Edgar Filing: HollyFrontier Corp

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

¨	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

HOLLYFRONTIER 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.)

2828 N. Harwood, Suite 1300 Dallas, Texas		75201
(Address of principal executive offices)		(Zip Code)

(214) 871-3555

Registrant’s telephone number, including area code

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer	x	Accelerated filer ¨

Non-accelerated filer	¨	Smaller reporting company¨

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

209,234,863 shares of Common Stock, par value $.01 per share, were outstanding on October 28, 2011.

HOLLYFRONTIER CORPORATION

INDEX


		Page
PART I. FINANCIAL INFORMATION

Forward-Looking Statements			3

Definitions			4

Item 1.	Financial Statements

	Consolidated Balance Sheets September 30, 2011 (Unaudited) and December 31, 2010		6

	Consolidated Statements of Income (Unaudited) Three and Nine Months Ended September 30, 2011 and 2010		7

	Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2011 and 2010		8

	Consolidated Statements of Comprehensive Income (Unaudited) Three and Nine Months Ended September 30, 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		32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		53

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles			53

Item 4.	Controls and Procedures		56

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		57

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		60

Item 6.	Exhibits		60

Signatures			61

Index to Exhibits			62

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

Holly Corporation (“Holly”) changed its name to HollyFrontier Corporation (“HollyFrontier” or “HollyFrontier Corporation”) in connection with the consummation of its “merger of equals” with Frontier Oil Corporation (“Frontier”), which became effective on July 1, 2011. References herein to HollyFrontier Corporation with respect to time periods prior to July 1, 2011 include Holly and its consolidated subsidiaries and do not include Frontier and its consolidated subsidiaries. References herein to HollyFrontier with respect to time periods from and after July 1, 2011 include the operations of the merged Frontier business. Unless otherwise specified, the financial statements included herein include financial information for the merged Frontier business operations for the period July 1, 2011 to September 30, 2011. 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 HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person. Also, the words “we,” “our,” “ours” and “us” generally include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier with certain exceptions where there are transactions or obligations between HEP and HollyFrontier 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 HollyFrontier. 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 Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and those in Part II, Item 1 “Legal Proceedings” 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;

•

our ability to realize fully or at all the anticipated benefits of our “merger of equals” with Frontier; and

•

other financial, operational and legal risks and uncertainties detailed from time to time in our SEC 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 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, 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.

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DEFINITIONS

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

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

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

“BPD” means the number of barrels per calendar day of crude oil or petroleum products.

“BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum products.

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

“Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is 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 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.

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

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

“Paraffinic oil” is a high paraffinic, high gravity oil produced by extracting aromatic 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 turning it back to a liquid in order to purify, fractionate or form the desired products.

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Item 1. Financial Statements

HOLLYFRONTIER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2011			December 31, 2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents (HEP: $1,802 and $403, respectively)	$	1,582,859		$	229,101
Marketable securities		133,445			1,343

Accounts receivable: Product and transportation (HEP: $23,821 and $22,508, respectively)		584,792			299,081
Crude oil resales		756,891			694,035

		1,341,683			993,116

Inventories: Crude oil and refined products		1,168,129			353,636
Materials and supplies (HEP: $703 and $202, respectively)		97,390			46,731

		1,265,519			400,367
Income taxes receivable		—			51,034
Prepayments and other (HEP: $942 and $573, respectively)		55,582			28,474

Total current assets		4,379,088			1,703,435

Properties, plants and equipment, at cost (HEP: $583,852 and $552,398, respectively)		3,533,309			2,215,828
Less accumulated depreciation (HEP: $(80,604) and $(60,300), respectively)		(536,781	)		(459,137	)

		2,996,528			1,756,691

Marketable securities (long-term)		43,049			—
Other assets: Turnaround costs		62,043			69,533
Goodwill (HEP: $81,602 and $81,602)		2,317,756			81,602
Intangibles and other (HEP: $74,489 and $72,434, respectively)		117,999			90,214

		2,497,798			241,349

Total assets	$	9,916,463		$	3,701,475

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $7,683 and $10,238, respectively)	$	2,102,915		$	1,317,446
Income taxes payable		140,086			—
Accrued liabilities (HEP: $11,998 and $21,206, respectively)		137,839			72,409

Total current liabilities		2,380,840			1,389,855

Long-term debt (HEP: $527,213 and $482,271, respectively)		1,224,987			810,561
Deferred income taxes		511,083			131,935
Other long-term liabilities (HEP: $8,144 and $10,809, respectively)		138,763			80,985

Equity:
HollyFrontier stockholders’ equity:
Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued		—			—
Common stock $.01 par value – 320,000,000 shares authorized; 255,962,866 and 152,692,864 shares issued as of September 30, 2011 and December 31, 2010, respectively		2,560			1,526
Additional capital		3,895,618			193,615
Retained earnings		1,866,873			1,206,328
Accumulated other comprehensive loss		(12,700	)		(26,246	)
Common stock held in treasury, at cost – 46,728,003 and 46,163,488 shares as of September 30, 2011 and December 31, 2010, respectively		(697,421	)		(677,804	)

Total HollyFrontier stockholders’ equity		5,054,930			697,419
Noncontrolling interest		605,860			590,720

Total equity		5,660,790			1,288,139

Total liabilities and equity	$	9,916,463		$	3,701,475

Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of September 30, 2011 and December 31, 2010. HEP is a consolidated variable interest entity.

Holly Corporation changed its name to HollyFrontier Corporation in connection with the consummation of its “merger of equals” with Frontier Oil Corporation which became effective on July 1, 2011. The financial statements included herein reflect financial information of the former Frontier business operations beginning July 1, 2011.

See accompanying notes.

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HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(In thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Sales and other revenues	$	5,173,398		$	2,090,988		$	10,467,116		$	6,111,138

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		3,989,927			1,807,044			8,421,639			5,379,120
Operating expenses (exclusive of depreciation and amortization)		227,883			130,263			501,971			378,638
General and administrative expenses (exclusive of depreciation and amortization)		43,141			16,925			78,641			50,623
Depreciation and amortization		43,240			29,138			106,380			85,719

Total operating costs and expenses		4,304,191			1,983,370			9,108,631			5,894,100

Income from operations		869,207			107,618			1,358,485			217,038

Other income (expense):
Earnings of equity method investments		532			570			1,739			1,595
Interest income		204			64			946			758
Interest expense		(25,074	)		(17,368	)		(56,471	)		(56,113	)
Merger transaction costs		(9,100	)		—			(15,114	)		—

		(33,438	)		(16,734	)		(68,900	)		(53,760	)

Income before income taxes		835,769			90,884			1,289,585			163,278

Income tax provision:
Current		296,670			9,042			461,210			48,964
Deferred		8,088			22,452			4,520			5,512

		304,758			31,494			465,730			54,476

Net income		531,011			59,390			823,855			108,802

Less net income attributable to noncontrolling interest		7,923			8,213			23,838			19,557

Net income attributable to HollyFrontier stockholders	$	523,088		$	51,177		$	800,017		$	89,245

Earnings per share attributable to HollyFrontier stockholders:
Basic	$	2.50		$	0.48		$	5.66		$	0.84

Diluted	$	2.48		$	0.48		$	5.63		$	0.83

Cash dividends declared per common share	$	1.09		$	0.08		$	1.24		$	0.23

Average number of common shares outstanding:
Basic		209,583			106,420			141,353			106,344
Diluted		210,579			107,134			142,092			107,062

See accompanying notes.

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HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	823,855		$	108,802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		106,380			85,719
Earnings of equity method investments, net of distributions		198			406
Deferred income taxes		4,520			5,512
Equity based compensation expense		15,535			7,814
Change in fair value – derivative instruments		(5,920	)		1,464
(Increase) decrease in current assets:
Accounts receivable		389,289			43,984
Inventories		(195,575	)		(110,502	)
Income taxes receivable		51,034			11,803
Prepayments and other		7,778			(304	)
Current assets of discontinued operations		—			2,195
Increase (decrease) in current liabilities:
Accounts payable		(297,080	)		69,030
Income taxes payable		182,468			—
Accrued liabilities		28,999			17,971
Turnaround expenditures		(27,985	)		(11,453	)
Other, net		5,707			3,527

Net cash provided by operating activities		1,089,203			235,968

Cash flows from investing activities:
Additions to properties, plants and equipment		(242,730	)		(119,885	)
Additions to properties, plants and equipment – HEP		(31,493	)		(8,054	)
Increase in cash due to merger with Frontier		872,158			—
Investment in Sabine Biofuels		(9,125	)		—
Purchases of marketable securities		(370,042	)		—
Sales and maturities of marketable securities		194,386			—

Net cash provided by (used for) investing activities		413,154			(127,939	)

Cash flows from financing activities:
Borrowings under credit agreement		—			310,000
Repayments under credit agreement		—			(310,000	)
Borrowings under credit agreement – HEP		93,000			52,000
Repayments under credit agreement – HEP		(50,000	)		(101,000	)
Proceeds from issuance of senior notes – HEP		—			147,540
Principal tender on 8.5% senior notes		(15	)		—
Repayments under financing obligation		(857	)		(760	)
Purchase of treasury stock		(38,955	)		(1,308	)
Contribution from joint venture partner		27,500			9,500
Dividends		(129,377	)		(23,889	)
Distributions to noncontrolling interest		(37,929	)		(36,139	)
Excess tax benefit from equity based compensation		1,399			(1,313	)
Purchase of units for restricted grants – HEP		(1,641	)		(2,276	)
Deferred financing costs		(11,724	)		(3,121	)
Issuance of common stock upon exercise of options		—			61

Net cash provided by (used for) financing activities		(148,599	)		39,295

Cash and cash equivalents:
Increase for the period		1,353,758			147,324
Beginning of period		229,101			124,596

End of period	$	1,582,859		$	271,920

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	50,570		$	49,051
Income taxes	$	225,499		$	45,040

See accompanying notes.

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HOLLYFRONTIER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	531,011		$	59,390		$	823,855		$	108,802
Other comprehensive income (loss):
Securities available-for-sale:
Unrealized loss on available-for-sale securities		(649	)		(51	)		(1,032	)		(58	)
Reclassification adjustment to net income on sale or maturity of marketable securities		(6	)		—			60			—

Total unrealized loss on available-for-sale securities		(655	)		(51	)		(972	)		(58	)

Hedging instruments:
Change in fair value of cash flow hedging instruments		23,272			(1,780	)		24,864			(4,837	)
Reclassification adjustment to net income on settlement of cash flow hedging instruments		—			(65	)		—			1,011

Total unrealized gain (loss) on hedging instruments		23,272			(1,845	)		24,864			(3,826	)

Retirement medical obligation adjustment		9			—			9			—

Other comprehensive income (loss) before income taxes		22,626			(1,896	)		23,901			(3,884	)
Income tax expense (benefit)		8,520			(558	)		8,618			(420	)

Other comprehensive income (loss)		14,106			(1,338	)		15,283			(3,464	)

Total comprehensive income		545,117			58,052			839,138			105,338

Less noncontrolling interest in comprehensive income		8,640			7,752			25,575			16,753

Comprehensive income attributable to HollyFrontier stockholders	$	536,477		$	50,300		$	813,563		$	88,585

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Description of Business and Presentation of Financial Statements

Holly Corporation (“Holly”) changed its name to HollyFrontier Corporation (“HollyFrontier” or “HollyFrontier Corporation”) in connection with the consummation of its “merger of equals” with Frontier Oil Corporation (“Frontier”), which became effective on July 1, 2011 (see Note 2). References herein to HollyFrontier Corporation with respect to time periods prior to July 1, 2011 include Holly and its consolidated subsidiaries and do not include Frontier and its consolidated subsidiaries. References herein to HollyFrontier with respect to time periods from and after July 1, 2011 include the operations of the merged Frontier businesses. Unless otherwise specified, the financial statements included herein include financial information for the merged Frontier business operations for the period July 1, 2011 to September 30, 2011. 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 HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person. Also, the words “we,” “our,” “ours” and “us” generally include HEP and its subsidiaries as consolidated subsidiaries of HollyFrontier with certain exceptions where there are transactions or obligations between HEP and HollyFrontier 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 HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

As of September 30, 2011, we:

•

owned and operated five 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”), two refinery facilities located in Tulsa, Oklahoma (collectively, the “Tulsa Refinery”), a refinery in El Dorado, Kansas (the “El Dorado Refinery”) and a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”);

•

owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona, New Mexico and Texas;

•

owned a 75% interest in a 12-inch refined products pipeline project, under construction, 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”);

•

owned Ethanol Management Company (“EMC”), a products terminal and blending facility near Denver, Colorado and a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”) a development stage biodiesel production facility located in Port Arthur, Texas, and

•

owned a 34% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and 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 (“SLC Pipeline”), a 95-mile intrastate 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, 2011, the consolidated results of operations and comprehensive income for the three and the nine months ended September 30, 2011 and 2010 and consolidated cash flows for the nine months ended September 30, 2011 and 2010 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

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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, 2010 that has been filed with the SEC.

On August 3, 2011, our Board of Directors declared a two-for-one stock split, payable in the form of a common stock dividend for each issued and outsatnding share of our common stock. The stock dividend was paid August 31, 2011 to all shareholders of record on August 24, 2011. We have retained the current par value of $0.01 per share for all shares of our common stock and have reclassified $763,000 (the amount equal to the par value of the additional stock issued) from additional capital to common stock to reflect this stock split at December 31, 2010. All references to share and per share amounts in these consolidated financial statements and related disclosures have been adjusted to reflect the effect of the stock split for all periods presented.

Beginning July 1, 2011, our business operations reflect the merged Frontier businesses (see Note 2). Our results of operations for the first nine months of 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. Our credit losses, which historically have been minimal, are charged to income when accounts are deemed uncollectible. At September 30, 2011, our allowance for doubtful accounts reserve was $3.5 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.

Goodwill

Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired and liabilities assumed. Goodwill is not subject to amortization and is tested annually or more frequently if events or circumstances indicate the possibility of impairment. As of September 30, 2011 there have been no impairments to goodwill.

New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, an accounting standard update was issued that requires the presentation of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminates the option to present the components of other comprehensive income in the statement of stockholders’ equity. This accounting standard update is effective January 1, 2012 and will be applied retrospectively. This update will not have an impact on our financial condition, results of operations and cash flows.

Intangibles — Goodwill and Other: Testing Goodwill for Impairment

In September 2011, an accounting standard update was issued that allows entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. Under this option, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that the reporting unit’s fair value is less than its carrying amount. This accounting standard update is effective for annual and interim goodwill impairment tests performed beginning January 1, 2012. This update will not have an impact on our financial condition, results of operations and cash flows.

NOTE 2: Holly-Frontier Merger

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier for purposes of creating a more diversified, combined company having a broader geographic sales footprint, stronger financial position and to reduce corporate overhead through the

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realization of synergies and promote earnings per share accretion. The legacy Frontier business operations consist of crude oil refining and the wholesale marketing of refined petroleum products. Frontier operates refineries in Cheyenne, Wyoming (the “Cheyenne Refinery”) and El Dorado, Kansas (the “El Dorado Refinery”) that serve markets in the Rocky Mountain and Plains States regions of the United States. The combined annual average crude oil capacity of these refineries is approximately 187,000 barrels per day.

On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Concurrent with the merger, we changed our name to HollyFrontier Corporation and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Subsequent to the merger and following approval by the post-closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the surviving corporation.

In accordance with the merger agreement, we issued approximately 102.8 million shares of HollyFrontier common stock in exchange for outstanding shares of Frontier common stock to former Frontier stockholders. Each outstanding share of Frontier common stock was converted into 0.4811 shares of HollyFrontier common stock with any fractional shares paid in cash. The aggregate consideration paid in connection with the merger was approximately $3.7 billion. This is based on our July 1, 2011 market closing price of $35.93 and includes a portion of the fair value of the outstanding quity-based awards assumed from Frontier that relates to pre-merger services. The number of shares issued in connection with our merger with Frontier and the closing market price of our common stock at July 1, 2011 has been adjusted to reflect the two-for-one stock split on August 31, 2011.

The merger has been accounted for using the acquisition method of accounting with Holly being considered the acquirer of Frontier for accounting purposes. Therefore, the purchase price was allocated to the fair value of the acquired assets and assumed liabilities at the acquisition date, with the excess purchase price being recorded as goodwill. Goodwill is not deductible for income tax purposes.

The following table summarizes our preliminary fair value estimates of the Frontier assets and liabilities recognized upon our merger on July 1, 2011:


	(in millions)
Cash and cash equivalents	$	872
Accounts receivable		738
Inventories		670
Properties, plants and equipment		1,052
Goodwill		2,235
Income taxes receivable		38
Other assets		12
Accounts payable		(1,072	)
Accrued liabilities		(41	)
Long-term debt		(371	)
Other long-term liabilities		(65	)
Deferred income taxes		(361	)

Net tangible and intangible assets acquired and liabilities assumed	$	3,707

Due to the short time frame since July 1, 2011, our valuations of the acquired Frontier assets and liabilities are not final as of September 30, 2011. These fair value estimates, including the value of goodwill and the allocation, thereof to our reporting units are preliminary in nature and therefore, may change upon the completion such valuations. Such changes could be material.

Beginning July 1, 2011, HollyFrontier’s consolidated financial and operating results reflect the operations of the merged Frontier businesses. Our Consolidated Statements of Income include revenues and income before income taxes of $2.2 billion and $397.6 million, respectively, for the period from July 1, 2011 through September 30, 2011 that are attributable to the operations of the legacy Frontier refineries.

Assuming the merger had been consummated on January 1, 2010, the beginning of the earliest period presented, pro forma revenues, net income and basic and diluted earnings per share (except in the case of the three months ended September 30, 2011 which represent actual results) are as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Sales and other revenues	$	5,173,398	$	3,507,460	$	14,446,297	$	10,348,634
Net income attributable to HollyFrontier stockholders	$	523,088	$	66,792	$	1,129,775	$	142,499
Basic earnings per share	$	2.50	$	0.32	$	5.39	$	0.68
Diluted earnings per share	$	2.48	$	0.32	$	5.37	$	0.68

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The pro forma financial information above reflects our preliminary fair value estimates of the acquired Frontier assets and liabilities. Adjustments made to derive pro forma net income primarily relate to depreciation and amortization expense in order to reflect our new basis in the acquired legacy Frontier refining facilities.

As of September 30, 2011, we have recognized $15.1 million in merger transaction costs that are presented separately in our income statements and primarily relate to legal, advisory and other professional fees incurred since the announcement of our merger agreement in February 2011. This does not include costs to integrate the operations of the combined company. For the three and nine months ended September 30, 2011, general and administrative expenses include $154 million in integration and severance costs associated with the integration of both companies.

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 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, 2011, we owned a 34% interest in HEP, including the 2% general partner interest. We are HEP’s primary beneficiary and therefore we consolidate HEP. See Note 17 for supplemental guarantor/non-guarantor financial information, including HEP balances included in these consolidated financial statements. All intercompany transactions with HEP are eliminated in our consolidated balances.

HEP has two primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further below), we accounted for 77% of HEP’s total revenues for the nine months ended September 30, 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.

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

2011 Pending Pipeline and Tankage Asset Transaction

We have announced an agreement in principle with HEP, subject to the execution of definitive agreements and certain closing conditions, for the sale of certain pipeline, tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries to HEP for $340 million that we expect to close in November 2011. The purchase price is expected to be paid in HEP promissory notes with an aggregate original principal amount of $150 million and in an additional number of HEP’s common units having a value equal to the remaining $190 million purchase price.

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In connection with the proposed transaction, we intend to enter into 15-year throughput agreements with HEP containing minimum annual revenue commitments that we project will result in $47 million of minimum annual payments to HEP.

2010 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.

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 sold to HEP in 2009 and 2010 and HEP’s Tulsa interconnect pipelines);

•

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 subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“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. As of September 30, 2011, these agreements result in minimum annualized payments to HEP of $145 million.

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.

The carrying amounts and related estimated fair values of our debt instruments at September 30, 2011 and December 31, 2010 were as follows:

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	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
HollyFrontier senior notes	$	659,850	$	684,829	$	289,509	$	327,000
HEP senior notes	$	325,213	$	337,938	$	323,271	$	339,900

These fair value estimates are based on market quotes (a Level 1 input) provided from a third-party bank. The fair value of the HEP credit agreement approximates its carrying value as interest rates are reset frequently using current interest rates. See Note 10 for additional information on these 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, 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 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.

NOTE 5: Earnings Per Share

Basic earnings per share is calculated as net income attributable to HollyFrontier stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares from stock options, variable restricted shares and variable performance shares. The average number of shares of common stock and per share amounts have been adjusted to reflect the two-for-one stock split effective August 31, 2011. The following is a reconciliation of the denominators of the basic and diluted per share computations for net income attributable to HollyFrontier stockholders:

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(In thousands, except per share data)
Earnings attributable to HollyFrontier stockholders	$	523,088	$	51,177	$	800,017	$	89,245

Average number of shares of common stock outstanding		209,583		106,420		141,353		106,344
Effect of dilutive stock options, variable restricted shares and performance share units ⁽¹⁾		996		714		739		718

Average number of shares of common stock outstanding assuming dilution		210,579		107,134		142,092		107,062

Basic earnings per share	$	2.50	$	0.48	$	5.66	$	0.84

Diluted earnings per share	$	2.48	$	0.48	$	5.63	$	0.83

(1) Excludes anti-dilutive restricted and performance share units of:		39		—		179		—

NOTE 6: Stock-Based Compensation

In addition to our existing share-based compensation plan, we have retained the legacy Frontier share-based compensation plan (collectively, the “Long-Term Incentive Compensation Plan”). Upon our July 1 merger, outstanding and unvested restricted stock and performance share grants under the legacy Frontier plan were converted into equivalent HollyFrontier units based on the July 1, 2011 common stock conversion ratio of .4811. A portion of the fair value of these awards (based on our July 1, 2011 closing stock price of $35.93) relative to the remaining vesting period of the awards will be expensed over the remaining terms of these grants.

The compensation cost that has been charged against income for these plans was $9.4 million and $2.1 million for the three months ended September 30, 2011 and 2010, respectively, and $13.9 million and $6.2 million for the nine months ended September 30, 2011 and 2010, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $3.6 million and $0.8 million for the three months ended September 30, 2011 and 2010, respectively, and $5.4 million and $2.4 million for the nine months ended September 30, 2011 and 2010, respectively. Our 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.

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 $0.6 million and $0.4 million for the three months ended September 30, 2011 and 2010, respectively, and $1.6 million and $1.8 million for the nine months ended September 30, 2011 and 2010, respectively.

Restricted Stock

Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients generally have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain 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.

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A summary of restricted stock activity and changes during the nine months ended September 30, 2011 is presented below:


Restricted Stock	Grants			Weighted- Average Grant Date Fair Value		Aggregate Intrinsic Value ($000)
Outstanding at January 1, 2011 (non-vested)		693,992		$	14.65
Granted ⁽¹⁾		1,034,738			29.54
Vesting and transfer of ownership to recipients		(510,730	)		17.25
Forfeited		(26,934	)		26.08

Outstanding at September 30, 2011 (non-vested)		1,191,066		$	26.22	$	31,226

(1)	Includes 480,876 non-vested performance share grants under the legacy Frontier plan that were outstanding and retained by HollyFrontier at July 1, 2011.

The total fair value of restricted stock vested and transferred to recipients during the nine months ended September 30, 2011 and 2010 was $8.8 million and $4.2 million, respectively. As of September 30, 2011, there was $22.8 million of total unrecognized compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 1.6 years.

Performance Share Units

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

The fair value of each performance share unit award is computed using the grant date closing stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately issued for each award will be based on our financial performance as compared to peer group companies over the performance period and can range from zero to 200%. As of September 30, 2011, estimated share payouts for outstanding non-vested performance share unit awards ranged from 125% to 185%.

For the legacy Frontier performance share units assumed at July 1, 2011, performance is based on market performance criteria. These share unit awards are payable in stock based on share price performance relative to our peer group over a specified period and can range from zero to 125%.

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


Performance Share Units	Grants
Outstanding at January 1, 2011 (non-vested)		556,186
Granted ⁽¹⁾		409,982
Vesting and transfer of ownership to recipients		(178,154	)

Outstanding at September 30, 2011 (non-vested)		788,014

(1)	Includes 280,438 non-vested performance share grants under the legacy Frontier plan that were outstanding and retained by HollyFrontier at July 1, 2011.

For the nine months ended September 30, 2011, we issued 237,802 shares of our common stock having a fair value of $4.8 million related to vested performance share units. Based on the weighted average grant date fair value of $20.90, there was $15.4 million of total unrecognized compensation cost related to non-vested performance share units. That cost is expected to be recognized over a weighted-average period of 1.4 years.

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

Our investment portfolio at September 30, 2011 consisted of cash, cash equivalents 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.

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We invest in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months. We also invest in other marketable debt securities with the maximum maturity of any individual issue generally not greater than two years from the date of purchase. All of these instruments including investments in equity securities are classified as available-for-sale, and as a result, are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.

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


	Available-for-Sale Securities
	Amortized Cost		Gross Unrealized Gain (Loss)			Estimated Fair Value (Net Carrying Amount)
	(In thousands)
September 30, 2011
Marketable debt securities (state and political subdivisions)	$	176,124	$	47		$	176,171
Equity securities		610		(287	)		323

Total marketable securities	$	176,734	$	(240	)	$	176,494

December 31, 2010
Equity securities	$	610	$	733		$	1,343

For the nine months ended September 30, 2011, we invested $370 million in marketable debt securities and received a total of $194.4 million from sales and maturities of marketable debt securities.

NOTE 8: Inventories

Inventory consists of the following components:


	September 30,		December 31,
	2011		2010
	(In thousands)
Crude oil	$	403,128	$	96,570
Other raw materials and unfinished products⁽¹⁾		174,009		68,792
Finished products⁽²⁾		590,992		188,274
Process chemicals⁽³⁾		42,029		22,512
Repairs and maintenance supplies and other		55,361		24,219

Total inventory	$	1,265,519	$	400,367

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

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

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

NOTE 9: Environmental

Consistent with our accounting policy for environmental remediation costs, we expensed $0.7 million and $1.5 million for the three months ended September 30, 2011 and 2010, respectively, and $0.6 million and $1.5 million for the nine months ended September 30, 2011 and 2010, respectively, for environmental remediation obligations. The accrued environmental liability reflected in our consolidated balance sheets was $30.3 million and $26.2 million at September 30, 2011 and December 31, 2010, respectively, of which $22.1 million and $20.4

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million, respectively, were classified as other long-term liabilities. These amounts include $7.3 million in environmental liabilities we assumed upon our merger with Frontier of which $4.9 million is classified as other long-term liabilities at September 30, 2011. This includes estimated costs of future expenditures for environmental remediation that are expected to be incurred over the next several years that are not discounted to their present value.

NOTE 10: Debt

Credit Facilities

On July 1, 2011, we entered into a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as administrative agent and BNP Paribas as syndication agent, and certain lenders from time to time party thereto, and terminated our previous $400 million credit agreement. Additionally, Frontier terminated its previous $500 million credit agreement. The HollyFrontier Credit Agreement matures in July 2016 and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries.

We were in compliance with all covenants at September 30, 2011. At September 30, 2011 we had no outstanding borrowings and outstanding letters of credit totaled $160.6 million under the HollyFrontier Credit Agreement. At that level of usage, the unused commitment was $839.4 million at September 30, 2011.

Indebtedness under the HollyFrontier Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.50% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.50%). We incur a commitment fee on the unused portion of the HollyFrontier Credit Agreement at a rate ranging from 0.375% to 0.50% based upon the credit ratings of our long-term, unsecured, senior debt. At September 30, 2011, we are subject to a 0.375% commitment fee on the $839.4 million unused portion of the credit agreement.

The $275 million HEP Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. In February 2011, HEP amended its previous credit agreement (expiring in August 2011), extended the expiration date and slightly reduced 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 HEP 6.25% Senior Notes (discussed below) are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the HEP Credit Agreement shall expire on that date. At September 30, 2011, HEP had outstanding borrowings totaling $202 million under the HEP Credit Agreement, with unused borrowing capacity of $73 million.

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 material, 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. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

HollyFrontier Senior Notes

Our senior notes consist of the following:

•

9.875% Senior Notes ($300 million principal amount maturing June 2017)

•

6.875% Senior Notes ($150 million principal amount maturing November 2018)⁽¹⁾

•

8.5% Senior Notes ($200 million principal amount maturing September 2016)⁽¹⁾

(1)	Represent senior notes assumed upon our July 1, 2011 merger with Frontier.

These notes (collectively, the “HollyFrontier 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 HollyFrontier 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 HollyFrontier Senior Notes.

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HollyFrontier 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 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 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.

HEP Senior Notes

HEP’s senior notes consist of the following:

•

6.25% Senior Notes ($185 million principal amount maturing March 2015)

•

8.25% Senior Notes ($150 million principal amount maturing March 2018)

These 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. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

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


	September 30, 2011			December 31, 2010
	(In thousands)
9.875% Senior Notes
Principal	$	300,000		$	300,000
Unamortized discount		(9,619	)		(10,491	)

		290,381			289,509
6.875% Senior Notes
Principal		150,000			—
Unamortized premium		6,792			—

		156,792			—
8.5% Senior Notes
Principal		199,985			—
Unamortized premium		12,692			—

		212,677			—
Financing obligation
Principal		37,924			38,781

Total HollyFrontier long-term debt		697,774			328,290


HEP Credit Agreement		202,000			159,000

HEP 6.25% Senior Notes
Principal		185,000			185,000
Unamortized discount		(8,988	)		(10,961	)
Unamortized premium – dedesignated fair value hedge		1,184			1,444

		177,196			175,483
HEP 8.25% Senior Notes
Principal		150,000			150,000
Unamortized discount		(1,983	)		(2,212	)

		148,017			147,788

Total HEP long-term debt		527,213			482,271

Total long-term debt	$	1,224,987		$	810,561

We capitalized interest attributable to construction projects of $5.8 million and $3 million for the three months ended September 30, 2011 and 2010, respectively, and $13.6 million and $5 million for the nine months ended September 30, 2011 and 2010, respectively.

NOTE 11: Derivative Instruments and Hedging Activities

Commodity Price Risk Management

Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined products, as well as volatility in the price of natural gas used in our refining operations.

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.

- 21 -

As of September 30, 2011, we have outstanding swap contracts serving as cash flow hedges against price risk on forecasted 2012 purchases of 10,980,000 barrels of WTI crude oil and forecasted sales of 5,490,000 barrels of ultra-low sulfur diesel and 5,490,000 barrels of conventional unleaded gasoline. In the aggregate, these cash flow hedges effectively hedge our gross margin on forecasted gasoline and diesel sales, totaling 30,000 BPD in 2012. These contracts have been designated as accounting hedges and are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to other comprehensive income. These fair value adjustments are later reclassified in the income statement as the hedging instruments mature. Also on a quarterly basis, hedge effectiveness is measured by comparing the change in fair value of the swap contracts against the expected future cash inflows/outflows on the respective transaction being hedged. Any ineffectiveness is recorded to cost of products sold. To date, ineffectiveness on these cash flow hedges have been insignificant.

We also have outstanding commodity price swap contracts serving as economic hedges to protect the value of temporary crude oil inventory builds of 15,000 barrels against price volatility through November 2011. Also, we have swap contracts that lock in the following spreads between WTS and WTI crude oil on forecasted purchases (1,403,000 barrels of crude oil through the end of 2011); between gasoline and butane on forecasted sales (225,000 barrels of gasoline through January 2012); between fuel oil and WTI crude oil on forecasted sales (276,000 barrels of fuel oil through the end of 2011); and between WTI crude oil and various other products on forecasted sales and purchases (279,000 barrels, net through 2013). These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to cost of products sold.

Interest Rate Risk Management

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

As of September 30, 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 2.5%, which equaled an effective interest rate of 6.24% as of September 30, 2011. This interest rate swap contract has been designated as a cash flow hedge and matures in February 2013. There was no ineffectiveness on this cash flow hedge for the periods covered in these consolidated financial statements.

The following table presents the fair values of outstanding derivative instruments. These amounts are presented on a gross basis in accordance with GAAP disclosure requirements and do not reflect the netting of asset or liability positions permitted under the terms of master netting arrangements. Therefore, they are not equal to amounts presented in our consolidated balance sheets.


Derivative Instruments	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
September 30, 2011
*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	122,682	Accrued liabilities	$	100,139
				Accumulated other comprehensive loss		22,181
				Cost of products sold (decrease)		362

		$	122,682	Total	$	122,682

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	7,378	Accumulated other comprehensive loss	$	7,378

*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	8,115	Cost of products sold (decrease)	$	8,115

Commodity price swap contracts	Accrued liabilities	$	1,184	Cost of products sold (increase)	$	1,184


Derivative Instruments	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
December 31, 2010
*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	38	Accumulated other comprehensive loss	$	38

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026

*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	497	Cost of products sold (increase)	$	497

At September 30, 2011, we have a net unrealized gain of $14.8 million classified in accumulated other comprehensive loss that relates to our cash flow hedges. Assuming commodity prices and interest rates remain unchanged, approximately $11 million of this unrealized gain will be effectively transferred from accumulated other comprehensive loss into the income statement as the hedging instruments mature over the next twelve-month period.

For the three and the nine months ended September 30, 2011, maturities and fair value adjustments attributable to our economic hedges resulted in decreases of $10 million and $9.3 million, respectively, to costs of products sold.

- 22 -

NOTE 12: Equity

Changes to equity during the nine months ended September 30, 2011 are presented below:


	HollyFrontier Stockholders’ Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2010	$	697,419		$	590,720		$	1,288,139
Net income		800,017			23,838			823,855
Dividends		(139,472	)		—			(139,472	)
Distributions to noncontrolling interest holders		—			(37,929	)		(37,929	)
Other comprehensive income		13,546			1,737			15,283
Contribution from joint venture partner		—			27,500			27,500
Common stock issued in connection with Frontier merger		3,707,076			—			3,707,076
Equity based compensation		13,900			1,635			15,535
Excess tax benefit on equity based compensation arrangements		1,399			—			1,399
Purchase of HEP units for restricted grants		—			(1,641	)		(1,641	)
Purchase of treasury stock ⁽¹⁾		(38,955	)		—			(38,955	)


Balance at September 30, 2011	$	5,054,930		$	605,860			$5,660,790

(1)	Includes 723,274 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.

On August 3, 2011, our Board of Directors declared a two-for-one stock split, payable in the form of a common stock dividend for each issued and outstanding share of our common stock. The stock dividend was paid August 31, 2011 to all shareholders of record on August 24, 2011. We have retained the current par value of $0.01 per share for all shares of our common stock and have reclassified $763,000 (the amount equal to the par value of the additional stock issued) from additional capital to common stock to reflect this stock split at December 31, 2010. All references to share and per share amounts in these consolidated financial statements and related disclosures have been adjusted to reflect the effect of the stock split for all periods presented.

In September 2011, our Board of Directors approved a stock repurchase authorization of up to $100 million to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. The stock repurchase program may be discontinued at any time by the Board of Directors. As of September 30, 2011, we have repurchased 460,600 shares at a cost of $14.5 million under this stock repurchase program.

During the nine months ended September 30, 2011, we repurchased 723,274 shares of our common stock at market price from certain executives and employees costing $24.4 million. These purchases were made under the terms of restricted stock and performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted and performance shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

- 23 -

NOTE 13: Other Comprehensive Income (Loss)

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


	Before-Tax			Tax Expense (Benefit)			After-Tax
	(In thousands)
Three Months Ended September 30, 2011
Unrealized loss on available-for-sale securities	$	(655	)	$	(252	)	$	(403	)
Unrealized gain on hedging activities		23,272			8,772			14,500
Retirement medical obligation adjustment		9			—			9

Other comprehensive income		22,626			8,520			14,106
Less other comprehensive income attributable to noncontrolling interest		717			—			717

Other comprehensive income attributable to HollyFrontier stockholders	$	21,909		$	8,520		$	13,389

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 HollyFrontier stockholders	$	(1,435	)	$	(558	)	$	(877	)

Nine Months Ended September 30, 2011
Unrealized loss on available-for-sale securities	$	(972	)	$	(376	)	$	(596	)
Unrealized gain on hedging activities		24,864			8,994			15,870
Retirement medical obligation adjustment		9			—			9

Other comprehensive income		23,901			8,618			15,283
Less other comprehensive income attributable to noncontrolling interest		1,737			—			1,737

Other comprehensive income attributable to HollyFrontier stockholders	$	22,164		$	8,618		$	13,546

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 HollyFrontier stockholders	$	(1,080	)	$	(420	)	$	(660	)

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

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


	September 30, 2011			December 31, 2010
	(In thousands)
Pension obligation adjustment	$	(22,672	)	$	(22,672	)
Retiree medical obligation adjustment		(1,885	)		(1,894	)
Unrealized gain (loss) on available-for-sale securities		(145	)		451
Unrealized gain (loss) on hedging activities, net of noncontrolling interest		12,002			(2,131	)

Accumulated other comprehensive loss	$	(12,700	)	$	(26,246	)

NOTE 14: Retirement Plan

We have a non-contributory defined benefit retirement plan that covers most of the legacy Holly non-union employees hired prior to January 1, 2007 and union employees prior to July 1, 2010. Our policy is to make contributions annually of not less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.

- 24 -

The retirement plan is closed to all new employees. To the extent an employee was hired prior to the plan closing date (January 1, 2007 for non-union employees and July 1, 2010 for union employees) and elected to participate in automatic contributions features under our defined contribution plan, their participation in future benefits of the retirement plan has been frozen. Effective January 1, 2012, benefits for all non-union employees participating in the retirement plan will cease. There will be a transition benefit over the next three years for such employees. Additionally, there will be changes in the employer contribution feature of our defined contribution for all non-union employees.

The net periodic pension expense consisted of the following components:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Service cost – benefit earned during the period	$	1,268		$	1,149		$	3,803		$	3,446
Interest cost on projected benefit obligations		1,281			1,288			3,844			3,865
Expected return on plan assets		(1,244	)		(1,144	)		(3,923	)		(3,432	)
Amortization of prior service cost		97			98			293			293
Amortization of net loss		529			549			1,594			1,647
Estimated effect of curtailment		798			—			798			—

Net periodic pension expense	$	2,729		$	1,940		$	6,409		$	5,819

The expected long-term annual rate of return on plan assets is 8%. This rate was used in measuring 2011 net periodic benefit costs. We contributed $10 million to the retirement plan in July 2011.

Upon our July 1, 2011 merger with Frontier, we recorded a long-term liability of $45.3 million that relates to a post-retirement healthcare and other benefits plan that is available to certain eligible employees of the El Dorado Refinery who were hired before certain defined dates and satisfy certain age and service requirements. Under this program, employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. For the period from July 1, 2011 through September 30, 2011, we recognized $0.8 million in benefit costs under this plan.

NOTE 15: Contingencies

We are a party to various 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.

- 25 -

NOTE 16: Segment Information

Our operations are 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 Tulsa, Navajo, Woods Cross Refineries and NK Asphalt, and effective July 1, 2011, includes the El Dorado and Cheyenne Refineries. Refining activities involve 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 Mid-Continent, Southwest and Rocky Mountain regions of the United States. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. NK Asphalt operates various asphalt terminals in Arizona, New Mexico and Texas.

The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates a system of petroleum product and crude gathering pipelines in Texas, New Mexico, Oklahoma and Utah, distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington and refinery tankage in New Mexico, Utah and Oklahoma. Revenues are generated by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon USA, Inc., by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its storage tanks and terminals. The HEP segment also includes a 25% interest in SLC Pipeline that services refineries in the Salt Lake City, Utah area. Revenues from the HEP segment are earned through transactions with unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline transportation services provided for our refining operations. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP segment may not agree to amounts reported in HEP’s periodic public filings.

The accounting policies for our segments are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2010.


	Refining			HEP		Corporate and Other			Consolidations and Eliminations			Consolidated Total
	(In thousands)
Three Months Ended September 30, 2011
Sales and other revenues	$	5,164,778	$49,288			$	299		$	(40,967	)	$	5,173,398
Depreciation and amortization	$	34,890	$7,326			$	1,231		$	(207	)	$	43,240
Income (loss) from operations	$	886,860	$25,261			$	(42,354	)	$	(560	)	$	869,207
Capital expenditures	$	46,294	$8,593			$	63,031		$	—		$	117,918

Three Months Ended September 30, 2010
Sales and other revenues	$	2,081,709		$	46,558	$	100		$	(37,379	)	$	2,090,988
Depreciation and amortization	$	21,274		$	6,830	$	1,329		$	(295	)	$	29,138
Income (loss) from operations	$	100,111		$	24,588	$	(16,652	)	$	(429	)	$	107,618
Capital expenditures	$	47,623		$	3,567	$	219		$	—		$	51,409

- 26 -


	Refining		HEP		Corporate and Other			Consolidations and Eliminations			Consolidated Total
	(In thousands)
Nine Months Ended September 30, 2011
Sales and other revenues	$	10,433,096	$	145,233	$	1,100		$	(112,313	)	$	10,467,116
Depreciation and amortization	$	81,351	$	21,870	$	3,780		$	(621	)	$	106,380
Income (loss) from operations	$	1,359,994	$	76,564	$	(76,490	)	$	(1,583	)	$	1,358,485
Capital expenditures	$	92,078	$	31,493	$	150,652		$	—		$	274,223

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

September 30, 2011
Cash, cash equivalents and investments in marketable securities	$	—	$	1,802	$	1,757,551		$	—		$	1,759,353
Total assets	$	3,114,748	$	685,463	$	6,148,879		$	(32,627	)	$	9,916,463
Long-term debt	$	—	$	527,213	$	714,349		$	(16,575	)	$	1,224,987

December 31, 2010
Cash, cash equivalents and investments in marketable securities	$	—	$	403	$	230,041		$	—		$	230,444
Total assets	$	2,490,193	$	669,820	$	573,531		$	(32,069	)	$	3,701,475
Long-term debt	$	—	$	482,271	$	345,215		$	(16,925	)	$	810,561

HEP segment revenues from external customers were $8.3 million and $9.2 million for the three months ended September 30, 2011 and 2010, respectively, and $33 million and $24.7 million for the nine months ended September 30, 2011 and 2010, respectively.

NOTE 17: Supplemental Guarantor/Non-Guarantor Financial Information

Our obligations under the HollyFrontier Senior Notes have been jointly and severally guaranteed by the substantial majority of our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”), which includes certain Frontier subsidiaries that merged with us on July 1, 2011. These guarantees are full and unconditional. HEP, in which we have a 34% ownership interest as of September 30, 2011, 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 HollyFrontier (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.

- 27 -

Condensed Consolidating Balance Sheet


September 30, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,554,831		$	8,724		$	17,502		$	—		$	1,581,057	$	1,802	$	—		$	1,582,859
Marketable securities		132,654			791			—			—			133,445		—		—			133,445
Accounts receivable		3,509			1,337,820			74						1,341,403		23,821		(23,541	)		1,341,683
Intercompany accounts receivable (payable)		898,166			(1,321,457	)		423,291			—			—		—		—			—
Inventories		—			1,264,816			—			—			1,264,816		703		—			1,265,519
Prepayments and other assets		15,438			42,939			5			—			58,382		942		(3,742	)		55,582

Total current assets		2,604,598			1,333,633			440,872			—			4,379,103		27,268		(27,283	)		4,379,088

Properties and equipment, net		21,256			2,125,285			353,227			—			2,499,768		503,248		(6,488	)		2,996,528
Marketable securities (long-term)		43,049			—			—			—			43,049		—		—			43,049
Investment in subsidiaries		3,426,419			694,031			(396,034	)		(3,724,416	)		—		—		—			—
Intangibles and other assets		19,465			2,322,242			—			—			2,341,707		154,947		1,144			2,497,798

Total assets	$	6,114,787		$	6,475,191		$	398,065		$	(3,724,416	)	$	9,263,627	$	685,463	$	(32,627	)	$	9,916,463


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	12,707		$	2,099,725		$	6,341		$	—		$	2,118,773	$	7,683	$	(23,541	)	$	2,102,915
Income taxes payable		—			140,086			—			—			140,086		—		—			140,086
Accrued liabilities		60,917			66,427			2,240			—			129,584		11,997		(3,742	)		137,839

Total current liabilities		73,624			2,306,238			8,581			—			2,388,443		19,680		(27,283	)		2,380,840
Long-term debt		659,851			54,498			—			—			714,349		527,213		(16,575	)		1,224,987
Deferred income taxes		282,862			222,351			919			—			506,132		—		4,951			511,083
Non-current liabilities		41,860			88,759			—			—			130,619		8,144		—			138,763
Distributions in excess of inv in HEP		—			376,926			—			—			376,926		—		(376,926	)		—
Equity – HollyFrontier		5,056,590			3,426,419			388,565			(3,814,984	)		5,056,590		130,426		(132,086	)		5,054,930
Equity – noncontrolling interest		—			—			—			90,568			90,568		—		515,292			605,860

Total liabilities and equity	$	6,114,787		$	6,475,191		$	398,065		$	(3,724,416	)	$	9,263,627	$	685,463	$	(32,627	)	$	9,916,463


Condensed Consolidating Balance Sheet
December 31, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP		Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	230,082		$	(9,035	)	$	7,651		$	—		$	228,698	$	403	$	—		$	229,101
Marketable securities		—			1,343			—			—			1,343		—		—			1,343
Accounts receivable		1,683			991,778			—			—			993,461		22,508		(22,853	)		993,116
Intercompany accounts receivable (payable)		(1,401,580	)		981,691			419,889			—			—		—		—			—
Inventories		—			400,165			—			—			400,165		202		—			400,367
Income taxes receivable		51,034			—			—			—			51,034		—		—			51,034
Prepayments and other assets		10,210			20,942			—			—			31,152		573		(3,251	)		28,474

Total current assets		(1,108,571	)		2,386,884			427,540			—			1,705,853		23,686		(26,104	)		1,703,435
Properties and equipment, net		17,177			1,017,877			236,648			—			1,271,702		492,098		(7,109	)		1,756,691
Investment in subsidiaries		2,273,159			595,888			(393,011	)		(2,476,036	)		—		—		—			—
Intangibles and other assets		8,569			77,600			—			—			86,169		154,036		1,144			241,349

Total assets	$	1,190,334		$	4,078,249		$	271,177		$	(2,476,036	)	$	3,063,724	$	669,820	$	(32,069	)	$	3,701,475


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,170		$	1,319,316		$	3,575		$	—		$	1,330,061	$	10,238	$	(22,853	)	$	1,317,446
Accrued liabilities		25,512			28,145			797			—			54,454		21,206		(3,251	)		72,409

Total current liabilities		32,682			1,347,461			4,372			—			1,384,515		31,444		(26,104	)		1,389,855

Long-term debt		289,509			55,706			—			—			345,215		482,271		(16,925	)		810,561
Deferred income taxes		126,160			259			565			—			126,984		—		4,951			131,935
Non-current liabilities		42,655			27,521			—			—			70,176		10,809		—			80,985
Distributions in excess of inv in HEP		—			374,143			—			—			374,143		—		(374,143	)		—
Equity – HollyFrontier		699,328			2,273,159			266,240			(2,539,399	)		699,328		145,296		(147,205	)		697,419
Equity – noncontrolling interest		—			—			—			63,363			63,363		—		527,357			590,720

Total liabilities and equity	$	1,190,334		$	4,078,249		$	271,177		$	(2,476,036	)	$	3,063,724	$	669,820	$	(32,069	)	$	3,701,475

- 28 -

Condensed Consolidating Statement of Income


Three Months Ended September 30, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	266		$	5,164,778		$	33		$	—		$	5,165,077		$	49,288		$	(40,967	)	$	5,173,398

Operating costs and expenses:
Cost of products sold		—			4,029,997			—			—			4,029,997			—			(40,070	)		3,989,927
Operating expenses		—			213,001			323			—			213,324			14,689			(130	)		227,883
General and administrative expenses		39,555			1,574			—			—			41,129			2,012			—			43,141
Depreciation and amortization		872			35,070			179			—			36,121			7,326			(207	)		43,240

Total operating costs and expenses		40,427			4,279,642			502			—			4,320,571			24,027			(40,407	)		4,304,191

Income (loss) from operations		(40,161	)		885,136			(469	)		—			844,506			25,261			(560	)		869,207

Other income (expense):
Equity in earnings of subsidiaries and joint venture		892,558			8,399			8,840			(901,066	)		8,731			641			(8,840	)		532
Interest income (expense)		(15,162	)		(977	)		14			—			(16,125	)		(9,391	)		646			(24,870	)
Merger transaction costs		(9,100	)		—			—			—			(9,100	)		—			—			(9,100	)

		868,296			7,422			8,854			(901,066	)		(16,494	)		(8,750	)		(8,194	)		(33,438	)

Income before income taxes		828,135			892,558			8,385			(901,066	)		828,012			16,511			(8,754	)		835,769

Income tax provision		304,835			—			—			—			304,835			(77	)		—			304,758

Net income		523,300			892,558			8,385			(901,066	)		523,177			16,588			(8,754	)		531,011

Less net income attributable to noncontrolling interest		—			—			—			(123	)		(123	)		—			8,046			7,923

Net income attributable to HollyFrontier stockholders	$	523,300		$	892,558		$	8,385		$	(900,943	)	$	523,300		$	16,588		$	(16,800	)	$	523,088


Condensed Consolidating Statement of Income
Three Months Ended September 30, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	100		$	2,081,707		$	2		$	—		$	2,081,809		$	46,558		$	(37,379	)	$	2,090,988

Operating costs and expenses:
Cost of products sold		—			1,843,464			103			—			1,843,567			—			(36,523	)		1,807,044
Operating expenses		—			116,763			—			—			116,763			13,632			(132	)		130,263
General and administrative expenses		15,538			(121	)		—			—			15,417			1,508			—			16,925
Depreciation and amortization		925			21,499			179			—			22,603			6,830			(295	)		29,138

Total operating costs and expenses		16,463			1,981,605			282			—			1,998,350			21,970			(36,950	)		1,983,370

Income (loss) from operations		(16,363	)		100,102			(280	)		—			83,459			24,588			(429	)		107,618

Other income (expense):
Equity in earnings of subsidiaries and joint venture		106,360			7,918			8,117			(114,278	)		8,117			570			(8,117	)		570
Interest income (expense)		(7,294	)		(1,660	)		11			—			(8,943	)		(8,979	)		618			(17,304	)

		99,066			6,258			8,128			(114,278	)		(826	)		(8,409	)		(7,499	)		(16,734	)

Income before income taxes		82,703			106,360			7,848			(114,278	)		82,633			16,179			(7,928	)		90,884

Income tax provision		31,418			—			—			—			31,418			76			—			31,494

Net income		51,285			106,360			7,848			(114,278	)		51,215			16,103			(7,928	)		59,390

Less net income attributable to noncontrolling interest		—			—			—			(70	)		(70	)		—			8,283			8,213

Net income attributable to HollyFrontier stockholders	$	51,285		$	106,360		$	7,848		$	(114,208	)	$	51,285		$	16,103		$	(16,211	)	$	51,177

- 29 -

Condensed Consolidating Statement of Income


Nine Months Ended September 30, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Sales and other revenues	$	1,067		$	10,433,096		$	33		$	—		$	10,434,196		$	145,233		$	(112,313	)	$	10,467,116

Operating costs and expenses:
Cost of products sold		—			8,531,358			—			—			8,531,358			—			(109,719	)		8,421,639
Operating expenses		—			459,678			832			—			460,510			41,851			(390	)		501,971
General and administrative expenses		71,884			1,809			—			—			73,693			4,948			—			78,641
Depreciation and amortization		2,719			81,875			537			—			85,131			21,870			(621	)		106,380

Total operating costs and expenses		74,603			9,074,720			1,369			—			9,150,692			68,669			(110,730	)		9,108,631

Income (loss) from operations		(73,536	)		1,358,376			(1,336	)		—			1,283,504			76,564			(1,583	)		1,358,485

Other income (expense):
Equity in earnings of subsidiaries and joint venture		1,381,010			25,230			26,340			(1,406,349	)		26,231			1,848			(26,340	)		1,739
Interest income (expense)		(27,033	)		(2,596	)		40			—			(29,589	)		(27,789	)		1,853			(55,525	)
Merger transaction costs		(15,114	)		—			—			—			(15,114	)		—			—			(15,114	)

		1,338,863			22,634			26,380			(1,406,349	)		(18,472	)		(25,941	)		(24,487	)		(68,900	)

Income before income taxes		1,265,327			1,381,010			25,044			(1,406,349	)		1,265,032			50,623			(26,070	)		1,289,585

Income tax provision		465,561			—			—			—			465,561			169			—			465,730

Net income		799,766			1,381,010			25,044			(1,406,349	)		799,471			50,454			(26,070	)		823,855

Less net income attributable to noncontrolling interest		—			—			—			(295	)		(295	)		—			24,133			23,838

Net income attributable to HollyFrontier stockholders	$	799,766		$	1,381,010		$	25,044		$	(1,406,054	)	$	799,766		$	50,454		$	(50,203	)	$	800,017


Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			Eliminations			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (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 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 HollyFrontier stockholders	$	89,307		$	216,349		$	21,263		$	(237,612	)	$	89,307		$	39,924		$	(39,986	)	$	89,245

- 30 -

Condensed Consolidating Statement of Cash Flows


Nine Months Ended September 30, 2011	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	1,690,926		$	(683,525	)	$	49,190		$	1,056,591		$	62,646		$	(30,034	)	$	1,089,203
Cash flows from investing activities
Additions to properties, plants and equipment		(6,056	)		(119,335	)		(117,339	)		(242,730	)		—			—			(242,730	)
Additions to properties, plants and equipment – HEP		—			—			—			—			(31,493	)		—			(31,493	)
Investment in Sabine Biofuels		(9,125	)		—			—			(9,125	)		—			—			(9,125	)
Cash received in merger with Frontier		182			871,976			—			872,158			—			—			872,158
Purchases of marketable securities		(370,042	)		—			—			(370,042	)		—			—			(370,042	)
Sales and maturities of marketable securities		194,386			—			—			194,386			—			—			194,386

		(190,655	)		752,641			(117,339	)		444,647			(31,493	)		—			413,154

Cash flows from financing activities
Net borrowings under credit agreements – HEP		—			—			—			—			43,000			—			43,000
Repayments under financing obligation		—			(857	)		—			(857	)		—			—			(857	)
Purchase of treasury stock		(38,955	)		—			—			(38,955	)		—			—			(38,955	)
Principle tender on 8.5% senior notes		(15	)		—			—			(15	)		—			—			(15	)
Contribution from joint venture partner		—			(50,500	)		78,000			27,500			—			—			27,500
Dividends		(129,377	)		—			—			(129,377	)		—			—			(129,377	)
Distributions to noncontrolling interest		—			—			—			—			(67,963	)		30,034			(37,929	)
Excess tax benefit from equity based compensation		1,399			—			—			1,399			—			—			1,399
Purchase of units for HEP restricted grants		—			—			—			—			(1,641	)		—			(1,641	)
Deferred financing costs		(8,574	)		—			—			(8,574	)		(3,150	)		—			(11,724	)

		(175,522	)		(51,357	)		78,000			(148,879	)		(29,754	)		30,034			(148,599	)

Cash and cash equivalents
Increase (decrease) for the period		1,324,749			17,759			9,851			1,352,359			1,399			—			1,353,758
Beginning of period		230,082			(9,035	)		7,651			228,698			403			—			229,101

End of period	$	1,554,831		$	8,724		$	17,502		$	1,581,057		$	1,802		$	—		$	1,582,859


Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2010	Parent			Guarantor Restricted Subsidiaries			Non- Guarantor Restricted Subsidiaries			HollyFrontier Before Consolidation of HEP			Non-Guarantor Non-Restricted Subsidiaries (HEP Segment)			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities	$	168,984		$	22,377		$	5,294		$	196,655		$	66,129		$	(26,816	)	$	235,968
Cash flows from investing activities
Additions to properties, plants and equipment		(1,498	)		(74,890	)		(43,497	)		(119,885	)		—			—			(119,885	)
Additions to properties, plants and equipment – HEP		—			—			—			—			(43,580	)		35,526			(8,054	)
Proceeds from sale of assets		—			39,040			—			39,040			—			(39,040	)		—

		(1,498	)		(35,850	)		(43,497	)		(80,845	)		(43,580	)		(3,514	)		(127,939	)

Cash flows from financing activities
Net repayments under credit agreements – HEP		—			—			—			—			(49,000	)		—			(49,000	)
Proceeds from issuance of senior notes – HEP		—			—			—			—			147,540			—			147,540
Repayments under financing obligation		—			(1,067	)		—			(1,067	)		—			307			(760	)
Purchase of treasury stock		(1,308	)		—			—			(1,308	)		—			—			(1,308	)
Contribution from joint venture partner		—			(28,500	)		38,000			9,500			—			—			9,500
Dividends		(23,889	)		—			—			(23,889	)		—			—			(23,889	)
Purchase price in excess of transferred basis in assets		—			53,960			—			53,960			(57,474	)		3,514			—
Distributions to noncontrolling interest		—			—			—			—			(62,648	)		26,509			(36,139	)
Excess tax expense from equity based compensation		(1,313	)		—			—			(1,313	)		—			—			(1,313	)
Deferred financing costs		(2,628	)		—			—			(2,628	)		(493	)		—			(3,121	)
Purchase of units for HEP restricted grants		—			—			—			—			(2,276	)		—			(2,276	)
Issuance of common stock upon exercise of options		61			—			—			61			—			—			61

		(29,077	)		24,393			38,000			33,316			(24,351	)		30,330			39,295

Cash and cash equivalents
Increase (decrease) for the period
Beginning of period		138,409			10,920			(203	)		149,126			(1,802	)		—			147,324
		127,560			(12,477	)		7,005			122,088			2,508			—			124,596

End of period	$	265,969		$	(1,557	)	$	6,802		$	271,214		$	706		$	—		$	271,920

- 31 -

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

This Item 2 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. Holly Corporation (“Holly”) changed its name to HollyFrontier Corporation (“HollyFrontier” or “HollyFrontier Corporation”) in connection with the consummation of its “merger of equals” with Frontier Oil Corporation (“Frontier”), which became effective on July 1, 2011 (see description below). References herein to HollyFrontier Corporation with respect to time periods prior to July 1, 2011 include Holly and its consolidated subsidiaries and do not include Frontier and its consolidated subsidiaries. References herein to HollyFrontier with respect to time periods from and after July 1, 2011 include the operations of the merged Frontier businesses. Unless otherwise specified, the financial information included herein includes financial information for the merged Frontier business operations for the period July 1, 2011 to September 30, 2011. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person. Also, the words “we,” “our,” “ours” and “us” generally include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier with certain exceptions where there are transactions or obligations between HEP and HollyFrontier 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 HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

OVERVIEW

We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We operate five refineries having a combined crude oil processing capacity of 443,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Our refineries are located in El Dorado, Kansas (the “El Dorado Refinery”), Tulsa, Oklahoma (the, “Tulsa Refinery”) which is comprised of two facilities, the Tulsa Refinery west and east facilities, a petroleum refinery 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”), Cheyenne, Wyoming (the, “Cheyenne Refinery”) and Woods Cross, Utah (the “Woods Cross Refinery”).

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier. On July 1, 2011, North Acquisition, Inc. a direct wholly-owned subsidiary of Holly merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Concurrent with the merger, we changed our name to HollyFrontier Corporation and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Subsequent to the merger and following approval by the post-closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the surviving corporation. This merger combined the legacy Frontier refinery operations, the El Dorado and Cheyenne Refineries, with Holly’s legacy refinery operations to form HollyFrontier.

In accordance with the merger agreement, we issued approximately 102.8 million shares of HollyFrontier common stock in exchange for outstanding shares of Frontier common stock to former Frontier stockholders. Each outstanding share of Frontier common stock was converted into 0.4811 shares of HollyFrontier common stock with any fractional shares paid in cash. Based on the July 1, 2011 market closing price of $35.93, the aggregate equity consideration paid in connection with the merger was approximately $3.7 billion. This is based on our July 1, 2011 market closing price of $35.93 and includes a portion of the fair value of the outstanding equity-based awards assumed from Frontier that relates to pre-merger services. The number of shares issued in connection with our merger with Frontier and the closing market price of our common stock at July 1, 2011 have been adjusted to reflect the two-for-one stock split on August 31, 2011.

At September 30, 2011, we owned a 34% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner interest. HEP has logistic assets including petroleum product and crude oil pipelines located in Texas, New Mexico, Oklahoma and Utah; ten refined product terminals; a jet fuel terminal;

- 32 -

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 (“SLC Pipeline”), a new 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

For the nine months ended September 30, 2011, sales and other revenues were $10.5 billion and net income attributable to HollyFrontier stockholders was $800 million. For the nine months ended September 30, 2010, sales and other revenues were $6.1 billion and net income attributable to HollyFrontier stockholders was $89.2 million. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the nine months ended September 30, 2011 were $9.1 billion compared to $5.9 billion for the nine months ended September 30, 2010.

Beginning July 1, 2011, HollyFrontier’s consolidated financial and operating results reflect the operations of the merged Frontier businesses. Assuming the merger had been consummated on January 1, 2010, the beginning of the earliest period presented, pro forma revenues and net income (except in the case of the three months ended September 30, 2011 which represent actual results) are as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(In thousands)
Sales and other revenues	$	5,173,398	$	3,507,460	$	14,446,297	$	10,348,634
Net income attributable to HollyFrontier stockholders	$	523,088	$	66,792	$	1,129,775	$	142,499

Sales and other revenues for both the three and nine month comparable periods increased principally due to increased sales prices of produced refined products sold. The net income increases are principally due to significantly higher refinery gross margins realized in 2011.

- 33 -

RESULTS OF OPERATIONS

Financial Data (Unaudited)


	Three Months Ended September 30,						Change from 2010
	2011			2010			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	5,173,398		$	2,090,988		$	3,082,410			147.4	%

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		3,989,927			1,807,044			2,182,883			120.8
Operating expenses (exclusive of depreciation and amortization)		227,883			130,263			97,620			74.9
General and administrative expenses (exclusive of depreciation and amortization)		43,141			16,925			26,216			154.9
Depreciation and amortization		43,240			29,138			14,102			48.4

Total operating costs and expenses		4,304,191			1,983,370			2,320,821			117.0

Income from operations		869,207			107,618			761,589			707.7

Other income (expense):
Equity in earnings of SLC Pipeline		532			570			(38	)		(6.7	)
Interest income		204			64			140			218.8
Interest expense		(25,074	)		(17,368	)		(7,706	)		44.4
Merger transaction costs		(9,100	)		—			(9,100	)		—

		(33,438	)		(16,734	)		(16,704	)		99.8

Income before income taxes		835,769			90,884			744,885			819.6
Income tax provision		304,758			31,494			273,264			867.7

Net income		531,011			59,390			471,621			794.1
Less net income attributable to noncontrolling interest		7,923			8,213			(290	)		(3.5	)

Net income attributable to HollyFrontier stockholders	$	523,088		$	51,177		$	471,911			922.1	%

Earnings per share attributable to HollyFrontier stockholders:
Basic	$	2.50		$	0.48		$	2.02			420.8	%

Diluted	$	2.48		$	0.48		$	2.00			416.7	%

Cash dividends declared per common share	$	1.09		$	0.08		$	1.01			1,262.5	%

Average number of common shares outstanding:
Basic		209,583			106,420			103,163			96.9	%
Diluted		210,579			107,134			103,445			96.6	%
EBITDA ⁽¹⁾	$	895,956		$	129,113		$	766,843			593.9	%

- 34 -


	Nine Months Ended September 30,						Change from 2010
	2011			2010			Change			Percent
	(In thousands, except per share data)
Sales and other revenues	$	10,467,116		$	6,111,138		$	4,355,978			71.3	%

Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)		8,421,639			5,379,120			3,042,519			56.6
Operating expenses (exclusive of depreciation and amortization)		501,971			378,638			123,333			32.6
General and administrative expenses (exclusive of depreciation and amortization)		78,641			50,623			28,018			55.3
Depreciation and amortization		106,380			85,719			20,661			24.1

Total operating costs and expenses		9,108,631			5,894,100			3,214,531			54.5

Income from operations		1,358,485			217,038			1,141,447			525.9

Other income (expense):
Equity in earnings of SLC Pipeline		1,739			1,595			144			9.0
Interest income		946			758			188			24.8
Interest expense		(56,471	)		(56,113	)		(358	)		0.6
Merger transaction costs		(15,114	)		—			(15,114	)		—

		(68,900	)		(53,760	)		(15,140	)		28.2

Income before income taxes		1,289,585			163,278			1,126,307			689.8
Income tax provision		465,730			54,476			411,254			754.9

Net income		823,855			108,802			715,053			657.2
Less net income attributable to noncontrolling interest		23,838			19,557			4,281			21.9

Net income attributable to HollyFrontier stockholders	$	800,017		$	89,245		$	710,772			796.4	%

Earnings per share attributable to HollyFrontier stockholders:
Basic	$	5.66		$	0.84		$	4.82			573.8	%

Diluted	$	5.63		$	0.83		$	4.80			578.3	%

Cash dividends declared per common share	$	1.24		$	0.23		$	1.01			439.1	%

Average number of common shares outstanding:
Basic		141,353			106,344			35,009			32.9	%
Diluted		142,092			107,062			35,030			32.7	%

EBITDA ⁽¹⁾	$	1,427,652		$	284,795		$	1,142,857			401.3	%

Balance Sheet Data (Unaudited)


	September 30, 2011		December 31, 2010
	September 30, 2011		December 31, 2010
	(In thousands)
Cash, cash equivalents and investments in marketable securities	$	1,759,353	$	230,444
Working capital	$	1,998,248	$	313,580
Total assets	$	9,916,463	$	3,701,475
Long-term debt	$	1,224,987	$	810,561
Total equity	$	5,660,790	$	1,288,139

- 35 -

(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.

Other Financial Data (Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Net cash provided by operating activities	$	631,207		$	197,622		$	1,089,203		$	235,968
Net cash provided by (used for) investing activities	$	668,216		$	(51,409	)	$	413,154		$	(127,939	)
Net cash provided by (used for) financing activities	$	(143,253	)	$	(14,505	)	$	(148,599	)	$	39,295
Capital expenditures	$	117,918		$	51,409		$	274,223		$	127,939

Our operations are 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Sales and other revenues
Refining ⁽¹⁾	$	5,164,778		$	2,081,709		$	10,433,096		$	6,086,243
HEP ⁽²⁾		49,288			46,558			145,233			132,730
Corporate and Other		299			100			1,100			317
Eliminations		(40,967	)		(37,379	)		(112,313	)		(108,152	)

Consolidated	$	5,173,398		$	2,090,988		$	10,467,116		$	6,111,138

Operating Income (loss)
Refining ⁽¹⁾	$	886,860		$	100,111		$	1,359,994		$	200,080
HEP ⁽²⁾		25,261			24,588			76,564			65,737
Corporate and Other		(42,354	)		(16,652	)		(76,490	)		(47,529	)
Eliminations		(560	)		(429	)		(1,583	)		(1,250	)

Consolidated	$	869,207		$	107,618		$	1,358,485		$	217,038

(1)

The Refining segment includes the operations of our Tulsa, Navajo and Woods Cross Refineries and NK Asphalt. Effective July 1, 2011, the Refining segment also includes the El Dorado and Cheyenne Refineries. Refining activities involve 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 Mid-Continent, Southwest and Rocky Mountain regions of the United States. Additionally, the Refining segment includes specialty lubricant products produced at our Tulsa Refinery that are marketed throughout North America and are distributed in Central and South America. NK Asphalt operates various asphalt terminals in Arizona, New Mexico and Texas.

- 36 -

(2)

The HEP segment involves all of the operations of 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 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 Tulsa, Navajo and Woods Cross Refineries and, effective July 1, 2011, the El Dorado and Cheyenne Refineries. Our Refineries serve the Mid-Continent, Southwest and Rocky Mountain regions of the United States. 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011⁽¹⁰⁾			2010
*Mid-Continent Region (Tulsa and El Dorado Refineries)*
Crude charge (BPD) ⁽¹⁾		263,260			114,820			160,230			112,340
Refinery throughput (BPD)⁽²⁾		283,970			117,450			168,150			114,070
Refinery production (BPD) ⁽³⁾		272,790			110,670			162,900			108,830
Sales of produced refined products (BPD)		263,180			113,040			159,230			107,950
Sales of refined products (BPD) ⁽⁴⁾		268,680			113,040			161,750			108,560

Refinery utilization ⁽⁵⁾		101.3	%		91.9	%		94.0	%		89.9	%

Average per produced barrel ⁽⁶⁾
Net sales	$	122.82		$	89.22		$	122.74		$	88.91
Cost of products ⁽⁷⁾		96.18			79.80			100.32			81.26

Refinery gross margin		26.64			9.42			22.42			7.65
Refinery operating expenses ⁽⁸⁾		4.57			4.80			5.09			5.10

Net operating margin	$	22.07		$	4.62		$	17.33		$	2.55

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	4.23		$	4.62		$	4.82		$	4.82

Feedstocks:
Sweet crude oil		75	%		83	%		84	%		90	%
Heavy sour crude oil		11	%		8	%		7	%		4	%
Sour crude oil		7	%		9	%		4	%		6	%
Other feedstocks and blends		7	%		—	%		5	%		—	%

Total		100	%		100	%		100	%		100	%

Sales of produced refined products:
Gasolines		44	%		39	%		41	%		39	%
Diesel fuels		35	%		30	%		33	%		31	%
Jet fuels		7	%		8	%		7	%		8	%
Lubricants		4	%		10	%		7	%		10	%
Gas oil / intermediates		2	%		4	%		4	%		3	%
Asphalt		2	%		6	%		4	%		5	%
LPG and other		6	%		3	%		4	%		4	%

Total		100	%		100	%		100	%		100	%

- 37 -


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011⁽¹⁰⁾			2010
*Southwest Region (Navajo Refinery)*
Crude charge (BPD) ⁽¹⁾		92,270			85,110			82,860			82,150
Refinery throughput (BPD)⁽²⁾		100,290			93,970			91,220			92,310
Refinery production (BPD) ⁽³⁾		100,100			91,550			90,230			90,290
Sales of produced refined products (BPD)		99,530			92,180			91,310			90,730
Sales of refined products (BPD) ⁽⁴⁾		102,940			94,900			95,980			93,780

Refinery utilization ⁽⁵⁾		92.3	%		85.1	%		82.9	%		82.2	%

Average per produced barrel ⁽⁶⁾
Net sales	$	120.67		$	87.60		$	119.84		$	88.98
Cost of products ⁽⁷⁾		92.33			79.39			97.37			81.44

Refinery gross margin		28.34			8.21			22.47			7.54
Refinery operating expenses ⁽⁸⁾		5.30			5.25			5.56			5.01

Net operating margin	$	23.04		$	2.96		$	16.91		$	2.53

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	5.26		$	5.15		$	5.57		$	4.92

Feedstocks:
Sour crude oil		70	%		81	%		72	%		84	%
Sweet crude oil		4	%		5	%		4	%		4	%
Heavy sour crude oil		18	%		6	%		15	%		2	%
Other feedstocks and blends		8	%		8	%		9	%		10	%

Total		100	%		100	%		100	%		100	%

Sales of produced refined products:
Gasolines		50	%		55	%		51	%		57	%
Diesel fuels		34	%		32	%		34	%		31	%
Jet fuels		1	%		2	%		1	%		4	%
Fuel oil		7	%		6	%		6	%		4	%
Asphalt		5	%		3	%		5	%		2	%
LPG and other		3	%		2	%		3	%		2	%

Total		100	%		100	%		100	%		100	%

*Rocky Mountain Region (Woods Cross and Cheyenne Refineries)*
Crude charge (BPD) ⁽¹⁾		70,060			27,440			41,050			26,870
Refinery throughput (BPD)⁽²⁾		75,860			29,250			44,340			28,440
Refinery production (BPD) ⁽³⁾		73,620			28,410			43,030			27,940
Sales of produced refined products (BPD)		72,400			27,540			42,390			28,260
Sales of refined products (BPD) ⁽⁴⁾		74,410			27,840			43,090			28,450

Refinery utilization ⁽⁵⁾		84.4	%		88.5	%		84.6	%		86.7	%

Average per produced barrel ⁽⁶⁾
Net sales	$	119.40		$	94.86		$	119.07		$	93.71
Cost of products ⁽⁷⁾		86.35			73.08			90.00			74.02

Refinery gross margin		33.05			21.78			29.07			19.69
Refinery operating expenses ⁽⁸⁾		6.55			6.11			6.44			5.86

Net operating margin	$	26.50		$	15.67		$	22.63		$	13.83

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	6.25		$	5.75		$	6.16		$	5.82

Feedstocks:
Sweet crude oil		49	%		61	%		53	%		60	%
Heavy sour crude oil		31	%		5	%		20	%		6	%
Black wax crude oil		10	%		30	%		18	%		29	%
Sour crude oil		3	%		—	%		2	%		—	%
Other feedstocks and blends		7	%		4	%		7	%		5	%

Total		100	%		100	%		100	%		100	%

- 38 -


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011⁽¹⁰⁾			2010
Sales of produced refined products:
Gasolines		50	%		60	%		55	%		62	%
Diesel fuels		34	%		33	%		32	%		31	%
Jet fuels		—	%		1	%		1	%		1	%
Fuel oil		1	%		2	%		2	%		1	%
Asphalt		7	%		2	%		5	%		3	%
LPG and other		8	%		2	%		5	%		2	%

Total		100	%		100	%		100	%		100	%

*Consolidated*
Crude charge (BPD) ⁽¹⁾		425,590			227,370			284,140			221,360
Refinery throughput (BPD)⁽²⁾		460,120			240,660			303,710			234,820
Refinery production (BPD) ⁽³⁾		446,510			230,630			296,160			227,060
Sales of produced refined products (BPD)		435,110			232,760			292,930			226,940
Sales of refined products (BPD) ⁽⁴⁾		446,030			235,780			300,820			230,790

Refinery utilization ⁽⁵⁾		96.1	%		88.8	%		89.1	%		86.5	%

Average per produced barrel ⁽⁶⁾
Net sales	$	121.76		$	89.25		$	121.31		$	89.53
Cost of products ⁽⁷⁾		93.66			78.84			97.91			80.43

Refinery gross margin		28.10			10.41			23.40			9.10
Refinery operating expenses ⁽⁸⁾		5.07			5.14			5.43			5.16

Net operating margin	$	23.03		$	5.27		$	17.97		$	3.94

Refinery operating expenses per throughput barrel ⁽⁹⁾	$	4.79		$	4.97		$	5.24		$	4.98

Feedstocks:
Sour crude oil		20	%		36	%		24	%		36	%
Sweet crude oil		55	%		49	%		55	%		53	%
Heavy sour crude oil		15	%		7	%		12	%		3	%
Black wax crude oil		2	%		4	%		3	%		4	%
Other feedstocks and blends		8	%		4	%		6	%		4	%

Total		100	%		100	%		100	%		100	%

Sales of produced refined products:
Gasolines		47	%		48	%		47	%		49	%
Diesel fuels		35	%		31	%		33	%		31	%
Jet fuels		4	%		5	%		4	%		6	%
Fuel oil		2	%		3	%		2	%		2	%
Asphalt		4	%		4	%		4	%		3	%
Lubricants		2	%		5	%		4	%		5	%
Gas oil / intermediates		1	%		2	%		2	%		1	%
LPG and other		5	%		2	%		4	%		3	%

Total		100	%		100	%		100	%		100	%

(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.

(4)	Includes refined products purchased for resale.

(5)	Represents crude charge divided by total crude capacity (BPSD). As a result of our merger effective July 1, 2011 our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD.

(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.

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

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

(9)	Represents refinery operating expenses, exclusive of depreciation and amortization divided by refinery throughput.

(10)

We merged with Frontier effective July 1, 2011. Refining operating data for the nine months ended September 30, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through September 30, 2011 only, and averaged over the 273 days in the nine months ended September 30, 2011.

- 39 -

Results of Operations – Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Summary

Net income attributable to HollyFrontier stockholders for the three months ended September 30, 2011 was $523.1 million ($2.50 per basic and $2.48 per diluted share), a $471.9 million increase compared to $51.2 million ($0.48 per basic and diluted share) for the three months ended September 30, 2010. Net income increased due principally to the acquired legacy Frontier operations and significantly higher refinery gross margins during the three months ended September 30, 2011. Overall refinery gross margins for the three months ended September 30, 2011 increased to $28.10 per produced barrel compared to $10.41 for the three months ended September 30, 2010.

Sales and Other Revenues

Sales and other revenues increased 147% from $2,091 million for the three months ended September 30, 2010 to $5,173.4 million for the three months ended September 30, 2011, due principally to the inclusion of $2,224 million in revenues attributable to the El Dorado and Cheyenne Refinery operations and the effects of increased refined product sales prices. The average sales price we received per produced barrel sold increased 36% from $89.25 for the three months ended September 30, 2010 to $121.76 for the three months ended September 30, 2011. Sales and other revenues for the three months ended September 30, 2011 and 2010, include $8.3 million and $9.2 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 121% from $1,807 million for the three months ended September 30, 2010 to $3,990 million for the three months ended September 30, 2011, due principally to the inclusion of sales volumes attributable to the El Dorado and Cheyenne Refineries and higher crude oil costs. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place increased 19% from $78.84 for the three months ended September 30, 2010 to $93.66 for the three months ended September 30, 2011.

Gross Refinery Margins

Gross refinery margin per produced barrel increased 170% from $10.41 for the three months ended September 30, 2010 to $28.10 for the three months ended September 30, 2011 due to the effects of an increase in the average sales price we received per barrel of produced refined products sold, partially offset by an increase in the average per barrel price we paid for crude oil and feedstocks. This was influenced by wide favorable differentials between inland and coastal-sourced crude oils. 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 75% from $130.3 million for the three months ended September 30, 2010 to $227.9 million for the three months ended September 30, 2011, due principally to the inclusion of the El Dorado and Cheyenne Refinery operations. Also contributing to a much lesser extent was increased payroll and maintenance costs attributable to the legacy Holly refining operations.

General and Administrative Expenses

General and administrative expenses increased 155% from $16.9 million for the three months ended September 30, 2010 to $43.1 million for the three months ended September 30, 2011. This includes $15 million in integration and severance costs associated with the integration of our merged companies. It also reflects higher payroll and equity based compensation costs.

Depreciation and Amortization Expenses

Depreciation and amortization increased 48% from $29.1 million for the three months ended September 30, 2010 to $43.2 million for the three months ended September 30, 2011. The increase was due principally to depreciation and amortization attributable to the El Dorado and Cheyenne Refinery assets and capitalized improvement projects.

- 40 -

Interest Expense

Interest expense was $25.1 million for the three months ended September 30, 2011 compared to $17.4 million for the three months ended September 30, 2010. This increase reflects the write-off of $5 million of previously deferred financing costs due to the July 1, 2011 termination of our previous credit agreement and the inclusion of interest attributable to the senior notes assumed upon our merger with Frontier. Additionally, we capitalized $3.8 million interest attributable to the UNEV Pipeline project. For the three months ended September 30, 2011 and 2010, interest expense included $9.4 million and $9 million, respectively, in interest costs attributable to HEP operations.

Merger Transaction Costs

For the three months ended September 30, 2011, we recognized merger transaction costs of $9.1 million related to our merger with Frontier effective July 1, 2011. These costs relate to legal, advisory and other professional fees that are directly attributable to the merger.

Income Taxes

For the three months ended September 30, 2011, we recorded income tax expense of $304.8 million compared to $31.5 million for the three months ended September 30, 2010. This increase was due principally to significantly higher pre-tax earnings during the three months ended September 30, 2011 compared to the same period of 2010. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 36.5% and 34.7% for the three months ended September 30, 2011 and 2010, respectively.

Results of Operations – Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Summary

Net income attributable to HollyFrontier stockholders for the nine months ended September 30, 2011 was $800 million ($5.66 per basic and $5.63 per diluted share), a $710.8 million increase compared to $89.2 million ($0.84 per basic and $0.83 per diluted share) for the nine months ended September 30, 2010. The increase in net income reflects both the effects of our recent merger and significantly higher refinery gross margins during the nine months ended September 30, 2011. Overall refinery gross margins for the nine months ended September 30, 2011 increased to $23.40 per produced barrel compared to $9.10 for the nine months ended September 30, 2010.

Overall production levels for the nine months ended September 30, 2011 increased over the same period of 2010 due principally to the inclusion of the El Dorado and Cheyenne Refinery operations beginning July 1, 2011. For the nine months ended September 30, 2011, overall production levels averaged 296,160 barrels per day (“BPD”) compared to 227,060 BPD for the same period last year.

Sales and Other Revenues

Sales and other revenues increased 71% from $6,111.1 million for the nine months ended September 30, 2010 to $10,467.1 million for the nine months ended September 30, 2011, due principally to the inclusion of $2,224 million in revenues attributable to the El Dorado and Cheyenne Refinery operations and increased sales prices of produced refined products sold. The average sales price we received per produced barrel sold increased 35% from $89.53 for the nine months ended September 30, 2010 to $121.31 for the nine months ended September 30, 2011. Sales and other revenues for the nine months ended September 30, 2011 and 2010, include $33 million and $24.7 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold

Cost of products sold increased 57% from $5,379.1 million for the nine months ended September 30, 2010 to $8,421.6 million for the nine months ended September 30, 2011, reflecting both the effects of our recent merger

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and higher crude oil costs. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place increased 22% from $80.43 for the nine months ended September 30, 2010 to $97.91 for the nine months ended September 30, 2011.

Gross Refinery Margins

Gross refinery margin per produced barrel increased 157% from $9.10 for the nine months ended September 30, 2010 to $23.40 for the nine months ended September 30, 2011 due to the effects of an increase in the average sales price we received per barrel of produced refined products sold, partially offset by an increase in the average per barrel price we paid for 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 33% from $378.6 million for the nine months ended September 30, 2010 to $502 million for the nine months ended September 30, 2011, due principally to the inclusion of the El Dorado and Cheyenne Refinery operations beginning July 1, 2011. Also contributing to a much lesser extent was increased payroll and maintenance costs attributable to the legacy Holly refining operations.

General and Administrative Expenses

General and administrative expenses increased 55% from $50.6 million for the nine months ended September 30, 2010 to $78.6 million for the nine months ended September 30, 2011. This includes $15 million in integration and severance costs associated with the integration of our merged companies. It also reflects higher compensation costs and professional fees.

Depreciation and Amortization Expenses

Depreciation and amortization increased 24% from $85.7 million for the nine months ended September 30, 2010 to $106.4 million for the nine months ended September 30, 2011. The increase was due principally to depreciation and amortization attributable to the El Dorado and Cheyenne Refinery assets and capitalized improvement projects.

Interest Expense

Interest expense was $56.5 million for the nine months ended September 30, 2011 compared to $56.1 million for the nine months ended September 30, 2010. This increase reflects the write-off of $5 million of previously deferred financing costs due to the July 1, 2011 termination of our previous credit agreement and the inclusion of interest attributable to the senior notes assumed upon our merger with Frontier. Additionally, we capitalized $9.2 million interest attributable to the UNEV Pipeline project. For the nine months ended September 30, 2011 and 2010, interest expense included $27.8 million and $27.2 million, respectively, in interest costs attributable to HEP operations.

Merger Transaction Costs

For the nine months ended September 30, 2011, we recognized merger transaction costs of $15.1 million that relate to legal, advisory and other professional fees incurred since our announced merger with Frontier on February 21, 2011.

Income Taxes

For the nine months ended September 30, 2011 we recorded income tax expense of $465.7 million compared to $54.5 million for the nine months ended September 30, 2010. This increase was due principally to significantly higher pre-tax earnings during the nine months ended September 30, 2011 compared to the same period of 2010. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 36.1% and 33.4% for the nine months ended September 30, 2011 and 2010, respectively.

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LIQUIDITY AND CAPITAL RESOURCES

HollyFrontier Credit Agreement

On July 1, 2011, we entered into a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as administrative agent and BNP Paribas as syndication agent, and certain lenders from time to time thereto, and terminated our previous $400 million credit agreement. Additionally, Frontier terminated its previous $500 million credit agreement. The HollyFrontier Credit Agreement matures in July 2016 and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries.

Indebtedness under the HollyFrontier Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.50% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.50% to 2.50%). We incur a commitment fee on the unused portion of the HollyFrontier Credit Agreement at a rate ranging from 0.375% to 0.50% based upon the credit ratings of our long-term, unsecured, senior debt. At September 30, 2011, we are subject to a 0.375% commitment fee on the $839.4 million unused portion of the credit agreement.

HEP Credit Agreement

HEP has a $275 million senior secured revolving Credit Agreement (the “HEP Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. In February 2011, HEP amended its previous credit agreement (expiring in August 2011), extended the expiration date and slightly reduced 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, 2011, HEP had outstanding borrowings totaling $202 million under the HEP Credit Agreement, with unused borrowing capacity of $73 million.

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. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

HollyFrontier Senior Notes

Our senior notes consist of the following:

•

9.875% Senior Notes ($300 million principal amount maturing June 2017)

•

6.875% Senior Notes ($150 million principal amount maturing November 2018)⁽¹⁾

•

8.5% Senior Notes ($200 million principal amount maturing September 2016)⁽¹⁾

These notes (collectively the “HollyFrontier 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 HollyFrontier 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 HollyFrontier Senior Notes.

⁽¹⁾	Represent senior notes assumed upon our July 1, 2011 merger with Frontier.

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HollyFrontier 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.

HEP Senior Notes

HEP’s senior notes consist of the following:

•

6.25% Senior Notes ($185 million principal amount maturing March 2015)

•

8.25% Senior Notes ($150 million principal amount maturing March 2018)

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

Liquidity

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

As of September 30, 2011, our cash, cash equivalents and investments in marketable securities totaled $1.8 billion. 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.

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During the nine months ended September 30, 2011, cash and cash equivalents increased by $1,353.8 million. Net cash provided by operating activities of $1,089.2 million and by investing activities of $413.2 million exceeded cash used for financing activities of $148.6 million. Working capital increased by $1,684.7 million during the nine months ended September 30, 2011.

Cash Flows – Operating Activities

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net cash flows provided by operating activities were $1,089.2 million for the nine months ended September 30, 2011 compared to net cash provided by operating activities of $236 million for the nine months ended September 30, 2010, an increase of $853.2 million. Net income for the nine months ended September 30, 2011 was $823.9 million, an increase of $715.1 million compared to $108.8 million for the nine months ended September 30, 2010. Non-cash adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense and fair value adjustments to derivative instruments resulted in an increase to operating cash flows of $120.5 million for the nine months ended September 30, 2011 compared to $100.5 million for the same period in 2010. Additionally, SLC Pipeline earnings, net of distributions increased operating cash flows by $0.2 million for the nine months ended September 30, 2011 and $0.4 million September 30, 2010, respectively. Changes in working capital items increased cash flows by $167.2 million for the nine months ended September 30, 2011 compared to an increase of $34.2 million for the nine months ended September 30, 2010. Additionally, for the nine months ended September 30, 2011, turnaround expenditures increased to $28 million from $11.5 million in 2010 due primarily to a major maintenance turnaround project at our Tulsa Refinery facilities that was completed in January 2011.

Cash Flows – Investing Activities and Planned Capital Expenditures

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net cash flows provided by investing activities were $413.2 million for the nine months ended September 30, 2011 compared to net cash flows used by investing activities of $127.9 million for the nine months ended September 30, 2010, an increase of $541.1 million. Current year investing activities reflect a net cash inflow due to an $872.2 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for the first nine months of 2011 increased to $274.2 million from $127.9 million for the same period in 2010. These include HEP capital expenditures of $31.5 million and $8.1 million for the nine months ended September 30, 2011 and 2010, respectively. Capital expenditures were significantly higher in the nine months ending September 30, 2011 due to construction of the UNEV Pipeline system. During the nine months ended September 30, 2011, we invested $9.1 million in Sabine Biofuels, a development stage biodiesel production facility. Also for the nine months ended September 30, 2011, we invested $370 million in marketable securities and received proceeds of $194.4 million from the sale or maturity of marketable securities.

Planned Capital Expenditures

HollyFrontier Corporation

Each year our Board of Directors approve 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 expected capital spending for projects in 2011 totals $340 million which includes capital projects approved in prior years and is comprised of $70 million at the Tulsa Refinery, $24 million at the Navajo Refinery, $13 million at the Woods Cross Refinery, $72 million at the Cheyenne Refinery, $35 million at the El Dorado Refinery, $111 million for our portion of the UNEV Pipeline project, $3 million for asphalt plant projects and $12 million for pipeline, product terminals and miscellaneous projects. This does not include approved turnaround or tank work for 2011.

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Tulsa Refinery

We have completed the integration project of our Tulsa Refinery west and east facilities. In September 2011, HEP completed its interconnecting pipeline project which now allows us to optimize gasoline blending, increase our utilization of better process technology, improve yields and reduce operating costs. The interconnect Hydrogen line also allowed for the production of up to 100% ULSD during the quarter due to the recently completed diesel hydrotreating unit expansion.

The Tulsa Refinery facilities also will be required to comply with new MSAT2 regulations in order to meet new federal benzene reduction requirements for gasoline. We have decided to primarily use existing equipment at the Tulsa Refinery east facility to split reformate from reformers at both west and east facilities and install a new benzene saturation unit to achieve the required benzene reduction at an estimated cost of $29 million. We are 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 average 1.3% benzene levels on an annual basis beginning in July 2012. This project was mechanically complete at the end of the third quarter and is in the process of startup.

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. Our Board of Directors have approved a project for $58 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 at an estimated cost of $10 million.

Navajo Refinery

The Navajo Refinery currently plans to comply with the new MSAT2 regulations by the fractionation of naphtha by revamping an existing fractionation unit to achieve benzene in gasoline levels below 1.3%. The Navajo Refinery will purchase or use credits generated at the Tulsa Refinery to reduce benzene 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. Also, we will be installing a new storm water surge tank and upgrading several other processes at the Artesia refinery’s waste water treatment plant. These projects are expected to cost approximately $17 million.

Woods Cross Refinery

Our Woods Cross Refinery is required to install a wet gas scrubber on its FCC unit by the end of 2012. We estimate the total cost to be $15 million. The MSAT2 solution for the refinery involves revamping its naphtha fractionation unit and installing a benzene saturation unit at an estimated cost of $18 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.

Cheyenne Refinery

At the Cheyenne Refinery, we are mechanically complete on an LPG recovery project that will recover significant quantities of saleable propane and butane and other LPGs for alkylation unit feed from the refinery fuel gas system. The project is estimated to cost approximately $40 million and is in the process of startup. Due to the merger of Holly and Frontier, our Cheyenne Refinery has until the end of 2013 to comply with the MSAT2 regulations because we no longer qualify for the small refiner’s exemption. We are currently in the process of determining the most economical solution.

El Dorado Refinery

At the El Dorado Refinery, we have a coker furnace replacement project which will replace the existing furnace with the latest technology in coking furnaces. This project, which is expected to cost $25 million, will let us avoid a substantial rebuild of the existing furnace in the 2013 turnaround and reduce the ongoing impact on coker throughput from decoking. This project is estimated to be completed in late 2012. The El Dorado Refinery has until the end of 2013 to comply with the MSAT2 regulations because as a result of the merger between Holly and

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Frontier we no longer qualify for the small refiner’s exemption. We currently operate with the gasoline pool below the 1.3% benzene requirement but are considering expanding our aromatic extraction unit to either generate benzene credits or minimize credit purchase requirements.

UNEV

Under a definitive agreement with Sinclair, we are jointly building the UNEV Pipeline, a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas. Under the agreement, we own a 75% interest in the joint venture pipeline with Sinclair, our joint venture partner, owning the remaining 25% interest. The initial capacity of the pipeline will be 62,000 BPD (based on gasoline equivalents), with the capacity for further expansion to 120,000 BPD. The current total cost of the pipeline project including terminals is expected to be approximately $385 million, with our share of the cost totaling $289 million. This project includes the construction of ethanol blending and storage facilities at the Cedar City terminal. The pipeline is in the final construction phase and is expected to be mechanically complete in November 2011 with startup by the end of the year. In connection with this project, we have entered into a 10-year commitment to ship an annual average of 15,000 barrels per day of refined products on the UNEV Pipeline at an agreed tariff. Our commitment for each year is subject to reduction by up to 5,000 barrels per day in specified circumstances relating to shipments by other shippers. We have an option agreement with HEP granting them an option to purchase all of our equity interests in this joint venture pipeline effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to our investment in this joint venture pipeline plus interest at 7% per annum.

Regulatory compliance items or other presently existing or future environmental regulations / consent decrees could cause us to make additional capital investments beyond those described above and incur additional operating costs to meet applicable requirements.

HEP

Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given year consist of expenditures approved for capital projects included in its current year capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2011 HEP capital budget is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

As described under our Tulsa Refinery integration project, HEP completed construction of five interconnecting pipelines between our Tulsa east and west refining facilities, costing approximately $35 million. These pipelines were placed in service in September 2011.

Additionally, HEP has two expansion projects to provide 60,000 bpd of additional crude pipeline take-away capacity resulting from increased Delaware Basin drilling activity in southeast New Mexico. The first project will increase one of its existing crude oil trunk lines from 35,000 bpd to 60,000 bpd. This project which includes the replacement of 5 miles of existing pipe with larger diameter pipe is expected to cost approximately $2 million with completion in the first half of 2012. The second project will consist of the reactivation and conversion to crude oil service a 70-mile, 8-inch petroleum products pipeline owned by HEP. Once in service, this pipeline would be capable of transporting up to 35,000 bpd of crude oil from the Carlsbad, New Mexico area to either a common carrier pipeline station for transport to major crude oil markets or to our Navajo refining facilities. The scope of this second project has not yet been finalized. Subject to receipt of acceptable shipper support and board approval, this project could also be completed during the first half of 2012.

Cash Flows – Financing Activities

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net cash flows used for financing activities were $148.6 million for the nine months ended September 30, 2011 compared to net cash flows provided by financing activities of $39.3 million for the nine months ended

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September 30, 2010, a decrease of $187.9 million. During the nine months ended September 30, 2011, we paid $0.9 million under our financing obligation to Plains, repurchased $39 million in our common stock of which $24.4 million was from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $129.4 million in dividends, received a $27.5 million contribution from our UNEV Pipeline joint venture partner and recognized $1.4 million in excess taxes on our equity based compensation. Additionally, we incurred $8.5 million in deferred financing costs in obtaining the HollyFrontier Credit Agreement. During the nine months ended September 30, 2011, HEP received $93 million and repaid $50 million under the HEP Credit Agreement, paid distributions of $37.9 million to noncontrolling interests, incurred $3.2 million in deferred financing costs and purchased $1.6 million in HEP common units in the open market for recipients of its restricted unit grants. During the nine months ended September 30, 2010, we received and repaid $310 million in advances under the previous Holly credit agreement, paid $0.8 million under our financing obligation to Plains, purchased $1.3 million in common stock from employees to provide funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards, paid $23.9 million in dividends and received a $9.5 million contribution from our UNEV Pipeline joint venture partner. Also during this period, HEP received $147.5 million in net proceeds upon the issuance of the HEP 8.25% Senior Notes, received $52 million and repaid $101 million under the HEP Credit Agreement, paid distributions of $36.1 million to noncontrolling interests and purchased $2.3 million in HEP common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs were incurred in connection with the issuance of the HEP 8.25% Senior Notes in March 2010 and an amendment to the previous Holly credit agreement.

Contractual Obligations and Commitments

HollyFrontier Corporation

The following table presents long-term contractual obligations as of September 30, 2011 that were assumed upon our merger with Frontier in total and by period due beginning October 1, 2011.


Contractual Obligations and Commitments	Total		Payments Due by Period
Contractual Obligations and Commitments	Total		Less than 1 Year		1-3 Years		3-5 Years		Over 5 Years
	(In thousands)
Long-term debt – principal ⁽¹⁾	$	349,985	$	—	$	—	$	199,985	$	150,000
Long-term debt – interest ⁽²⁾		158,910		27,313		54,626		54,626		22,345
Crude oil, feedstocks and natural gas supply agreements⁽³⁾		378,530		145,502		150,793		59,765		22,470
Operating leases		35,209		11,146		14,773		9,290		—
Transportation agreements		16,799		4,134		5,657		4,601		2,407
Capital lease		3,052		456		1,037		1,234		325
Other agreements		7,054		2,608		3,012		1,434		—

Total	$	949,539	$	191,159	$	229,898	$	330,935	$	197,547

(1)	Long-term debt consists of the $200 million 8.5% Senior Notes maturing in September 2016 and the $150 million 6.875% Senior Notes maturing in November 2018.

(2)	Interest payments consist of interest on the 8.5% Senior Notes and the 6.875% Senior Notes.

(3)	These agreements consist of long-term supply agreements to purchase minimum quantities of crude oil, feedstocks and natural gas at market prices through 2017. We have estimated our future obligations using current market prices.

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HEP

During the nine months ended September 30, 2011, HEP received net advances of $43 million resulting in $202 million of outstanding borrowings under the HEP Credit Agreement at September 30, 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, 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 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

Presentation of Comprehensive Income

Intangibles – Goodwill and Other: Testing Goodwill for Impairment

RISK MANAGEMENT

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

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Commodity Price Risk Management

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.

We also have outstanding commodity price swap contracts serving as economic hedges to protect the value of temporary crude oil inventory builds of 15,000 barrels against price volatility through November 2011. Also, we have swap contracts that lock in the following spreads: between WTS and WTI crude oil on forecasted purchases (1,403,000 barrels of crude oil through the end of 2011); between gasoline and butane on forecasted sales (225,000 barrels of gasoline through January 2012); between fuel oil and WTI crude oil on forecasted sales (276,000 barrels of fuel oil through the end of 2011); and between WTI crude oil and various other products on forecasted sales and purchases (279,000 barrels, net through 2013). These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to cost of products sold.

Interest Rate Risk Management

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

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Derivative Instruments	Balance Sheet Location	Fair Value		Location of Offsetting Balance	Offsetting Amount
	(Dollars in thousands)
September 30, 2011
*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	122,682	Accrued liabilities	$	100,139
				Accumulated other comprehensive loss		22,181
				Cost of products sold (decrease)		362

		$	122,682		$	122,682

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	7,378	Accumulated other comprehensive loss	$	7,378

*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Prepayments and other current assets	$	8,115	Cost of products sold (decrease)	$	8,115

Commodity price swap contracts	Accrued liabilities	$	1,184	Cost of products sold (increase)	$	1,184

December 31, 2010
*Derivatives designated as cash flow hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	38	Accumulated other comprehensive loss	$	38

Variable-to-fixed interest rate swap contract	Other long-term liabilities	$	10,026	Accumulated other comprehensive loss	$	10,026

*Derivatives not designated as hedging instruments:*
Commodity price swap contracts	Accrued liabilities	$	497	Cost of products sold (increase)	$	497

For the nine months ended September 30, 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. 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.

For the fixed rate HollyFrontier Senior Notes and HEP Senior Notes, changes in interest rates will generally affect fair value of the debt, but not our earnings or cash flows. The outstanding principal, estimated fair value and estimated change in fair value assuming a hypothetical 10% change in the yield-to-maturity rates for these debt instruments as of September 30, 2011 is presented below:

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	Outstanding Principal		Estimated Fair Value		Estimated Change in Fair Value
	(In thousands)
HollyFrontier Senior Notes	$	649,985	$	684,829	$	32,986
HEP Senior Notes	$	335,000	$	337,938	$	9,450

For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At September 30, 2011, borrowings outstanding under the HEP Credit Agreement were $202 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 6.24%. For the unhedged $47 million portion, a hypothetical 10% change in interest rates applicable to the HEP Credit Agreement would not materially affect cash flows.

At September 30, 2011, cash and cash equivalents included investments in investment grade, highly liquid investments with maturities of 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 cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

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

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles

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

Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income attributable to HollyFrontier 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.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Net income attributable to HollyFrontier stockholders	$	523,088		$	51,177		$	800,017		$	89,245
Add income tax provision		304,758			31,494			465,730			54,476
Add interest expense		25,074			17,368			56,471			56,113
Subtract interest income		(204	)		(64	)		(946	)		(758	)
Add depreciation and amortization		43,240			29,138			106,380			85,719

EBITDA	$	895,956		$	129,113		$	1,427,652		$	284,795

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.

Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of produced refined products. Net operating margin per barrel is the difference between refinery gross margin and refinery operating expenses per barrel of produced refined products. These two margins do not include the effect of depreciation and amortization. Each of these component performance measures can be reconciled directly to our Consolidated Statements of Income.

Other companies in our industry may not calculate these performance measures in the same manner.

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Refinery Gross and Net Operating Margins

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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Dollars in thousands, except per barrel amounts)
*Consolidated*
Average sales price per produced barrel sold	$	121.76		$	89.25		$	121.31		$	89.53
Times sales of produced refined products sold (BPD)		435,110			232,760			292,930			226,940
Times number of days in period		92			92			273			273

Refined product sales from produced products sold	$	4,874,067		$	1,911,192		$	9,701,147		$	5,546,797

Total refined product sales	$	4,874,067		$	1,911,192		$	9,701,147		$	5,546,797
Add refined product sales from purchased products and rounding ⁽¹⁾		127,520			24,495			266,355			93,447

Total refined product sales		5,001,587			1,935,687			9,967,502			5,640,244
Add direct sales of excess crude oil ⁽²⁾		148,989			106,364			422,890			355,381
Add other refining segment revenue ⁽³⁾		14,204			39,658			42,704			90,618

Total refining segment revenue		5,164,780			2,081,709			10,433,096			6,086,243
Add HEP segment sales and other revenues		49,288			46,558			145,233			132,730
Add corporate and other revenues		297			100			1,100			317
Subtract consolidations and eliminations		(40,967	)		(37,379	)		(112,313	)		(108,152	)

Sales and other revenues	$	5,173,398		$	2,090,988		$	10,467,116		$	6,111,138

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Dollars in thousands, except per barrel amounts)
*Consolidated*
Average cost of products per produced barrel sold	$	93.66		$	78.84		$	97.91		$	80.43
Times sales of produced refined products sold (BPD)		435,110			232,760			292,930			226,940
Times number of days in period		92			92			273			273

Cost of products for produced products sold	$	3,749,221		$	1,688,273		$	7,829,852		$	4,983,010

Total cost of products for produced products sold	$	3,749,221		$	1,688,273		$	7,829,852		$	4,983,010
Add refined product costs from purchased products sold and rounding ⁽¹⁾		128,857			24,648			268,390			93,923

Total cost of refined products sold		3,878,078			1,712,921			8,098,242			5,076,933
Add crude oil cost of direct sales of excess crude oil ⁽²⁾		147,223			105,091			416,084			351,643
Add other refining segment cost of products sold ⁽⁴⁾		4,696			25,555			17,032			56,186

Total refining segment cost of products sold		4,029,997			1,843,567			8,531,358			5,484,762
Subtract consolidations and eliminations		(40,070	)		(36,523	)		(109,719	)		(105,642	)

Costs of products sold (exclusive of depreciation and amortization)	$	3,989,927		$	1,807,044		$	8,421,639		$	5,379,120

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Dollars in thousands, except per barrel amounts)
*Consolidated*
Average refinery operating expenses per produced barrel sold	$	5.07		$	5.14		$	5.43		$	5.16
Times sales of produced refined products sold (BPD)		435,110			232,760			292,930			226,940
Times number of days in period		92			92			273			273

Refinery operating expenses for produced products sold	$	202,953		$	110,068		$	434,237		$	319,686

Total refinery operating expenses per produced products sold	$	202,953		$	110,068		$	434,237		$	319,686
Add other refining segment operating expenses and rounding ⁽⁵⁾		10,080			6,689			26,156			19,116

Total refining segment operating expenses		213,033			116,757			460,393			338,802
Add HEP segment operating expenses		14,689			13,632			41,851			40,187
Add corporate and other costs		291			6			117			24
Subtract consolidations and eliminations		(130	)		(132	)		(390	)		(375	)

Operating expenses (exclusive of depreciation and amortization)	$	227,883		$	130,263		$	501,971		$	378,638

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Dollars in thousands, except per barrel amounts)
*Consolidated*
Net operating margin per barrel	$	23.03		$	5.27		$	17.97		$	3.94
Add average refinery operating expenses per produced barrel		5.07			5.14			5.43			5.16

Refinery gross margin per barrel		28.10			10.41			23.40			9.10
Add average cost of products per produced barrel sold		93.66			78.84			97.91			80.43

Average sales price per produced barrel sold	$	121.76		$	89.25		$	121.31		$	89.53
Times sales of produced refined products sold (BPD)		435,110			232,760			292,930			226,940
Times number of days in period		92			92			273			273

Refined product sales from produced products sold	$	4,874,067		$	1,911,192		$	9,701,147		$	5,546,797

Total refined product sales from produced products sold	$	4,874,067		$	1,911,192		$	9,701,147		$	5,546,797
Add refined product sales from purchased products and rounding ⁽¹⁾		127,520			24,495			266,355			93,447

Total refined product sales		5,001,587			1,935,687			9,967,502			5,640,244
Add direct sales of excess crude oil ⁽²⁾		148,989			106,364			422,890			355,381
Add other refining segment revenue ⁽³⁾		14,204			39,658			42,704			90,618

Total refining segment revenue		5,164,780			2,081,709			10,433,096			6,086,243
Add HEP segment sales and other revenues		49,288			46,558			145,233			132,730
Add corporate and other revenues		297			100			1,100			317
Subtract consolidations and eliminations		(40,967	)		(37,379	)		(112,313	)		(108,152	)

Sales and other revenues	$	5,173,398		$	2,090,988		$	10,467,116		$	6,111,138

(1)

We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.

(2)

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

(3)

Other refining segment revenue includes the incremental revenues associated with NK Asphalt and miscellaneous revenue.

(4)

Other refining segment cost of products sold includes the incremental cost of products for NK Asphalt and miscellaneous costs.

(5)

Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses of NK Asphalt.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 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.

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PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

Commitment and Contingency Reserves

We periodically 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.

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 approximately 10 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. Two wrongful death lawsuits and two personal injury lawsuits seeking damages, including punitive damages, were filed on behalf of the estates of the two deceased workers and on behalf of the two survivors in state court in Dallas County, Texas (two lawsuits) and state court in Eddy County, New Mexico (two lawsuits). A confidential settlement was reached in the two Texas cases, and the cases have been dismissed. One of the cases in New Mexico is set for trial in March of 2012. The other case is not set for trial. At the date of this report, it is not possible to predict the percentage of fault that may be attributed to Navajo Refining Company, LLC, our subsidiary (“Navajo”), though fault can be expected. This matter is being reported due to the serious nature of the injuries and potential verdicts. Because of our insurance coverage, the total cost to the Company for these cases is not expected to be material.

New Mexico OHSB 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, alleging 10 willful violations and one 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. The parties were unable to reach an agreement, thus OHSB filled an administrative complaint with New Mexico Occupational Health and Safety

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Review Commission (“OHSRC”) on December 20, 2010. Discovery is under way at this time. OHSRC granted the parties’ joint request that a hearing commence no sooner than July 5, 2012, but the specific hearing date has not yet been established.

OSHA Inspections – Tulsa Refinery

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 standard. OSHA proposed penalties totaling $57,150. Our subsidiary, Holly Refining & Marketing – Tulsa LLC, our subsidiary (“HRM-Tulsa”), filed a notice of contest, and challenged each citation item. On October 12, 2011, a settlement favorable to HRM-Tulsa was reached in which four of the citation items were withdrawn, several were reclassified as other than serious, and the total penalty was reduced to $9,500.

On March 28, 2011, OSHA issued a serious citation to HRM-Tulsa with respect to the Tulsa Refinery west facility, alleging one facility siting and two housekeeping violations, which stemmed from its investigation of an employee complaint that it received during a previous NEP inspection. OSHA proposed penalties of $6,275. HRM Tulsa 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 15, 2011. Discovery is underway and the hearing is scheduled to commence January 10, 2012.

Discharge Permit Appeal – Tulsa Refinery West Facility

HRM-Tulsa, is party to parallel Oklahoma administrative and state district court proceedings involving a challenge to the terms of the Oklahoma Department of Environmental Quality (“ODEQ”) permit that governs the discharge of industrial wastewater from our Tulsa Refinery west facility. Pursuant to a settlement agreement between HRM-Tulsa and ODEQ, both proceedings have been stayed to allow ODEQ to issue a revised permit that modifies the existing permit’s requirements for toxicity testing and for managing storm flows. The parties are now in discussions regarding the appropriate changes in the permit language to accomplish these modifications. Once agreed-upon revisions are made and become effective, both proceedings will be dismissed. Any changes to refinery processes that result from the permit revisions 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.

Clean Air Act Notice of Violation – Tulsa Refinery East 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 was the number of valves that the facility had classed as “Difficult to Monitor.” The agency maintained 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. After further discussion with the EPA, the ODEQ has now decided not to pursue the matter any further.

The original notification also disclosed the agency’s intent to seek a separate fine of $17,500 for separate Clean Air Act violations that were alleged to have occurred 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 and believes that the proposed fine will be substantially reduced. Even if this remaining fine is not reduced, the amount at issue is not material without the alleged valve violations that are no longer being pursued.

Benzene Waste Operations Regulatory Proceedings – Tulsa Refinery East and West Facilities

On July 13, 2011, the Environmental Protection Agency issued a determination that HRM – Tulsa’s two refineries should be considered a single facility for purposes of a particular Clean Air Act regulation, the

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Benzene Waste Operations NESHAP. As a single facility, the refineries’ emissions would be combined for purposes of assessing whether they were exceeding the relevant regulatory threshold. We disagree with this interpretation, however, and have appealed the matter to the U.S. Court of Appeals for the Tenth Circuit. Should it be ultimately determined that the two refineries are to be treated as a single unit for these purposes, the cost of compliance would be an estimated $10 million. It is possible that the regulatory agencies will rely on the announced interpretation to seek fines as well. The amount of any such fines cannot currently be estimated.

Litigation Related to the Merger with Frontier Oil Corporation

Twelve substantially similar shareholder lawsuits styled as class actions were 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, Holly and our wholly owned subsidiary, North Acquisition, Inc., as aiders and abettors. To date, such shareholder actions remain pending in Harris County, Texas, the U.S. District Court for the Northern District of Texas, and the U.S. District Court for the Southern District of Texas. One case filed in Laramie County, Wyoming was dismissed without prejudice.

These lawsuits generally allege that (1) the consideration received by Frontier’s shareholders in the merger was 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. In the three federal court cases discussed more fully below, we and/or North Acquisition, Inc. were also alleged to have violated Section 14(a) and Section 20(a) of the Exchange Act of 1934 by soliciting proxies based on an allegedly false and/or misleading proxy statement concerning the merger. 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.

The eight lawsuits filed in the District Courts of Harris County, Texas (the “Texas State Court Lawsuits”) are consolidated under the caption: In re Frontier Oil Corporation, Cause No. 2011-11451 (first case filed February 22, 2011). On September 12, 2011, the lead plaintiff and the defendants in the Texas State Court Lawsuits submitted a Stipulation and Agreement of Settlement to the Court for preliminary approval. Pursuant to that agreement, the actions were stayed and certain additional disclosures were made to Frontier’s shareholders on June 20, 2011. After a hearing on October 7, 2011, the Court granted preliminary approval of the settlement and scheduled a final settlement hearing for January 6, 2012. At that time, the court will consider the fairness, reasonableness and adequacy of the settlement which, if finally approved by the court, will resolve on behalf of the class all of the claims that were or could have been brought in the actions being settled. We cannot be certain that the court will approve the settlement. If it does not, the settlement may be terminated.

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). On June 29, 2011, the plaintiff filed an amended complaint, and one month later, the parties filed an agreed motion to stay the case so that the proposed settlement in the Texas State Court Lawsuits could be considered and resolved by the state court. The motion to stay was granted.

The two remaining lawsuits filed in the U.S. District Court for the Southern District of Texas are consolidated under the caption: Tim Wilcox, Individually and Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (first case filed on March 7, 2011). We and our wholly owned subsidiary moved to dismiss the amended complaint on April 21, 2011, and the other defendants moved for dismissal in July after they were served. These motions to dismiss remain pending. On June 24, 2011, the court denied plaintiffs’ motion for a temporary restraining order and preliminary injunction to enjoin the proposed merger and prevent Frontier’s shareholders from voting on it. On August 9, 2011, the defendants filed an unopposed motion to stay the consolidated case in light of the proposed settlement of the Texas State Court Lawsuits. The court has not yet ruled on that motion.

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.

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Unclaimed Property Audits

A multi-state audit of legacy Holly Corporation’s unclaimed property compliance and reporting is being conducted by Kelmar Associates, LLC on behalf of eleven states. We are currently in the fourth year of this ongoing audit that covers the period 1981 – 2004. It is not yet possible to accurately estimate the amount, if any, that is owed to each of the states.

We have been notified of the commencement of a similar multi-state audit of legacy Frontier Oil Corporation’s unclaimed property compliance and reporting, which is also being conducted by Kelmar Associates, LLC on behalf of six states. The audit work has not yet begun, and it is not yet possible to accurately estimate the amount, if any, that might be owed to each of the states participating in this audit.

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.

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

(c) Common Stock Repurchases Made in the Quarter

Under our common stock repurchase program repurchases are being made from time to time in the open market or privately negotiated transactions based on market conditions, securities law limitations and other factors. The following table includes repurchases made under this program during the third quarter of 2011.


Period	Total Number of Shares Purchased		Average price Paid Per Share		Total Number of Shares Purchased under Approved Stock Repurchase Program		Maximum Dollar Value of Shares Yet to be Purchased under Approved Stock Repurchase Program
July 2011		—	$	—		—	$	—
August 2011		—	$	—		—	$	—
September 2011		460,600	$	31.48		460,600	$	85,501,037

Total for July to September 2011		460,600				460,600

Additionally during the three months ended September 30, 2011, we repurchased 593,806 shares of our common stock at market price from certain executives and employees costing $21.4 million. These repurchases were made under the terms of restricted stock performance share unit agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of officers and employees who did not elect to satisfy such taxes by other means.

Item 6. Exhibits

The Exhibit Index on page 63 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.

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SIGNATURES

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


	HOLLYFRONTIER CORPORATION
	(Registrant)
Date: November 8, 2011		/s/ Douglas S. Aron
		Douglas S. Aron
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
		/s/ Scott C. Surplus
		Scott C. Surplus
		Vice President and Controller (Principal Accounting Officer)

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Exhibit Index


Exhibit Number		Description

3.1		Amended and Restated Certificate of Incorporation of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

3.2		Amended and Restated Bylaws of HollyFrontier Corporation (incorporated by reference to Exhibit 3.2 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

4.1		Indenture, dated as of November 22, 2010, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee, providing for the issuance of 6⁷/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report dated November 22, 2010, File Number 1-07627).

4.2		First Supplemental Indenture, dated as of November 22, 2010, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6⁷/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report dated November 22, 2010, File Number 1-07627).

4.3		Second Supplemental Indenture, dated as of May 26, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6⁷/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report dated May 27, 2011, File Number 1-07627).

4.4		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated November 22, 2010, providing for the issuance of 6⁷/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

4.5		Form of global note for 6⁷/8% Senior Notes due 2018 (incorporated by reference to Exhibit 4.3 of Frontier’s Form 8-K Current Report dated November 22, 2010, File Number 1-07627).

4.6		Indenture, dated as of September 17, 2008, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report dated September 17, 2008, File Number 1-07627).

4.7		First Supplemental Indenture, dated as of September 17, 2008, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 of Frontier’s Form 8-K Current Report dated September 17, 2008, File Number 1-07627).

4.8		Second Supplemental Indenture, dated as of May 26, 2011, among HollyFrontier Corporation, as

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		issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier’s Form 8-K Current Report dated May 27, 2011, File Number 1-07627).

4.9		Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation, as issuer (as successor-in-interest to Frontier Oil Corporation), the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (supplemental to Indenture dated September 17, 2008, providing for the issuance of 8.5% Senior Notes due 2016) (incorporated by reference to Exhibit 4.2 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

4.10		Form of global note for 8.5% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 of Frontier’s Form 8-K Current Report dated September 17, 2008, File Number 1-07627).

4.11+		Second Supplemental Indenture, dated July 18, 2011, among HollyFrontier Corporation, the subsidiary guarantors named therein and U.S. Bank Trust National Association, as trustee (supplemental to Indenture dated June 10, 2009, providing for the issuance of 9.875% Senior Notes due 2017).

10.1		Credit Agreement dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers, and Union Bank, N.A., as administrative agent, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

10.2		Guarantee and Collateral Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries in favor of Union Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

10.3		First Amendment to Credit Agreement dated as of August 24, 2011 by and among HollyFrontier Corporation and certain subsidiaries of HollyFrontier Corporation, as borrowers, Union Bank, N.A., as administrative agent, and each of the financial institutions party thereto as lenders (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 30, 2011, File No. 001-03876).

10.4		Retention and Assumption Agreement, dated as of February 21, 2011, by and among Frontier Oil Corporation, Holly Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed on February 21, 2011).

10.5		Retention and Assumption Agreement, dated as of February 21, 2011, by and among Frontier Oil Corporation, Holly Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed on February 21, 2011).

10.6		HollyFrontier Corporation Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 of Registrant’s Form 8-K Current Report dated July 8, 2011, File No. 001-03876).

10.7		Second Amended and Restated Pipelines, Tankage, and Loading Rack Throughput Agreement, dated August 31, 2011 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated September 1, 2011, File No. 001-03876).

10.8		Fifth Amendment and Restated Omnibus Agreement, dated August 31, 2011 (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K Current Report dated September 1, 2011, File No. 001-03876).

10.9		Frontier Products Offtake Agreement El Dorado Refinery, dated as of October 19, 1999 by and between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the Agreement”), and First Amendment to

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		the Agreement dated September 18, 2000, Second Amendment to the Agreement dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eight Amendment to the Agreement dated May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September 30, 2007, Fourteenth Amendment to the Agreement dated May 1, 2008 and Fifteenth Amendment to the Agreement dated May 28, 2008 (incorporated by reference to Exhibit 10.1 to Frontier Oil and Refining Company’s Quarterly Report on Form 10-Q filed August 7, 2008).

10.10		Sixteenth Amendment dated November 1, 2009, to the Frontier Products Offtake Agreement El Dorado Refinery, dated as of October 19, 1999 by and between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.14 to Frontier Oil and Refining Company’s Annual Report on Form 10-K filed February 25, 2010).

10.11		Master Crude Oil Purchase and Sale Agreement, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation (incorporated by reference to Exhibit 10.1 to Frontier Oil and Refining Company’s Quarterly Report on Form 10-Q filed November 4, 2010).

10.12		Guaranty dated November 1, 2010 made by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp (incorporated by reference to Exhibit 10.1 to Frontier Oil and Refining Company’s Quarterly Report on Form 10-Q filed November 4, 2010).

10.13		Form of Indemnification Agreement by and between the Company and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier’s Annual Report Form 10-K filed February 28, 2007).

10.14+		Letter Agreement, dated October 14, 2011, regarding the Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009.

10.15+		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit Agreement with Double Trigger Vesting

10.16+		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Restricted Stock Agreement with Double Trigger Vesting

10.17		Frontier Deferred Compensation Plan (previously named Wainoco Deferred Compensation Plan dated October 29, 1993 and incorporated by reference to Exhibit 10.19 to Frontier’s Annual Report on Form 10-K filed March 17, 1995).

10.18		Frontier Deferred Compensation Plan for Directors (previously named Wainoco Deferred Compensation Plan for Directors dated May 1, 1994 and incorporated by reference to Exhibit 10.20 to Frontier’s Annual Report on Form 10-K filed March 17, 1995).

10.19		Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit/Restricted Stock Agreement (incorporated by reference to Exhibit 4.8 to Frontier’s Form S-8 filed April 27, 2006).

10.20		Form of Indemnification Agreement by and between Frontier and each of its officers and directors (incorporated by reference to Exhibit 10.41 to Frontier’s Annual Report Form 10-K filed February 28, 2007).

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10.21		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.22		Amendment to Executive and Change in Control Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.23		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.4 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.24		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (incorporated by reference to Exhibit 10.6 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.25		Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (incorporated by reference to Exhibit 10.15 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.26		Executive Change in Control Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Joshua Goodmanson (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.27		Executive Change in Control Severance Agreement, dated September 9, 2009, between Frontier Oil Corporation and Kevin D. Burke (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form 8-K filed September 09, 2009).

10.28		Executive Change in Control Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester (incorporated by reference to Exhibit 10.1 to Frontier’s Current Report on Form filed November 4, 2010).

10.29		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (incorporated by reference to Exhibit 10.16 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.30		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (incorporated by reference to Exhibit 10.18 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.31		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (incorporated by reference to Exhibit 10.20 to Frontier’s Current Report on Form 8-K filed January 2, 2009).

10.32		Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (incorporated by reference to Exhibit 10.29 to Frontier’s Form 8-K filed January 2, 2009).

10.33		Executive Severance Agreement, dated April 28, 2009, between Frontier Oil Corporation and Joshua Goodmanson (incorporated by reference to Exhibit 10.3 to Frontier’s Current Report on Form 8-K filed May 01, 2009).

10.34		Executive Severance Agreement, dated September 9, 2009, between Frontier Oil Corporation and Kevin D. Burke (incorporated by reference to Exhibit 10.2 to Frontier’s Current Report on Form 8- K filed September 09, 2009).
10.34

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10.35		Executive Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester (incorporated by reference to Exhibit 10.1 to Frontier’s Quarterly Report on Form 10-Q filed on November 4, 2010).

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 HollyFrontier Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 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.

+ Filed herewith.

++ Furnished herewith.

** Furnished electronically herewith.

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