962	)	$	179,652
Cash flows from investing activities
Additions to properties, plants and equipment — Holly		(2,930	)		(172,304	)		(43,309	)		(218,543	)		—			—			(218,543	)
Additions to properties, plants and equipment — HEP		—			—			—			—			(73,478	)		46,000			(27,478	)
Acquisition of Tulsa Refinery west facility — Holly		—			(157,814	)		—			(157,814	)		—			—			(157,814	)
Investment in SLC Pipeline — HEP		—			—			—			—			(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
Proceeds from sales of assets		—			34,200			—			34,200			—			(34,200	)		—
		51,459			(295,918	)		(43,309	)		(287,768	)		(98,978	)		11,800			(374,946	)
Cash flows from financing activities
Proceeds from issuance of senior notes — Holly		187,925			—			—			187,925			—			—			187,925
Net borrowings under credit agreement — HEP		—			—			—			—			45,000			—			45,000
Proceeds from issuance of common units — HEP		—			—			—			—			58,355			—			58,355
Purchase of treasury stock		(1,214	)		—			—			(1,214	)		—			—			(1,214	)
Contribution from joint venture partner		—			(34,950	)		48,600			13,650			—			—			13,650
Dividends		(22,569	)		—			—			(22,569	)		—			—			(22,569	)
Distributions to noncontrolling interest		—			—			—			—			(44,993	)		21,634			(23,359	)
Excess tax benefit from equity based compensation		2,140			—			—			2,140			—			—			2,140
Deferred financing costs		(6,356	)		—			—			(6,356	)		—			—			(6,356	)
Other		60			16,247			—			16,307			(5,391	)		(11,472	)		(556	)
		159,986			(18,703	)		48,600			189,883			52,971			10,162			253,016
Cash and cash equivalents
Increase (decrease) for the period		52,564			119			6,258			58,941			(1,219	)		—			57,722
Beginning of period		33,316			(1,182	)		3,402			35,536			5,269			—			40,805
End of period	$	85,880		$	(1,063	)	$	9,660		$	94,477		$	4,050		$	—		$	98,527

- 31 -

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

This Item 2 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words “we,” “our,” “ours” and “us” refer only to Holly Corporation and its consolidated subsidiaries or to Holly Corporation or an individual subsidiary and not to any other person. For periods after our reconsolidation of Holly Energy Partners, L.P. (“HEP”) effective March 1, 2008, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of Holly Corporation with certain exceptions where there are transactions or obligations between HEP and Holly Corporation or its other subsidiaries. This document 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 consisting of refinery facilities in Artesia and Lovington, New Mexico (collectively, the “Navajo Refinery”), Woods Cross, Utah (the “Woods Cross Refinery”) and two refinery facilities in Tulsa, Oklahoma (collectively, operated as the “Tulsa Refinery”). As of September 30, 2010, our refineries had a combined crude capacity of 256,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At September 30, 2010, we also owned a 34% interest in HEP (including the 2% general partner interest) which owns and operates pipeline and terminalling assets, and owns a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”).

Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel, jet fuel and asphalt products in markets in the Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. We also produce specialty lubricant products that are marketed throughout North America and are distributed in Central and South America. For the nine months ended September 30, 2010, sales and other revenues were $6,111.1 million and net income attributable to Holly Corporation stockholders was $89.2 million. For the nine months ended September 30, 2009, sales and other revenues from continuing operations were $3,172.3 million and net income attributable to Holly Corporation stockholders was $60 million. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the nine months ended September 30, 2010 were $5,894.1 million compared to $3,041.5 million for the nine months ended September 30, 2009.

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate of Sunoco, Inc. (“Sunoco”) for $157.8 million in cash, including crude oil, refined product and other inventories valued at $92.8 million. 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.

On December 1, 2009, we acquired a 75,000 BPSD refinery that is also located in Tulsa, Oklahoma (the “Tulsa Refinery east facility”) from an affiliate of Sinclair Oil Company (“Sinclair”) for $183.3 million, including crude oil, refined product and other inventories valued at $46.4 million. The refinery produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region of the United States. We are in the process of integrating the operations of both Tulsa Refinery facilities (collectively, the “Tulsa Refinery”). Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD.

Separately, HEP, also a party to the December 1, 2009 transaction with Sinclair, acquired certain logistics and storage assets located at our Tulsa Refinery east facility. See “Note 3 — Holly Energy Partners” to the Consolidated Financial Statements under Item 1 for additional information on this transaction as well as HEP’s 2010 and 2009 asset acquisitions from us.

Also on December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande are presented in discontinued operations.

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RESULTS OF OPERATIONS

Financial Data (Unaudited)

	Three Months Ended
	September 30,						Change from 2009
	2010			2009			Change			Percent
				(In thousands, except per share data)
Sales and other revenues	$	2,090,988		$	1,488,491		$	602,497			40.5	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		1,807,044			1,295,438			511,606			39.5
Operating expenses (exclusive of depreciation and amortization)		130,263			96,717			33,546			34.7
General and administrative expenses (exclusive of depreciation and amortization)		16,925			16,728			197			1.2
Depreciation and amortization		29,138			24,026			5,112			21.3
Total operating costs and expenses		1,983,370			1,432,909			550,461			38.4
Income from operations		107,618			55,582			52,036			93.6
Other income (expense):
Equity in earnings of SLC Pipeline		570			646			(76	)		(11.8	)
Interest income		64			231			(167	)		(72.3	)
Interest expense		(17,368	)		(12,407	)		(4,961	)		40.0
Tulsa refinery acquisition costs		—			(378	)		378			(100.0	)
		(16,734	)		(11,908	)		(4,826	)		40.5
Income from continuing operations before income taxes		90,884			43,674			47,210			108.1
Income tax provision		31,494			13,497			17,997			133.3
Income from continuing operations		59,390			30,177			29,213			96.8
Income from discontinued operations, net of taxes of $182		—			901			(901	)		(100.0	)
Net income		59,390			31,078			28,312			91.1
Less net income attributable to noncontrolling interest		8,213			7,594			619			8.2
Net income attributable to Holly Corporation stockholders	$	51,177		$	23,484		$	27,693			117.9	%
Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	51,177		$	23,213		$	27,964			120.5	%
Income from discontinued operations		—			271			(271	)		(100.0	)
Net income	$	51,177		$	23,484		$	27,693			117.9	%
Earnings per share attributable to Holly Corporation stockholders — basic:
Income from continuing operations	$	0.96		$	0.46		$	0.50			108.7	%
Income from discontinued operations		—			0.01			(0.01	)		(100.0	)
Net income	$	0.96		$	0.47		$	0.49			104.3	%
Earnings per share attributable to Holly Corporation stockholders — diluted:
Income from continuing operations	$	0.96		$	0.46		$	0.50			108.7	%
Income from discontinued operations		—			0.01			(0.01	)		(100.0	)
Net income	$	0.96		$	0.47		$	0.49			104.3	%
Cash dividends declared per common share	$	0.15		$	0.15		$	—			—	%
Average number of common shares outstanding:
Basic		53,210			50,244			2,966			5.9	%
Diluted		53,567			50,327			3,240			6.4	%

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	Nine Months Ended
	September 30,						Change from 2009
	2010			2009			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	6,111,138		$	3,172,299		$	2,938,839			92.6	%
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		5,379,120			2,687,018			2,692,102			100.2
Operating expenses (exclusive of depreciation and amortization)		378,638			241,518			137,120			56.8
General and administrative expenses (exclusive of depreciation and amortization)		50,623			43,572			7,051			16.2
Depreciation and amortization		85,719			69,367			16,352			23.6
Total operating costs and expenses		5,894,100			3,041,475			2,852,625			93.8
Income from operations		217,038			130,824			86,214			65.9
Other income (expense):
Equity in earnings of SLC Pipeline		1,595			1,309			286			21.8
Interest income		758			2,561			(1,803	)		(70.4	)
Interest expense		(56,113	)		(25,849	)		(30,264	)		117.1
Tulsa refinery acquisition costs		—			(1,988	)		1,988			(100.0	)
		(53,760	)		(23,967	)		(29,793	)		124.3
Income from continuing operations before income taxes		163,278			106,857			56,421			52.8
Income tax provision		54,476			34,668			19,808			57.1
Income from continuing operations		108,802			72,189			36,613			50.7
Income from discontinued operations, net of taxes of $718		—			3,438			(3,438	)		(100.0	)
Net income		108,802			75,627			33,175			43.9
Less net income attributable to noncontrolling interest		19,557			15,593			3,964			25.4
Net income attributable to Holly Corporation stockholders	$	89,245		$	60,034		$	29,211			48.7	%
Earnings attributable to Holly Corporation stockholders:
Income from continuing operations	$	89,245		$	59,014		$	30,231			51.2	%
Income from discontinued operations		—			1,020			(1,020	)		(100.0	)
Net income	$	89,245		$	60,034		$	29,211			48.7	%
Earnings per share attributable to Holly Corporation stockholders — basic:
Income from continuing operations	$	1.68		$	1.18		$	0.50			42.4	%
Income from discontinued operations		—			0.02			(0.02	)		(100.0	)
Net income	$	1.68		$	1.20		$	0.48			40.0	%
Earnings per share attributable to Holly Corporation stockholders — diluted:
Income from continuing operations	$	1.67		$	1.17		$	0.50			42.7	%
Income from discontinued operations		—			0.02			(0.02	)		(100.0	)
Net income	$	1.67		$	1.19		$	0.48			40.3	%
Cash dividends declared per common share	$	0.45		$	0.45		$	—			—	%
Average number of common shares outstanding:
Basic		53,172			50,153			3,019			6.0	%
Diluted		53,531			50,272			3,259			6.5	%

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Balance Sheet Data (Unaudited)

	September 30,		December 31,
	2010		2009
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	273,091	$	125,819
Working capital (1)	$	204,758	$	257,899
Total assets	$	3,397,379	$	3,145,939
Long-term debt	$	650,906	$	707,458
Total equity	$	1,265,477	$	1,207,781

(1) HEP’s credit agreement expires in August 2011; therefore, working capital at September 30, 2010 reflects $157 million of credit agreement borrowings that are classified as current liabilities. HEP intends to renew its credit agreement prior to expiration and to continue to finance outstanding borrowings. Upon renewal, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt. Excluding HEP’s $157 million in credit agreement borrowings, working capital was $361.8 million at September 30, 2010.

Other Financial Data (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Net cash provided by operating activities	$	197,622		$	38,102		$	235,968		$	179,652
Net cash used for investing activities	$	(51,409	)	$	(62,628	)	$	(127,939	)	$	(374,946	)
Net cash provided by (used for) financing activities	$	(14,505	)	$	14,365		$	39,295		$	253,016
Capital expenditures	$	51,409		$	62,628		$	127,939		$	246,021
EBITDA from continuing operations (1)	$	129,113		$	72,912		$	284,795		$	186,337

(1) Earnings before interest, taxes, depreciation and amortization, which we refer to as (“EBITDA”), is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; 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 Eliminations.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Sales and other revenues
Refining (1)	$	2,081,709		$	1,476,304		$	6,086,243		$	3,136,017
HEP (2)		46,558			40,805			132,730			108,136
Corporate and Other		100			229			317			423
Eliminations		(37,379	)		(28,847	)		(108,152	)		(72,277	)
Consolidated	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Operating Income (loss)
Refining (1)	$	100,111		$	50,584		$	200,080		$	121,703
HEP (2)		24,588			21,880			65,737			53,287
Corporate and Other		(16,652	)		(16,183	)		(47,529	)		(43,467	)
Eliminations		(429	)		(699	)		(1,250	)		(699	)
Consolidated	$	107,618		$	55,582		$	217,038		$	130,824

(1)

The Refining segment includes the operations of our Navajo, Woods Cross and Tulsa Refineries and Holly Asphalt Company (“Holly Asphalt”) and involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. The petroleum products are primarily marketed in the Southwest, Rocky Mountain and Mid-Continent regions of the United States and northern Mexico. Additionally, specialty lubricant products produced at our Tulsa Refinery are marketed throughout North America and are distributed in Central and South America. Holly Asphalt manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.

(2)

The HEP segment involves all of the operations of HEP. HEP owns and operates a system of petroleum product and crude gathering pipelines and refinery tankage in Texas, New Mexico, Oklahoma and Utah, and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, Oklahoma and Washington. 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 its storage tanks and terminals. 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 with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations.

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 measures, about our consolidated refinery operations. The cost of products and refinery gross margin do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 3 of Part I of this Form 10-Q.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Navajo Refinery
Crude charge (BPD) (1)		85,110			86,250			82,150			76,670
Refinery production (BPD) (2)		91,550			93,620			90,290			84,560
Sales of produced refined products (BPD)		92,180			93,996			90,730			84,102
Sales of refined products (BPD) (3)		94,900			96,580			93,780			88,110
Refinery utilization (4)		85.1	%		86.2	%		82.2	%		80.7	%
Average per produced barrel (5)
Net sales	$	87.60		$	78.15		$	88.98		$	69.21
Cost of products (6)		79.39			70.88			81.44			60.25
Refinery gross margin		8.21			7.27			7.54			8.96
Refinery operating expenses (7)		5.25			4.37			5.01			4.88
Net operating margin	$	2.96		$	2.90		$	2.53		$	4.08

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Feedstocks:
Sour crude oil		88	%		86	%		86	%		84	%
Sweet crude oil		4	%		6	%		4	%		6	%
Other feedstocks and blends		8	%		8	%		10	%		10	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		55	%		56	%		57	%		57	%
Diesel fuels		32	%		33	%		31	%		33	%
Jet fuels		2	%		3	%		4	%		2	%
Fuel oil		6	%		4	%		4	%		3	%
Asphalt		3	%		2	%		2	%		3	%
LPG and other		2	%		2	%		2	%		2	%
Total		100	%		100	%		100	%		100	%
Woods Cross Refinery
Crude charge (BPD) (1)		27,440			26,860			26,870			25,670
Refinery production (BPD) (2)		28,410			27,630			27,940			26,220
Sales of produced refined products (BPD)		27,540			27,098			28,260			27,061
Sales of refined products (BPD) (3)		27,840			27,150			28,450			27,520
Refinery utilization (4)		88.5	%		86.7	%		86.7	%		81.9	%
Average per produced barrel (5)
Net sales	$	94.86		$	80.87		$	93.71		$	66.87
Cost of products (6)		73.08			65.68			74.02			55.22
Refinery gross margin		21.78			15.19			19.69			11.65
Refinery operating expenses (7)		6.11			6.44			5.86			6.45
Net operating margin	$	15.67		$	8.75		$	13.83		$	5.20
Feedstocks:
Sour crude oil		5	%		6	%		6	%		4	%
Sweet crude oil		61	%		61	%		60	%		63	%
Black wax crude oil		30	%		27	%		29	%		28	%
Other feedstocks and blends		4	%		6	%		5	%		5	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		60	%		59	%		62	%		65	%
Diesel fuels		33	%		32	%		31	%		28	%
Jet fuels		1	%		3	%		1	%		1	%
Fuel oil		2	%		3	%		1	%		3	%
Asphalt		2	%		2	%		3	%		1	%
LPG and other		2	%		1	%		2	%		2	%
Total		100	%		100	%		100	%		100	%
Tulsa Refinery (8)
Crude charge (BPD) (1)		114,820			66,230			112,340			28,300
Refinery production (BPD) (2)		110,670			64,230			108,830			27,400
Sales of produced refined products (BPD)		113,040			60,596			107,950			26,077
Sales of refined products (BPD) (3)		113,040			60,850			108,560			26,250
Refinery utilization (4)		91.9	%		77.9	%		89.9	%		74.5	%
Average per produced barrel (5)
Net sales	$	89.22		$	76.80		$	88.91		$	76.65
Cost of products (6)		79.80			70.10			81.26			70.80
Refinery gross margin		9.42			6.70			7.65			5.85
Refinery operating expenses (7)		4.80			4.64			5.10			4.76
Net operating margin	$	4.62		$	2.06		$	2.55		$	1.09

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Feedstocks:
Sour crude oil		9	%		—	%		6	%		—	%
Sweet crude oil		91	%		100	%		94	%		100	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		39	%		23	%		39	%		23	%
Diesel fuels		30	%		30	%		31	%		30	%
Jet fuels		8	%		11	%		8	%		11	%
Lubricants		10	%		18	%		10	%		18	%
Gas oil / intermediates		4	%		16	%		3	%		16	%
Asphalt		6	%		—	%		5	%		—	%
LPG and other		3	%		2	%		4	%		2	%
Total		100	%		100	%		100	%		100	%
Consolidated
Crude charge (BPD) (1)		227,370			179,350			221,360			130,640
Refinery production (BPD) (2)		230,630			185,480			227,060			138,190
Sales of produced refined products (BPD)		232,760			181,690			226,940			137,240
Sales of refined products (BPD) (3)		235,780			184,570			230,790			141,890
Refinery utilization (4)		88.8	%		83.0	%		86.5	%		80.5	%
Average per produced barrel (5)
Net sales	$	89.25		$	78.11		$	89.53		$	70.16
Cost of products (6)		78.84			69.84			80.43			61.26
Refinery gross margin		10.41			8.27			9.10			8.90
Refinery operating expenses (7)		5.14			4.77			5.16			5.17
Net operating margin	$	5.27		$	3.50		$	3.94		$	3.73
Feedstocks:
Sour crude oil		39	%		44	%		37	%		52	%
Sweet crude oil		54	%		47	%		55	%		36	%
Black wax crude oil		4	%		4	%		4	%		5	%
Other feedstocks and blends		3	%		5	%		4	%		7	%
Total		100	%		100	%		100	%		100	%
Sales of produced refined products:
Gasolines		48	%		45	%		49	%		52	%
Diesel fuels		31	%		32	%		31	%		31	%
Jet fuels		5	%		6	%		6	%		3	%
Fuel oil		3	%		2	%		2	%		3	%
Asphalt		4	%		2	%		3	%		2	%
Lubricants		5	%		6	%		5	%		4	%
Gas oil / intermediates		2	%		5	%		1	%		3	%
LPG and other		2	%		2	%		3	%		2	%
Total		100	%		100	%		100	%		100	%

(1)	Crude charge represents the barrels per day of crude oil processed 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 15,000 BPSD effective April 1, 2009 (our Navajo Refinery expansion), 85,000 BPSD effective June 1, 2009 (our Tulsa Refinery west facility acquisition) and 40,000 BPSD effective December 1, 2009 (our Tulsa Refinery east facility acquisition), increasing our consolidated crude capacity to 256,000 BPSD.

- 38 -

(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, terminal and refinery storage 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 nine months ended September 30, 2009 include crude oil processed and products yielded from the Tulsa Refinery west facility for the period from June 1, 2009 (date of Tulsa Refinery west facility acquisition) through September 30, 2009 only, and averaged over the 273 days for the nine months ended.

     Operating data for the period from June 1, 2009 through September 30, 2009 is as follows:

Tulsa Refinery
Crude charge (BPD)	63,330
Refinery production (BPD)	61,310
Sales of produced refined products (BPD)	58,360
Sales of refined products (BPD)	58,740
Refinery utilization	74.5%

Results of Operations — Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Summary

Net income attributable to Holly Corporation stockholders for the three months ended September 30, 2010 was $51.2 million ($0.96 per basic and diluted share), a $27.7 million increase compared to $23.5 million ($0.47 per basic and diluted share) for the three months ended September 30, 2009. Net income increased due principally to higher refinery gross margins during the three months ended September 30, 2010 combined with increased volumes of produced refined products sold. Overall refinery gross margins for the three months ended September 30, 2010 were $10.41 per produced barrel compared to $8.27 for the three months ended September 30, 2009.

Overall production levels for the three months ended September 30, 2010 increased by 24% over the same period of 2009 due principally to production from our Tulsa Refinery east facility acquired in December 2009.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 41% from $1,488.5 million for the three months ended September 30, 2009 to $2,091 million for the three months ended September 30, 2010, due principally to the effects of a 28% increase in year-over-year third quarter volumes of produced refined products sold combined with increased sales prices of produced refined products sold. The average sales price we received per produced barrel sold increased 14% from $78.11 for the three months ended September 30, 2009 to $89.25 for the three months ended September 30, 2010. Sales and other revenues for the three months ended September 30, 2010 and 2009, include $9.2 million and $12.4 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 40% from $1,295.4 million for the three months ended September 30, 2009 to $1,807 million for the three months ended September 30, 2010, due principally to higher crude oil costs combined with a 28% increase in volumes of produced 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 increased 13% from $69.84 for the three months ended September 30, 2009 to $78.84 for the three months ended September 30, 2010.

Gross Refinery Margins

Gross refinery margin per produced barrel increased 26% from $8.27 for the three months ended September 30, 2009 to $10.41 for the three months ended September 30, 2010 due to the effects of an increase in the average sales price we received per produced barrel sold, partially offset by an increase in the average price we paid per

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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 35% from $96.7 million for the three months ended September 30, 2009 to $130.3 million for the three months ended September 30, 2010, due principally to the inclusion of costs attributable to the operations of our Tulsa Refinery east facility acquired in December 2009 and higher refinery utility costs.

General and Administrative Expenses

General and administrative expenses increased slightly from $16.7 million for the three months ended September 30, 2009 to $16.9 million for the three months ended September 30, 2010, due principally to increased payroll costs.

Depreciation and Amortization Expenses

Depreciation and amortization increased 21% from $24 million for the three months ended September 30, 2009 to $29.1 million for the three months ended September 30, 2010. The increase was due principally to depreciation and amortization attributable to our Tulsa Refinery east facility and capitalized refinery improvement projects in early 2010 and 2009.

Interest Expense

Interest expense was $17.4 million for the three months ended September 30, 2010 compared to $12.4 million for the three months ended September 30, 2009. The increase was due principally to interest incurred on the $300 million Holly 9.875% senior notes due 2017 and the HEP 8.25% senior notes due 2018. For the three months ended September 30, 2010 and 2009, interest expense included $9 million and $6.6 million, respectively, in interest costs attributable to HEP operations.

Income Taxes

Income taxes were $31.5 million for the three months ended September 30, 2010 compared to $13.5 million for the three months ended September 30, 2009. This increase was due principally to significantly higher pre-tax earnings during the three months ended September 30, 2010 compared to the same period of 2009. Our effective tax rates, before consideration of earnings attributable to noncontrolling interest, were 34.7% and 30.9% for the three months ended September 30, 2010 and 2009, respectively.

Discontinued Operations

On December 1, 2009, HEP sold its 70% interest in Rio Grande. Rio Grande operations generated earnings of $0.9 million for the three months ended September 30, 2009.

Results of Operations — Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Summary

Net income attributable to Holly Corporation stockholders for the nine months ended September 30, 2010 was $89.2 million ($1.68 per basic and $1.67 per diluted share), a $29.2 million increase compared to $60 million ($1.20 per basic and $1.19 per diluted share) for the nine months ended September 30, 2009. Net income increased due principally to higher refinery gross margins during the current year-to-date period combined with increased volumes of produced refined products sold. Overall refinery gross margins for the nine months ended September 30, 2010 were $9.10 per produced barrel compared to $8.90 for the nine months ended September 30, 2009.

Overall production levels for the nine months ended September 30, 2010 increased by 64% over the same period of 2009 due to production from our Tulsa Refinery facilities acquired in June and December 2009 combined with

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higher production levels at our Navajo and Woods Cross Refineries. Additionally, production levels were lower during the first quarter of 2009 due to scheduled downtime during a planned major maintenance turnaround at our Navajo Refinery.

Sales and Other Revenues

Sales and other revenues from continuing operations increased 93% from $3,172.3 million for the nine months ended September 30, 2009 to $6,111.1 million for the nine months ended September 30, 2010, due principally to the effects of a 65% increase in year-over-year volumes of produced refined products sold combined with increased sales prices of produced refined products sold. The average sales price we received per produced barrel sold increased 28% from $70.16 for the nine months ended September 30, 2009 to $89.53 for the nine months ended September 30, 2010. Sales and other revenues for the nine months ended September 30, 2010 and 2009, include $24.7 million and $36.4 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 100% from $2,687 million for the nine months ended September 30, 2009 to $5,379.1 million for the nine months ended September 30, 2010, due principally to higher crude oil costs combined with a 65% increase in volumes of produced 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 increased 31% from $61.26 for the nine months ended September 30, 2009 to $80.43 for the nine months ended September 30, 2010.

Gross Refinery Margins

Gross refining margin per produced barrel increased 2% from $8.90 for the nine months ended September 30, 2009 to $9.10 for the nine months ended September 30, 2010 due to the effects of an increase in the average sales price we received per produced barrel sold, partially offset by an increase 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 57% from $241.5 million for the nine months ended September 30, 2009 to $378.6 million for the nine months ended September 30, 2010, due principally to the inclusion of costs attributable to the operations of our Tulsa Refinery facilities acquired in June and December 2009 and higher refinery utility costs.

General and Administrative Expenses

General and administrative expenses increased 16% from $43.6 million for the nine months ended September 30, 2009 to $50.6 million for the nine months ended September 30, 2010, due principally to costs associated with the support and integration of our Tulsa Refinery operations and increased payroll costs.

Depreciation and Amortization Expenses

Depreciation and amortization increased 24% from $69.4 million for the nine months ended September 30, 2009 to $85.7 million for the nine months ended September 30, 2010. The increase was due principally to depreciation and amortization attributable to our Tulsa refinery facilities and capitalized refinery improvement projects in early 2010 and 2009.

Interest Expense

Interest expense was $56.1 million for the nine months ended September 30, 2010 compared to $25.8 million for the nine months ended September 30, 2009. The increase was due principally to interest incurred on the $300 million Holly 9.875% senior notes due 2017 and the HEP 8.25% senior notes due 2018. For the nine months ended September 30, 2010 and 2009, interest expense included $27.2 million and $17.5 million, respectively, in interest costs attributable to HEP operations.

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Income Taxes

Income taxes were $54.5 million for the nine months ended September 30, 2010 compared to $34.7 million for the nine months ended September 30, 2009. Our effective tax rates, before consideration of earnings attributable to noncontrolling interest, were 33.4% and 32.4% for the nine months ended September 30, 2010 and 2009, respectively.

Discontinued Operations

Rio Grande operations generated earnings of $3.4 million for the nine months ended September 30, 2009.

LIQUIDITY AND CAPITAL RESOURCES

Holly Credit Agreement

We have a $400 million senior secured credit agreement expiring in March 2013 (the “Holly Credit Agreement”) with Bank of America, N.A. as administrative agent and one of a syndicate of lenders. In June 2010, the agreement was upsized by $30 million pursuant to the accordion feature. The Holly Credit Agreement 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 September 30, 2010. At September 30, 2010, we had no outstanding borrowings and outstanding letters of credit totaling $84.3 million under the Holly Credit Agreement. At that level of usage, the unused commitment was $315.7 million at September 30, 2010. We entered into an amendment to the Holly Credit Agreement on May 6, 2010 that changed certain financial covenants and provided other enhancements to the agreement.

There are currently a total of fifteen lenders under the Holly Credit Agreement with individual commitments ranging from $10 million to $47.5 million. If any particular lender could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient 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 Holly 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 Credit Agreement

HEP has a $300 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, working capital and for other general partnership purposes. At September 30, 2010, HEP had outstanding borrowings totaling $157 million under the HEP Credit Agreement, with unused borrowing capacity of $143 million. The HEP Credit Agreement expires in August 2011; therefore, outstanding borrowings are currently classified as current liabilities. HEP intends to renew the HEP Credit Agreement prior to expiration and to continue to finance outstanding borrowings. Upon renewal, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt.

HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our Consolidated Balance Sheets). 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. During the first quarter of 2010, our previous agreements to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to a $171 million aggregate principal amount of borrowings under the HEP Credit Agreement were terminated.

There are currently a total of thirteen lenders under the HEP Credit Agreement with individual commitments ranging from $15 million to $40 million. If any particular lender could not honor its commitment, HEP believes the unused capacity that would be available from the remaining lenders would be sufficient to meet its 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.

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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.

Holly Senior Notes Due 2017

In June 2009, we issued $200 million in aggregate principal amount of 9.875% senior notes maturing June 15, 2017 (the “Holly 9.875% Senior Notes”). A portion of the $187.9 million in net proceeds received was used for post-closing payments for inventories of crude oil and refined products acquired from Sunoco following the closing of the Tulsa Refinery west facility purchase on June 1, 2009. In October 2009, we issued an additional $100 million aggregate principal amount as an add-on offering to the Holly 9.875% Senior Notes that was used to fund the cash portion of our acquisition of the Tulsa Refinery east facility.

The Holly 9.875% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our 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 9.875% 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 9.875% Senior Notes.

HEP Senior Notes Due 2018 and 2015

In March 2010, HEP issued $150 million in aggregate principal amount of 8.25% senior notes maturing March 15, 2018 (the “HEP 8.25% Senior Notes”). A portion of the $147.5 million in net proceeds received was used to fund HEP’s $93 million purchase of certain storage assets at our Tulsa Refinery east facility and Navajo Refinery Lovington facility on March 31, 2010. Additionally, HEP used a portion to repay $42 million in outstanding HEP Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.

HEP also has $185 million in aggregate principal amount of 6.25% senior notes maturing March 1, 2015 (the “HEP 6.25% Senior Notes”) that are registered with the SEC. The HEP 6.25% Senior Notes and HEP 8.25% Senior Notes (collectively, 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. However, 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. During the first quarter of 2010, our previous agreement to indemnify HEP’s controlling partner to the extent it makes any payment in satisfaction of debt service due on up to $35 million of the principal amount of the HEP 6.25% Senior Notes was terminated.

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

Holly Financing Obligation

In October 2009, we sold approximately 400,000 barrels of crude oil tankage at our Tulsa Refinery west facility as well as certain crude oil pipeline receiving facilities to an affiliate of Plains All American Pipeline, L.P. (“Plains”) for $40 million in cash. In connection with this transaction, we entered into a 15-year lease agreement with Plains, whereby we agreed to pay a fixed monthly fee for the exclusive use of this tankage as well as a fee for volumes received at the receiving facilities purchased by Plains. Additionally, we have a margin sharing agreement with Plains under which we will equally share contango profits with Plains for crude oil purchased by them and delivered to our Tulsa Refinery west facility for storage. Due to our continuing involvement in these assets, this transaction has been accounted for as a financing obligation. As a result, we retained these assets on our books and recorded a liability representing the $40 million in proceeds received.

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HEP Equity Offerings

In November 2009, HEP closed on a public offering of 2,185,000 of its common units priced at $35.78 per unit. Aggregate net proceeds of $74.9 million were used to fund the cash portion of HEP’s December 1, 2009 asset acquisitions, to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.

Additionally in May 2009, HEP closed a public offering of 2,192,400 of its common units priced at $27.80 per unit. Net proceeds of $58.4 million were used to repay outstanding borrowings under the HEP Credit Agreement and for general partnership purposes.

Liquidity

We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our credit facilities will provide sufficient resources to fund currently planned capital projects, including our planned integration of the Tulsa Refinery facilities, 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.

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 September 30, 2010, we had cash and cash equivalents of $271.9 million and short-term investments in marketable securities of $1.2 million.

Cash and cash equivalents increased by $147.3 million during the nine months ended September 30, 2010. Net cash provided by operating activities and financing activities of $236 million and $39.3 million, respectively, exceeded cash used for investing activities of $127.9 million. Working capital decreased by $53.1 million during the nine months ended September 30, 2010, due principally to the reclassification of HEP’s $157 million in credit agreement borrowings as current liabilities. Excluding HEP’s $157 million credit agreement borrowings, working capital increased by $103.9 million.

Cash Flows — Operating Activities

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Net cash flows provided by operating activities were $236 million for the nine months ended September 30, 2010 compared to $179.7 million for the nine months ended September 30, 2009, an increase of $56.3 million. Net income for the nine months ended September 30, 2010 was $108.8 million, an increase of $33.2 million compared to net income of $75.6 million for the nine months ended September 30, 2009. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense, interest rate swap adjustments and noncontrolling interest in earnings of Rio Grande resulted in an increase to operating cash flows of $100.5 million for the nine months ended September 30, 2010 compared to $103.8 million for the same period in 2009. Additionally, SLC Pipeline earnings, net of distributions increased operating cash flows by $0.4 million for the nine months ended September 30, 2010 compared to a $1.3 million decrease for the nine months ended September 30, 2009. Changes in working capital items increased cash flows by $34.2 million for the nine months ended September 30, 2010 compared to $22.3 million for the nine months ended September 30, 2009. Additionally, for the nine months ended September 30, 2010, turnaround expenditures decreased to $11.5 million from $33.1 million in 2009 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

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Net cash flows used for investing activities were $127.9 million for the nine months ended September 30, 2010 compared to $374.9 million for the nine months ended September 30, 2009, a decrease of $247 million. Cash expenditures for properties, plants and equipment for the first nine months of 2010 decreased to $127.9 million from $246 million for the same period in 2009. These include HEP capital expenditures of $8.1 million and $27.5 million for the nine months ended September 30, 2010 and 2009, respectively. Capital expenditures were significantly lower in the nine months ending September 30, 2010 due to a higher level of capital project initiatives in 2009 including refinery expansion projects. During the nine months ended September 30, 2009, we acquired the Tulsa Refinery west facility from Sunoco for $157.8 million, invested $165.9 million in marketable securities and received proceeds of $220.3 million from the sale or maturity of marketable securities. Additionally, HEP purchased a 25% joint venture interest in the SLC Pipeline for $25.5 million.

Planned Capital Expenditures

Holly Corporation

Each year our Board of Directors approves in our annual capital budget 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 approved capital budget for 2010 is $159.6 million. Additionally, capital costs of $38.8 million have been approved for refinery turnarounds and tank work. Excluding capital reimbursement required by the Sinclair Tulsa purchase agreement, we expect to spend approximately $165 million in capital costs in 2010, including capital projects approved in prior years. Our capital spending for 2010 is comprised of $48.5 million for projects at the Navajo Refinery, $10.8 million for projects at the Woods Cross Refinery, $46.7 million for projects at the Tulsa Refinery, $55 million for our portion of the Salt Lake City, Utah to Las Vegas, Nevada pipeline project (the “UNEV Pipeline”), $1.5 million for asphalt plant projects and $2.5 million for marketing-related and miscellaneous projects. The following summarizes our key capital projects.

We are proceeding with the integration project of our Tulsa Refinery west and east facilities. Upon completion, the Tulsa Refinery will have an integrated crude processing rate of 125,000 BPSD. The integration project involves the installation of interconnect pipelines that will permit us to transfer various intermediate streams between the two facilities. We have also signed a 10-year agreement with a third party for the use of an additional line for the transfer of gasoline blend stocks which is currently in service. These interconnect lines will allow us to eliminate the sale of gas oil at a discount to WTI under our 5-year gas oil off take agreement with a third party, optimize gasoline blending, increase our utilization of better process technology, improve yields and reduce operating costs. HEP is currently constructing five additional interconnect pipelines and we are currently finalizing terms for a long-term agreement with HEP to transfer intermediate products via these pipelines that will commence upon completion of the project. Also, as part of the integration, we are planning to expand the diesel hydrotreater unit at the east facility to permit the processing of all high sulfur diesel produced to ULSD. This expansion is expected to cost approximately $20 million and will use the reactor that we acquired as part of the Tulsa Refinery west facility acquisition. We are currently planning to complete the integration projects by the end of the first quarter of 2011.

The combined Tulsa facilities also will be required to comply with new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations in order to meet new federal benzene reduction requirements for gasoline. We have elected to largely use existing equipment at the Tulsa Refinery east facility to split reformate from reformers at both Tulsa west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of $28.5 million. We will be required to buy benzene credits to get the gasoline pool below 0.62% by volume until this project is complete, as required by law, beginning in 2011. There is an additional requirement to meet 1.3% benzene levels on every gallon of gasoline beginning in July 2012 and we expect to complete this project well before then.

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Our consent decree with the EPA requires recovery of sulfur from the refinery fuel gas system and the shutdown or replacement of two low pressure boilers at the Tulsa Refinery west facility by the end of 2013. We are evaluating the best solution to the low pressure boiler issue. In addition to the consent decree requirements, flare gas recovery and coker blowdown modifications are required to comply with new flare regulations. We have previously estimated a cost of $20 million to meet these requirements but are currently evaluating a larger project in the $45 million range which would meet these requirements as well as increase our ability to run additional lower priced sour crude types at the Tulsa Refinery east facility. A decision on this matter has not yet been made.

We completed phase II of our major capital projects at the Navajo Refinery in the second quarter of 2010. These improvements provide the capability to process up to 40,000 BPSD of heavy type crudes. Phase II involved the installation of a new 18,000 BPSD solvent deasphalter and the revamp of our Artesia crude and vacuum units.

Also, we expect to complete our asphalt tankage project at the Navajo Refinery and at the Holly Asphalt facility in Artesia, New Mexico in November 2010 that will enhance asphalt economics by permitting the storage of asphalt during the winter months when asphalt prices are generally lower. These asphalt tank additions and the approved upgrade of our rail loading facilities at the Artesia refinery are expected to cost $21 million.

The Navajo Refinery currently plans to comply with the new MSAT2 regulations by the fractionation of raw naphtha with existing equipment to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will use credits to be generated at the Woods Cross and Tulsa Refineries in order to reduce benzene down to the required 0.62%. Due to our acquisition of the Tulsa Refinery facilities from Sunoco and Sinclair, our Navajo Refinery has until the end of 2011 to comply with the MSAT2 regulations because we no longer qualify for the small refiner’s exemption. We have 30 months to comply starting after we became a large refiner in mid-2009.

Our Woods Cross refinery is required to install a wet gas scrubber on its FCC unit by the end of 2012. We estimate the total cost to be $12 million. The MSAT2 solution for Woods Cross involves installing a new reformate splitter and a benzene saturation unit at an estimated cost of $18 million. Like our Navajo Refinery, our Woods Cross Refinery has until the end of 2011 to comply with the MSAT2 regulations.

Under a definitive agreement with Sinclair, we are jointly building the UNEV Pipeline, 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 with Sinclair, our joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD (based on gasoline equivalents), with the capacity for further expansion to 120,000 BPD. The current total cost of the pipeline project including terminals is expected to be approximately $300 million, with our share of the cost totaling $225 million. This includes a project scope change that includes the construction of ethanol blending and storage facilities at the Cedar City terminal. We have commenced the final construction phase of the pipeline and expect the pipeline to be mechanically complete in the second quarter of 2011.

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.

Regulatory compliance items at our refineries 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.

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HEP

Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in their current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2010 HEP capital budget is comprised of $4.8 million for maintenance capital expenditures and $6 million for expansion capital expenditures.

As described above, HEP is currently constructing five interconnecting pipelines between our Tulsa east and west refining facilities. The project is expected to cost approximately $25 million with completion in the first quarter of 2011. We are currently finalizing terms for a long-term agreement with HEP to transfer intermediate products via these pipelines that will commence upon completion of the project.

Cash Flows — Financing Activities

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Net cash flows provided by financing activities were $39.3 million for the nine months ended September 30, 2010 compared to $253 million for the nine months ended September 30, 2009, a decrease of $213.7 million. During the nine months ended September 30, 2010, we received and repaid $310 million in advances under the Holly Credit Agreement, paid $0.8 million under our financing obligation to Plains, purchased $1.3 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $23.9 million in dividends, received a $9.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.3 million excess tax expense on our equity based compensation. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $52 million and repaid $101 million under the HEP Credit Agreement, paid distributions of $36.1 million to noncontrolling interests and purchased $2.3 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the Holly Credit Agreement. During the nine months ended September 30, 2009, we received $187.9 million in net proceeds upon the issuance of the Holly Senior Notes, received and repaid $94 million in advances under the Holly Credit Agreement, paid $22.6 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 $13.7 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 $197 million and repaid $152 million in advances under the HEP Credit Agreement, paid distributions of $23.4 million to noncontrolling interest holders and purchased $0.6 million in HEP common units for recipients of its restricted unit grants. Additionally, we paid $6.4 million in deferred financing costs during the nine months ended September 30, 2009. The deferred financing costs relate to the 9.875% Holly Senior Notes issued in June 2009.

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Contractual Obligations and Commitments

Holly Corporation

There were no significant changes to our contractual obligations during the nine months ended September 30, 2010.

HEP

During the nine months ended September 30, 2010, HEP repaid net advances of $49 million resulting in $157 million of outstanding principal under the HEP Credit Agreement at September 30, 2010.

In March 2010, HEP issued $150 million aggregate principal amount of HEP 8.25% Senior Notes maturing March 15, 2018.

There were no other significant changes to HEP’s long-term contractual obligations during this period.

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, 2009. 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 2010.

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.

New Accounting Pronouncements

Variable Interest Entities

On January 1, 2010, new accounting standards became effective that replace the previous quantitative-based risk and rewards calculation provided under GAAP with a qualitative approach in determining whether an entity is the primary beneficiary of a variable interest entity (“VIE”). Additionally, these standards require an entity to assess on an ongoing basis whether it is the primary beneficiary of a VIE and enhance disclosure requirements with respect to an entity’s involvement in a VIE. See “Note 3 — Holly Energy Partners” to the Consolidated Financial Statements under Item 1 for additional information on our involvement with HEP, a consolidated VIE.

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.

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Commodity Price Risk Management

During the third quarter of 2010, we entered into two types of hedging transactions.

We entered into multiple gasoline price swap contracts relating to forecasted sales transactions of unleaded 87 gasoline produced at our Tulsa Refinery facilities in order to protect margins on winter grade gasoline. Winter grade gasoline specifications allow for the blending of butane as an additive. Since the cost of butane is subject to price risk (fluctuating prices), our refined product margins are exposed to the adverse affects of higher butane costs during winter months when demand for butane is generally higher and lower gasoline sales prices when demand for finished gasoline products is generally lower. To mitigate the effects of higher butane costs during winter months, we regularly purchase volumes of butane at more favorable prices during the summer season. Furthermore, in order to maintain a favorable spread between the cost of this butane and the ultimate sales price we receive on quantities of produced winter grade gasoline, we have entered into gasoline price swaps that effectively fix the sales price on forecasted sales totaling 135,000 barrels of unleaded 87 gasoline at a weighted average price of $81.61 per barrel. These barrels will be ratably sold between September and December 2010, matching the terms of the swap contracts maturing between September and December 2010.

Additionally, we entered into natural gas price swap contracts relating to forecasted purchases of natural gas to be used in production at our refining facilities during the 2010-2011 winter season. Natural gas prices are subject to price risk (fluctuating prices), therefore, the profitability of our refinery operations is exposed to the adverse affects of higher natural gas prices during winter months when demand for natural gas is generally higher. In order to mitigate the effects of higher natural gas prices, we have entered into natural gas price swaps that effectively fix our purchase price on forecasted natural gas purchases aggregating 2,500,000 million British thermal units (“MMBTU”) (approximately 30% of our refineries’ projected winter season consumption) to be ratably purchased between November 2010 and March 2011 at a weighted-average cost of $4.20 per MMBTU.

We have designated these commodity price swaps as cash flow hedges. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that our gasoline price swaps are effective in offsetting the variability in sales prices to be received on forecasted sales of finished gasoline inventory resulting from changes in gasoline reference prices. We have also determined that our natural gas price swaps are effective in offsetting the variability in prices to be paid on forecasted natural gas purchases resulting from changes in natural gas reference prices. Under hedge accounting, we adjust our cash flow hedges on a quarterly basis to fair value with offsetting fair value adjustments to accumulated other comprehensive income. Hedge effectiveness is measured by comparing the combined effects of amounts expected to be received or paid under these price swap contracts and prices to be received and paid under the forecasted transactions as discussed above against prestablished fixed prices. Any ineffectiveness is reclassified from accumulated other comprehensive income to cost of products sold. As of September 30, 2010, we have had no ineffectiveness on these cash flow hedges.

Interest Rate Risk Management

HEP uses interest rate swaps to manage its exposure to interest rate risk.

As of September 30, 2010, HEP has an interest rate swap that hedges its exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million HEP Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of September 30, 2010. The maturity date of this swap contract is February 28, 2013.

HEP 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 this interest rate swap is effective in offsetting the variability in interest payments on the $155 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

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or received on the variable leg of the swap against the expected future interest payments on the $155 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. As of September 30, 2010, HEP had no ineffectiveness on its cash flow hedge.

The following table presents balance sheet locations and related fair values of outstanding derivative instruments.

	Balance Sheet			Location of
Derivative Instruments	Location	Fair Value		Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
September 30, 2010
Derivatives designated as cash flow hedging instruments:
Variable-to-fixed commodity price swap contracts (forecasted volumes of gasoline sales)	Accrued liabilities	$	406	Accumulated other comprehensive loss	$	406
Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)	Accrued liabilities		738	Accumulated other comprehensive loss		738
		$	1,144		$	1,144
Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	11,825	Accumulated other comprehensive loss	$	11,825
December 31, 2009
Derivative designated as cash flow hedging instrument:
Variable-to-fixed interest rate swap contract ($171 million LIBOR based debt interest payments)	Other long-term liabilities	$	9,141	Accumulated other comprehensive loss	$	9,141
Derivatives not designated as hedging instruments:
Fixed-to-variable interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other assets	$	2,294	Long-term debt	$	1,791	(1)
				Equity		503	(2)
		$	2,294		$	2,294
Variable-to-fixed interest rate swap contract ($60 million of HEP 6.25% Senior Notes)	Other long-term liabilities	$	2,555	Equity	$	2,555	(2)

(1)	Represents unamortized balance of dedesignated hedge premium.
(2)	Represents prior year charges to interest expense.

Publicly available information is reviewed on the counterparties in order to review and monitor their financial stability and assess their ongoing ability to honor their commitments under the swap contracts. These counterparties are large financial institutions. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments.

The market risk inherent in our fixed-rate debt and positions is the potential change arising from increases or decreases in interest rates as discussed below.

At September 30, 2010, outstanding principal under the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes was $300 million, $185 million and $150 million, respectively. For these fixed rate notes, changes in interest rates will generally affect fair value of the debt, but not our earnings or cash flows. At September 30, 2010, the estimated fair values of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were $324 million, $183.2 million and $156.8 million, respectively. We estimate that a hypothetical 10% change in the yield-to-maturity rates applicable to these notes would result in a fair value change to the notes of approximately $13 million, $5 million and $6 million, respectively.

For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At September 30, 2010, borrowings outstanding under the HEP Credit Agreement were $157 million. By means of its cash flow hedge, HEP has effectively converted the variable rate on $155 million of outstanding principal to a fixed rate of 5.49%. At September 30, 2010, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of nine months or less at the time of purchase and hence the interest rate market risk implicit in these cash investments is low. Due to the short-term nature of our

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cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

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 GAAP; 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 from continuing operations.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands)
Income from continuing operations	$	59,390		$	30,177		$	108,802		$	72,189
Subtract noncontrolling interest in income from continuing operations		(8,213	)		(6,964	)		(19,557	)		(13,175	)
Add income tax provision		31,494			13,497			54,476			34,668
Add interest expense		17,368			12,407			56,113			25,849
Subtract interest income		(64	)		(231	)		(758	)		(2,561	)
Add depreciation and amortization		29,138			24,026			85,719			69,367
EBITDA from continuing operations	$	129,113		$	72,912		$	284,795		$	186,337

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.

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Refinery Gross Margin

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Average per produced barrel:
Navajo Refinery
Net sales	$	87.60	$	78.15	$	88.98	$	69.21
Less cost of products		79.39		70.88		81.44		60.25
Refinery gross margin	$	8.21	$	7.27	$	7.54	$	8.96
Woods Cross Refinery
Net sales	$	94.86	$	80.87	$	93.71	$	66.87
Less cost of products		73.08		65.68		74.02		55.22
Refinery gross margin	$	21.78	$	15.19	$	19.69	$	11.65
Tulsa Refinery
Net sales	$	89.22	$	76.80	$	88.91	$	76.65
Less cost of products		79.80		70.10		81.26		70.80
Refinery gross margin	$	9.42	$	6.70	$	7.65	$	5.85
Consolidated
Net sales	$	89.25	$	78.11	$	89.53	$	70.16
Less cost of products		78.84		69.84		80.43		61.26
Refinery gross margin	$	10.41	$	8.27	$	9.10	$	8.90

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Average per produced barrel:
Navajo Refinery
Refinery gross margin	$	8.21	$	7.27	$	7.54	$	8.96
Less refinery operating expenses		5.25		4.37		5.01		4.88
Net operating margin	$	2.96	$	2.90	$	2.53	$	4.08
Woods Cross Refinery
Refinery gross margin	$	21.78	$	15.19	$	19.69	$	11.65
Less refinery operating expenses		6.11		6.44		5.86		6.45
Net operating margin	$	15.67	$	8.75	$	13.83	$	5.20
Tulsa Refinery
Refinery gross margin	$	9.42	$	6.70	$	7.65	$	5.85
Less refinery operating expenses		4.80		4.64		5.10		4.76
Net operating margin	$	4.62	$	2.06	$	2.55	$	1.09
Consolidated
Refinery gross margin	$	10.41	$	8.27	$	9.10	$	8.90
Less refinery operating expenses		5.14		4.77		5.16		5.17
Net operating margin	$	5.27	$	3.50	$	3.94	$	3.73

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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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Dollars in thousands, except per barrel amounts)
Navajo Refinery
Average sales price per produced barrel sold	$	87.60		$	78.15		$	88.98		$	69.21
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	742,897		$	675,812		$	2,203,971		$	1,589,051
Woods Cross Refinery
Average sales price per produced barrel sold	$	94.86		$	80.87		$	93.71		$	66.87
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	240,345		$	201,610		$	722,971		$	494,012
Tulsa Refinery
Average sales price per produced barrel sold	$	89.22		$	76.80		$	88.91		$	76.65
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	927,859		$	428,147		$	2,620,209		$	545,673
Sum of refined product sales from produced products sold from our three refineries (1)	$	1,911,101		$	1,305,569		$	5,547,151		$	2,628,736
Add refined product sales from purchased products and rounding (2)		24,586			21,539			93,093			83,579
Total refined product sales		1,935,687			1,327,108			5,640,244			2,712,315
Add direct sales of excess crude oil (3)		106,364			98,540			355,381			320,416
Add other refining segment revenue (4)		39,658			50,656			90,618			103,286
Total refining segment revenue		2,081,709			1,476,304			6,086,243			3,136,017
Add HEP segment sales and other revenues		46,558			40,805			132,730			108,136
Add corporate and other revenues		100			229			317			423
Subtract consolidations and eliminations		(37,379	)		(28,847	)		(108,152	)		(72,277	)
Sales and other revenues	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299

(1)	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.
(2)	We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
(3)	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.
(4)	Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales.

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in thousands, except per barrel amounts)
Average sales price per produced barrel sold	$	89.25	$	78.11	$	89.53	$	70.16
Times sales of produced refined products sold (BPD)		232,760		181,690		226,940		137,240
Times number of days in period		92		92		273		273
Refined product sales from produced products sold	$	1,911,101	$	1,305,569	$	5,547,151	$	2,628,736

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Dollars in thousands, except per barrel amounts)
Navajo Refinery
Average cost of products per produced barrel sold	$	79.39		$	70.88		$	81.44		$	60.25
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102
Times number of days in period		92			92			273			273
Cost of products for produced products sold	$	673,272		$	612,944		$	2,017,211		$	1,383,331
Woods Cross Refinery
Average cost of products per produced barrel sold	$	73.08		$	65.68		$	74.02		$	55.22
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061
Times number of days in period		92			92			273			273
Cost of products for produced products sold	$	185,161		$	163,741		$	571,063		$	407,946
Tulsa Refinery
Average cost of products per produced barrel sold	$	79.80		$	70.10		$	81.26		$	70.80
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077
Times number of days in period		92			92			273			273
Cost of products for produced products sold	$	829,894		$	390,796		$	2,394,761		$	504,027
Sum of cost of products for produced products sold from our three refineries (1)	$	1,688,327		$	1,167,481		$	4,983,035		$	2,295,304
Add refined product costs from purchased products sold and rounding (2)		24,594			22,295			93,898			88,271
Total refined cost of products sold		1,712,921			1,189,776			5,076,933			2,383,575
Add crude oil cost of direct sales of excess crude oil (3)		105,091			97,400			351,643			317,954
Add other refining segment cost of products sold (4)		25,555			36,282			56,186			56,685
Total refining segment cost of products sold		1,843,567			1,323,458			5,484,762			2,758,214
Subtract consolidations and eliminations		(36,523	)		(28,020	)		(105,642	)		(71,196	)
Costs of products sold (exclusive of depreciation and amortization)	$	1,807,044		$	1,295,438		$	5,379,120		$	2,687,018

(1)	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.
(2)	We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
(3)	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.
(4)	Other refining segment cost of products sold includes the cost of products for Holly Asphalt and costs attributable to feedstock and sulfur credit sales.

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in thousands, except per barrel amounts)
Average cost of products per produced barrel sold	$	78.84	$	69.84	$	80.43	$	61.26
Times sales of produced refined products sold (BPD)		232,760		181,690		226,940		137,240
Times number of days in period		92		92		273		273
Cost of products for produced products sold	$	1,688,327	$	1,167,481	$	4,983,035	$	2,295,304

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Dollars in thousands, except per barrel amounts)
Navajo Refinery
Average refinery operating expenses per produced barrel sold	$	5.25		$	4.37		$	5.01		$	4.88
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102
Times number of days in period		92			92			273			273
Refinery operating expenses for produced products sold	$	44,523		$	37,790		$	124,094		$	112,044
Woods Cross Refinery
Average refinery operating expenses per produced barrel sold	$	6.11		$	6.44		$	5.86		$	6.45
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061
Times number of days in period		92			92			273			273
Refinery operating expenses for produced products sold	$	15,481		$	16,055		$	45,210		$	47,650
Tulsa Refinery
Average refinery operating expenses per produced barrel sold	$	4.80		$	4.64		$	5.10		$	4.76
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077
Times number of days in period		92			92			273			273
Refinery operating expenses for produced products sold	$	49,918		$	25,867		$	150,299		$	33,887
Sum of refinery operating expenses per produced products sold from our three refineries (1)	$	109,922		$	79,712		$	319,603		$	193,581
Add other refining segment operating expenses and rounding (2)		6,835			6,023			19,199			16,209
Total refining segment operating expenses		116,757			85,735			338,802			209,790
Add HEP segment operating expenses		13,632			11,103			40,187			32,076
Add corporate and other costs		6			7			24			34
Subtract consolidations and eliminations		(132	)		(128	)		(375	)		(382	)
Operating expenses (exclusive of depreciation and amortization)	$	130,263		$	96,717		$	378,638		$	241,518

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in thousands, except per barrel amounts)
Average refinery operating expenses per produced barrel sold	$	5.14	$	4.77	$	5.16	$	5.17
Times sales of produced refined products sold (BPD)		232,760		181,690		226,940		137,240
Times number of days in period		92		92		273		273
Refinery operating expenses for produced products sold	$	109,922	$	79,712	$	319,603	$	193,581

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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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Dollars in thousands, except per barrel amounts)
Navajo Refinery
Net operating margin per barrel	$	2.96		$	2.90		$	2.53		$	4.08
Add average refinery operating expenses per produced barrel		5.25			4.37			5.01			4.88
Refinery gross margin per barrel		8.21			7.27			7.54			8.96
Add average cost of products per produced barrel sold		79.39			70.88			81.44			60.25
Average sales price per produced barrel sold	$	87.60		$	78.15		$	88.98		$	69.21
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	742,897		$	675,812		$	2,203,971		$	1,589,051
Woods Cross Refinery
Net operating margin per barrel	$	15.67		$	8.75		$	13.83		$	5.20
Add average refinery operating expenses per produced barrel		6.11			6.44			5.86			6.45
Refinery gross margin per barrel		21.78			15.19			19.69			11.65
Add average cost of products per produced barrel sold		73.08			65.68			74.02			55.22
Average sales price per produced barrel sold	$	94.86		$	80.87		$	93.71		$	66.87
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	240,345		$	201,610		$	722,971		$	494,012
Tulsa Refinery
Net operating margin per barrel	$	4.62		$	2.06		$	2.55		$	1.09
Add average refinery operating expenses per produced barrel		4.80			4.64			5.10			4.76
Refinery gross margin per barrel		9.42			6.70			7.65			5.85
Add average cost of products per produced barrel sold		79.80			70.10			81.26			70.80
Average sales price per produced barrel sold	$	89.22		$	76.80		$	88.91		$	76.65
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077
Times number of days in period		92			92			273			273
Refined product sales from produced products sold	$	927,859		$	428,147		$	2,620,209		$	545,673
Sum of refined product sales from produced products sold from our three refineries (1)	$	1,911,101		$	1,305,569		$	5,547,151		$	2,628,736
Add refined product sales from purchased products and rounding (2)		24,586			21,539			93,093			83,579
Total refined product sales		1,935,687			1,327,108			5,640,244			2,712,315
Add direct sales of excess crude oil (3)		106,364			98,540			355,381			320,416
Add other refining segment revenue (4)		39,658			50,656			90,618			103,286
Total refining segment revenue		2,081,709			1,476,304			6,086,243			3,136,017
Add HEP segment sales and other revenues		46,558			40,805			132,730			108,136
Add corporate and other revenues		100			229			317			423
Subtract consolidations and eliminations		(37,379	)		(28,847	)		(108,152	)		(72,277	)
Sales and other revenues	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299

(1)	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.
(2)	We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.
(3)	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.
(4)	Other refining segment revenue includes the revenues associated with Holly Asphalt and revenue derived from feedstock and sulfur credit sales.

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in thousands, except per barrel amounts)
Net operating margin per barrel	$	5.27	$	3.50	$	3.94	$	3.73
Add average refinery operating expenses per produced barrel		5.14		4.77		5.16		5.17
Refinery gross margin per barrel		10.41		8.27		9.10		8.90
Add average cost of products per produced barrel sold		78.84		69.84		80.43		61.26
Average sales price per produced barrel sold	$	89.25	$	78.11	$	89.53	$	70.16
Times sales of produced refined products sold (BPD)		232,760		181,690		226,940		137,240
Times number of days in period		92		92		273		273
Refined product sales from produced products sold	$	1,911,101	$	1,305,569	$	5,547,151	$	2,628,736

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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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2010.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Commitment and Contingency Reserves

When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

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 case was remanded to FERC and consolidated with other cases that together addressed SFPP’s rates for the period from January 1992 through May 2006. In 2003 we received an initial payment of $15.3 million from SFPP as reparations for the period from 1992 through July 2000. On April 16, 2010, a settlement among us, SFPP, and other shippers was filed with FERC for its approval. FERC approved the settlement on May 28, 2010. Pursuant to the settlement, we received an additional settlement payment of $8.6 million. This settlement finally resolves the amount of additional payments SFPP owes us for the period January 1992 through May 2006.

b. Other Settlements

We and other shippers also engaged in settlement discussions with SFPP relating to East Line service in the FERC proceedings that address periods after May 2006. 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 $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 FERC approved the settlement on January 29, 2009. The settlement reduced SFPP’s current rates and required SFPP to make additional payments to us of $2.9 million, which were received on May 18, 2009.

c. The Latest Rate Proceeding

On June 2, 2009, SFPP notified us that it would terminate the October 22, 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 and several other shippers filed protests at the FERC, challenging the rate increase and asking the FERC to suspend the effectiveness of the increased rates. On August 31, 2009, the FERC issued an order suspending the effective date of the rate increase until January 1, 2010, on which date the rate increase was placed into effect subject to refund, and setting the rate increase for a full evidentiary hearing to be held in 2010. SFPP subsequently reduced its rates for the East Line service, effective September 1, 2010. The rates placed in effect on January 1, 2010, and the lower rates put into effect on September 1, 2010, remain subject to refund subject to the outcome of the evidentiary hearing. We are not in a position to predict the ultimate outcome of the rate proceeding.

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Cut Bank Hill Environmental Claims

Prior to the sale by Holly Corporation of the Montana Refining Company (“MRC”) 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 MRC and other companies to undertake cleanup actions; (2) a U.S. Coast Guard claim against MRC and other companies for response costs of $0.3 million in connection with its cleanup efforts at the Cut Bank Hill site; and (3) a unilateral order by the Montana Department of Environmental Quality (“MDEQ”) directing MRC and other companies to complete a remedial investigation and a request by the MDEQ that MRC and other companies pay $0.2 million to reimburse the State’s costs for remedial actions. MRC has denied responsibility for the requested EPA and the MDEQ cleanup actions and the MDEQ and Coast Guard response costs.

Navajo Tank Fire

On March 2, 2010, a tank caught fire while under construction. At the time of the incident, four individuals were working on top of the tank. These individuals were all employees of a third-party contractor who was placing insulation on the tank. Two individuals sustained injuries and two individuals died as a result of the incident. Four lawsuits were filed on behalf of the two survivors and on behalf of the estate of the two deceased workers in state court in Dallas County, Texas (two lawsuits) and state court in Eddy County, New Mexico (two lawsuits). Two of the cases are set for trial in April and May of 2011, respectively. At the date of this report, it is not possible to predict the likely outcome of this litigation. This matter is being reported due to the serious nature of the injuries. Because of our insurance coverage, the total cost to the Company for these cases is not expected to be material.

New Mexico OHSB Inspection – Navajo Tank Fire

On March 3, 2010, the New Mexico Occupational Health and Safety Bureau (“OHSB”), the New Mexico regulatory agency responsible for enforcing certain state occupational health and safety regulations, which are identical to Federal Occupational Safety and Health Administration (“OSHA”) regulations, commenced an inspection in relation to the tank fire that took place on March 2, 2010 at the Navajo facility in Artesia, New Mexico. On August 31, 2010, OHSB issued two citations to Navajo Refining Company, LLC (“Navajo”), alleging 10 willful violations and 1 serious violation of various construction safety standards. OHSB proposed penalties in the amount of $0.7 million. Navajo filed a notice of contest, challenging the citations. An informal administrative review of the citations is anticipated to take place in November 2010. Following the informal review, Navajo will have the right to challenge the citations before the New Mexico Occupational Health and Safety Review Commission (“OSHRC”), and have the right to take discovery.

OSHA Inspections – Tulsa Refinery

In June 2007, OSHA announced a national emphasis program (“NEP”) for inspecting approximately 80 refineries within its jurisdiction. As part of the NEP, OSHA conducted an inspection of Sinclair Tulsa Refining Company’s (“Sinclair Tulsa”) refinery in Tulsa, Oklahoma (our Tulsa Refinery east facility) from February 4, 2009 through August 3, 2009. On August 4, 2009, OSHA issued two citations to Sinclair Tulsa, alleging 51 serious violations and 1 willful violation of various safety standards including the Process Safety Management Standard (“PSM”) and the General Duty Clause. OSHA proposed penalties totaling $0.2 million. Sinclair filed a notice of contest, challenging the citations.

Our subsidiary, Holly Refining & Marketing – Tulsa LLC (“HRM-Tulsa”), entered into an Asset Sale & Purchase Agreement (the “Agreement”) with Sinclair Tulsa dated October 19, 2009 to acquire the Tulsa Refinery east facility, and the sale closed on December 1, 2009. HRM-Tulsa intervened in the case against Sinclair Tulsa pending before the OSHRC shortly after the sale closed. Under the terms of the Agreement, Sinclair retains responsibility for defending the OSHA citations and paying any penalties, and HRM-Tulsa has the discretion to select the means and methods of improving the PSM program. HRM-Tulsa has evaluated the feasibility of various PSM program improvements and developed a plan to implement a number of safety enhancements at the Tulsa Refinery east facility. HRM-Tulsa management presented its safety improvement plan to OSHA and

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OSHA approved the plan. HRM-Tulsa and OSHA negotiated a settlement agreement which memorializes OSHA’s approval of the safety improvement plan. The settlement agreement between HRM-Tulsa and OSHA was filed with the OSHRC on August 11, 2010. On August 23, 2010, the OSHRC entered an order approving both the settlement agreement between Sinclair Tulsa and OSHA and the agreement between HRM-Tulsa and OSHA.

OSHA conducted an inspection of our Tulsa Refinery west facility from January 20, 2010 through June 9, 2010. On July 12, 2010, OSHA issued a citation, alleging 10 serious violations of various safety standards, including the Process Safety Management (“PSM”) standard. OSHA proposed penalties totaling $57,150. HRM–Tulsa filed a notice of contest, and challenged each citation item. The matter has been assigned to Judge Patrick B. Augustine. A pretrial conference, in which the discovery schedule will be established, will take place on November 3, 2010.

OSHA began the NEP inspection of our Tulsa Refinery west facility on September 14, 2010. The inspection is ongoing.

Discharge Permit Appeal – Tulsa Refinery West Facility

Our subsidiary, HRM Tulsa is party to parallel Oklahoma administrative and state district court proceedings involving a challenge to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from our Tulsa Refinery west facility. Pursuant to a settlement agreement between HRM Tulsa and ODEQ, both proceedings have been stayed to allow ODEQ to issue a revised permit that modifies the existing permit’s requirements for toxicity testing and for managing storm flows. The parties are now in discussions regarding the appropriate changes in the permit language to accomplish these modifications. Once agreed-upon revisions are made and become effective, both proceedings will be dismissed. Any changes to refinery processes that result from the permit revisions will be subject to regulatory review and approval. Accordingly, it is not possible to estimate the costs of compliance with the new permit provisions at this time.

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 currently in the third year of this ongoing audit that covers the period 1981–2004. It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states.

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

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.
101**	The following financial information from Holly Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Comprehensive Income, and (v) Notes to the Consolidated Financial Statements (tagged as blocks of text).

+	Filed herewith.
++	Furnished herewith.
**	Furnished electronically 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: November 5, 2010	/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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Exhibit Index

Exhibit Number	Description
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.
101**	The following financial information from Holly Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Comprehensive Income, and (v) Notes to the Consolidated Financial Statements (tagged as blocks of text).

+	Filed herewith.
++	Furnished herewith.
**	Furnished electronically herewith.

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EX-31.1

Exhibit 31.1

CERTIFICATION

     I, Matthew P. Clifton, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Holly Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2010	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Bruce R. Shaw, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Holly Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2010	/s/ Bruce R. Shaw
	Bruce R. Shaw
	Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE
OFFICER OF HOLLY CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

     In connection with the accompanying report on Form 10-Q for the quarterly period ended September 30, 2010 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Matthew P. Clifton, Chief Executive Officer of Holly Corporation (the “Company”) hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 5, 2010	/s/ Matthew P. Clifton
	Matthew P. Clifton
	Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL
OFFICER OF HOLLY CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

     In connection with the accompanying report on Form 10-Q for the quarterly period ended September 30, 2010 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bruce R. Shaw, Chief Financial Officer of Holly Corporation (the “Company”) hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 5, 2010	/s/ Bruce R. Shaw
	Bruce R. Shaw
	Senior Vice President and Chief Financial Officer