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~~March 31, 2011


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~~


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

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

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

Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

Yeso Noþ

~~53,210,016~~53,312,273 shares of Common Stock, par value $.01 per share, were outstanding on ~~October~~April 29, ~~2010.~~2011.

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~~The words “we,” “our,” “ours” and “us” generally include ~~HEP~~Holly Energy Partners, L.P. (“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;

	•		risks and uncertainties with respect to our proposed “merger of equals” with Frontier Oil Corporation, including our ability to complete the merger in the anticipated timeframe or at all, the diversion of management in connection with the merger and our ability to realize fully or at all the anticipated benefits of the merger; 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~~2010 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.

- 3 -

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~~a 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 the vapor slightly above atmospheric pressure ~~the vapor~~turning it 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.

- 4 -

“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.

“MMBTU” means one million British thermal units.

“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~~oils 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.

“RFS2” or advanced renewable fuel standard is a regulatory mandate required by the Energy Independence and Security Act of 2007 that requires 36 billion gallons of renewable fuel to be blended into transportation fuels by 2022. New mandated blending requirements for this standard became effective July 1, 2010.

“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 the vapor below atmospheric pressure ~~the vapor~~turning it back to a liquid in order to purify, fractionate or form the desired products.

- 5 -

Item 1.Financial Statements

HOLLY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30,			December 31,			March 31,			December 31,
	2010			2009			2011			2010
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents(HEP: $706 and $2,508, respectively)	$	271,920		$	124,596
Cash and cash equivalents(HEP: $1,502 and $403, respectively)							$	224,114		$	229,101
Marketable securities		1,171			1,223			48,947			1,343

Accounts receivable: Product and transportation(HEP: $21,319 and $18,767, respectively)		250,098			292,310
Accounts receivable: Product and transportation(HEP: $23,475 and $22,508, respectively)								349,509			299,081
Crude oil resales		468,373			470,145			802,745			694,035

		718,471			762,455			1,152,254			993,116

Inventories: Crude oil and refined products		368,260			259,582			424,785			353,636
Materials and supplies(HEP: $197 and $165, respectively )		45,755			43,931
Materials and supplies(HEP: $185 and $202, respectively)								48,671			46,731

		414,015			303,513			473,456			400,367

Income taxes receivable		26,269			38,072			2,042			51,034
Prepayments and other(HEP: $924 and $574, respectively)		43,261			50,957
Current assets of discontinued operations(HEP: $2,195)		—			2,195
Prepayments and other(HEP: $360 and $573, respectively)								14,941			28,474

Total current assets		1,475,107			1,283,011			1,915,754			1,703,435

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	)
Properties, plants and equipment, at cost(HEP: $563,834 and $552,398, respectively)								2,282,634			2,215,828
Less accumulated depreciation(HEP: $(66,995) and $(60,300), respectively)								(481,082	)		(459,137	)

		1,697,383			1,629,970			1,801,552			1,756,691

Marketable securities (long-term)								19,550			—

Other assets: Turnaround costs		50,948			53,463			69,409			69,533
Goodwill(HEP: $81,602 and $81,602)		81,602			81,602			81,602			81,602
Intangibles and other(HEP: $73,192 and $77,443, respectively)		92,339			97,893
Intangibles and other(HEP: $75,138 and $72,434, respectively)								101,893			90,214

		224,889			232,958			252,904			241,349

Total assets	$	3,397,379		$	3,145,939		$	3,989,760		$	3,701,475


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			—
Accounts payable(HEP: $10,325 and $10,238, respectively)							$	1,498,508		$	1,317,446
Accrued liabilities(HEP: $13,691 and $21,206, respectively)								76,734			72,409

Total current liabilities		1,270,349			1,025,112			1,575,242			1,389,855

Long-term debt(HEP: $322,623 and $379,198, respectively)		650,906			707,458
Long-term debt(HEP: $505,918 and $482,271, respectively)								834,213			810,561
Deferred income taxes		129,677			124,585			131,698			131,935
Other long-term liabilities(HEP: $12,534 and $12,349, respectively)		80,970			81,003
Other long-term liabilities(HEP: $9,511 and $10,809, respectively)								80,657			80,985

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
Common stock $.01 par value — 160,000,000 shares authorized; 76,346,432 shares issued as of March 31, 2011 and December 31, 2010								763			763
Additional capital		191,030			195,565			193,121			194,378
Retained earnings		1,199,605			1,134,341			1,283,021			1,206,328
Accumulated other comprehensive loss		(26,360	)		(25,700	)		(25,866	)		(26,246	)
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	)
Common stock held in treasury, at cost — 23,034,159 and 23,081,744 shares as of March 31, 2011 and December 31, 2010, respectively								(677,253	)		(677,804	)

Total Holly Corporation stockholders’ equity		687,127			619,039			773,786			697,419

Noncontrolling interest		578,350			588,742			594,164			590,720

Total equity		1,265,477			1,207,781			1,367,950			1,288,139

Total liabilities and equity	$	3,397,379		$	3,145,939		$	3,989,760		$	3,701,475

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


	Three Months Ended
	March 31,
	2011			2010
Sales and other revenues	$	2,326,585		$	1,874,290

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		1,984,617			1,723,864
Operating expenses (exclusive of depreciation and amortization)		134,743			127,544
General and administrative expenses (exclusive of depreciation and amortization)		16,818			17,869
Depreciation and amortization		31,308			27,757

Total operating costs and expenses		2,167,486			1,897,034


Income (loss) from operations		159,099			(22,744	)

Other income (expense):
Equity in earnings of SLC Pipeline		740			481
Interest income		85			59
Interest expense		(16,204	)		(17,722	)
Merger transaction costs		(3,698	)		—

		(19,077	)		(17,182	)

Income (loss) before income taxes		140,022			(39,926	)

Income tax provision (benefit):
Current		49,489			5,361
Deferred		(478	)		(22,033	)

		49,011			(16,672	)


Net income (loss)		91,011			(23,254	)

Less net income attributable to noncontrolling interest		6,317			4,840


Net income (loss) attributable to Holly Corporation stockholders	$	84,694		$	(28,094	)


Earnings per share attributable to Holly Corporation stockholders:
Basic	$	1.59		$	(0.53	)

Diluted	$	1.58		$	(0.53	)


Cash dividends declared per common share	$	0.15		$	0.15

Average number of common shares outstanding:
Basic		53,307			53,094
Diluted		53,633			53,094

See accompanying notes.

- 7 -

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2010			2009⁽¹⁾			2011			2010
Cash flows from operating activities:
Net income	$	108,802		$	75,627
Net income (loss)							$	91,011		$	(23,254	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		85,719			70,088			31,308			27,757
SLC Pipeline earnings, net of distributions		406			(1,309	)		(365	)		(481	)
Deferred income taxes		5,512			25,593			(478	)		(22,033	)
Equity based compensation expense		7,814			6,579			1,754			2,907
Change in fair value — interest rate swaps		1,464			300
Noncontrolling interest in earnings of Rio Grande Pipeline Company		—			1,191
Change in fair value — derivative instruments								1,092			1,464
(Increase) decrease in current assets:
Accounts receivable		43,984			(327,568	)		(159,138	)		(121,085	)
Inventories		(110,502	)		(73,813	)		(73,089	)		(117,509	)
Income taxes receivable		11,803			966			48,992			7,824
Prepayments and other		(304	)		(7,987	)		6,978			(30,420	)
Current assets of discontinued operations		2,195			—			—			2,195
Increase (decrease) in current liabilities:
Accounts payable		69,030			429,465			181,045			180,298
Accrued liabilities		17,971			1,225			14,155			7,590
Turnaround expenditures		(11,453	)		(33,112	)		(16,924	)		(7,257	)
Other, net		3,527			12,407			4,201			1,980

Net cash provided by operating activities		235,968			179,652
Net cash provided by (used for) operating activities								130,542			(90,024	)

Cash flows from investing activities:
Additions to properties, plants and equipment — Holly Corporation		(119,885	)		(218,543	)		(62,563	)		(29,187	)
Additions to properties, plants and equipment — Holly Energy Partners		(8,054	)		(27,478	)		(11,475	)		(1,911	)
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	)		(98,937	)		—
Sales and maturities of marketable securities		—			220,281			31,925			—

Net cash used for investing activities		(127,939	)		(374,946	)		(141,050	)		(31,098	)

Cash flows from financing activities:
Borrowings under credit agreement — Holly Corporation		310,000			94,000			—			310,000
Repayments under credit agreement — Holly Corporation		(310,000	)		(94,000	)		—			(310,000	)
Borrowings under credit agreement — Holly Energy Partners		52,000			197,000			30,000			33,000
Repayments under credit agreement — Holly Energy Partners		(101,000	)		(152,000	)		(7,000	)		(68,000	)
Proceeds from issuance of senior notes — Holly Corporation		—			187,925
Proceeds from issuance of senior notes — Holly Energy Partners		147,540			—			—			147,540
Proceeds from issuance of common units — Holly Energy Partners		—			58,355
Repayments under financing obligation — Holly Corporation		(760	)		—			(277	)		(246	)
Purchase of treasury stock		(1,308	)		(1,214	)		(2,051	)		(1,055	)
Contribution from joint venture partner		9,500			13,650			8,500			1,250
Dividends		(23,889	)		(22,569	)		(7,984	)		(7,926	)
Distributions to noncontrolling interest		(36,139	)		(23,359	)		(12,485	)		(11,963	)
Excess tax benefit (expense) from equity based compensation		(1,313	)		2,140			261			(1,045	)
Purchase of units for restricted grants — Holly Energy Partners		(2,276	)		(616	)		(399	)		(1,745	)
Deferred financing costs		(3,121	)		(6,356	)		(3,044	)		(56	)
Issuance of common stock upon exercise of options		61			60			—			61

Net cash provided by financing activities		39,295			253,016			5,521			89,815

Cash and cash equivalents:

Increase for the period		147,324			57,722
Decrease for the period								(4,987	)		(31,307	)
Beginning of period		124,596			40,805			229,101			124,596

End of period	$	271,920		$	98,527		$	224,114		$	93,289


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	49,051		$	20,555		$	12,602		$	11,879
Income taxes	$	45,040		$	18,219		$	8		$	—

HOLLY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(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


	Three Months Ended
	March 31,
	2011		2010
Net income (loss)	$	91,011	$	(23,254	)

Other comprehensive income (loss):
Unrealized gain on available-for-sale securities		142		244

Hedging instruments:
Change in fair value of cash flow hedging instruments		1,321		(1,362	)


Other comprehensive income (loss) before income taxes		1,463		(1,118	)
Income tax expense (benefit)		242		318


Other comprehensive income (loss)		1,221		(1,436	)


Total comprehensive income (loss)		92,232		(24,690	)

Less noncontrolling interest in comprehensive income		7,159		2,904


Comprehensive income (loss) attributable to Holly Corporation stockholders	$	85,073	$	(27,594	)

See accompanying notes.

- 9 -

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~~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,~~March 31, 2011, 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 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~~a consolidated variable interest entity (“VIE”), which includes our 2% general ~~partnership interest), which owns and operates logistics~~partner interest. HEP has logistic assets including ~~approximately 2,500 miles of~~ petroleum product and crude oil pipelines located ~~principally~~ in ~~west~~ Texas, New Mexico, Oklahoma and ~~New Mexico;~~Utah; ten refined product terminals; a jet fuel terminal; ~~eight refinery~~ loading rack ~~facilities;~~facilities at each of our three refineries, a refined products tank farm ~~facility;~~facility and on-site crude oil tankage at our Navajo, Woods Cross and Tulsa ~~Refineries, on-site refined product tankage at our Tulsa Refinery and~~Refineries. Additionally, HEP owns a 25% interest in SLC Pipeline LLC (“SLC Pipeline”), a new 95-mile ~~crude oil~~intrastate pipeline ~~joint venture (the “SLC Pipeline”).~~system that serves refineries in the Salt Lake City area.

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,~~March 31, 2011, the consolidated results of operations and comprehensive income (loss) for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ and consolidated cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 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~~2010 filed with the SEC.

Our results of operations for the first ~~nine~~three months of ~~2010~~2011 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

- 10 -

when accounts are deemed uncollectible and historically have been minimal. At ~~September 30, 2010,~~March 31, 2011, our allowance for doubtful accounts reserve was ~~$1.9~~$2.4 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~~Pending Holly Frontier Merger

On ~~June 1, 2009,~~February 21, 2011, we ~~acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa Refinery west facility”) from an affiliate~~entered into a merger agreement providing for a “merger of ~~Sunoco, Inc.~~equals” business combination of us and Frontier Oil Corporation (“~~Sunoco”~~Frontier”) ~~for $157.8 million in cash, including crude oil, refined product~~. Subject to the terms 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~~conditions 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 transactionmerger agreement which 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~~approved unanimously by both our and Frontier’s board 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 2,789,155directors, Frontier shareholders will receive 0.4811 shares of our common stock ~~having a value~~for each share of ~~$74 million. Additionally, we reimbursed Sinclair $8.4 million upon their completion of certain environmental projects at~~Frontier common stock if the ~~refinery in July 2010. The refinery produces gasoline, diesel fuel and jet fuel products and also serves markets in the Mid-Continent region~~merger is completed. Completion of the ~~United States. We are~~merger is subject to certain conditions, including, among others, (i) approval by our stockholders of the issuance of our common stock to Frontier’s stockholders in connection with the ~~process~~merger, (ii) adoption of ~~integrating~~ the ~~operations~~merger agreement by Frontier’s stockholders, (iii) the expiration or termination of ~~both Tulsa Refinery facilities. This will result in~~ the ~~Tulsa Refinery~~applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the registration statement on Form S-4 used to register the common stock to be issued as consideration for the merger having ~~an integrated crude processing rate of 125,000 BPSD.~~been declared effective by the SEC and (v) the entry into a new credit facility for the combined company.

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.March 2011, the Federal Trade Commission (“FTC”) granted early termination of its Hart-Scott-Rodino antitrust review of the proposed merger.

NOTE 3: Holly Energy Partners

HEP, a consolidated 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

~~- 11 -~~

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,~~March 31, 2011, 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, weWe 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%~~76% of HEP’s total revenues for the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011. 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.

- 11 -

We have pledged 6,000,000 of our HEP common units to collateralize certain crude oil purchases in 2011.

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”).

~~- 12 -~~

~~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).~~

	•		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~~subject to annual tariff rate adjustments on July 1, based ~~upon the change in~~on 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~~

~~- 13 -~~

~~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,~~As of March 31, 2011, 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 borrowings outstanding ~~principal~~ under HEP’s $275 million revolving credit agreement (the “HEP 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

- 12 -

Notes”). The ~~$157~~$182 million carrying amount of borrowings outstanding ~~debt~~ under ~~HEP’s credit agreement~~the HEP Credit Agreement approximates fair value as interest rates are reset frequently using current interest rates. At ~~September 30, 2010,~~March 31, 2011, the estimated fair ~~value~~values of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were ~~$324~~$338.3 million, ~~$183.2~~$185 million and ~~$156.8~~$160.5 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.

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

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

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

Our investments in marketable securities are measured at fair value using quoted market prices, a Level 1 input. See Note 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~~is 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.

~~- 14 -~~

NOTE 5: Earnings Per Share

Basic earnings per share ~~from continuing operations~~ is calculated as net income ~~from continuing operations~~attributable to Holly Corporation stockholders 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 net income ~~from continuing operations:~~attributable to Holly Corporation stockholders:

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


	Three Months Ended
	March 31,
	2011		2010
	(In thousands, except per share data)
Net income attributable to Holly Corporation stockholders	$	84,694	$	(28,094	)

Average number of shares of common stock outstanding		53,307		53,094
Effect of dilutive stock options, variable restricted shares and performance share units		326		—

Average number of shares of common stock outstanding assuming dilution		53,633		53,094


Basic earnings per share	$	1.59	$	(0.53	)

Diluted earnings per share	$	1.58	$	(0.53	)

- 13 -

NOTE 6: Stock-Based Compensation

On ~~September 30, 2010,~~March 31, 2011, we had ~~three~~two 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~~$1.1 million and $2$1.9 million for the three months ended ~~September 30,~~March 31, 2011 and 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 $0.4 million and $0.8 million for the three months ended ~~September 30,~~March 31, 2011 and 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~~We have proposed to a vote of ~~common stock were reserved for future grants under~~shareholders, an amendment to the ~~current~~ Long-Term Incentive Compensation Plan ~~which reservation allows for~~that will extend the term of the plan and our ability to grant equity compensation awards ~~of options, restricted stock or other performance awards.~~until December 31, 2020.

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~~$0.7 million and ~~$0.2~~$1 million for the three months ended ~~September 30,~~March 31, 2011 and 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.

~~- 15 -~~

~~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~~three months ended ~~September 30, 2010~~March 31, 2011 is presented below:


				Weighted-
				Average Grant		Aggregate					Weighted-Average
				Date Fair		Intrinsic					Grant Date Fair		Aggregate Intrinsic
Restricted Stock	Grants			Value		Value ($000)		Grants			Value		Value ($000)
Outstanding at January 1, 2010 (non-vested)		284,450		$	31.82
Outstanding at January 1, 2011 (non-vested)									346,996		$	29.31
Vesting and transfer of ownership to recipients		(123,307	)		33.84				(87,232	)		29.80
Granted		192,248			28.44
Forfeited		(2,714	)		28.38				(12,965	)		52.02

Outstanding at September 30, 2010 (non-vested)		350,677		$	29.29	$	10,082
Outstanding at March 31, 2011 (non-vested)									246,799		$	27.94	$	14,996

A summary of performance share unit activity and changes during the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 is presented below:


Performance Share Units	Grants
Outstanding at January 1, ~~2010~~2011 (non-vested)		~~215,170~~278,093
Vesting and transfer of ownership to recipients		(~~38,653~~	)
~~Granted~~		~~110,489~~
~~Forfeited~~		~~(3,720~~53,962	)

Outstanding at ~~September 30, 2010~~March 31, 2011 (non-vested)		~~283,286~~224,131

For the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, we issued ~~66,483~~75,007 shares of our common stock having a fair value of ~~$2.2~~$3.6 million related to vested performance share units, representing a ~~172%~~139% payout. Based on the weighted average grant date fair value of ~~$3.2 million,~~$25.82, there was ~~$4.7~~$6.6 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~~1.2 years.

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

Our investment portfolio at March 31, 2011, consisted of cash, ~~and~~ cash equivalents ~~at September 30, 2010. In addition, we own~~and investments in debt securities primarily issued by government entities. We also hold 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~~We 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~~ We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments including investments in ~~marketable~~equity securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are 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						Available-for-Sale Securities
					Estimated Fair						Estimated Fair Value
			Gross		Value				Gross Unrealized		(Net Carrying
			Unrealized		(Net Carrying		Amortized Cost		Gain		Amount)
	Amortized Cost		Gain		Amount)		(In thousands)
	(In thousands)
September 30, 2010

March 31, 2011
State and political subdivision debt securities							$	67,012	$	8	$	67,020
Equity securities	$	610	$	561	$	1,171		610		867		1,477


December 31, 2009
Total marketable securities							$	67,622	$	875	$	68,497


December 31, 2010
Equity securities	$	604	$	619	$	1,223	$	610	$	733	$	1,343

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~~Our $300 million ~~aggregate principal amount of Holly~~ 9.875% Senior Notes mature onin June ~~15, 2017. The Holly 9.875% Senior Notes~~2017 and 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~~which mature in 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 outstanding mature in 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,~~HEP’s creditors have no other recourse to our ~~previous agreement to indemnify HEP’s controlling partner~~assets. Furthermore, our creditors have no recourse to the ~~extent it makes any payment in satisfaction~~assets of ~~debt service due on up to $35 million of the principal amount of the~~ HEP ~~6.25% Senior Notes was terminated.~~and its consolidated subsidiaries.

~~- 19 -~~

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,~~March 31, 2011, 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%~~2.5%, which equaled an effective interest rate of ~~5.49%~~6.24% as of ~~September 30, 2010. The maturity date of this~~March 31, 2011. This interest rate swap contract ~~is February 28, 2013.~~

~~HEP~~has been designated ~~this interest rate swap~~ as a cash flow ~~hedge. Based~~hedge and matures in February 2013.

This contract initially hedged variable LIBOR interest on ~~its assessment of effectiveness using the change~~$171 million in ~~variable cash flows method,~~outstanding 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 rateCredit Agreement 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.

~~- 21 -~~

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⁾


	Balance Sheet
Derivative Instruments	Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
March 31, 2011

*Derivative designated as cash flow hedging instrument:*

Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	8,743	Accumulated other comprehensive loss	$	8,743


*Derivatives not designated as hedging instruments:*

Variable-to-fixed commodity price swap contracts (various inventory positions)	Prepayments and other current assets	$	6,555	Cost of products sold (decrease)	$	6,555


Fixed/variable-to-variable/fixed commodity price contracts (various inventory positions)	Accrued liabilities	$	5,960	Cost of products sold (increase)	$	5,960


December 31, 2010

*Derivative designated as cash flow hedging instruments:*

Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)	Accrued liabilities	$	38	Accumulated other comprehensive loss	$	38


Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026


*Derivatives not designated as hedging instruments:*

Fixed-to-variable rate swap contracts (various inventory positions)	Accrued liabilities	$	497	Cost of products sold (increase)	$	497

For the three months ended March 31, 2011, maturities and fair value adjustments attributable to our economic hedges resulted in a $3.7 million increase to costs of products sold.

For the three months ended March 31, 2010, HEP recognized $1.5 million in charges to interest expense as a result of fair value changes to interest rate swap contracts that were settled in the first quarter of 2010.

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

~~- 25 -~~

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.~~2010.


								Consolidations and													Consolidations and
	Refining		HEP⁽¹⁾		Corporate and Other			Eliminations			Consolidated Total		Refining			HEP⁽¹⁾		Corporate and Other			Eliminations			Consolidated Total
					(In thousands)								(In thousands)
Three Months Ended September 30, 2010
Three Months Ended March 31, 2011
Sales and other revenues	$	2,081,709	$	46,558	$	100		$	(37,379	)	$	2,090,988	$	2,315,092		$	45,005	$	648		$	(34,160	)	$	2,326,585
Depreciation and amortization	$	21,274	$	6,830	$	1,329		$	(295	)	$	29,138	$	22,983		$	7,235	$	1,297		$	(207	)	$	31,308
Income (loss) from operations	$	100,111	$	24,588	$	(16,652	)	$	(429	)	$	107,618	$	152,104		$	23,611	$	(16,098	)	$	(518	)	$	159,099
Capital expenditures	$	47,623	$	3,567	$	219		$	—		$	51,409	$	22,965		$	11,475	$	39,598		$	—		$	74,038

Three Months Ended September 30, 2009
Three Months Ended March 31, 2010
Sales and other revenues	$	1,476,304	$	40,805	$	229		$	(28,847	)	$	1,488,491	$	1,867,174		$	40,689	$	66		$	(33,639	)	$	1,874,290
Depreciation and amortization	$	16,527	$	5,974	$	1,525		$	—		$	24,026	$	20,726		$	6,805	$	521		$	(295	)	$	27,757
Income (loss) from operations	$	50,584	$	21,880	$	(16,183	)	$	(699	)	$	55,582	$	(24,579	)	$	18,261	$	(15,767	)	$	(659	)	$	(22,744	)
Capital expenditures	$	54,946	$	5,652	$	2,030		$	—		$	62,628	$	19,209		$	1,911	$	9,978		$	—		$	31,098

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
March 31, 2011
Cash, cash equivalents and investments in marketable securities	$	—	$	706	$	272,385		$	—		$	273,091	$	—		$	1,502	$	291,109		$	—		$	292,611
Total assets	$	2,210,374	$	660,727	$	555,419		$	(29,141	)	$	3,397,379	$	2,725,065		$	679,101	$	619,825		$	(34,231	)	$	3,989,760
Long-term debt													$	—		$	505,918	$	345,108		$	(16,813	)	$	834,213

December 31, 2009
December 31, 2010
Cash, cash equivalents and investments in marketable securities	$	—	$	2,508	$	123,311		$	—		$	125,819	$	—		$	403	$	230,041		$	—		$	230,444
Total assets	$	2,142,317	$	641,775	$	392,007		$	(30,160	)	$	3,145,939	$	2,490,193		$	669,820	$	573,531		$	(32,069	)	$	3,701,475
Long-term debt													$	—		$	482,271	$	345,215		$	(16,925	)	$	810,561

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.

- 2723 -

Condensed Consolidating Balance Sheet


							Non-								Non-Guarantor													Non-								Non-Guarantor
							Guarantor						Holly Corp. Before		Non-Restricted													Guarantor						Holly Corp. Before		Non-Restricted
				Guarantor Restricted			Restricted						Consolidation of		Subsidiaries										Guarantor Restricted			Restricted						Consolidation of		Subsidiaries
September 30, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP		(HEP Segment)		Eliminations			Consolidated
March 31, 2011																						Parent			Subsidiaries			Subsidiaries			Eliminations			HEP		(HEP Segment)			Eliminations			Consolidated
										(In thousands)												(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	265,969		$	(1,557	)	$	6,802		$	—		$	271,214	$	706	$	—		$	271,920	$	203,343		$	(633	)	$	19,902		$	—		$	222,612	$	1,502		$	—		$	224,114
Marketable securities		—			1,171			—			—			1,171		—		—			1,171		47,469			1,478			—			—			48,947		—			—			48,947
Accounts receivable		(6,957	)		724,081			—			—			717,124		21,319		(19,972	)		718,471		2,427			1,147,038			4,001			—			1,153,466		23,475			(24,687	)		1,152,254
Intercompany accounts receivable (payable)		(1,385,596	)		988,726			396,870			—			—		—		—			—		(1,474,477	)		1,058,765			415,712			—			—		—			—			—
Inventories		—			413,818			—			—			413,818		197		—			414,015		—			473,271			—			—			473,271		185			—			473,456
Income taxes receivable		26,269			—			—			—			26,269		—		—			26,269		2,042			—			—			—			2,042		—			—			2,042
Prepayments and other assets		26,704			19,040			—			—			45,744		924		(3,407	)		43,261		8,283			10,084			—			—			18,367		360			(3,786	)		14,941

Total current assets		(1,073,611	)		2,145,279			403,672			—			1,475,340		23,146		(23,379	)		1,475,107		(1,210,913	)		2,690,003			439,615			—			1,918,705		25,522			(28,473	)		1,915,754

Properties and equipment, net		17,971			1,004,329			199,203			—			1,221,503		482,786		(6,906	)		1,697,383		17,279			1,019,342			274,994			—			1,311,615		496,839			(6,902	)		1,801,552
Marketable securities (long-term)																							19,550			—			—			—			19,550		—			—			19,550
Investment in subsidiaries		2,227,676			545,056			(393,379	)		(2,379,353	)		—		—		—			—		2,437,180			630,718			(394,511	)		(2,673,387	)		—		—			—			—
Intangibles and other assets		9,352			59,599			—			—			68,951		154,794		1,144			224,889		7,800			87,220			—			—			95,020		156,740			1,144			252,904

Total assets	$	1,181,388		$	3,754,263		$	209,496		$	(2,379,353	)	$	2,765,794	$	660,726	$	(29,141	)	$	3,397,379	$	1,270,896		$	4,427,283		$	320,098		$	(2,673,387	)	$	3,344,890	$	679,101		$	(34,231	)	$	3,989,760


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,348		$	1,043,545		$	7,570		$	—		$	1,058,463	$	5,786	$	(19,972	)	$	1,044,277	$	5,707		$	1,496,835		$	10,328		$	—		$	1,512,870	$	10,325		$	(24,687	)	$	1,498,508
Accrued liabilities		33,644			22,591			492			—			56,727		15,752		(3,407	)		69,072		30,244			35,525			1,060			—			66,829		13,691			(3,786	)		76,734
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		35,951			1,532,360			11,388			—			1,579,699		24,016			(28,473	)		1,575,242

Long-term debt		289,233			56,085			—			—			345,318		322,623		(17,035	)		650,906		289,792			55,316			—			—			345,108		505,918			(16,813	)		834,213
Non-current liabilities		38,098			30,338			—			—			68,436		12,534		—			80,970		44,444			26,703			—			—			71,147		9,510			—			80,657
Deferred income taxes		124,640			(239	)		325			—			124,726		—		4,951			129,677		125,685			325			737			—			126,747		—			4,951			131,698
Distributions in excess of inv in HEP		—			374,267			—			—			374,267		—		(374,267	)		—		—			375,399			—			—			375,399		—	��		(375,399	)		—
Equity — Holly Corporation		688,425			2,227,676			201,109			(2,428,785	)		688,425		147,031		(148,329	)		687,127		775,024			2,437,180			307,973			(2,745,153	)		775,024		139,657			(140,895	)		773,786
Equity — noncontrolling interest		—			—			—			49,432			49,432		—		528,918			578,350		—			—			—			71,766			71,766		—			522,398			594,164

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	$	1,270,896		$	4,427,283		$	320,098		$	(2,673,387	)	$	3,344,890	$	679,101		$	(34,231	)	$	3,989,760

Condensed Consolidating Statement of Income


																Non-Guarantor															Non-									Non-Guarantor
							Non-Guarantor						Holly Corp. Before			Non-Restricted															Guarantor						Holly Corp. Before			Non-Restricted
Three Months Ended				Guarantor Restricted				Restricted					Consolidation of			Subsidiaries												Guarantor Restricted			Restricted						Consolidation of			Subsidiaries
September 30, 2010	Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
March 31, 2011																									Parent			Subsidiaries			Subsidiaries			Eliminations			HEP			(HEP Segment)			Eliminations			Consolidated
										(In thousands)															(In thousands)
Sales and other revenues	$	100		$	2,081,707		$	2		$	—		$	2,081,809		$	46,558		$	(37,379	)	$	2,090,988		$	648		$	2,315,092		$	—		$	—		$	2,315,740		$	45,005		$	(34,160	)	$	2,326,585

Operating costs and expenses:
Cost of products sold		—			1,843,464			103			—			1,843,567			—			(36,523	)		1,807,044			—			2,017,926			—			—			2,017,926			—			(33,309	)		1,984,617
Operating expenses		—			116,763			—			—			116,763			13,632			(132	)		130,263			—			121,685			388			—			122,073			12,796			(126	)		134,743
General and administrative expenses		15,538			(121	)		—			—			15,417			1,508			—			16,925			15,353			102			—			—			15,455			1,363			—			16,818
Depreciation and amortization		925			21,499			179			—			22,603			6,830			(295	)		29,138			940			23,161			179			—			24,280			7,235			(207	)		31,308


Total operating costs and expenses		16,463			1,981,605			282			—			1,998,350			21,970			(36,950	)		1,983,370			16,293			2,162,874			567			—			2,179,734			21,394			(33,642	)		2,167,486


Income (loss) from operations		(16,363	)		100,102			(280	)		—			83,459			24,588			(429	)		107,618			(15,645	)		152,218			(567	)		—			136,006			23,611			(518	)		159,099

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			158,957			7,563			8,020			(166,520	)		8,020			740			(8,020	)		740
Interest income (expense)		(7,294	)		(1,660	)		11			—			(8,943	)		(8,979	)		618			(17,304	)		(6,808	)		(824	)		13			—			(7,619	)		(9,112	)		612			(16,119	)
Merger transaction costs																										(3,698	)		—			—			—			(3,698	)		—			—			(3,698	)

		99,066			6,258			8,128			(114,278	)		(826	)		(8,409	)		(7,499	)		(16,734	)
																										148,451			6,739			8,033			(166,520	)		(3,297	)		(8,372	)		(7,408	)		(19,077	)
Income from continuing operations before income taxes		82,703			106,360			7,848			(114,278	)		82,633			16,179			(7,928	)		90,884

Income before income taxes																										132,806			158,957			7,466			(166,520	)		132,709			15,239			(7,926	)		140,022

Income tax provision		31,418			—			—			—			31,418			76			—			31,494			48,783			—			—			—			48,783			228			—			49,011


Net income		51,285			106,360			7,848			(114,278	)		51,215			16,103			(7,928	)		59,390			84,023			158,957			7,466			(166,520	)		83,926			15,011			(7,926	)		91,011

Less net income attributable to noncontrolling interest		—			—			—			(70	)		(70	)		—			8,283			8,213			—			—			—			97			97			—			(6,414	)		(6,317	)


Net income attributable to Holly Corporation stockholders	$	51,285		$	106,360		$	7,848		$	(114,208	)	$	51,285		$	16,103		$	(16,211	)	$	51,177		$	84,023		$	158,957		$	7,466		$	(166,423	)	$	84,023		$	15,011		$	(14,340	)	$	84,694

~~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~~25 -

Condensed Consolidating Statement of Cash Flows


													Non-Guarantor																					Non-Guarantor
							Non-Guarantor			Holly Corp. Before			Non-Restricted												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
Three Months Ended																									Restricted			Restricted			Consolidation of			Subsidiaries
March 31, 2011																						Parent			Subsidiaries			Subsidiaries			HEP			(HEP Segment)			Eliminations			Consolidated
	(In thousands)																					(In thousands)
Cash flows from operating activities	$	168,984		$	22,377		$	5,294		$	196,655		$	66,129		$	(26,816	)	$	235,968		$	51,090		$	57,174		$	16,776		$	125,040		$	15,222		$	(9,720	)	$	130,542

Cash flows from investing activities
Additions to properties, plants and equipment — Holly		(1,498	)		(74,890	)		(43,497	)		(119,885	)		—			—			(119,885	)		(1,043	)		(22,995	)		(38,525	)		(62,563	)		—			—			(62,563	)
Additions to properties, plants and equipment — HEP		—			—			—			—			(43,580	)		35,526			(8,054	)		—			—			—			—			(11,475	)		—			(11,475	)
Proceeds from sale of assets		—			39,040			—			39,040			—			(39,040	)		—
Purchases of marketable securities																							(98,937	)		—			—			(98,937	)		—			—			(98,937	)
Sales and maturities of marketable securities																							31,925			—			—			31,925			—			—			31,925


																							(68,055	)		(22,995	)		(38,525	)		(129,575	)		(11,475	)		—			(141,050	)
		(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
Net borrowings under credit agreements — HEP																							—			—			—			—			23,000			—			23,000
Repayments under financing obligation — Holly		—			(1,067	)		—			(1,067	)		—			307			(760	)		—			(277	)		—			(277	)		—						(277	)
Purchase of treasury stock		(1,308	)		—			—			(1,308	)		—			—			(1,308	)		(2,051	)		—			—			(2,051	)		—			—			(2,051	)
Contribution from joint venture partner		—			(28,500	)		38,000			9,500			—			—			9,500			—			(25,500	)		34,000			8,500			—			—			8,500
Dividends		(23,889	)		—			—			(23,889	)		—			—			(23,889	)		(7,984	)		—			—			(7,984	)		—			—			(7,984	)
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	)		—			—			—			—			(22,205	)		9,720			(12,485	)
Excess tax expense from equity based compensation		(1,313	)		—			—			(1,313	)		—			—			(1,313	)
Excess tax benefit from equity based compensation																							261			—			—			261			—			—			261
Deferred financing costs		(2,628	)		—			—			(2,628	)		(493	)		—			(3,121	)		—			—			—			—			(3,044	)		—			(3,044	)
Purchase of units for HEP restricted grants		—			—			—			—			(2,276	)		—			(2,276	)		—			—			—			—			(399	)		—			(399	)
Other		61			—			—			61			—			—			61


																							(9,774	)		(25,777	)		34,000			(1,551	)		(2,648	)		9,720			5,521
		(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			(26,739	)		8,402			12,251			(6,086	)		1,099			—			(4,987	)
Beginning of period		127,560			(12,477	)		7,005			122,088			2,508			—			124,596			230,082			(9,035	)		7,651			228,698			403			—			229,101


End of period	$	265,969		$	(1,557	)	$	6,802		$	271,214		$	706		$	—		$	271,920		$	203,343		$	(633	)	$	19,902		$	222,612		$	1,502		$	—		$	224,114

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~~The words “we,” “our,” “ours” and “us” generally include ~~HEP~~Holly Energy Partners, L.P. (“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~~that produces high value light products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. Navajo Refining Company, L.L.C., one of our wholly-owned subsidiaries, owns a petroleum refinery ~~facilities~~ in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”)~~, Woods Cross,~~. The Navajo Refinery can process sour (high sulfur) crude oils and serves markets in the southwestern United States and northern Mexico. Our refinery located just north of Salt Lake City, Utah (the “Woods Cross Refinery”) is operated by Holly Refining & Marketing Company — Woods Cross, one of our wholly-owned subsidiaries. This facility is a high conversion refinery that primarily processes regional sweet (lower sulfur) and ~~two~~sour Canadian crude oils. Our refinery ~~facilities~~located in Tulsa, Oklahoma ~~(collectively, operated as the~~(the “Tulsa Refinery”)~~. As~~ is comprised of ~~September 30, 2010, our refineries had a combined crude capacity of 256,000 BPSD. Our profitability depends largely on~~two facilities, the ~~spread between market prices for refined petroleum products~~Tulsa Refinery west and ~~crude oil prices.~~ east facilities.

At ~~September 30, 2010,~~March 31, 2011, we ~~also~~ owned a 34% interest in HEP, ~~(including the~~a consolidated variable interest entity (“VIE”), which includes our 2% general partner ~~interest) which owns~~interest. HEP has logistic assets including petroleum product and ~~operates pipeline~~crude oil pipelines located in Texas, New Mexico, Oklahoma and ~~terminalling assets,~~Utah; ten refined product terminals; a jet fuel terminal; loading rack facilities at each of our three refineries, a refined products tank farm facility and on-site crude oil tankage at our Navajo, Woods Cross and Tulsa Refineries. Additionally, HEP owns a 25% interest in SLC Pipeline LLC ~~(the “SLC~~(“SLC Pipeline”), a new 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination of us and Frontier Oil Corporation (“Frontier”). Subject to the terms and conditions of the merger agreement which has been approved unanimously by both our and Frontier’s board of directors, Frontier shareholders will receive 0.4811 shares of our common stock for each share of Frontier common stock if the merger is completed. Completion of the merger is subject to certain conditions, including, among others, (i) approval by our stockholders of the issuance of our common stock to Frontier’s stockholders in connection with the merger, (ii) adoption of the merger agreement by Frontier’s stockholders, (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iv) the registration statement on Form S-4 used to register the common stock to be issued as consideration for the merger having been declared effective by the SEC and (v) the entry into a new credit facility for the combined company. In March 2011, the Federal Trade Commission (“FTC”) granted early termination of its Hart-Scott-Rodino antitrust review of the proposed merger.

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~~three months ended ~~September 30, 2010,~~March 31, 2011, sales and other revenues were ~~$6,111.1~~$2,326.6 million and net income attributable to Holly Corporation stockholders was ~~$89.2~~$84.7 million. For the ~~nine~~three months ended ~~September 30, 2009,~~March 31, 2010, sales and other revenues ~~from continuing operations~~ were ~~$3,172.3~~$1,874.3 million and the net ~~income~~loss attributable to Holly Corporation stockholders was ~~$60~~$28.1 million. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 were ~~$5,894.1~~$2,167.5 million compared to ~~$3,041.5~~$1,897 million for the ~~nine~~three 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.March 31, 2010.

- 3227 -

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 %


	Three Months Ended
	March 31,						Change from 2010
	2011			2010			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	2,326,585		$	1,874,290		$	452,295			24.1	%

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		1,984,617			1,723,864			260,753			15.1
Operating expenses (exclusive of depreciation and amortization)		134,743			127,544			7,199			5.6
General and administrative expenses (exclusive of depreciation and amortization)		16,818			17,869			(1,051	)		(5.9	)
Depreciation and amortization		31,308			27,757			3,551			12.8

Total operating costs and expenses		2,167,486			1,897,034			270,452			14.3


Income (loss) from operations		159,099			(22,744	)		181,843			799.5

Other income (expense):
Equity in earnings of SLC Pipeline		740			481			259			53.8
Interest income		85			59			26			44.1
Interest expense		(16,204	)		(17,722	)		1,518			8.6
Merger transaction costs		(3,698	)		—			(3,698	)		(100.0	)

		(19,077	)		(17,182	)		(1,895	)		11.0


Income (loss) before income taxes		140,022			(39,926	)		179,948			450.7

Income tax provision (benefit)		49,011			(16,672	)		65,683			394.0


Net income (loss)		91,011			(23,254	)		114,265			491.4

Less net income attributable to noncontrolling interest		6,317			4,840			1,477			30.5


Net income (loss) attributable to Holly Corporation stockholders	$	84,694		$	(28,094	)	$	112,788			401.5	%


Earnings per share attributable to Holly Corporation stockholders:
Basic	$	1.59		$	(0.53	)	$	2.12			400.0	%

Diluted	$	1.58		$	(0.53	)	$	2.11			398.1	%


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


Average number of common shares outstanding:
Basic		53,307			53,094			213			0.4	%
Diluted		53,633			53,094			539			1.0	%

Balance Sheet Data (Unaudited)


	March 31,		December 31,
	2011		2010
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	292,611	$	230,444
Working capital	$	340,512	$	313,580
Total assets	$	3,989,760	$	3,701,475
Long-term debt	$	834,213	$	810,561
Total equity	$	1,367,950	$	1,288,139

- 3328 -

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 %

~~- 34 -~~

~~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


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Net cash provided by (used for) operating activities	$	130,542		$	(90,024	)
Net cash used for investing activities	$	(141,050	)	$	(31,098	)
Net cash provided by financing activities	$	5,521		$	89,815
Capital expenditures	$	74,038		$	31,098
EBITDA⁽¹⁾	$	181,132		$	654


(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

~~- 35 -~~


		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						Three Months Ended
	September 30,						September 30,						March 31,
	2010			2009			2010			2009			2011			2010
*Navajo Refinery*
Crude charge (BPD)⁽¹⁾		85,110			86,250			82,150			76,670			69,980			78,910
Refinery production (BPD)⁽²⁾		91,550			93,620			90,290			84,560
Refinery throughput (BPD)⁽²⁾														78,930			90,490
Refinery production (BPD)⁽³⁾														76,720			87,530
Sales of produced refined products (BPD)		92,180			93,996			90,730			84,102			79,840			86,930
Sales of refined products (BPD)⁽³⁾		94,900			96,580			93,780			88,110
Sales of refined products (BPD)⁽⁴⁾														86,700			90,120

Refinery utilization⁽⁴⁾		85.1	%		86.2	%		82.2	%		80.7	%
Refinery utilization⁽⁵⁾														70.0	%		78.9	%

Average per produced barrel⁽⁵⁾
Average per produced barrel⁽⁶⁾
Net sales	$	87.60		$	78.15		$	88.98		$	69.21		$	110.99		$	88.06
Cost of products⁽⁶⁾		79.39			70.88			81.44			60.25
Cost of products⁽⁷⁾														95.60			82.96

Refinery gross margin		8.21			7.27			7.54			8.96			15.39			5.10
Refinery operating expenses⁽⁷⁾		5.25			4.37			5.01			4.88
Refinery operating expenses⁽⁸⁾														6.34			5.18

Net operating margin	$	2.96		$	2.90		$	2.53		$	4.08		$	9.05		$	(0.08	)


Refinery operating expenses per throughput barrel													$	6.42		$	4.97

Feedstocks:
Sour crude oil														73	%		87	%
Sweet crude oil														5	%		4	%
Heavy sour crude oil														11	%		—	%
Other feedstocks and blends														11	%		9	%

Total														100	%		100	%


Sales of produced refined products:
Gasolines														51	%		59	%
Diesel fuels														35	%		30	%
Jet fuels														1	%		4	%
Fuel oil														5	%		4	%
Asphalt														5	%		1	%
LPG and other														3	%		2	%

Total														100	%		100	%


*Woods Cross Refinery*
Crude charge (BPD)⁽¹⁾														25,770			25,680
Refinery throughput (BPD)⁽²⁾														27,900			27,110
Refinery production (BPD)⁽³⁾														26,620			26,540
Sales of produced refined products (BPD)														26,650			28,170
Sales of refined products (BPD)⁽⁴⁾														26,740			28,360

Refinery utilization⁽⁵⁾														83.1	%		82.8	%


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2010			2009			2010			2009			2011			2010
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⁾
Average per produced barrel⁽⁶⁾
Net sales	$	94.86		$	80.87		$	93.71		$	66.87		$	108.77		$	89.52
Cost of products⁽⁶⁾		73.08			65.68			74.02			55.22
Cost of products⁽⁷⁾														89.87			74.72

Refinery gross margin		21.78			15.19			19.69			11.65			18.90			14.80
Refinery operating expenses⁽⁷⁾		6.11			6.44			5.86			6.45
Refinery operating expenses⁽⁸⁾														6.43			6.20

Net operating margin	$	15.67		$	8.75		$	13.83		$	5.20		$	12.47		$	8.60


Refinery operating expenses per throughput barrel													$	6.14		$	6.45

Feedstocks:
Sour crude oil		5	%		6	%		6	%		4	%
Sweet crude oil		61	%		61	%		60	%		63	%		57	%		61	%
Heavy sour crude oil														4	%		7	%
Black wax crude oil		30	%		27	%		29	%		28	%		31	%		28	%
Other feedstocks and blends		4	%		6	%		5	%		5	%		8	%		4	%

Total		100	%		100	%		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		60	%		59	%		62	%		65	%		61	%		64	%
Diesel fuels		33	%		32	%		31	%		28	%		29	%		28	%
Jet fuels		1	%		3	%		1	%		1	%		2	%		1	%
Fuel oil		2	%		3	%		1	%		3	%		2	%		1	%
Asphalt		2	%		2	%		3	%		1	%		3	%		3	%
LPG and other		2	%		1	%		2	%		2	%		3	%		3	%

Total		100	%		100	%		100	%		100	%		100	%		100	%


*Tulsa Refinery*⁽⁸⁾
*Tulsa Refinery*
Crude charge (BPD)⁽¹⁾		114,820			66,230			112,340			28,300			105,600			103,600
Refinery production (BPD)⁽²⁾		110,670			64,230			108,830			27,400
Refinery throughput (BPD)⁽²⁾														106,690			104,810
Refinery production (BPD)⁽³⁾														106,160			102,890
Sales of produced refined products (BPD)		113,040			60,596			107,950			26,077			100,010			98,760
Sales of refined products (BPD)⁽³⁾		113,040			60,850			108,560			26,250
Sales of refined products (BPD)⁽⁴⁾														100,400			100,620

Refinery utilization⁽⁴⁾		91.9	%		77.9	%		89.9	%		74.5	%
Refinery utilization⁽⁵⁾														84.5	%		82.9	%

Average per produced barrel⁽⁵⁾
Average per produced barrel⁽⁶⁾
Net sales	$	89.22		$	76.80		$	88.91		$	76.65		$	115.29		$	86.22
Cost of products⁽⁶⁾		79.80			70.10			81.26			70.80
Cost of products⁽⁷⁾														100.50			82.89

Refinery gross margin		9.42			6.70			7.65			5.85			14.79			3.33
Refinery operating expenses⁽⁷⁾		4.80			4.64			5.10			4.76
Refinery operating expenses⁽⁸⁾														5.98			5.91

Net operating margin	$	4.62		$	2.06		$	2.55		$	1.09		$	8.81		$	(2.58	)


Refinery operating expenses per throughput barrel													$	5.61		$	5.56

Feedstocks:
Sweet crude oil														97	%		99	%
Heavy sour crude oil														2	%		—	%
Other feedstocks and blends														1	%		1	%

Total														100	%		100	%


Sales of produced refined products:
Gasolines														37	%		41	%
Diesel fuels														31	%		30	%
Jet fuels														8	%		9	%
Lubricants														11	%		10	%
Asphalt														4	%		4	%
Gas oil / intermediates														7	%		2	%
LPG and other														2	%		4	%

Total														100	%		100	%


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2010			2009			2010			2009			2011			2010
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			201,350			208,190
Refinery production (BPD)⁽²⁾		230,630			185,480			227,060			138,190
Refinery throughput (BPD)⁽²⁾														213,520			222,410
Refinery production (BPD)⁽³⁾														209,500			216,960
Sales of produced refined products (BPD)		232,760			181,690			226,940			137,240			206,500			213,860
Sales of refined products (BPD)⁽³⁾		235,780			184,570			230,790			141,890
Sales of refined products (BPD)⁽⁴⁾														213,840			219,100

Refinery utilization⁽⁴⁾		88.8	%		83.0	%		86.5	%		80.5	%
Refinery utilization⁽⁵⁾														78.7	%		81.3	%

Average per produced barrel⁽⁵⁾
Average per produced barrel⁽⁶⁾
Net sales	$	89.25		$	78.11		$	89.53		$	70.16		$	113.28		$	87.40
Cost of products⁽⁶⁾		78.84			69.84			80.43			61.26
Cost of products⁽⁷⁾														97.56			81.84

Refinery gross margin		10.41			8.27			9.10			8.90			15.72			5.56
Refinery operating expenses⁽⁷⁾		5.14			4.77			5.16			5.17
Refinery operating expenses⁽⁸⁾														6.24			5.65

Net operating margin	$	5.27		$	3.50		$	3.94		$	3.73		$	9.48		$	(0.09	)


Refinery operating expenses per throughput barrel													$	5.98		$	5.43

Feedstocks:
Sour crude oil		39	%		44	%		37	%		52	%		27	%		35	%
Sweet crude oil		54	%		47	%		55	%		36	%		58	%		56	%
Heavy sour crude oil														5	%		1	%
Black wax crude oil		4	%		4	%		4	%		5	%		4	%		3	%
Other feedstocks and blends		3	%		5	%		4	%		7	%		6	%		5	%

Total		100	%		100	%		100	%		100	%		100	%		100	%


Sales of produced refined products:
Gasolines		48	%		45	%		49	%		52	%		45	%		51	%
Diesel fuels		31	%		32	%		31	%		31	%		33	%		30	%
Jet fuels		5	%		6	%		6	%		3	%		4	%		6	%
Fuel oil		3	%		2	%		2	%		3	%		2	%		2	%
Asphalt		4	%		2	%		3	%		2	%		4	%		3	%
Lubricants		5	%		6	%		5	%		4	%		6	%		4	%
Gas oil / intermediates		2	%		5	%		1	%		3	%		3	%		1	%
LPG and other		2	%		2	%		3	%		2	%		3	%		3	%

Total		100	%		100	%		100	%		100	%		100	%		100	%

~~barrel of~~for crude oil and feedstocks. Our processing of 100% lower priced West Texas Intermediate related crude oil combined with strong diesel and unseasonably high gasoline margins at all of our refineries helped fuel this margin improvement. 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%~~6% from ~~$96.7~~$127.5 million for the three months ended ~~September 30, 2009~~March 31, 2010 to ~~$130.3~~$134.7 million for the three months ended ~~September 30, 2010,~~March 31, 2011, due principally to increased repair and maintenance costs during the ~~inclusion of costs attributable to the operations of our Tulsa Refinery east facility acquired in December 2009 and higher refinery utility costs.~~current year first quarter.

General and Administrative Expenses

General and administrative expenses ~~increased slightly~~decreased 6% from ~~$16.7~~$17.9 million for the three months ended ~~September 30, 2009~~March 31, 2010 to ~~$16.9~~$16.8 million for the three months ended ~~September 30, 2010,~~March 31, 2011, due principally to ~~increased payroll costs.~~lower equity based compensation costs and fees for professional services.

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Depreciation and Amortization Expenses

Depreciation and amortization increased ~~21%~~13% from ~~$24~~$27.8 million for the three months ended ~~September 30, 2009~~March 31, 2010 to ~~$29.1~~$31.3 million for the three months ended ~~September 30, 2010.~~March 31, 2011. 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.~~2010.

Interest Expense

Interest expense was ~~$17.4~~$16.2 million for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$12.4~~$17.7 million for the three months ended ~~September 30, 2009.~~March 31, 2010. The ~~increase~~decrease was due principally to interest ~~incurred~~capitalized on the ~~$300 million Holly 9.875% senior notes due 2017 and the HEP 8.25% senior notes due 2018.~~UNEV Pipeline project. For the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ interest expense included $9$9.1 million and ~~$6.6~~$8.1 million, respectively, in interest costs attributable to HEP operations.

Income Taxes

~~Income taxes were $31.5~~For the three months ended March 31, 2011 we recorded income tax expense of $49 million compared to an income tax benefit of $16.7 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,March 31, 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.~~March 31, 2011. At ~~September 30, 2010,~~March 31, 2011, we had no outstanding borrowings and outstanding letters of credit totaling ~~$84.3~~$70 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.$330 million.

~~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~~$275 million senior secured revolving ~~credit agreement expiring in August 2011~~Credit Agreement (the “HEP Credit Agreement”)~~. The HEP Credit Agreement~~ that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for ~~other~~ general partnership purposes. In February 2011, HEP amended its previous credit agreement (expiring in August 2011), slightly, reducing the size of the credit facility from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The HEP Credit Agreement expires in February 2016; however, in the event that the 6.25% HEP Senior Notes (discussed later) are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the HEP Credit Agreement will expire on that date. At ~~September 30, 2010,~~March 31, 2011, HEP had outstanding borrowings totaling ~~$157~~$182 million under the HEP Credit Agreement, with unused borrowing capacity of ~~$143~~$93 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,~~HEP’s creditors have no other recourse to our ~~previous agreements to indemnify HEP’s controlling partner~~assets. Furthermore, our creditors have no recourse to the ~~extent it makes any payment in satisfaction~~assets of ~~debt service due on up to a $171 million aggregate principal amount of borrowings under the~~ HEP ~~Credit Agreement were terminated.~~and its consolidated subsidiaries.

~~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 under the HEP Credit agreement, 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~~does 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~~Our $300 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~~ mature in ~~net proceeds received was used for post-closing payments for inventories of crude oil~~June 2017 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 in 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 outstanding of 6.25% senior notes maturing in 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.

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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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,~~March 31, 2011, we had cash and cash equivalents of ~~$271.9~~$224.1 million and short-term investments in marketable securities of ~~$1.2~~$48.9 million.

Cash and cash equivalents ~~increased~~decreased by ~~$147.3~~$5 million during the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011. Net cash used for investing activities of $141 million exceeded cash provided by operating activities and financing activities of ~~$236~~$130.5 million and ~~$39.3~~$5.5 million, ~~respectively, exceeded cash used for investing activities of $127.9 million.~~respectively. Working capital ~~decreased~~increased by ~~$53.1~~$26.4 million during the ~~nine~~three 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.March 31, 2011.

Cash Flows — Operating Activities

~~Nine~~Three Months Ended ~~September 30, 2010~~March 31, 2011 Compared to ~~Nine~~Three Months Ended ~~September 30, 2009~~March 31, 2010

Net cash flows provided by operating activities were ~~$236~~$130.5 million for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$179.7~~net cash used by operating activities of $90 million for the ~~nine~~three months ended ~~September 30, 2009,~~March 31, 2010, an increase of ~~$56.3~~$220.5 million. Net income for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 was ~~$108.8~~$91 million, an increase of ~~$33.2~~$114.3 million compared to a net ~~income~~loss of ~~$75.6~~$23.3 million for the ~~nine~~three months ended ~~September 30, 2009.~~March 31, 2010. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense ~~interest rate swap~~and fair value adjustments ~~and noncontrolling interest in earnings of Rio Grande~~to derivative instruments resulted in an increase to operating cash flows of ~~$100.5~~$33.7 million for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$103.8~~$10.1 million for the same period in ~~2009.~~2010. Additionally, SLC Pipeline earnings, net of distributions ~~increased~~decreased operating cash flows by $0.4 million and $0.5 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and March 31, 2010, ~~compared to a $1.3 million decrease for the nine months ended September 30, 2009.~~respectively. Changes in working capital items increased cash flows by ~~$34.2~~$18.9 million for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$22.3~~a decrease of $71.1 million for the ~~nine~~three months ended ~~September 30, 2009.~~March 31, 2010. Additionally, for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, turnaround expenditures ~~decreased~~increased to ~~$11.5~~$16.9 million from ~~$33.1~~$7.3 million in ~~2009~~2010 due to ~~the planned~~a major maintenance turnaround project at our ~~Navajo~~Tulsa Refinery facilities that was completed in ~~the first quarter of 2009.~~January 2011.

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Cash Flows — Investing Activities and Planned Capital Expenditures

~~Nine~~Three Months Ended ~~September 30, 2010~~March 31, 2011 Compared to ~~Nine~~Three Months Ended ~~September 30, 2009~~March 31, 2010

Net cash flows used for investing activities were ~~$127.9~~$141 million for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$374.9~~$31.1 million for the ~~nine~~three months ended ~~September 30, 2009, a decrease~~March 31, 2010, an increase of ~~$247~~$109.9 million. Cash expenditures for properties, plants and equipment for the first ~~nine~~three months of ~~2010 decreased~~2011 increased to ~~$127.9~~$74 million from ~~$246~~$31.1 million for the same period in ~~2009.~~2010. These include HEP capital expenditures of ~~$8.1~~$11.5 million and ~~$27.5~~$1.9 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively. Capital expenditures were significantly ~~lower~~higher in the ~~nine~~three months ending ~~September 30, 2010~~March 31, 2011 due to ~~a higher level~~construction of ~~capital project initiatives in 2009 including refinery expansion projects. During~~ the ~~nine~~UNEV Pipeline system. Also, for the three months ended ~~September 30, 2009,~~March 31, 2011, we ~~acquired the Tulsa Refinery west facility from Sunoco for $157.8 million,~~ invested ~~$165.9~~$98.9 million in marketable securities and received proceeds of ~~$220.3~~$31.9 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~~2011 is ~~$159.6~~$142.4 million. Additionally, capital costs of ~~$38.8~~$11.7 million have been approved for refinery turnarounds and tank work. ~~Excluding capital reimbursement required by the Sinclair Tulsa purchase agreement, we~~We expect to spend approximately ~~$165~~$185 million in capital costs in ~~2010,~~2011, including capital projects approved in prior years. Our capital spending for ~~2010~~2011 is comprised of ~~$48.5~~$24 million for projects at the Navajo Refinery, ~~$10.8~~$13 million for projects at the Woods Cross Refinery, ~~$46.7~~ $70

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million for projects at the Tulsa Refinery, ~~$55~~$69 million for our portion of the ~~Salt Lake City, Utah to Las Vegas, Nevada pipeline~~UNEV Pipeline project, ~~(the “UNEV Pipeline”), $1.5~~$3 million for asphalt plant projects and ~~$2.5~~$6 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~~Currently, we are using an ~~additional~~existing third-party line for the transfer of ~~gasoline blend stocks which is currently in service.~~intermediates from the west facility to the east facility under a 10-year agreement. 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~~negotiating 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, during the first quarter of 2011 we ~~are planning to expand~~completed the expansion of the diesel ~~hydrotreater~~hydrotreating unit at the east facility toat an expected cost of $27 million. This expanded unit will permit the processing of all high sulfur diesel produced to ~~ULSD. This expansion is expected~~ULSD once the interconnecting pipelines are complete and available to ~~cost approximately $20 million~~move high sulfur diesel and ~~will use~~hydrogen produced in the ~~reactor that we acquired as part of the Tulsa Refinery~~ west facility ~~acquisition.~~to the east facility. We are currently planning to complete the integration projects byin the ~~end of the first quarter~~summer of 2011.

The combined Tulsa Refinery facilities also will be required to comply with new ~~Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”)~~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~~an annual average beginning in July ~~2012 and we~~2012. 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. WeOur Board of Directors have approved a project for $44 million 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. Also, 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~~regulations at an 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$10 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 purchase or use credits ~~to be~~ generated at the ~~Woods Cross and~~ Tulsa ~~Refineries in order~~Refinery to reduce benzene ~~down~~content 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~~Also, we will be installing a new storm water surge tank and upgrade several other processes at the refinery’s Artesia waste water treatment plant. These projects are expected to ~~comply starting after we became a large refiner in mid-2009.~~cost approximately $17 million.

Our Woods Cross ~~refinery~~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~~the refinery involves revamping its naphtha fractionation unit and installing ~~a new reformate splitter and~~ a benzene saturation unit at an estimated cost of ~~$18~~$10 million. These projects will reduce benzene levels in gasoline below the 1.3% annual average level. The Woods Cross Refinery will purchase credits to meet the 0.62% benzene requirement. 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.

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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~~its current ~~year’s~~year capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The ~~2010~~2011 HEP capital budget is comprised of ~~$4.8~~$5.8 million for maintenance capital expenditures and $6$20.1 million for expansion capital expenditures.

As described ~~above,~~under our Tulsa Refinery integration project, HEP is currently constructing five interconnecting pipelines between our Tulsa east and west refining facilities. The project is expected to cost approximately ~~$25~~$35 million with completion in the ~~first quarter~~summer of 2011. We are currently ~~finalizing~~negotiating 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~~Three Months Ended ~~September 30, 2010~~March 31, 2011 Compared to ~~Nine~~Three Months Ended ~~September 30, 2009~~March 31, 2010

Net cash flows provided by financing activities were ~~$39.3~~$5.5 million for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$253~~$89.8 million for the ~~nine~~three months ended ~~September 30, 2009,~~March 31, 2010, a decrease of ~~$213.7~~$84.3 million. During the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, we ~~received and repaid $310 million in advances under the Holly Credit Agreement,~~ paid ~~$0.8~~$0.3 million under our financing obligation to Plains, purchased ~~$1.3~~$2.1 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~~$8 million in dividends, received ~~a $9.5~~an $8.5 million contribution from our UNEV Pipeline joint venture partner and recognized ~~$1.3~~$0.3 million excess tax ~~expense~~benefit on our equity based compensation. ~~Also during this period,~~During the three months ended March 31, 2011, HEP received ~~$147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $52~~$30 million and repaid ~~$101~~$7 million under the HEP Credit Agreement, paid distributions of ~~$36.1~~$12.5 million to noncontrolling interests, incurred $3 million in deferred financing costs and purchased ~~$2.3~~$0.4 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~~three months ended ~~September 30, 2009,~~March 31, 2010, we ~~received $187.9 million in net proceeds upon the issuance of the Holly Senior Notes,~~ received and repaid ~~$94~~$310 million in advances under the Holly Credit Agreement, paid ~~$22.6~~$0.2 million under our financing obligation to Plains, paid $7.9 million in dividends, purchased ~~$1.2~~$1.1 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~~$1.3 million contribution from our UNEV Pipeline joint venture partner and recognized ~~$2.1~~$1 million in excess tax ~~benefits~~expense on our equity based compensation. ~~Also during this period,~~During the three months ended March 31, 2010, HEP received $147.5 million in net proceeds ~~of $58.4 million~~ upon the issuance of ~~additional common units,~~the HEP 8.25% Senior Notes, received ~~$197~~$33 million and repaid ~~$152~~$68 million ~~in advances~~ under the HEP Credit Agreement, paid distributions of ~~$23.4~~$12 million to noncontrolling ~~interest holders~~interests and purchased ~~$0.6~~$1.7 million in HEP common units in the open market 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.

- 4738 -

Contractual Obligations and Commitments

Holly Corporation

There were no significant changes to our contractual obligations during the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011.

HEP

In February 2011, HEP amended its previous credit agreement (expiring in August 2011), slightly, reducing the size of the credit facility from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The HEP Credit Agreement expires in February 2016; however, in the event that the 6.25% HEP Senior Notes are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the HEP Credit Agreement will expire on that date. During the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, HEP ~~repaid~~received net advances of ~~$49~~$23 million resulting in ~~$157~~$182 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.~~31, 2011.

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.~~2010. 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.~~2011.

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.

~~- 48 -~~

We periodically enter into derivative contracts in the form of commodity price swaps to mitigate price exposure with respect to:

our inventory positions;

natural gas purchases;

costs of crude oil;

prices of refined products; and

our refining margins.

As of March 31, 2011, we ~~entered into two types of hedging transactions.~~

~~We entered into multiple gasoline~~have outstanding commodity price swap contracts ~~relating to forecasted sales transactions of unleaded 87 gasoline produced at our Tulsa Refinery facilities in order~~serving as economic hedges to protect ~~margins on winter grade gasoline. Winter grade gasoline specifications allow for~~ the ~~blending~~value of ~~butane as an additive. Since the cost~~a temporary crude oil inventory build of ~~butane is subject~~105,000 barrels against price volatility and to ~~price risk (fluctuating prices), our refined product~~protect refining 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.

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~~6.2 million barrels of produced gasoline. These contracts 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 ameasured quarterly ~~basis to~~at 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(gains / losses) recorded directly 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.

~~HEP~~has been designated ~~this interest rate swap~~ as a cash flow ~~hedge. Based~~hedge and matures in February 2013.

This contract initially hedged variable LIBOR interest on ~~its assessment~~$171 million in outstanding HEP Credit Agreement debt. In May 2010, HEP repaid $16 million of ~~effectiveness using~~ the ~~change in variable cash flows method,~~ HEP ~~determined that this~~Credit Agreement debt and also settled a corresponding portion of its interest rate swap ~~is effective in offsetting the variability in interest payments on the $155~~agreement having a notional amount of $16 million ~~variable rate debt resulting from changes in LIBOR. Under hedge accounting,~~for $1.1 million. Upon payment, HEP ~~adjusts the cash flow hedge on~~reduced its swap liability and reclassified 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

~~- 49 -~~

~~or received on the variable leg of the swap against the expected future interest payments on the $155~~$1.1 million ~~variable rate debt. Any ineffectiveness is reclassified~~charge from accumulated other comprehensive ~~income~~loss to interest ~~expense. As~~expense, representing the application of ~~September 30, 2010, HEP had no ineffectiveness on its cash flow hedge.~~hedge accounting prior to settlement.

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⁾

Balance Sheet

Location of Offsetting

Offsetting

Derivative Instruments

Location

Fair Value

Balance

Amount

(Dollars in thousands)

March 31, 2011

Derivative designated as cash flow hedging instrument:

Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)

Other long-term liabilities

8,743

Accumulated other comprehensive loss

8,743

Derivatives not designated as hedging instruments:

Variable-to-fixed commodity price swap contracts (various inventory positions)

Prepayments and other current assets

6,555

Cost of products sold (decrease)

6,555

Fixed/variable-to-variable/fixed commodity price contracts (various inventory positions)

Accrued liabilities

5,960

Cost of products sold (increase)

5,960

- 40 -

Balance Sheet

Location of Offsetting

Offsetting

Derivative Instruments

Location

Fair Value

Balance

Amount

(Dollars in thousands)

December 31, 2010

Derivative designated as cash flow hedging instruments:

Variable-to-fixed commodity price swap contracts (forecasted volumes of natural gas purchases)

Accrued liabilities

Accumulated other comprehensive loss

Variable-to-fixed interest rate swap contract ($155 million LIBOR based debt interest payments)

Other long-term liabilities

10,026

Accumulated other comprehensive loss

10,026

Derivatives not designated as hedging instruments:

Fixed-to-variable rate swap contracts (various inventory positions)

Accrued liabilities

497

Cost of products sold (increase)

497

For the three months ended March 31, 2011, maturities and fair value adjustments attributable to our economic hedges resulted in a $3.7 million increase to costs of products sold.

There was no ineffectiveness on the cash flow hedges during the periods covered in these consolidated financial statements.


⁽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,~~March 31, 2011, 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,~~March 31, 2011, the estimated fair values of the Holly 9.875% Senior Notes, HEP 6.25% Senior Notes and HEP 8.25% Senior Notes were ~~$324~~$338.3 million, ~~$183.2~~$185 million and ~~$156.8~~$160.5 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~~$12.5 million, $5$4.2 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,~~March 31, 2011, borrowings outstanding under the HEP Credit Agreement were ~~$157~~$182 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%~~6.24%. For the unhedged $27 million portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.

At ~~September 30, 2010,~~March 31, 2011, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of ~~nine~~three 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

~~- 50 -~~

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 attributable to Holly Corporation stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under 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.~~EBITDA.

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


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Net income (loss) attributable to Holly Corporation stockholders	$	84,694		$	(28,094	)
Add income tax provision (subtract benefit)		49,011			(16,672	)
Add interest expense		16,204			17,722
Subtract interest income		(85	)		(59	)
Add depreciation and amortization		31,308			27,757

EBITDA	$	181,132		$	654

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.

- 5242 -

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,						Three Months Ended
	2010			2009			2010			2009			March 31,
	(Dollars in thousands, except per barrel amounts)												2011			2010
*Navajo Refinery*
Average sales price per produced barrel sold	$	87.60		$	78.15		$	88.98		$	69.21		$	110.99		$	88.06
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102			79,840			86,930
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	742,897		$	675,812		$	2,203,971		$	1,589,051		$	797,530		$	688,955


*Woods Cross Refinery*
Average sales price per produced barrel sold	$	94.86		$	80.87		$	93.71		$	66.87		$	108.77		$	89.52
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061			26,650			28,170
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	240,345		$	201,610		$	722,971		$	494,012		$	260,885		$	226,960


*Tulsa Refinery*
Average sales price per produced barrel sold	$	89.22		$	76.80		$	88.91		$	76.65		$	115.29		$	86.22
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077			100,010			98,760
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	927,859		$	428,147		$	2,620,209		$	545,673		$	1,037,714		$	766,358


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
Sum of refined products sales from produced products sold from our three refineries⁽¹⁾													$	2,096,129		$	1,682,273
Add refined product sales from purchased products and rounding⁽²⁾		24,586			21,539			93,093			83,579			75,804			41,506

Total refined product sales		1,935,687			1,327,108			5,640,244			2,712,315
Total refined products sales														2,171,933			1,723,779
Add direct sales of excess crude oil⁽³⁾		106,364			98,540			355,381			320,416			135,409			134,862
Add other refining segment revenue⁽⁴⁾		39,658			50,656			90,618			103,286			7,750			8,533

Total refining segment revenue		2,081,709			1,476,304			6,086,243			3,136,017			2,315,092			1,867,174
Add HEP segment sales and other revenues		46,558			40,805			132,730			108,136			45,005			40,689
Add corporate and other revenues		100			229			317			423			648			66
Subtract consolidations and eliminations		(37,379	)		(28,847	)		(108,152	)		(72,277	)		(34,160	)		(33,639	)

Sales and other revenues	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299		$	2,326,585		$	1,874,290

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,						Three Months Ended
	2010			2009			2010			2009			March 31,
	(Dollars in thousands, except per barrel amounts)												2011			2010
*Navajo Refinery*
Average cost of products per produced barrel sold	$	79.39		$	70.88		$	81.44		$	60.25		$	95.60		$	82.96
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102			79,840			86,930
Times number of days in period		92			92			273			273			90			90

Cost of products for produced products sold	$	673,272		$	612,944		$	2,017,211		$	1,383,331		$	686,943		$	649,054


*Woods Cross Refinery*
Average cost of products per produced barrel sold	$	73.08		$	65.68		$	74.02		$	55.22		$	89.87		$	74.72
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061			26,650			28,170
Times number of days in period		92			92			273			273			90			90

Cost of products for produced products sold	$	185,161		$	163,741		$	571,063		$	407,946		$	215,553		$	189,438


*Tulsa Refinery*
Average cost of products per produced barrel sold	$	79.80		$	70.10		$	81.26		$	70.80		$	100.50		$	82.89
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077			100,010			98,760
Times number of days in period		92			92			273			273			90			90

Cost of products for produced products sold	$	829,894		$	390,796		$	2,394,761		$	504,027		$	904,590		$	736,759


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		$	1,807,086		$	1,575,251
Add refined product costs from purchased products sold and rounding⁽²⁾		24,594			22,295			93,898			88,271			75,622			41,464

Total refined cost of products sold		1,712,921			1,189,776			5,076,933			2,383,575			1,882,708			1,616,715
Add crude oil cost of direct sales of excess crude oil⁽³⁾		105,091			97,400			351,643			317,954			132,880			133,667
Add other refining segment cost of products sold⁽⁴⁾		25,555			36,282			56,186			56,685			2,338			6,051

Total refining segment cost of products sold		1,843,567			1,323,458			5,484,762			2,758,214			2,017,926			1,756,433
Subtract consolidations and eliminations		(36,523	)		(28,020	)		(105,642	)		(71,196	)		(33,309	)		(32,569	)

Costs of products sold (exclusive of depreciation and amortization)	$	1,807,044		$	1,295,438		$	5,379,120		$	2,687,018		$	1,984,617		$	1,723,864

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,						Three Months Ended
	2010			2009			2010			2009			March 31,
	(Dollars in thousands, except per barrel amounts)												2011			2010
*Navajo Refinery*
Average refinery operating expenses per produced barrel sold	$	5.25		$	4.37		$	5.01		$	4.88		$	6.34		$	5.18
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102			79,840			86,930
Times number of days in period		92			92			273			273			90			90

Refinery operating expenses for produced products sold	$	44,523		$	37,790		$	124,094		$	112,044		$	45,557		$	40,527


*Woods Cross Refinery*
Average refinery operating expenses per produced barrel sold	$	6.11		$	6.44		$	5.86		$	6.45		$	6.43		$	6.20
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061			26,650			28,170
Times number of days in period		92			92			273			273			90			90

Refinery operating expenses for produced products sold	$	15,481		$	16,055		$	45,210		$	47,650		$	15,422		$	15,719


*Tulsa Refinery*
Average refinery operating expenses per produced barrel sold	$	4.80		$	4.64		$	5.10		$	4.76		$	5.98		$	5.91
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077			100,010			98,760
Times number of days in period		92			92			273			273			90			90

Refinery operating expenses for produced products sold	$	49,918		$	25,867		$	150,299		$	33,887		$	53,825		$	52,530


Sum of refinery operating expenses per produced products sold from our three refineries⁽¹⁾	$	109,922		$	79,712		$	319,603		$	193,581		$	114,804		$	108,776
Add other refining segment operating expenses and rounding⁽²⁾		6,835			6,023			19,199			16,209			7,275			5,818

Total refining segment operating expenses		116,757			85,735			338,802			209,790			122,079			114,594
Add HEP segment operating expenses		13,632			11,103			40,187			32,076			12,796			13,060
Add corporate and other costs		6			7			24			34			(6	)		6
Subtract consolidations and eliminations		(132	)		(128	)		(375	)		(382	)		(126	)		(116	)

Operating expenses (exclusive of depreciation and amortization)	$	130,263		$	96,717		$	378,638		$	241,518		$	134,743		$	127,544

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,						Three Months Ended
	2010			2009			2010			2009			March 31,
	(Dollars in thousands, except per barrel amounts)												2011			2010
*Navajo Refinery*
Net operating margin per barrel	$	2.96		$	2.90		$	2.53		$	4.08		$	9.05		$	(0.08	)
Add average refinery operating expenses per produced barrel		5.25			4.37			5.01			4.88			6.34			5.18

Refinery gross margin per barrel		8.21			7.27			7.54			8.96			15.39			5.10
Add average cost of products per produced barrel sold		79.39			70.88			81.44			60.25			95.60			82.96

Average sales price per produced barrel sold	$	87.60		$	78.15		$	88.98		$	69.21		$	110.99		$	88.06
Times sales of produced refined products sold (BPD)		92,180			93,996			90,730			84,102			79,840			86,930
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	742,897		$	675,812		$	2,203,971		$	1,589,051
Refined products sales from produced products sold													$	797,530		$	688,955


*Woods Cross Refinery*
Net operating margin per barrel	$	15.67		$	8.75		$	13.83		$	5.20		$	12.47		$	8.60
Add average refinery operating expenses per produced barrel		6.11			6.44			5.86			6.45			6.43			6.20

Refinery gross margin per barrel		21.78			15.19			19.69			11.65			18.90			14.80
Add average cost of products per produced barrel sold		73.08			65.68			74.02			55.22			89.87			74.72

Average sales price per produced barrel sold	$	94.86		$	80.87		$	93.71		$	66.87		$	108.77		$	89.52
Times sales of produced refined products sold (BPD)		27,540			27,098			28,260			27,061			26,650			28,170
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	240,345		$	201,610		$	722,971		$	494,012
Refined products sales from produced products sold													$	260,885		$	226,960


*Tulsa Refinery*
Net operating margin per barrel	$	4.62		$	2.06		$	2.55		$	1.09		$	8.81		$	(2.58	)
Add average refinery operating expenses per produced barrel		4.80			4.64			5.10			4.76			5.98			5.91

Refinery gross margin per barrel		9.42			6.70			7.65			5.85			14.79			3.33
Add average cost of products per produced barrel sold		79.80			70.10			81.26			70.80			100.50			82.89

Average sales price per produced barrel sold	$	89.22		$	76.80		$	88.91		$	76.65		$	115.29		$	86.22
Times sales of produced refined products sold (BPD)		113,040			60,596			107,950			26,077			100,010			98,760
Times number of days in period		92			92			273			273			90			90

Refined product sales from produced products sold	$	927,859		$	428,147		$	2,620,209		$	545,673
Refined products sales from produced products sold													$	1,037,714		$	766,358


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
Sum of refined products sales from produced products sold from our three refineries⁽¹⁾													$	2,096,129		$	1,682,273
Add refined product sales from purchased products and rounding⁽²⁾		24,586			21,539			93,093			83,579			75,804			41,506

Total refined product sales		1,935,687			1,327,108			5,640,244			2,712,315
Total refined products sales														2,171,933			1,723,779
Add direct sales of excess crude oil⁽³⁾		106,364			98,540			355,381			320,416			135,409			134,862
Add other refining segment revenue⁽⁴⁾		39,658			50,656			90,618			103,286			7,750			8,533

Total refining segment revenue		2,081,709			1,476,304			6,086,243			3,136,017			2,315,092			1,867,174
Add HEP segment sales and other revenues		46,558			40,805			132,730			108,136			45,005			40,689
Add corporate and other revenues		100			229			317			423			648			66
Subtract consolidations and eliminations		(37,379	)		(28,847	)		(108,152	)		(72,277	)		(34,160	)		(33,639	)

Sales and other revenues	$	2,090,988		$	1,488,491		$	6,111,138		$	3,172,299		$	2,326,585		$	1,874,290

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.~~March 31, 2011.

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.

- 5949 -

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”)~~FERC in proceedings brought by us and other parties against ~~SFPP, L.P. (“SFPP”).~~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 byas limited 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 regarding the East Line’s Phase I expansion rates 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 regarding the East Line’s Phase II expansion rates covering the period from December ~~2008~~2007 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

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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. MRC is considering an invitation by the other companies to participate in the group based on an allocation of 9.16 percent of the group’s past and ongoing investigation and other 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~~Two wrongful death lawsuits and two personal injury lawsuits seeking damages, including punitive damages, were filed on behalf of the estates of the two ~~survivors~~deceased workers and on behalf of the ~~estate of the~~ two ~~deceased workers~~survivors in state court in Dallas County, Texas (two lawsuits) and state court in Eddy County, New Mexico (two lawsuits). ~~Two of the~~The two Texas cases have been consolidated and are set for trial in ~~April and May~~September of ~~2011, respectively.~~2011. One of the cases in New Mexico is set for trial in March of 2012. 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 –~~Complaint — 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~~took place on November 17, 2010, at which time counsel for the parties discussed possible settlement options. The parties were unable to ~~take place in November 2010. Following the informal review, Navajo will have the right to challenge the citations before the~~reach an agreement. Thus, OHSB filed an administrative complaint with New ~~Mexico~~Mexico’s Occupational Health and Safety Review Commission (“~~OSHRC”~~OHSRC”), on December 20, 2010. Navajo will challenge the citations before the OHSRC, and ~~have~~filed its answer to the ~~right to take discovery.~~complaint on January 6, 2011. Discovery is under way at this time. OHSRC granted the parties’ joint request that a hearing commence no sooner than September 5, 2011, but the specific hearing date has not yet been established.

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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”) standard 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~~OHSRC 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

~~- 61 -~~

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~~OHSRC on August 11, 2010. On August 23, 2010, the ~~OSHRC~~OHSRC 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”)~~PSM standard. OSHA proposed penalties totaling $57,150. ~~HRM–Tulsa~~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,~~Discovery is currently underway, and the hearing in ~~which the discovery schedule will be established, will take place on November 3, 2010.~~this matter is scheduled to begin July 25, 2011.

OSHA began the NEP inspection of our Tulsa Refinery west facility on September 14, 2010. ~~The inspection~~On March 14, 2011, OSHA issued a citation alleging 15 serious violations of federal workplace standards. OSHA proposed penalties totaling $62,500. On April 4, a settlement was reached that was favorable to HRM-Tulsa and the penalty was reduced to $31,750.

On March 28, 2011, OSHA issued a serious citation to HRM-Tulsa with respect to the Tulsa west facility, alleging one facility siting and two housekeeping violations, which stemmed from its investigation of an employee complaint that it received during the NEP inspection. OSHA proposed penalties of $6,275. HRM Tulsa is ~~ongoing.~~engaged in informal settlement negotiations with OSHA, but was unable to reach a resolution and filed its notice of contest, challenging each citation item, on April 18, 2011. It is too early to predict the likely outcome or cost, if any, of this matter.

Discharge Permit Appeal –— Tulsa Refinery West Facility

Our subsidiary, ~~HRM Tulsa~~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~~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~~are 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.

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Clean Air Act Notice of Violation — Tulsa Refinery East and West Facilities

HRM Tulsa received a notification from the ODEQ that the agency intends to seek a fine of $192,500 for alleged violations of the Clean Air Act at the Tulsa Refinery West Facility. The ODEQ’s primary area of concern is the number of valves that the facility has classed as “Difficult to Monitor.” The agency maintains that no more than 3% of valves can be so designated. HRM Tulsa interprets the applicable regulation as instead only imposing the 3% cap on new units. The parties have agreed to ask for a formal regulatory interpretation from the Environmental Protection Agency to assist them in resolving the dispute. HRM Tulsa believes that even if the ODEQ’s interpretation is correct, the proposed fine is excessive. The company will seek to have the fine reduced. The same notification also disclosed the agency’s intent to seek a separate fine of $17,500 for alleged Clean Air Act violations at the Tulsa Refinery East Facility. These alleged violations include a failure to conduct monthly monitoring of components previously found to be leaking and the discovery of three open ended lines, one of which was alleged to be leaking at the time of discovery. HRM Tulsa is currently in discussions with ODEQ regarding the alleged violations at the East Facility. It is not possible at this point to estimate what amount, if any, will ultimately be assessed for any of the foregoing items.

Litigation Related to the Merger with Frontier Oil Corporation

Twelve substantially similar shareholder lawsuits styled as class actions have been filed by alleged Frontier shareholders challenging our proposed “merger of equals” with Frontier and naming as defendants Frontier, its board of directors and, in certain instances, us and our wholly owned subsidiary, North Acquisition, Inc., as aiders and abettors. To date, such shareholder actions have been filed in Harris County, Texas, Laramie County, Wyoming, the U.S. District Court for the Northern District of Texas, and the U.S. District Court for the Southern District of Texas.

The lawsuits filed in the District Courts of Harris County, Texas are entitled: Adam Walker, Individually and On Behalf of All Others Similarly Situated vs. Frontier Oil Corporation, et al. (filed February 22, 2011), Andrew Goldberg, on Behalf of Himself and All Other Similarly Situated Shareholders of Frontier Oil Corporation v. Frontier Oil Corporation, et al. (filed February 24, 2011), L.A. Murphy, On Behalf of Herself and All Others Similarly Situated v. Paul B. Loyd, Jr., et al. (filed February 24, 2011), Zhixin Huang v. Frontier Oil Corp., et al. (filed February 24, 2011), Robert Pettigrew, individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed February 25, 2011), Walter E. Ryan, Jr., On Behalf of Himself and All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed February 25, 2011), Christopher Borrelli, Individually and on Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed March 2, 2011), and Randy Whitman, Individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed on March 8, 2011). The lawsuit filed in the District Court of Laramie County, Wyoming is entitled Thomas Greulich, Individually and on Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed March 1, 2011). The lawsuit filed in the U.S. District Court for the Northern District of Texas is entitled Angelo Chiarelli, On Behalf of Himself and All Others Similarly Situated v. Holly Corporation, et al. (filed on March 2, 2011). The lawsuits filed in the U.S. District Court for the Southern District of Texas are entitled Tim Wilcox, Individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed on March 7, 2011), and Jackie A. Rhymes, individually and on behalf of others similarly situated v. Michael Jennings, et al. (filed on March 17, 2011).

These lawsuits generally allege that (1) the consideration to be received by Frontier’s shareholders in the merger is inadequate, (2) the Frontier directors breached their fiduciary duties by, among other things, approving the merger at an inadequate price under circumstances involving certain alleged conflicts of interest, (3) the merger agreement includes preclusive deal protection provisions, and (4) Frontier, and in some cases we and North Acquisition, Inc., aided and abetted Frontier’s board of directors in breaching its fiduciary duties to Frontier’s shareholders. The shareholder actions seek various remedies, including enjoining the transaction from being consummated in accordance with its agreed-upon terms, compensatory damages, and costs and disbursements relating to the lawsuits.

In the cases pending in Texas state court, on March 21, 2011, plaintiff in the Walker lawsuit filed an amended petition alleging that Frontier’s current directors also breached their fiduciary duties by failing to disclose

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material information or making materially inadequate disclosures concerning the proposed merger in the registration statement on Form S-4. On March 25, 2011, the lawsuits pending in the District Court of Harris County, Texas, were consolidated under the style In re: Frontier Oil Corp., Cause No. 2011-11451, and interim class counsel was appointed on April 12, 2011.

With respect to the federal lawsuits, on March 24, 2011, plaintiffs in the lawsuits pending in the United States District Court for the Southern District of Texas filed a motion to consolidate the Wilcox and Rhymes cases pending in that district and to appoint interim lead counsel. On April 7, 2011, plaintiffs in the Wilcox and Rhymes cases filed substantially similar amended complaints. In addition to the claims described in general above, these lawsuits also allege that the defendants violated Sections 14(a) and 20(a) of the Exchange Act by making untrue statements of material fact and omitting to state material facts necessary to make the statements that were made not misleading in the registration statement on Form S-4.

The defendants intend to vigorously defend these and any future lawsuits, as they believe that they have valid defenses to all claims and that the lawsuits are entirely without merit.

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–~~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.

~~- 62 -~~

Exhibit Index


Exhibit ~~Number~~
Number		Description
2.1		Agreement and Plan of Merger, dated as of February 21, 2011, among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K filed February, 22, 2011, File No. 1-03876).

10.1		Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.5 of the Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.2		Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011, between Holly Refining & Marketing — Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.8 of the Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.3		Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement), effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing-Woods Cross and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.4		Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.14 of the Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.5		Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing-Tulsa LLC and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.17 of the Registrant’s Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).

10.6		Second Amended and Restated Credit Agreement, dated as of February 14, 2011, among Holly Energy Partners — Operating, L.P., Wells Fargo Bank, N.A., as administrative agent and an issuing bank, Union Bank, N.A., as syndication agent, BBVA Compass Bank and U.S. Bank N.A., as co-documentation agents, and certain other lenders (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.’s Current Report on Form 8-K filed February 18, 2011, File No. 1-32225).

10.7*		Holly Corporation Amended and Restated Change in Control Agreement Policy (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed March 1, 2011, File No. 1-03876).

10.8*		Holly Corporation Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed February 20, 2008, File No. 1-03876).

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			Page
PART I.	FINANCIAL INFORMATION

Forward-Looking Statements		3

Definitions				4
Item 1. Financial Statements
Consolidated Balance Sheets March 31, 2011 (Unaudited) and December 31, 2010		6
Consolidated Statements of Income (Unaudited) Three Months Ended March 31, 2011 and 2010		7
Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2011 and 2010		8
Consolidated Statements of Comprehensive Income (Loss) (Unaudited) Three Months Ended March 31, 2011 and 2010		9
Notes to Consolidated Financial Statements (Unaudited)		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		42
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles		42
Item 4. Controls and Procedures		49
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	~~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
				50
Item 6. Exhibits	~~Exhibits~~			63
				54
Signatures		55
Index to Exhibits	64	56
EX-10.9
EX-10.10
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


	September 30,		December 31,		March 31,		December 31,
	2010		2009		2011		2010
	(In thousands)				(In thousands)
Crude oil	$	96,706	$	60,874	$	83,513	$	96,570
Other raw materials and unfinished products⁽¹⁾		48,521		42,783		69,485		68,792
Finished products⁽²⁾		223,033		155,925		271,787		188,274
Process chemicals⁽³⁾		22,492		22,823		22,532		22,512
Repairs and maintenance supplies and other		23,263		21,108		26,139		24,219

Total inventory	$	414,015	$	303,513	$	473,456	$	400,367


	September 30,			December 31,			March 31,			December 31,
	2010			2009			2011			2010
	(In thousands)						(In thousands)
Holly 9.875% Senior Notes
Principal	$	300,000		$	300,000		$	300,000		$	300,000
Unamortized discount		(10,767	)		(11,549	)		(10,209	)		(10,491	)

		289,233			288,451			289,791			289,509

Holly financing obligation
Principal		39,050			39,809			38,504			38,781


Total Holly long-term debt		328,283			328,260			328,295			328,290


HEP Credit Agreement		157,000			206,000			182,000			159,000

HEP 6.25% Senior Notes
Principal		185,000			185,000			185,000			185,000
Unamortized discount		(11,620	)		(13,593	)		(10,304	)		(10,961	)
Unamortized premium – dedesignated fair value hedge		1,531			1,791

Unamortized premium — dedesignated fair value hedge								1,357			1,444
		174,911			173,198
								176,053			175,483
HEP 8.25% Senior Notes
Principal		150,000			—			150,000			150,000
Unamortized discount		(2,288	)		—			(2,135	)		(2,212	)

		147,712			—			147,865			147,788


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			505,918			482,271


Total long-term debt	$	650,906		$	707,458		$	834,213		$	810,561


				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	)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2010			2009			2010			2009			2011			2010
				(In thousands)									(In thousands)
Service cost – benefit earned during the period	$	1,149		$	1,158		$	3,446		$	3,236
Service cost — benefit earned during the period													$	1,267		$	1,141
Interest cost on projected benefit obligations		1,288			1,287			3,865			3,707			1,281			1,286
Expected return on plan assets		(1,144	)		(959	)		(3,432	)		(2,883	)		(1,339	)		(1,124	)
Amortization of prior service cost		98			98			293			293			98			98
Amortization of net loss		549			1,024			1,647			2,861			533			624

Net periodic pension expense	$	1,940		$	2,608		$	5,819		$	7,214		$	1,840		$	2,025


~~(1)~~		~~Includes cash flows attributable to discontinued operations.~~


						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


(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.


				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⁾


	Holly Corporation									Holly
	Stockholders’			Noncontrolling			Total			Corporation
	Equity			Interest			Equity			Stockholders’			Noncontrolling			Total
				(In thousands)						Equity			Interest			Equity
Balance at December 31, 2009	$	619,039		$	588,742		$	1,207,781
										(In thousands)
Balance at December 31, 2010										$	697,419		$	590,720		$	1,288,139

Net income		89,245			19,557			108,802			84,694			6,317			91,011
Dividends		(23,981	)		—			(23,981	)		(8,001	)		—			(8,001	)
Distributions to noncontrolling interest holders		—			(36,139	)		(36,139	)		—			(12,485	)		(12,485	)
Other comprehensive loss		(660	)		(2,804	)		(3,464	)
Other comprehensive income											380			841			1,221
Contribution from joint venture partner		—			9,500			9,500			—			8,500			8,500
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			1,084			670			1,754
Tax expense from equity based compensation arrangements		(1,512	)		—			(1,512	)
Tax benefit from equity based compensation arrangements											261			—			261
Purchase of HEP units for restricted grants		—			(2,276	)		(2,276	)		—			(399	)		(399	)
Purchase of treasury stock⁽¹⁾		(1,308	)		—			(1,308	)		(2,051	)		—			(2,051	)


Balance at September 30, 2010	$	687,127		$	578,350		$	1,265,477
Balance at March 31, 2011										$	773,786		$	594,164		$	1,367,950


(1)		~~Represents~~Includes 40,673 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.


(1)		HEP segment revenues from external customers were ~~$9.2~~$10.9 million and ~~$12.4~~$7.1 million for the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009, respectively, and $24.7 million and $36.4 million for the nine months ended September 30, 2010 and 2009,~~ respectively.


	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	%


(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, Oklahoma, Kansas, Missouri, Texas and northern Mexico.

(2)		The HEP segment involves all of the operations of ~~HEP.~~ HEP which 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


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

(2)		Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.

(3)		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)~~(4)		Includes refined products purchased for resale.

~~(4)~~(5)		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 tois 256,000 BPSD.


~~(5)~~(6)		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)~~(7)		Transportation ~~terminal and refinery storage~~ costs billed from HEP are included in cost of products.

~~(7)~~(8)		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.


*~~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%~~


(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.


(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.


(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.


		~~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.~~


	HOLLY CORPORATION
	(Registrant)



Date: ~~November 5, 2010~~May 6, 2011		/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)


Exhibit
Number		Description
10.9* +		Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Matthew P. Clifton

10.10* +		Waiver Agreement, dated as of February 21, 2011, by and between Holly Corporation and Bruce R. Shaw

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,~~March 31, 2011, 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.

*		Constitutes management contracts or compensatory plans or arrangements

**		Furnished electronically herewith.