UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

þ Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

OR

¨ 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 1-7627

FRONTIER OIL CORPORATION

(Exact name of registrant as specified in its charter)

Wyoming	74-1895085
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
10000 Memorial Drive, Suite 600	77024-3411
Houston, Texas	(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: (713) 688-9600

Former name, former address and former fiscal year, if

changed since last report.

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

Yes  þ   No ¨

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

Yes  þ   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. (Check one)

Large accelerated filer  þ	Accelerated filer ¨
Non-accelerated filer   ¨ (Do not check if a smaller reporting company)	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  þ

Registrant’s number of common shares outstanding as of May 2, 2011:  106,455,209

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2011

INDEX

FORWARD-LOOKING STATEMENTS

This Form 10-Q contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”).  Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations.  These include, without limitation:

  · statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

  · statements relating to future financial performance, future capital sources and other matters;

  · statements relating to our proposed merger with a subsidiary of Holly Corporation, including the anticipated timing thereof and the anticipated benefits therefrom; and

  · any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved.  These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances.  Such statements are subject to a number of risks and uncertainties, many of which are beyond our control.  You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.

All forward-looking statements contained in this Form 10-Q only speak as of the date of this document.  We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.

PART I - FINANCIAL INFORMATION

ITEM 1.               FINANCIAL STATEMENTS

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands except per share data)
	Three Months Ended March 31,
	2011			2010
Revenues:
Refined products	$	1,915,670		$	1,275,039
Other		(7,016	)		(2,895	)
Total revenues		1,908,654			1,272,144
Costs and expenses:
Raw material, freight and other costs		1,561,403			1,223,764
Refinery operating expenses, excluding depreciation		75,807			68,883
Selling and general expenses, excluding depreciation		10,603			10,976
Holly Corporation merger costs		5,148			-
Depreciation, amortization and accretion		26,968			26,609
Gain on sales of assets		(21	)		(1	)
Total costs and expenses		1,679,908			1,330,231
Operating income (loss)		228,746			(58,087	)
Interest expense and other financing costs		8,634			7,235
Interest and investment income		(347	)		(527	)
Income (loss) before income taxes		220,459			(64,795	)
Provision (benefit) for income taxes		80,593			(24,531	)
Net income (loss)	$	139,866		$	(40,264	)
Comprehensive income (loss)	$	139,868		$	(40,397	)
Basic earnings (loss) per share of common stock	$	1.34		$	(0.39	)
Diluted earnings (loss) per share of common stock	$	1.32		$	(0.39	)
Dividends declared per common share	$	0.34		$	-
The accompanying notes are an integral part of these condensed consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands except share data)
March 31, 2011 and December 31, 2010	2011			2010
ASSETS
Current assets:
Cash, including cash equivalents of $681,857 and $556,737 at 2011 and 2010,     respectively	$	685,375		$	558,641
Trade receivables, net of allowance of $1,000 at 2011 and 2010		261,630			145,033
Income taxes receivable		30,634			49,305
Other receivables, net		3,333			1,734
Inventory of crude oil, products and other		299,882			280,847
Deferred income tax assets - current		13,757			30,516
Other current assets		8,474			12,981
Total current assets		1,303,085			1,079,057
Property, plant and equipment, net		1,014,139			1,014,868
Deferred turnaround and catalyst costs, net		51,177			51,347
Deferred financing costs, net of accumulated amortization of $2,760 and $2,400 at     2011 and 2010, respectively		5,912			6,271
Intangible assets, net of accumulated amortization of $766 and $736 at 2011 and     2010, respectively		1,063			1,094
Deferred state income tax assets - noncurrent		5,450			11,768
Other assets		4,840			4,359
Total assets	$	2,385,666		$	2,168,764
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	557,981		$	493,212
Accrued income taxes		57,607			47
Accrued liabilities and other		34,043			42,365
Total current liabilities		649,631			535,624
Long-term debt, net of unamortized discount of $2,151 and $2,227 at 2011    and 2010, respectively		347,849			347,773
Contingent income tax liabilities		3,882			3,830
Post-retirement employee liabilities		43,999			43,313
Long-term capital lease obligation		2,818			2,938
Other long-term liabilities		14,882			14,066
Deferred federal income tax liabilities		231,246			234,673
Commitments and contingencies
Shareholders' equity:
Preferred stock, $100 par value, 500,000 shares authorized, no shares issued		-			-
Common stock, no par value, 180,000,000 shares authorized, 131,850,356 shares issued    at both period ends		57,736			57,736
Paid-in capital		266,870			263,706
Retained earnings		1,171,414			1,068,004
Accumulated other comprehensive loss		(6,491	)		(6,493	)
Treasury stock, at cost, 25,412,959 and 26,097,398 shares at 2011 and 2010, respectively		(398,170	)		(396,406	)
Total shareholders' equity		1,091,359			986,547
Total liabilities and shareholders' equity	$	2,385,666		$	2,168,764
The accompanying notes are an integral part of these condensed consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
	For the three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	139,866		$	(40,264	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation, amortization and accretion		26,968			26,609
Deferred income tax provision (benefit)		19,642			(23,470	)
Stock-based compensation expense		3,224			3,720
Excess income tax benefits of stock-based compensation		(1,101	)		(63	)
Amortization of debt issuance costs		359			372
Senior Notes discount amortization		76			70
Decrease in allowance for investment loss and bad debts		(251	)		(52	)
Gain on sales of assets		(21	)		(1	)
Increase in other long-term liabilities		1,499			445
Turnaround and catalyst costs paid		(4,942	)		(4,027	)
Other		(481	)		(517	)
Changes in working capital from operations		(4,006	)		89,422
Net cash provided by operating activities		180,832			52,244
Cash flows from investing activities:
Additions to property, plant and equipment		(16,213	)		(22,515	)
Proceeds from sales of assets		25			1
Net cash used in investing activities		(16,188	)		(22,514	)
Cash flows from financing activities:
Purchase of treasury stock		(3,233	)		(1,898	)
Dividends paid		(35,919	)		(6,393	)
Proceeds from issuance of common stock		350			-
Excess income tax benefits of stock-based compensation		1,101			63
Debt issuance costs and other		(209	)		(101	)
Net cash used in financing activities		(37,910	)		(8,329	)
Increase in cash and cash equivalents		126,734			21,401
Cash and cash equivalents, beginning of period		558,641			425,280
Cash and cash equivalents, end of period	$	685,375		$	446,681
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	8,712		$	12,931
Cash paid during the period for income taxes		87			46
Cash refunds of income taxes		16,426			43,932
Noncash investing activities - accrued capital expenditures, end of period		11,835			13,698
The accompanying notes are an integral part of these condensed consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 (Unaudited)

1.      Financial Statement Presentation

The interim condensed consolidated financial statements include the accounts of Frontier Oil Corporation (“FOC”), a Wyoming corporation, and its wholly-owned subsidiaries, collectively referred to as “Frontier” or “the Company.”  The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”).

The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas.  The Company owns Ethanol Management Company (“EMC”), a products terminal and blending facility located near Denver, Colorado.  The Company also owns a refined products pipeline which runs from Cheyenne, Wyoming to Sidney, Nebraska and the associated refined products terminal and truck rack at Sidney, Nebraska.  The Company utilizes the equity method of accounting for investments in entities in which it has the ability to exercise significant influence.  Entities in which the Company has the ability to exercise control are consolidated.  All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States.  The Rocky Mountain region includes the states of Colorado, Wyoming, western Nebraska, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and South Dakota.  The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke.  The operations of refining and marketing of petroleum products are considered part of one reporting segment.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and include all adjustments (comprised of only normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been condensed or omitted pursuant to such rules and regulations.  The Company believes that the disclosures contained herein are adequate to make the information presented not misleading.  The condensed consolidated financial statements included herein should be read in conjunction with the financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2010.  These interim financial statements are not indicative of annual results.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were issued.

Earnings per share

The Company computes basic earnings or loss per share (“EPS”) by dividing net income or loss by the weighted average number of common shares outstanding during the period.  No adjustments to income are used in the calculation of basic EPS.  Diluted EPS includes the effects of potentially dilutive shares, principally common stock options and unvested restricted stock and performance stock units outstanding during the period.  The basic and diluted average shares outstanding were as follows:

	Three Months Ended March 31,
	2011		2010
Basic		104,579,872		103,934,315
Diluted		105,764,974		103,934,315

For the three months ended March 31, 2011 and 2010, 422,894 and 434,793 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS as they were anti-dilutive. Correspondingly, during the three months ended March 31, 2010, there were 1.3 million outstanding restricted stock and stock unit awards not included in the computation of diluted EPS due to the Company’s net loss.

The Company’s Board of Directors declared a special cash dividend of $0.28 per share of common stock and a quarterly cash dividend of $0.06 per share of common stock in February 2011, which was paid in March 2011.  As of March 31, 2011, the Company had $318.4 million and $330.2 million available to pay dividends under the restricted payments basket of its 6.875% Senior Notes and 8.5% Senior Notes, respectively (collectively, the “Senior Notes”) covenants.

Foreign currency transactions

The Company at times has receivables and payables denominated in Canadian dollars from certain crude oil purchases and related taxes on such purchases.  These amounts are accounted for in accordance with GAAP on the Condensed Consolidated Balance Sheet by translating the balances at the applicable exchange rates until they are settled.  The corresponding gain or loss is recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  For the three months ended March 31, 2011 and 2010, the Company recognized a loss in “Other Revenues” of $634,000 and $39,000, respectively, due to the translation of its foreign denominated assets and liabilities.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current period financial statement presentation.  The Company has reclassified turnaround and catalyst amortization on the Consolidated Statements of Operations from “Refinery operating expenses, excluding depreciation” to “Depreciation, amortization and accretion” to be more consistent with industry peers.  The reclassifications have no effect on previously reported operating income (loss) or net income (loss).  In addition, the Company has reflected the turnaround and catalyst costs paid as a separate line on the Consolidated Statements of Cash Flows.  The reclassifications have no effect on previously reported cash provided by operating activities.

Related Party Transactions

During the first quarter of 2010, the Company made a relocation-related loan to an officer of one of its subsidiaries in the amount of $120,000 with a term of one year.  The Company accounted for this balance in “Other Receivables” on the Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010.  During the first quarter of 2011, the term of this loan was extended an additional year.

New accounting pronouncements

In January 2010, the FASB issued ASU 2010-06, which amended ASC 820, “Fair Value Measurements and Disclosures.”  New disclosures included in this ASU require the Company to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the related reasoning for the transfer.  Also included in the new disclosure requirements is the separate presentation of purchases, sales, issuances and settlements on a gross basis in the reconciliation for significant unobservable inputs, or Level 3 inputs.  Further, this ASU clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value for either Level 2 or Level 3 measurements.  Finally, this ASU amends guidance on employers’ disclosures about postretirement benefit plan assets under ASC 715 to change terminology from major categories of assets to classes of assets on how to determine appropriate classes to present fair value disclosures.  The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the rollforward of activity in Level 3 fair value measurements.  These Level 3 specific disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.  The adoption of the disclosures required for the Company during the first quarter of 2010 did not have a material impact on the Company’s financial statement disclosures.  The additional disclosures required for 2011 related to Level 3 requirements did not have a material impact on the Company’s financial statement disclosures.

2.      Holly Corporation Proposed Merger

On February 21, 2011, the Company entered into a definitive merger agreement with Holly Corporation (“Holly”) under which the companies will combine in an all-stock merger of equals transaction.  Under the terms of the agreement, the Company’s shareholders will receive 0.4811 Holly shares for each share of the Company’s common stock.  Upon closing of the transaction, Holly shareholders are expected to own approximately 51 percent and the Company’s shareholders are expected to own approximately 49 percent of the combined company.  The transaction is structured to be tax-free to the shareholders of both companies.  The merger is expected to close in the third quarter of 2011.  On March 18, 2011, Holly and the Company were notified of the early termination of the pre-merger waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, thus satisfying one of the conditions to the completion of the pending merger.  On March 21, 2011, Holly filed a Form S-4 Registration Statement, relating to the proposed merger with the Securities and Exchange Commission (“SEC”).  On April 27, 2011, Holly filed an amended Registration Statement Form S-4/A to address comments received from the SEC.  The merger remains subject to, among other things, approval by both companies’ shareholders and other customary closing conditions.

3.      Inventories

Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a LIFO basis or market, which is determined using current estimated selling prices.  Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other costs.  Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned.  These include unfinished gasoline and diesel, blendstocks and other feedstocks.  Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products.  Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values.  Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts.  The net exchange balance is included in inventory.  Inventories of process chemicals and repairs and maintenance supplies and other are recorded at the lower of average cost or market.  Crude oil inventories, unfinished product inventories and finished product inventories are used to secure financing for operations under the Company’s revolving credit facility.  The components of inventory as of March 31, 2011 and December 31, 2010 were as follows:

	March 31,			December 31,
	2011			2010
	(in thousands)
Crude oil	$	346,493		$	319,452
Unfinished products		169,949			193,389
Finished products		123,298			86,160
LIFO reserve - adjustment to inventories		(365,834	)		(344,149	)
		273,906			254,852
Process chemicals		773			770
Repairs and maintenance supplies and other		25,203			25,225
	$	299,882		$	280,847

4.         Other Current Assets

	March 31,		December 31,
	2011		2010
	(in thousands)
Margin deposits	$	-	$	3,569
Derivative assets		2,480		1,195
Prepaid insurance		4,454		6,599
Other		1,540		1,618
	$	8,474	$	12,981

5.      Property, Plant and Equipment

	March 31,			December 31,
	2011			2010
	(in thousands)
Refineries, pipelines and terminal equipment	$	1,473,822		$	1,454,861
Buildings		43,271			43,271
Land and land improvements		15,761			15,592
Furniture, fixtures and other equipment		17,563			17,184
Property, plant and equipment, at cost		1,550,417			1,530,908
Accumulated depreciation		(536,278	)		(516,040	)
Property, plant and equipment, net	$	1,014,139		$	1,014,868

6.      Accrued Liabilities and Other

	March 31,		December 31,
	2011		2010
	(in thousands)
Accrued compensation	$	7,820	$	21,427
Accrued property taxes		8,945		5,805
Accrued interest		4,421		6,188
Accrued environmental costs		2,125		2,245
Accrued dividends		871		334
Derivative liabilities		2,486		2,389
Renewable fuels blending obligation		3,632		-
Other		3,743		3,977
	$	34,043	$	42,365

7.      Income Taxes

The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under ASC 740 “Income Taxes.”  Although amounts the Company has paid for unresolved IRS audit issues for 2006 and 2005 totaling $18.1 million are no longer reflected as a liability on the Condensed Consolidated Balance Sheets, as of March 31, 2011 or December 31, 2010, the amounts are still included in the following table of unrecognized tax benefits.  A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding accrued interest and the federal income tax benefit of state contingencies is as follows:

	Three Months Ended March 31,
	2011		2010
	(in thousands)
Balance beginning of period	$	22,577	$	23,854
Additions based on tax positions related to the current year		-		-
Additions for tax positions of prior years		-		-
Reductions for tax positions of prior years		-		-
Settlements		-		-
Reductions due to lapse of applicable statutes of limitations		-		(66	)
Balance end of period	$	22,577	$	23,788

The total contingent income tax liabilities and accrued interest of $3.9 million and $3.8 million at March 31, 2011 and December 31, 2010, respectively, are reflected in the Condensed Consolidated Balance Sheets under “Contingent income tax liabilities.”  The Company recognized net interest expense on contingent income tax liabilities of $52,000 and $400,000 during the three months ended March 31, 2011 and 2010, respectively.

8.      Treasury Stock

The Company accounts for its treasury stock under the cost method on a first-in, first-out basis.  A rollforward of treasury stock for the three months ended March 31, 2011 is as follows:

	Number of shares			Amount
	(in thousands except share amounts)
Balance as of December 31, 2010		26,097,398		$	396,406
Shares received to fund withholding taxes		119,350			3,233
Shares issued for restricted stock unit vestings		(119,596	)		(219	)
Shares issued for stock option exercises		(11,899	)		(19	)
Shares issued for restricted stock grants		(295,000	)		(540	)
Shares issued for conversion of stock unit awards		(377,294	)		(691	)
Balance as of March 31, 2011		25,412,959		$	398,170

 9.      Stock-based Compensation

Stock-based compensation costs and income tax benefits recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months ended March 31, 2011 and 2010 were as follows:

	Three Months Ended March 31,
	2011		2010
	(in thousands)
Restricted shares and units	$	2,668	$	2,911
Contingently issuable stock unit awards		556		809
Total stock-based compensation expense	$	3,224	$	3,720
Income tax benefit recognized in the income statement	$	1,225	$	1,414

Omnibus Incentive Compensation Plan.  As of March 31, 2011, 6,316,092 shares were available to be awarded under the Company’s Omnibus Incentive Compensation Plan (the “Plan”) assuming maximum payout is achieved on the contingently issuable awards made in 2009, 2010 and 2011 (see “Contingently Issuable Awards” below).  For purposes of determining compensation expense, forfeitures are estimated at the time Awards are granted based on historical average forfeiture rates and the group of individuals receiving those Awards.  The Plan provides that the source of shares for Awards may be either newly issued shares or treasury shares.  For the three months ended March 31, 2011, treasury shares were re-issued for stock options exercised and restricted stock awards.  The Company does not plan to repurchase additional treasury shares in 2011 strictly for issuing share Awards; however, treasury shares that are repurchased or are currently in treasury may be issued as share Awards in 2011.  As of March 31, 2011, there was $30.0 million of total unrecognized compensation cost related to the Plan, including costs for restricted stock and performance-based awards, which is expected to be recognized over a weighted-average period of 2.21 years.  However, the majority of this compensation cost will be accelerated when the Holly merger closes.

Upon completion of the Holly merger, approximately 1.1 million restricted shares and restricted stock units (excluding the 2011 restricted share grants) will vest and be converted into the right to receive 0.4811 fully vested shares of Holly common stock.  In addition, the outstanding contingently issuable stock unit awards made in 2009 and 2010 (excluding 2011 contingently issuable stock unit awards) shall be cancelled in full on such date and a number of shares equal to 125% of the number of contingently issuable stock units (approximately 665,000) will be converted into the right to receive 0.4811 fully vested shares of Holly common stock.

Stock Options.  Stock option changes during the three months ended March 31, 2011 are presented below:

	Number of  awards			Weighted- Average Exercise Price		Aggregate Intrinsic Value of Options
						(in thousands)
Outstanding at beginning of period		434,793		$	29.3850
Granted		-			-
Exercised		(11,899	)		29.3850
Expired or forfeited		-			-
Outstanding at end of period		422,894		$	29.3850	$	-
Vested		422,894		$	29.3850	$	-
Exercisable at end of period		422,894		$	29.3850	$	-

The Company received $350,000 of cash for stock options exercised during the three months ended March 31, 2011.  The total intrinsic value of stock options exercised during the three months ended March 31, 2011 was $6,000.  The Company realized $2,000 of income tax benefit, nearly all of which was excess income tax benefit, for the three months ended March 31, 2011 related to exercises of stock options.  There were no stock option exercises during the three months ended March 31, 2010.   Excess income tax benefits are the benefits from deductions that are allowed for income tax purposes in excess of the expenses recorded in the Company’s financial statements.  These excess income tax benefits are recorded as an increase to paid-in capital, and the majority of these amounts are reflected as cash flows from financing activities in the Condensed Consolidated Statements of Cash Flows.  All outstanding stock options were vested and exercisable at March 31, 2011 with weighted average remaining contractual lives of 0.07 years.

Restricted Shares and Restricted Stock Units.  The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the three months ended March 31, 2011:

	Shares/Units			Weighted- Average Grant- Date Market Value
Nonvested at beginning of period		1,247,995		$	14.5218
Conversion of stock unit awards		377,294			12.7000
Granted		337,360			25.8435
Vested		(273,412	)		15.6555
Forfeited		-			-
Nonvested at end of period		1,689,237			16.1925

The total grant date fair value of restricted shares and restricted stock units which vested during the three months ended March 31, 2011 and 2010 was $4.3 million and $4.5 million, respectively.  The total fair value at vesting of restricted shares and restricted stock during the three months ended March 31, 2011 and 2010 was $7.4 million and $3.5 million, respectively.  The Company realized $2.8 million of income tax benefit for the vestings during the three months ended March 31, 2011, and increased the Company’s APIC pool by $1.2 million.  The Company realized $1.3 million of income tax benefits related to the vestings during the three months ended March 31, 2010, of which $378,000 decreased its additional paid-in capital

(“APIC”) pool.

In March 2011, following certification by the Compensation Committee of the Company’s Board of Directors that the specified performance criteria of the Company’s return of capital employed versus that of a defined peer group had been achieved for the year ended December 31, 2010, the Company issued 377,294 shares of restricted stock in connection with the February 2010 grant of contingently issuable stock unit awards.  The following tables summarize the vesting schedules of the 377,294 stock unit awards converted to restricted stock and the 337,360 shares of restricted stock shares and units granted during the three months ended March 31, 2011.

			Vesting Dates and Share Amounts
Conversion Date	Converted stock unit awards		June 30, 2011		June 30, 2012		June 30, 2013
March 11, 2011		377,294		125,769		125,756		125,769

			Vesting Dates and Share Amounts
Grant Date	Shares/Units Granted (Net of Forfeits)		December 30, 2011		March 13, 2012		March 13, 2013		March 13, 2014
January 25, 2011		42,360		42,360
March 24, 2011		295,000				73,751		73,749		147,500
Total		337,360		42,360		73,751		73,749		147,500

Contingently Issuable Awards.  During the three months ended March 31, 2011, the Company granted 295,000 stock unit awards contingent upon certain share price performance versus the Company’s peers being met over a three-year period ending on December 31, 2013.  Depending on achievement of the market-based performance goal, awards earned could be between 0% and 125% of the base number of market-based stock units.  If any of the market-based performance goals are achieved and certified by the Compensation Committee, these stock unit awards (or a portion thereof) will be converted into stock.  The stock unit awards were valued at approximately eighty-eight percent of market value on the date of grant and are being amortized to compensation expense on a straight-line basis over the nominal vesting period, adjusted for retirement-eligible employees, as required under GAAP.

In February 2011, following certification by the Compensation Committee of the Company’s Board of Directors that the specified share price performance criteria in connection with the 2008 grant of contingently issuable stock unit awards to be met over a three-year period ended December 31, 2010 had been achieved, the Company issued 119,596 shares of stock to certain employees of the Company.  The total grant date fair value of these performance awards was $3.8 million and the total fair value of these shares at issuance was $3.2 million.  The Company recognized $1.2 million of income tax benefit related to these vestings, including a reduction of the Company’s APIC pool by $220,000.

As of March 31, 2011, the Company also had outstanding (net of forfeitures) 230,287 and 301,830 contingently issuable stock unit awards issued in 2009 and 2010, respectively, to be earned should certain share price criteria be met over a three-year period ending December 31, 2011 and 2012, respectively.  Depending on achievement of the performance goal, awards earned could be between 0% and 125% of the base number of performance stock units.  If the market performance goal is achieved and certified by the Compensation Committee, the stock unit awards (or a portion thereof) will be converted into stock.

When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents (on the stock unit awards) and dividends (once the stock unit awards are converted to restricted stock) are accrued on the contingently issuable stock units and restricted stock but are not paid until the restricted stock vests (except for restricted stock awards granted in 2011 which will receive dividends as they are payable).

10.      Employee Benefit Plans

Defined Benefit Plans

The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery.  Eligible employees are employees hired by the El Dorado Refinery before certain defined dates and who satisfy certain age and service requirements.  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. These plans were unfunded as of March 31, 2011 and December 31, 2010.  The post-retirement healthcare plan requires retirees to pay between 20% and 40% of total healthcare costs based on age and length of service.  The plan’s prescription drug benefits are at least equivalent to Medicare Part D benefits.

The following tables set forth the net periodic benefit costs recognized for these benefit plans in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss):

	Three Months Ended March 31,
Post-retirement Healthcare and Other Benefits	2011			2010
	(in thousands)
Components of net periodic benefit cost and other amounts recognized in other comprehensive income (loss):
Components of net periodic benefit cost:
Service cost	$	183		$	190
Interest cost		604			517
Amortization of prior service cost		(469	)		(469	)
Amortized net actuarial loss		478			262
Net periodic benefit cost		796			500
Changes in assets and benefit obligations recognized in other comprehensive income (loss):
Net loss		-			7
Amortization of prior service cost		469			469
Amortization of loss		(478	)		(262	)
Total recognized in other comprehensive income		(9	)		214
Total recognized in net periodic benefit cost and other    comprehensive income (loss)	$	787		$	714

11.      Fair Value Measurement

The three-level valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.  The three levels are defined as follows:

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3 – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

The following tables present information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Derivative asset (liability) as of March 31, 2011
Description	Level 1		Level 2			Level 3		Total
Commodity contracts	$	1,770	$	(2,486	)	$	-	$	(716	)
Foreign exchange contracts		-		78			-		78
Interest rate contracts		-		632			-		632

	Derivative asset (liability) as of December 31, 2010
Description	Level 1			Level 2			Level 3		Total
Commodity contracts	$	(1,263	)	$	(1,126	)	$	-	$	(2,389	)
Foreign exchange contracts		-			266			-		266
Interest rate contracts		-			929			-		929

As of March 31, 2011 and December 31, 2010, the commodity contracts measured under Level 1 are NYMEX crude oil contracts and thus are valued using quoted market prices at the end of each period.  The foreign exchange contracts are valued using month-end exchange rates and the variation from each contracts’ strike price.  Due to the variety of sources available to price month-end exchange rates, these contracts were deemed to have Level 2 inputs.  The commodity contracts measured under Level 2 are valued using pricing models based on NYMEX crude oil contracts.  The interest rate swap contracts measured under Level 2 are valued using a mark-to-market valuation that took into consideration anticipated cash flows from the transactions using market prices and other economic data, and assumptions were used to value the swaps.  A mark-to-market valuation that takes into consideration anticipated cash flows from the transactions using market prices and other economic data and assumptions are used to value the swaps.  Given the degree of varying assumptions used to value the swaps, their valuation was deemed as having Level 2 inputs.

The fair value of the Company’s Senior Notes was estimated based on quotations obtained from broker-dealers who make markets in these and similar securities.  At March 31, 2011 and December 31, 2010, the carrying amounts of the Company’s 6.875% Senior Notes were $150.0 million, and the estimated fair values were $155.8 million and $152.6 million, respectively.  At March 31, 2011 and December 31, 2010, the carrying amounts of the Company’s 8.5% Senior Notes were $197.8 million ($200.0 million less the unamortized discount of $2.2 million), and the estimated fair values were $216.3 million and $212.8 million, respectively.  For cash and cash equivalents, the carrying amounts at March 31, 2011 and December 31, 2010 of $685.4 million and $558.6 million, respectively, are reasonable estimates of fair value.

12.      Price and Interest Risk Management Activities

The Company, at times, enters into derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production or to hedge interest rate risk.  The commodity derivative contracts used by the Company may take the form of futures contracts, forward contracts, collars or price or interest rate swaps.  The Company, also at times, enters into foreign exchange contracts to manage its exposure to foreign currency fluctuations on its purchases of foreign crude oil.  The Company believes that there is minimal credit risk with respect to its counterparties.  The Company’s commodity derivative contracts and foreign exchange contracts, while economic hedges, are not designated as cash flow or fair value hedges and thus are accounted for under mark-to-market accounting and gains and losses recorded directly to earnings.  The Company has derivative contracts which it holds directly and also derivative contracts, in connection with its crude oil purchase and sale contract, held on Frontier’s behalf by BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (collectively, “BNP”).  For additional fair value disclosures relating to the Company’s derivative contracts, see Note 11, “Fair Value Measurement.”  As of March 31, 2011, the Company had the following outstanding commodity derivative contracts:

Commodity	Number of barrels
	(in thousands)
Crude oil contracts to hedge crude purchases in-transit		807
Crude oil contracts to hedge excess intermediate, finished product and crude oil inventory		560

As of March 31, 2011, the Company held two $75.0 million interest rate swaps totaling $150.0 million of notional amount, that effectively convert a portion of interest expense from fixed to variable rate debt.  Under these swap contracts, interest on each of the $75.0 million notional amount is computed using 30-day LIBOR plus a spread of 5.34% and 5.335%, which equaled an effective interest rate of 5.59% and 5.58%, respectively, as of the transaction date.  Interest is paid semiannually on the swap contracts, April 1 and October 1, until maturity.  The interest accrued by the Company on these swap contracts effectively reduced “Interest expense and other financing costs” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) by $360,000 and $372,000 for the three months ended March 31, 2011 and 2010, respectively.  The Company had a receivable of $723,000 and $363,000, respectively, which is included in “Other Receivables” on the Condensed Consolidated Balance sheets as of March 31, 2011 and December 31, 2010.

The following table presents the location of the Company’s outstanding derivative contracts on the Condensed Consolidated Balance Sheet and the related fair values at the balance sheet dates.

	Asset Derivatives in Other Current Assets							Liability Derivatives in Accrued Liabilities and Other
	March 31, 2011			December 31, 2010			March 31, 2011			December 31, 2010
		Fair Value			Fair Value			Fair Value			Fair Value
	(in thousands)
Derivatives not designated    as hedging instruments
Commodity contracts		$	1,770		$	-		$	2,486		$	2,389
Foreign exchange contracts			78			266			-			-
Interest rate swap contracts			632			929			-			-
Total derivatives		$	2,480		$	1,195		$	2,486		$	2,389

The following table presents the location of the gains and losses reported in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the current and previous periods presented.

		Amount of Derivatives Gain or (Loss) Recognized
		Three Months Ended March 31,
Derivatives not designated    as hedging instruments	Location in Statement    of Operations	2011			2010
		(in thousands)
Commodity contracts	Other Revenues	$	(6,894	)	$	(2,840	)
Foreign exchange contracts	Other Revenues		488			-
Interest rate swap contracts	Interest expense and other financing costs		(297	)		851

13.      Environmental

The Company’s operations and many of its manufactured products are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations.  The 1990 amendments to the CAA contain provisions that will require capital expenditures for the production of cleaner transportation fuels and the installation of certain air pollution control devices at the Refineries during the next several years as discussed below.

The Environmental Protection Agency (“EPA”) has promulgated regulations requiring the phase-in of gasoline sulfur standards, which began January 1, 2004 and continued through 2008, with special provisions for small business refiners such as Frontier.  As allowed by subsequent regulation, Frontier elected to extend its small refinery interim gasoline sulfur standard at each of the Refineries until January 1, 2011 by complying with the highway ultra low sulfur diesel standard by June 2006.  The Company has reevaluated its initial strategy of capital investment at its Cheyenne Refinery to meet the new gasoline sulfur standard and is now planning to comply with these requirements starting January 1, 2011 for approximately five years through the redemption of gasoline sulfur credits.  For long-term compliance, the Company expects to utilize internally generated credits and purchased credits and spend approximately $40.0 million ($18.5 million incurred as of March 31, 2011) for the FCCU gasoline hydrotreater project comprised of new process unit capacity and intermediate inventory handling equipment.  In addition, new federal benzene regulations and anticipated state requirements for reduction in gasoline Reid Vapor Pressure (“RVP”) suggest that additional capital expenditures may be required for environmental compliance projects.  The Company is presently evaluating projects and the total potential cost in connection with an overall compliance strategy for the Cheyenne Refinery.  Total capital expenditures for the El Dorado Refinery to comply with the final gasoline sulfur standard were $95.0 million, including capitalized interest, and were completed in the fourth quarter of 2010.  The $95.0 million of expenditures primarily related to the El Dorado Refinery’s gasoil hydrotreater revamp project.  The gasoil hydrotreater revamp project addressed most of the El Dorado Refinery’s modifications needed to achieve gasoline sulfur compliance.

The Company is a holder of gasoline sulfur credits retained from prior generation years at both the Cheyenne and the El Dorado Refineries.  There were no sulfur credit sales during the three months ended March 31, 2011 and 2010.

In March 2009, settlement agreements associated with the EPA’s National Petroleum Refining Enforcement Initiative were finalized and are now in effect.  The Company currently estimates that, in addition to the flare gas recovery systems previously installed at each facility, capital expenditures totaling approximately $37.0 million ($697,000 incurred as of March 31, 2011) at the Cheyenne Refinery and $6.0 million ($1.5 million incurred as of March 31, 2011) at the El Dorado Refinery will need to be incurred prior to 2017.  The Company may also choose to incur additional costs at the Cheyenne Refinery and at the El Dorado Refinery to comply with certain requirements of the agreement if such projects are determined to be the most cost effective compliance strategy.  Notwithstanding these settlements, many of these same expenditures are required for the Company to comply with preexisting regulatory requirements or to implement its planned facility expansions.  Consequently, the costs associated with these other projects are not included in the totals above.  In addition, the settlement agreement provides for stipulated penalties for violations, which are periodically reported by the Company.  Stipulated penalties under the decree are not automatic but must be requested by one of the agency signatories.  As stipulated penalties are requested, the Company will separately report that matter and the amount of the proposed penalty, if material.

The EPA has promulgated regulations to enact the provisions of the Energy Policy Act of 2005 regarding mandated blending of renewable fuels in gasoline.  The Energy Independence and Security Act of 2007 significantly increased the amount of renewable fuels that had been required by the 2005 legislation.  The Company, as a small refiner, was exempt until January 1, 2011 from these requirements at which time it began incurring additional costs in order to meet the new requirements.  The Company has renewable fuels blending facilities and purchases ethanol with Renewable Identification Numbers (RINs) credits attached.  Ethanol RINs were created to assist in tracking compliance with these EPA regulations for the blending of renewable fuels.  At March 31, 2011, the Company had a liability of $3.6 million related to the expected additional costs for compliance.  There were no RIN sales during the three months ended March 31, 2011 and 2010.  While not yet proposed or promulgated, other pending regulation regarding the mandated use of alternative or renewable fuels and/or the reduction of greenhouse gas emissions from either transportation fuels or manufacturing processes is under consideration by the EPA.  In addition, the EPA has recently determined that greenhouse gases, including carbon dioxide, present a danger to human health and the environment, which may result in future regulation of such gases.  If greenhouse gas control regulations are promulgated, these requirements could materially impact the operations and financial position of the Company (see “Other Future Environmental Considerations” below).

On February 26, 2007, the EPA promulgated regulations limiting the amount of benzene in gasoline.  These regulations take effect for large refiners on January 1, 2011 and for small refiners, such as Frontier, on January 1, 2015.  While not yet estimable, the Company anticipates that potentially material capital expenditures may be necessary to achieve compliance with the new regulation at its Cheyenne Refinery.  Gasoline manufactured at the El Dorado Refinery typically contains benzene concentrations near the new standard.  The Company therefore believes that necessary benzene compliance expenditures at the El Dorado Refinery will be substantially less than those at its Cheyenne Refinery.  The Company’s recently announced merger with Holly Corporation, if completed, will likely result in the loss of small refiner status for the Company and will result in an earlier compliance deadline for these benzene limits.

The Company owns terminals and pipelines in which various groundwater remediation and monitoring activities are underway and as of March 31, 2011 and December 31, 2010, the Company had a total accrual of $558,000.  As is the case with companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that the Company may have manufactured, handled, used, released or disposed.

Cheyenne Refinery.  The Company is party to an agreement with the State of Wyoming requiring investigation and interim remediation actions at the Cheyenne Refinery’s property that may have been impacted by past operational activities.  As a result of past and ongoing investigative efforts, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects.  As of March 31, 2011 and December 31, 2010, the Company had a $4.8 million accrual, included on the Condensed Consolidated Balance Sheets related to the remediation program.  The accrual at March 31, 2011 reflects the estimated present value of a $705,000 cost in 2011 and $690,000 in annual costs for 2012 through 2020, assuming a 3% inflation rate, ten more years of the ongoing groundwater remediation program, and discounted at a rate of 7.9%.  The Company estimates a total cost of $7.8 million ($7.3 million incurred as of March 31, 2011) for the cleanup and on-going monitoring activities of a waste water treatment pond located on land adjacent to the Cheyenne Refinery which the Company had historically leased from the landowner.  Cleanup of the waste water pond pursuant to the aforementioned agreement with the State of Wyoming was completed in 2010 with various on-going monitoring for approximately two years.  Depending upon information collected during the on-going monitoring, or by a subsequent administrative order or permit, additional remedial action and costs could be required.

In October 2009, Frontier Refining Inc. (which owns the Cheyenne Refinery) was served with a Complaint from Region 8 of the EPA alleging unlawful storage of untreated or partially treated refinery wastewater in an on-site surface impoundment.  To resolve this issue, the Company has entered into a negotiated settlement agreement with the EPA.  Based on this agreement, the total settlement expense was $2.8 million.  This comprised of a $900,000 penalty (paid in June 2010) and $1.0 million for the first phase of the pond cleaning expenses related to injunctive relief with the remaining costs being for legal expenses.  Initially, the Company expected that capital costs for injunctive relief related to the removal and repair of the liner would have been incurred after June 1, 2011.  However, after further analysis and review, the Company has decided to close the on-site surface impoundment by third quarter 2011 for an estimated cost of $1.0 million, which was accrued at March 31, 2011 and December 31, 2010.  An alternative capital project related to storm water overflow, estimated at $2.8 million, is currently under development.

The Company completed in 2007 the negotiation of a settlement of a Notice of Violation (“NOV”) from the Wyoming Department of Environmental Quality (“WDEQ”) alleging non-compliance with certain refinery waste management requirements.  The Company has estimated that the minimum capital cost for required corrective measures will be approximately $4.4 million and is estimated to be completed in early 2011.  In addition, the Company incurred a total of $2.3 million for additional work related to the corrective measures, which was substantially completed in 2010.

The Company has received a draft wastewater discharge permit from the WDEQ designed to renew the existing permit.  This draft includes new discharge limits for selenium and chloride in addition to a requirement for more rigorous toxicity testing of the wastewater discharge.  The Company is currently evaluating options to achieve compliance with the proposed limits.  Costs for compliance with the new limits, which are currently proposed to become effective on January 1, 2013, are currently not estimable.

El Dorado Refinery.  The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and Environment (“KDHE”).  Subject to the terms of the purchase and sale agreement for the El Dorado Refinery entered into between the Company and Shell Oil Products US (“Shell”), Shell is responsible for the costs of continued compliance with this order.  This order, including various subsequent modifications, requires the El Dorado Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation.  More specifically, the El Dorado Refinery must continue to operate the hydrocarbon recovery well systems and containment barriers at the site and conduct sampling from monitoring wells and surface water stations.  Quarterly and annual reports must also be submitted to the KDHE.  The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the Refinery are met.

In addition to the State order described above, on March 9, 2011, EPA Region 7 issued a draft Administrative Order on Consent jointly to the Company and to Shell that will eventually require investigation and potential corrective measures at the facility related to possible past releases of hazardous materials or historical waste management activities.  The Company and Shell have initiated preliminary discussions with the EPA to clarify requirements, responsibilities and coordination with the pre-existing State order.

Other Future Environmental Considerations.  Recent scientific studies have suggested that emissions of certain gases commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere.  On April 2, 2007, in Massachusetts, et al. v. EPA, the U.S. Supreme Court held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act and that the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources such as cars and trucks.  On April 17, 2009, the EPA proposed that certain greenhouse gases, including carbon dioxide, present a danger to public health or welfare.  The proposed “endangerment finding” was promulgated on December 7, 2009, opening the door to direct regulation of such greenhouse gases under the provisions and programs of the existing Clean Air Act.  Thus, the EPA can impose restrictions on the emission of greenhouse gases even if the U.S. Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  In October 2009, the EPA published a final rule requiring large emitters of greenhouse gases and certain industrial sectors to monitor and report their greenhouse gas emissions to the EPA beginning in 2011 for emissions in 2010.  On November 30, 2010, the EPA published a final rule expanding its existing GHG emission reporting rule to include onshore oil and natural gas production facilities beginning for 2012 for emissions occurring after January 1, 2011.  In May 2010, the EPA issued a final rule that determines which stationary sources of greenhouse gas emissions need to obtain a construction or operating permit and install the best available control technology for greenhouse gas emissions.  The regulation did not identify such technologies.  In response to the endangerment finding, the EPA adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also could trigger permit review for GHG emission from certain stationary sources.  The EPA has determined that the motor vehicle GHG emission standards triggered Clean Air Act construction and operating permit requirements for stationary sources beginning on January 2, 2011 when the motor vehicle standards took effect.  In addition, the EPA has stated its intent to propose regulations in 2011 that would require utilities and refineries to limit incremental greenhouse gas emissions resulting from future facility expansions.   The Agency further stated their intent to promulgate such regulations in 2012.  Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact the Company’s business, any such future laws and regulations will most likely result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on the Company’s business, financial condition and results of operations, including demand for the refined petroleum products that it produces.

14.      Litigation

The Company is involved in various lawsuits and regulatory actions which are incidental to its business.  In relation to the Holly proposed merger, twelve substantially similar shareholder lawsuits styled as class actions have been filed by alleged Frontier shareholders challenging the merger and naming as defendants Frontier, its board of directors and, in certain instances, Holly Corporation and a subsidiary of Holly Corporation, as aiders and abettors. In management’s opinion, the adverse determination of such lawsuits would not have a material adverse effect on the Company’s liquidity, financial position or results of operations.

15.      Consolidating Financial Statements

Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of the Company’s 6.875% Senior Notes and 8.5% Senior Notes.   Presented on the following pages are the Company’s condensed consolidating balance sheets, statements of operations, and statements of cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.  As specified in Rule 3-10, the condensed consolidating balance sheets, statements of operations, and statements of cash flows presented on the following pages meet the requirements for financial statements of the issuer and each guarantor of the notes because the guarantors are all direct or indirect 100%-owned subsidiaries of Frontier Oil Corporation, and all of the guarantees are full and unconditional on a joint and several basis.  The Company files a consolidated U.S. federal income tax return and consolidated state income tax returns in the majority of states in which it does business.  Accordingly, the equity in earnings of subsidiaries recorded for Frontier Oil Corporation is equal to the subsidiaries’ net income adjusted for consolidating pre-tax adjustments and for the portion of the subsidiaries’ income tax provision which is eliminated in consolidation.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2011
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,915,670		$	-	$	-		$	1,915,670
Other		(6	)		(7,041	)		31		-			(7,016	)
Total revenues		(6	)		1,908,629			31		-			1,908,654
Costs and expenses:
Raw material, freight and other costs		-			1,561,403			-		-			1,561,403
Refinery operating expenses, excluding     depreciation		-			75,807			-		-			75,807
Selling and general expenses, excluding     depreciation		3,909			6,694			-		-			10,603
Holly Corporation merger costs		5,148			-			-		-			5,148
Depreciation, amortization and     accretion		14			26,677			-		277			26,968
Gain on sales of assets		(2	)		(19	)		-		-			(21	)
Total costs and expenses		9,069			1,670,562			-		277			1,679,908
Operating (loss) income		(9,075	)		238,067			31		(277	)		228,746
Interest expense and other financing    costs		7,084			1,761			-		(211	)		8,634
Interest and investment income		(257	)		(90	)		-		-			(347	)
Equity in earnings of subsidiaries		(236,321	)		-			-		236,321			-
Income before income taxes		220,419			236,396			31		(236,387	)		220,459
Provision for income taxes		80,553			86,152			12		(86,124	)		80,593
Net income	$	139,866		$	150,244		$	19	$	(150,263	)	$	139,866

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,275,039		$	-	$	-		$	1,275,039
Other		(11	)		(2,913	)		29		-			(2,895	)
Total revenues		(11	)		1,272,126			29		-			1,272,144
Costs and expenses:
Raw material, freight and other costs		-			1,223,764			-		-			1,223,764
Refinery operating expenses, excluding     depreciation		-			68,883			-		-			68,883
Selling and general expenses, excluding     depreciation		4,522			6,454			-		-			10,976
Depreciation, amortization and     accretion		20			26,357			-		232			26,609
Gain on sales of assets		(1	)		-			-		-			(1	)
Total costs and expenses		4,541			1,325,458			-		232			1,330,231
Operating (loss) income		(4,552	)		(53,332	)		29		(232	)		(58,087	)
Interest expense and other financing    costs		6,173			1,587			-		(525	)		7,235
Interest and investment income		(387	)		(140	)		-		-			(527	)
Equity in earnings of subsidiaries		54,364			-			-		(54,364	)		-
(Loss) income before income taxes		(64,702	)		(54,779	)		29		54,657			(64,795	)
(Benefit) provision for income taxes		(24,438	)		(21,018	)		11		20,914			(24,531	)
Net (loss) income	$	(40,264	)	$	(33,761	)	$	18	$	33,743		$	(40,264	)

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of March 31, 2011
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	245,865	$	439,510	$	-	$	-		$	685,375
Trade and other receivables, net		31,477		264,120		-		-			295,597
Inventory of crude oil, products and    other		-		299,882		-		-			299,882
Deferred income tax assets - current		13,757		10,678		-		(10,678	)		13,757
Other current assets		1,236		7,231		7		-			8,474
Total current assets		292,335		1,021,421		7		(10,678	)		1,303,085
Property, plant and equipment, net		318		990,451		-		23,370			1,014,139
Deferred turnaround and catalyst costs,    net		-		51,177		-		-			51,177
Deferred financing costs, net		4,941		971		-		-			5,912
Intangible assets, net		-		1,063		-		-			1,063
Deferred income tax assets - noncurrent		5,450		1,213		10		(1,223	)		5,450
Other assets		4,661		179		-		-			4,840
Receivable from affiliated companies		-		8,869		622		(9,491	)		-
Investment in subsidiaries		1,444,575		-		-		(1,444,575	)		-
Total assets	$	1,752,280	$	2,075,344	$	639	$	(1,442,597	)	$	2,385,666
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,279	$	556,687	$	15	$	-		$	557,981
Income taxes payable		57,607		-		-		-			57,607
Accrued liabilities and other		6,068		27,975		2		(2	)		34,043
Total current liabilities		64,954		584,662		17		(2	)		649,631
Long-term debt		347,849		-		-		-			347,849
Contingent income tax liabilities		2,799		1,083		-		-			3,882
Long-term capital lease obligations		-		2,818		-		-			2,818
Other long-term liabilities		4,581		54,300		-		-			58,881
Deferred income tax liabilities		231,246		219,952		-		(219,952	)		231,246
Payable to affiliated companies (1)		9,492		55,573		331		(65,396	)		-
Shareholders' equity		1,091,359		1,156,956		291		(1,157,247	)		1,091,359
Total liabilities and shareholders'    equity	$	1,752,280	$	2,075,344	$	639	$	(1,442,597	)	$	2,385,666
(1) FHI payable to affiliated companies balance relates to income taxes payable to parent under a tax sharing agreement.

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2010
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	278,163	$	280,478	$	-	$	-		$	558,641
Trade and other receivables, net		49,398		146,674		-		-			196,072
Inventory of crude oil, products and    other		-		280,847		-		-			280,847
Deferred income tax assets - current		30,516		26,647		-		(26,647	)		30,516
Other current assets		1,403		11,571		7		-			12,981
Total current assets		359,480		746,217		7		(26,647	)		1,079,057
Property, plant and equipment, net		328		991,104		-		23,436			1,014,868
Deferred turnaround and catalyst costs,    net		-		51,347		-		-			51,347
Deferred financing costs, net		5,124		1,147		-		-			6,271
Intangible assets, net		-		1,094		-		-			1,094
Deferred income tax assets - noncurrent		11,768		6,642		10		(6,652	)		11,768
Other assets		4,180		179		-		-			4,359
Receivable from affiliated companies(1)		-		15,892		591		(16,483	)		-
Investment in subsidiaries		1,208,245		-		-		(1,208,245	)		-
Total assets	$	1,589,125	$	1,813,622	$	608	$	(1,234,591	)	$	2,168,764
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	147	$	493,050	$	15	$	-		$	493,212
Accrued liabilities and other		9,823		32,588		3		(2	)		42,412
Total current liabilities		9,970		525,638		18		(2	)		535,624
Long-term debt		347,773		-		-		-			347,773
Contingent income tax liabilities		2,758		1,072		-		-			3,830
Long-term capital lease obligations		-		2,938		-		-			2,938
Other long-term liabilities		4,093		53,286		-		-			57,379
Deferred income tax liabilities		234,673		223,978		22		(224,000	)		234,673
Payable to affiliated companies		3,311		-		296		(3,607	)		-
Shareholders' equity		986,547		1,006,710		272		(1,006,982	)		986,547
Total liabilities and shareholders'    equity	$	1,589,125	$	1,813,622	$	608	$	(1,234,591	)	$	2,168,764
(1) FHI receivable from affiliated companies balance includes $13,173 for income taxes receivable from parent under a tax sharing agreement.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2011
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	139,866		$	150,244		$	19		$	(150,263	)	$	139,866
Adjustments to reconcile net income    to net cash from operating activities:
Equity in earnings of subsidiaries		(236,321	)		-			-			236,321			-
Depreciation, amortization and    accretion		14			26,677			-			277			26,968
Deferred income tax provision		19,642			-			-			-			19,642
Stock-based compensation expense		3,224			-			-			-			3,224
Excess income tax benefits of    stock-based compensation		(1,101	)		-			-			-			(1,101	)
Intercompany income taxes		-			86,112			12			(86,124	)		-
Other intercompany transactions		6,181			(6,150	)		(31	)		-			-
Amortization of debt issuance costs		183			176			-			-			359
Senior notes discount amortization		76			-			-			-			76
Decrease in allowance for investment     loss and bad debts		(21	)		(230	)		-			-			(251	)
Gain on sales of assets		(2	)		(19	)		-			-			(21	)
Increase in other long-term liabilities		529			970			-			-			1,499
Turnaround and catalyst costs paid		-			(4,942	)		-			-			(4,942	)
Other		(481	)		-			-			-			(481	)
Changes in working capital from    operations		73,714			(77,674	)		-			(46	)		(4,006	)
Net cash provided by operating activities		5,503			175,164			-			165			180,832
Cash flows from investing activities:
Additions to property, plant and    equipment		(5	)		(16,043	)		-			(165	)		(16,213	)
Proceeds from sales of assets		4			21			-			-			25
Net cash used in investing activities		(1	)		(16,022	)		-			(165	)		(16,188	)
Cash flows from financing activities:
Purchase of treasury stock		(3,233	)		-			-			-			(3,233	)
Dividends paid		(35,919	)		-			-			-			(35,919	)
Proceeds from issuance of common    stock		350			-			-			-			350
Excess income tax benefits of    stock-based compensation		1,101			-			-			-			1,101
Debt issuance costs and other		(99	)		(110	)		-			-			(209	)
Net cash used in financing activities		(37,800	)		(110	)		-			-			(37,910	)
Increase (decrease) in cash and cash    equivalents		(32,298	)		159,032			-			-			126,734
Cash and cash equivalents, beginning of    period		278,163			280,478			-			-			558,641
Cash and cash equivalents, end of    period	$	245,865		$	439,510		$	-		$	-		$	685,375

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(40,264	)	$	(33,761	)	$	18		$	33,743		$	(40,264	)
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		54,364			-			-			(54,364	)		-
Depreciation, amortization and    accretion		20			26,357			-			232			26,609
Deferred income tax provision		(23,470	)		-			-			-			(23,470	)
Stock-based compensation expense		3,720			-			-			-			3,720
Excess income tax benefits of    stock-based compensation		(63	)		-			-			-			(63	)
Intercompany income taxes		-			(20,925	)		11			20,914			-
Intercompany dividends		6,200			-			-			(6,200	)		-
Other intercompany transactions		1,714			(1,685	)		(29	)		-			-
Amortization of debt issuance costs		196			176			-			-			372
Senior notes discount amortization		70			-			-			-			70
Decrease in allowance for investment    loss and bad debts		(4	)		(48	)		-			-			(52	)
Net gains on sales of assets		(1	)		-			-			-			(1	)
Increase (decrease) in other long-term    liabilities		948			(503	)		-			-			445
Turnaround and catalyst costs paid		-			(4,027	)		-			-			(4,027	)
Other		(552	)		35			-			-			(517	)
Changes in working capital from    operations		31,973			56,850			-			599			89,422
Net cash provided by operating activities		34,851			22,469			-			(5,076	)		52,244
Cash flows from investing activities:
Additions to property, plant and    equipment		9			(21,400	)		-			(1,124	)		(22,515	)
Proceeds from sales of assets		1			-			-			-			1
Net cash provided by (used in)    investing activities		10			(21,400	)		-			(1,124	)		(22,514	)
Cash flows from financing activities:
Purchase of treasury stock		(1,898	)		-			-			-			(1,898	)
Dividends paid		(6,393	)		-			-			-			(6,393	)
Excess income tax benefits of    stock-based compensation		63			-			-			-			63
Debt issuance costs and other		-			(101	)		-			-			(101	)
Intercompany dividends		-			(6,200	)		-			6,200			-
Net cash used in financing activities		(8,228	)		(6,301	)		-			6,200			(8,329	)
Increase (decrease) in cash and cash    equivalents		26,633			(5,232	)		-			-			21,401
Cash and cash equivalents, beginning of    period		211,775			213,505			-			-			425,280
Cash and cash equivalents, end of    period	$	238,408		$	208,273		$	-		$	-		$	446,681

ITEM 2.                 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products.  We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of approximately 187,000 barrels per day (“bpd”).  To assist in understanding our operating results, please refer to the operating data at the end of this analysis, which provides key operating information for our Refineries.  Refinery operating data is also included in our annual report on Form 10-K, our quarterly reports on Form 10-Q and on our web site at http://www.frontieroil.com.  We make our web site content available for informational purposes only.  The web site should not be relied upon for investment purposes nor is it incorporated by reference in this Form 10-Q.  We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, proxy statements, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.

Overview

The terms “Frontier,” “we”, “us” and “our” refer to Frontier Oil Corporation and its subsidiaries.  Several significant indicators of our profitability, which are reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential, the WTI/WTS crude oil differential and the average laid-in crude oil differential (the weighted average differential between the NYMEX WTI benchmark crude oil price and the composite cost of all crude oil purchased and delivered to our Refineries).  Other significant factors that influence our results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and maintenance).  We typically do not use derivative instruments to offset price risk on our base level of operating inventories.  See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of futures trading.

On February 21, 2011, we entered into a definitive merger agreement with Holly Corporation (“Holly”) under which the companies will combine in an all-stock merger of equals transaction.  Under the terms of the agreement, Frontier’s shareholders will receive 0.4811 Holly shares for each share of Frontier’s common stock.  Upon closing of the transaction, Holly shareholders are expected to own approximately 51 percent and the Frontier shareholders are expected to own approximately 49 percent of the combined company.  The transaction is structured to be tax-free to the shareholders of both companies.  The merger is expected to close in the third quarter of 2011.  On March 18, 2011, Holly and Frontier were notified of the early termination of the pre-merger waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, thus satisfying one of the conditions to the completion of the pending merger.  On March 21, 2011, Holly filed a Form S-4 Registration Statement, relating to the proposed merger with the Securities and Exchange Commission (“SEC”).  On April 27, 2011, Holly filed an amended Registration Statement Form S-4/A to address comments received from the SEC.  The merger remains subject to, among other things, approval by both companies’ shareholders and other customary closing conditions.

Three months ended March 31, 2011 compared with the same period in 2010

Overview of Results

We had net income for the three months ended March 31, 2011 of $139.9 million, or $1.32 per diluted share, compared to a net loss of $40.3 million, or $0.39 per share, in the same period in 2010.  Our operating income of $228.7 million for the three months ended March 31, 2011 increased $286.8 million from the $58.1 million operating loss for the comparable period in 2010.  The increase in our operating income from the first three months of 2010 to the first three months of 2011 was due to the improvements of the diesel crack spread (from $7.41 per barrel in 2010 to $25.53 per barrel in 2011) and gasoline crack spread (from $6.37 per barrel in 2010 to $15.43 per barrel in 2011) and a significant increase in crude oil differentials.  Our average laid-in crude oil differential increased to $7.16 per barrel for the three months ended March 31, 2011 from $1.85 in the same period in 2010.  The light/heavy crude oil differential increased from $4.91 per barrel for the three months ended March 31, 2010 to $18.60 per barrel for the comparable period of 2011.  The WTI/WTS crude oil differential increased from $1.77 per barrel for the three months ended March 31, 2010 to $3.58 per barrel for the comparable period of 2011.

In late 2009, we began taking actions to improve the profitability at our Cheyenne Refinery with the objective of improving profitability at the Refinery by $3 to $4 per barrel (compared to a historical average) by the end of 2011.  These actions include a combination of operating expense reductions (including maintenance, personnel, consulting, legal, environmental, and water treating chemicals) and projects aimed at energy efficiency, yield improvements and enhancing the types of crude oil that can be processed at the Refinery.  During 2010, we processed a higher percentage of light crude oils and have reduced controllable refinery operating expenses in Cheyenne.  We are proceeding with a liquefied petroleum gas (LPG) recovery capital project that will recover significant quantities of saleable propane and butane and other LPGs.  We believe that we are on course to meet our objective; however, future profitability of the Cheyenne Refinery cannot be guaranteed and is dependent on factors outside our control, including the price of crude oil.

Specific Variances

Refined product revenues.  Refined product revenues increased $640.6 million, or 50%, from $1.28 billion to $1.92 billion for the three months ended March 31, 2011 compared to the same period in 2010.  This increase resulted from correspondingly higher refined product prices based on higher crude oil prices, higher gasoline and diesel crack spreads and an overall 15% increase in sales volumes in the three months ended March 31, 2011 compared to the same period in 2010.  Gasoline sales prices averaged $110.48 per bbl in the three months ended March 31, 2011, compared to $86.06 per bbl for the comparable period in 2010.  Diesel sales prices averaged $121.07 per bbl in the three months ended March 31, 2011, compared to $87.27 per bbl for the comparable period in 2010.

Manufactured product yields.  Yields increased 16,783 bpd at the El Dorado Refinery and increased 3,381 bpd at the Cheyenne Refinery for the three months ended March 31, 2011 compared to same period in 2010.  The El Dorado refinery yields increased for the first quarter of 2011 when compared to 2010 due to planned and unplanned shutdowns in 2010.  During the 2010 period at both refineries, we reduced charges due to the economics of lower product margins.

Other revenues.  Other revenues decreased $4.1 million to a loss of $7.0 million for the three months ended March 31, 2011, compared to a loss of $2.9 million for the same period in 2010, the primary source of this decrease being $6.9 million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories in the three months ended March 31, 2011, compared to $2.8 million of losses in the three months ended March 31, 2010.  See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs.  Raw material, freight and other costs increased by $337.6 million, from $1.22 billion in the three months ended March 31, 2010 to $1.56 billion in the same period for 2011.  The increase in raw material, freight and other costs was due to higher average crude oil prices, increased overall crude oil charges, and increased purchased product during the three months ended March 31, 2011 when compared to the same period in 2010.  These increases were partially offset by an increase in the average laid-in crude oil differential.

The Cheyenne Refinery raw material, freight and other costs of $84.71 per sales barrel for the three months ended March 31, 2011 increased from $80.82 per sales barrel in the same period in 2010 due to higher average crude oil prices, increased crude oil charges, and increased purchased products partially offset by a higher average laid-in crude oil differential.  The average laid-in crude oil differential for the Cheyenne Refinery increased to $14.27 per barrel for the three months ended March 31, 2011, due to the widening of the light/heavy crude oil differential, compared to $2.60 per barrel in the same period in 2010.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $21.43 per barrel in the three months ended March 31, 2011 compared to $6.46 per barrel in the same period in 2010.

The El Dorado Refinery raw material, freight and other costs of $88.30 per sales barrel for the three months ended March 31, 2011 increased from $78.14 per sales barrel in the same period in 2010 primarily due to higher average crude oil prices, and increased crude oil charges, partially offset by a higher average laid-in crude oil differential.  The average laid-in crude oil differential increased to $4.95 per barrel for the three months ended March 31, 2011 compared to $1.59 per barrel in the same period in 2010 due to improved light/heavy and WTI/WTS crude oil differentials.  The WTI/WTS crude oil differential increased from an average of $1.77 per barrel in the three month period ended March 31, 2010 to $3.58 per barrel in the same period in 2011.  The light/heavy crude oil differential increased from an average of $3.95 per barrel in the three month period ended March 31, 2010 to $16.59 per barrel in the same period in 2011.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $75.8 million in the three months ended March 31, 2011 compared to $68.9 million in the comparable period of 2010.

The Cheyenne Refinery operating expenses, excluding depreciation, were $26.0 million for the three months ended March 31, 2011 compared to $23.8 million in the comparable period of 2010.  The primary areas of increased costs were: increased maintenance costs ($2.3 million, including $700,000 related to cold weather shutdowns and an increase in the number of maintenance projects in 2011), higher salaries and benefits ($667,000), increased environmental costs ($585,000), and higher consulting and legal expenses ($541,000).  These increased costs were partially offset by a decrease in natural gas costs ($2.2 million due to lower prices and volumes).

The El Dorado Refinery operating expenses, excluding depreciation, were $49.8 million for the three months ended March 31, 2011, increasing from $45.1 million in the same period of 2010.  Primary areas of increased costs and variance amounts for the 2011 period compared to the 2010 period were: higher maintenance costs ($2.2 million, due to an increase in the number of maintenance projects in 2011), higher consulting and legal expenses ($777,000), increased electricity costs ($748,000), higher salaries and benefits ($666,000), increased environmental costs ($608,000), increased additives and chemicals costs ($585,000), and higher operating supplies expenses ($483,000).  These increased costs were offset by a decrease in natural gas costs ($1.9 million due to lower prices and volumes).

Selling and general expenses.  Selling and general expenses, excluding depreciation, decreased $373,000, or 3%, from $11.0 million for the three months ended March 31, 2010 to $10.6 million for the three months ended March 31, 2011, primarily due to lower salaries and benefits and stock-based compensation expense in 2011.

Holly Corporation merger costs.  During the three months ended March 31, 2011, we incurred $5.1 million in consulting, legal and audit costs related to the pending merger with Holly.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $359,000, or 1%, for the three months ended March 31, 2011 compared to the same period in 2010.  Depreciation expense for the three months ended March 31, 2011 increased $675,000 (including an increase of $1.0 million for the El Dorado Refinery, offset by a decrease of $335,000 for the Cheyenne Refinery) to $21.1 million from $20.4 million in the comparable 2010 period.  The increase related to increased capital investments at our Refineries, including the El Dorado Refinery’s gasoil hydrotreater revamp final phase which was placed into service in December 2010.

Deferred turnaround and catalyst amortization for the three months ended March 31, 2011 decreased $295,000 (including $36,000 and $258,000 decreases for the El Dorado Refinery and the Cheyenne Refinery, respectively) to $5.8 million from $6.1 million in the comparable 2010 period.  The decrease for the Cheyenne Refinery was primarily due to a deferral to 2011 of certain 2010 turnarounds and catalyst change-outs.

Interest expense and other financing costs.  Interest expense and other financing costs of $8.6 million for the three months ended March 31, 2011 increased from $7.2 million in the comparable period in 2010.  Our interest expense for the three months ended March 31, 2011 was reduced by $63,000 for the net benefit of our interest rate swaps compared to a benefit of $1.2 million during the three months ended March 31, 2010.  In addition we had $314,000 less capitalized interest, and $356,000 higher revolving credit facility fees for the thee months ended March 31, 2011 when compared to the same period in 2010.

Average debt outstanding was $350.0 million for both the three months ended March 31, 2011 and 2010 (excluding amounts payable to BNP under the BNP Crude Financing Arrangement).

Interest and investment income.  Interest and investment income decreased $180,000, from $527,000 in the three months ended March 31, 2010, to $347,000 in the three months ended March 31, 2011.

Provision (benefit) for income taxes.  The provision for income taxes for the three months ended March 31, 2011 was $80.6 million on pretax income of $220.5 million (or 36.6%).  The 2011 period effective tax rate was reduced by 1.7% from our estimated statutory tax rate of 38.2% for the benefit of the Section 199 production activities deduction. Our benefit for income taxes for the three months ended March 31, 2010 was $24.5 million on a pretax loss of $64.8 million (or 37.9%).

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities.  Net cash provided by operating activities was $180.8 million for the three months ended March 31, 2011 compared to net cash provided by operating activities of $52.2 million during the three months ended March 31, 2010.  Working capital changes were a use of cash during the 2011 period while providing cash during the same period in 2010.  Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risks.”

Working capital changes used a total of $4.0 million of cash during the first three months of 2011 compared to providing $89.4 million for the same period in 2010.  The $4.0 million net working capital uses for the 2011 period primarily resulted from increased receivables of $99.3 million and increased inventories of $19.0 million (due to higher prices), offset by working capital provided by $60.1 million of increased payables (including a $51.7 million increase in crude payables primarily due to higher crude oil prices) and $49.7 million of increased current accrued liabilities (including a $57.6 million in income taxes payable).  In the first three months of 2010, the working capital change of $89.4 million primarily resulted from a $97.3 million increase in payables and $20.6 million decrease in receivables, offset by $17.7 million of decreased current accrued liabilities and $12.8 million of increased inventory.  During the three months ended March 31, 2011, we received federal and state income tax refunds of $16.4 million.  At March 31, 2011, we had $685.4 million of cash and cash equivalents, $653.5 million of working capital, no cash borrowings under our revolving credit facility, and $200.4 million of availability for cash borrowings under our $500.0 million revolving credit facility.

Cash flows used in investing activities.  Capital expenditures during the first three months of 2011 were $16.2  million, which included approximately $10.2 million for the Cheyenne Refinery and $5.8 million for the El Dorado Refinery.  The $10.2 million of capital expenditures for our Cheyenne Refinery included $6.2 million for the liquefied petroleum gas recovery project as well as safety, operational and environmental projects.  The $5.8 million of capital expenditures for our El Dorado Refinery included operational, safety and environmental projects.

Cash flows from financing activities.  During the three months ended March 31, 2011, treasury stock increased by 119,350 shares ($3.2 million) from stock surrendered by employees to pay withholding taxes on stock-based compensation which vested during the first three months of 2011.  We also paid $35.9 million in dividends during the three months ended March 31, 2011.  We received $350,000 in proceeds from stock option exercises.

During the three months ended March 31, 2011 we had no borrowings under our revolving credit facility.  As of March 31, 2011, we had $347.8 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $299.6 million of letters of credit outstanding under our revolving credit facility.  We were in compliance with the financial covenants of our revolving credit facility as of March 31, 2011.  Shareholders’ equity as of March 31, 2011 was $1.09 billion.

Our Board of Directors declared a special cash dividend of $0.28 per share of common stock and a quarterly cash dividend of $0.06 per share of common stock in February 2011, which was paid in March 2011.  Any future dividends paid by the Company will be subject to the approval of our Board of Directors.

FUTURE CAPITAL AND TURNAROUND EXPENDITURES

Significant future capital projects.  At the Cheyenne Refinery, the completion of the FCCU gas hydrotreater project, originally planned to be completed during the fourth quarter of 2010 to comply with low sulfur gasoline requirements, has been deferred.  We plan to initially comply with the low sulfur gasoline requirements at the Cheyenne Refinery through alternative methods and in the long-term with the completion of the FCCU gas hydrotreater project (see “Environmental” in Note 12 in the Notes to Condensed Consolidated Financial Statements).  The estimated total cost of the project is $40.0 million of which approximately half will be spent by the end of 2011 ($18.5 million incurred as of March 31, 2011), with the remaining amount temporarily postponed.  In addition at the Cheyenne Refinery, we are working on a liquefied petroleum gas (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 total estimated cost of this project is $40.0 million ($23.8 million incurred as of March 31, 2011) and is estimated to be substantially completed by mid-2011.  At the El Dorado Refinery, we plan to do a $26.2 million coker furnace replacement project which will replace the existing furnace with the latest technology in coking furnaces.  This project 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 above amounts include estimated capitalized interest.

2011 capital expenditures.  Including the projects discussed above, 2011 capital expenditures aggregating approximately $110.0 million are currently forecasted ($16.2 million spent through March 31, 2011).  The 2011 capital expenditures include $72.0 million at our Cheyenne Refinery, $35.0 million at our El Dorado Refinery, $2.0 million for our pipeline and product terminals and blending facility and $626,000 at our Denver and Houston offices.  The $72.0 million of forecasted capital expenditures for our Cheyenne Refinery includes $28.0 million for the LPG recovery project, discussed above, $9.0 million for tank farm optimization and $3.0 million for a FCCU main fractionator replacement, as well as environmental, operational, safety, payout and administrative projects.  The $35.0 million of forecasted capital expenditures for our El Dorado Refinery includes $5.0 million for the coke drum charge furnace replacement, as well as environmental, operational, safety, payout and administrative projects.  We expect that our remaining 2011 capital expenditures will be funded with cash generated by our operations and/or by using a portion of our existing cash balance or additional borrowings, if necessary.  We may experience cost overruns and/or schedule delays or adjust the scope on any of these projects.

2011 turnaround expenditures.  We forecast spending of approximately $23.0 million on turnarounds and catalyst in 2011 ($4.9 million spent as of March 31, 2011) comprised of $20.0 million at our Cheyenne Refinery on the alkylation, FCCU, scanfiner and butamer units in the spring of 2011 and $3.0 million at our El Dorado Refinery primarily on the aromatics recovery unit in the fall of 2011.  These expenditures will be deferred and subsequently amortized through the next scheduled turnaround or catalyst estimated useful life.

Operating Data

The following tables set forth the refining operating statistical information on a consolidatedbasis and for each Refinery for the three months ended March 31, 2011 and 2010.  The statistical information includes the following terms:

  · Charges - the quantity of crude oil and other feedstock processed through refinery process units on a bpd basis.

  · Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis.

  · NYMEX WTI - the benchmark West Texas Intermediate crude oil priced on the New York Mercantile Exchange.

  · Average laid-in crude oil differential - the weighted average differential between the NYMEX WTI crude oil price and the composite cost of all crude oil purchased and delivered to our Refineries.

  · WTI/WTS crude oil differential - the average differential between the NYMEX WTI crude oil price and the West Texas sour crude oil priced at Midland, Texas.

  · Cheyenne Refinery light/heavy crude oil differential - the average differential between the NYMEX WTI crude oil price and the cost of heavy crude oil delivered to the Cheyenne Refinery.

  · El Dorado Refinery light/heavy crude oil differential - the average differential between the NYMEX WTI crude oil price and the cost of heavy crude oil delivered to the El Dorado Refinery.

  · Gasoline and diesel crack spreads - the average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average NYMEX WTI crude oil price.

Consolidated:
	Three Months Ended March 31,
	2011		2010
Charges (bpd)
Light crude		79,230		64,136
Heavy and intermediate crude		96,566		95,378
Other feed and blendstocks		16,476		12,794
Total		192,272		172,308
Manufactured product yields (bpd)
Gasoline		96,544		82,963
Diesel and jet fuel		71,810		66,094
Asphalt		3,891		3,782
Other		17,004		16,247
Total		189,249		169,086
Total product sales (bpd)
Gasoline		105,819		89,544
Diesel and jet fuel		70,512		65,916
Asphalt		3,902		2,839
Other		18,199		14,132
Total		198,432		172,431
Refinery operating margin information (per sales barrel)
Refined products revenue	$	107.27	$	82.16
Raw material, freight and other costs		87.43		78.86
Refinery operating expenses, excluding depreciation (1)		4.24		4.44
Depreciation, amortization and accretion (1)		1.50		1.71
Average NYMEX WTI (per barrel)	$	94.11	$	78.54
Average laid-in crude oil differential (per barrel)		7.16		1.85
Average light/heavy differential (per barrel)		18.60		4.91
Average gasoline crack spread (per barrel)		15.43		6.37
Average diesel crack spread (per barrel)		25.53		7.41
Average sales price (per sales barrel)
Gasoline	$	110.48	$	86.06
Diesel and jet fuel		121.07		87.27
Asphalt		64.38		71.54
Other		44.27		35.79
(1) Prior period amounts are adjusted to reflect current year presentation of turnaround and catalyst amortization as depreciation, amortization and accretion instead of refinery operating expenses.

Cheyenne Refinery:
	Three Months Ended March 31,
	2011		2010
Charges (bpd)
Light crude		16,015		26,736
Heavy and intermediate crude		26,652		12,482
Other feed and blendstocks		1,935		2,202
Total		44,602		41,420
Manufactured product yields (bpd)
Gasoline		19,014		20,158
Diesel		13,972		14,778
Asphalt		3,891		3,782
Other		6,720		1,498
Total		43,597		40,216
Total product sales (bpd)
Gasoline		25,913		26,385
Diesel		14,237		14,872
Asphalt		3,902		2,839
Other		3,949		2,162
Total		48,001		46,258
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	102.71	$	83.43
Raw material, freight and other costs		84.71		80.82
Refinery operating expenses, excluding depreciation (1)		6.01		5.71
Depreciation, amortization and accretion (1)		2.13		2.37
Average laid-in crude oil differential (per barrel)	$	14.27	$	2.60
Average light/heavy crude oil differential (per barrel)		21.43		6.46
Average gasoline crack spread (per barrel)		14.42		6.06
Average diesel crack spread (per barrel)		27.35		9.76
Average sales price (per sales barrel)
Gasoline	$	108.69	$	85.85
Diesel		123.58		89.13
Asphalt		64.38		71.54
Other		26.12		30.27
(1) Prior period amounts are adjusted to reflect current year presentation of turnaround and catalyst amortization as depreciation, amortization and accretion instead of refinery operating expenses.

El Dorado Refinery:
	Three Months Ended March 31,
	2011		2010
Charges (bpd)
Light crude		63,215		37,399
Heavy and intermediate crude		69,914		82,896
Other feed and blendstocks		14,541		10,593
Total		147,670		130,888
Manufactured product yields (bpd)
Gasoline		77,530		62,805
Diesel and jet fuel		57,838		51,316
Other		10,285		14,749
Total		145,653		128,870
Total product sales (bpd)
Gasoline		79,906		63,159
Diesel and jet fuel		56,275		51,045
Other		14,250		11,969
Total		150,431		126,173
Refinery operating margin information (per sales barrel)
Refined products revenue	$	108.72	$	81.70
Raw material, freight and other costs		88.30		78.14
Refinery operating expenses, excluding depreciation (1)		3.68		3.97
Depreciation, amortization and accretion (1)		1.30		1.47
Average laid-in crude oil differential (per barrel)	$	4.95	$	1.59
Average WTI/WTS crude oil differential (per barrel)		3.58		1.77
Average light/heavy crude oil differential (per barrel)		16.59		3.95
Average gasoline crack spread (per barrel)		15.76		6.50
Average diesel crack spread (per barrel)		25.07		6.72
Average sales price (per sales barrel)
Gasoline	$	111.06	$	86.15
Diesel and jet fuel		120.44		86.72
Other		49.30		36.78
(1) Prior period amounts are adjusted to reflect current year presentation of turnaround and catalyst amortization as depreciation, amortization and accretion instead of refinery operating expenses.

ITEM 3.                QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Impact of Changing Prices.  Our earnings and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices.  The prices of crude oil and refined products have fluctuated substantially in recent years.  These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depend on, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics.  The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets.  The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil.  Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products.  The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.

Commodity Price Risks.  At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on future production.  The commodity derivative contracts used by us may take the form of futures contracts, collars or price swaps.  We believe that there is minimal credit risk with respect to our counterparties.  We account for our commodity derivative contracts that do not qualify for hedge accounting, utilizing mark-to-market accounting, with gains or losses on transactions being reflected in “Other revenues” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for each period.  See Note 12 “Price and Interest Risk Management Activities” in the Notes to Condensed Consolidated Financial Statements.

Our outstanding derivatives sale contracts and net unrealized gains and losses as of March 31, 2011 are summarized below:

Commodity	Period	Volume (thousands of bbls)	Expected Close Out Date	Unrealized Net Gains (Losses) (in thousands)
Crude Oil	May 2011	889	April 2011	$(2,923)
Crude Oil	June 2011	43	May 2011	(52)
Crude Oil	December 2011	24	November 2011	290
Crude Oil	December 2012	177	November 2012	1,636
Crude Oil	December 2013	234	November 2013	333

Interest Rate Risk.  Borrowings under our revolving credit facility bear a current market rate of interest.  A one percent increase or decrease in the interest rates on our revolving credit facility would not significantly affect our earnings or cash flows.  Our $150.0 million principal of 6.875% Senior Notes due 2018 and $200.0 million 8.5% Senior Notes due 2016 that were outstanding at March 31, 2011 have fixed interest rates.  In the fourth quarter of 2009, the Company entered into fixed to floating interest rate swaps of $150.0 million to manage interest rate exposure related to our 6.625% Senior Notes.  These interest rate swaps expose that portion of our long-term debt to cash flow risk from interest rate changes.  Our long-term debt is also exposed to fair value risk; see below table for fair values at the balance sheet dates.  The following table provides information about our financial instruments that are sensitive to changes in short-term interest rates, including interest rate swaps and debt obligations.  For our debt obligations, this table presents principal cash flows and related weighted average interest rates by expected maturity dates.  For our interest rate swaps, this table presents notional amounts and weighted average interest rates by maturity dates.  Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting dates.  The fair value of our debt obligations was estimated based on quotations obtained from broker-dealers who make markets in these and similar securities. A mark-to-market valuation that took into consideration anticipated cash flows from the transactions using market prices and other economic data and assumptions were used to value our interest rate swaps.

	As of March 31, 2011
	Expected maturity dates																	Fair value
	2011			2012		2013		2014		2015		Thereafter			Total
	(in thousands)
Long-term debt:
Fixed rate	$	-		$	-	$	-	$	-	$	-	$	350,000		$	350,000		$	372,063
Average interest rate		-			-		-		-		-		7.804	%		7.804	%
Interest rate swaps:
Fixed to variable	$	150,000		$	-	$	-	$	-	$	-	$	-		$	150,000		$	632
Average pay rate		5.782	%		-		-		-		-		-			5.782	%
Average receive rate		6.625	%		-		-		-		-		-			6.625	%
	As of December 31, 2010
	Expected maturity dates																	Fair value
		2011			2012		2013		2014		2015	Thereafter			Total
	(in thousands)
Long-term debt:
Fixed rate	$	-		$	-	$	-	$	-	$	-	$	350,000		$	350,000		$	365,375
Average interest rate		-			-		-		-		-		7.804	%		7.804	%
Interest rate swaps:
Fixed to variable	$	150,000		$	-	$	-	$	-	$	-	$	-		$	150,000		$	929
Average pay rate		5.799	%		-		-		-		-		-			5.799	%
Average receive rate		6.625	%		-		-		-		-		-			6.625	%

ITEM 4.                CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.  As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, the  effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act.  Based on that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

Legal Proceedings – See Notes 13 and 14 in the Notes to Condensed Consolidated Financial Statements. Litigation Related to the Proposed Merger with Holly Corporation. Twelve substantially similar shareholder lawsuits styled as class actions have been filed by alleged Frontier shareholders challenging the proposed merger with Holly Corporation (“Holly”) and naming as defendants Frontier, its board of directors and, in certain instances, Holly and a subsidiary of Holly, as aiders and abettors. To date, such shareholder actions have been filed in Harris County, Texas, Laramie County, Wyoming, the U.S. District Court for the Northern District of Texas, and the U.S. District Court for the Southern District of Texas. The lawsuits filed in the District Courts of Harris County, Texas are entitled: Adam Walker, Individually and On Behalf of All Others Similarly Situated vs. Frontier Oil Corporation, et al. (filed February 22, 2011), Andrew Goldberg, on Behalf of Himself and All Other Similarly Situated Shareholders of Frontier Oil Corporation v. Frontier Oil Corporation, et al. (filed February 24, 2011), L.A. Murphy, On Behalf of Herself and All Others Similarly Situated v. Paul B. Loyd, Jr., et al. (filed February 24, 2011), Zhixin Huang v. Frontier Oil Corp., et al. (filed February 24, 2011), Robert Pettigrew, individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed February 25, 2011), Walter E. Ryan, Jr., On Behalf of Himself and All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed February 25, 2011), Christopher Borrelli, Individually and on Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed March 2, 2011), and Randy Whitman, Individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed on March 8, 2011). The lawsuit filed in the District Court of Laramie County, Wyoming is entitled Thomas Greulich, Individually and on Behalf of All Others Similarly Situated v. Frontier Oil Corporation, et al. (filed March 1, 2011). The lawsuit filed in the U.S. District Court for the Northern District of Texas is entitled Angelo Chiarelli, On Behalf of Himself and All Others Similarly Situated v. Holly Corporation, et al. (filed on March 2, 2011). The lawsuits filed in the U.S. District Court for the Southern District of Texas are entitled Tim Wilcox, Individually and on behalf of all others similarly situated v. Frontier Oil Corporation, et al. (filed on March 7, 2011), and Jackie A. Rhymes, Individually and on behalf of all others similarly situated v. Michael Jennings, et al. (filed on March 17, 2011).

ITEM 1A.

Risk Factors – In addition to the other information set forth in this report, you should carefully consider the factors discussed under the caption “Risk Factors” included in Part I, Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2010, as well as the risk factors noted below, which could materially affect our business, financial condition or results of operations. The Merger is subject to a number of conditions beyond our control.  Failure to complete the Merger within the expected timeframe or at all could adversely affect our stock price and our future business and financial results. Completion of the Merger is subject to a number of conditions beyond our control that may prevent, delay or otherwise materially and adversely affect its completion, including certain approvals of our shareholders and the stockholders of Holly.  We cannot predict whether and when these conditions will be satisfied.  Any delay in completing the Merger could cause the combined company not to realize some or all of the synergies that we expect to achieve if the Merger is successfully completed within its expected timeframe.  We will also incur certain transaction costs whether or not the Merger is completed.  Any failure to complete the Merger could have a material adverse effect on our stock price and our future business and financial results. Prior to the closing of the Merger, we face uncertainties and restrictions on our business, which could adversely affect us or the future business and operations of the combined company, whether or not the Merger is completed. Prior to the closing of the Merger, we will face additional uncertainties and restrictions on the manner in which we operate our business, including, among other things, that: ·our operations will be restricted by the terms of the merger agreement with Holly, which may cause us to forego otherwise beneficial business opportunities; ·we may lose management personnel and other key employees and be unable to attract and retain such personnel and employees; and ·management’s attention and other company resources may be focused on the Merger instead of on pursuing other opportunities beneficial to us. These uncertainties and restrictions could adversely affect us or the future business and operations of the combined company, whether or not the Merger is completed.  If the Merger is not completed during the third quarter of 2011 as currently anticipated, the adverse effects of these uncertainties and restrictions could be exacerbated by the delay. The anticipated benefits of the Merger may not be realized fully, or at all, or may take longer to realize than expected. If the Merger is consummated, the anticipated benefits of the Merger may not be realized fully, or at all, or may take longer to realize than expected as a result of a number of events or occurrences, including the following: ·the combined company may be unable to integrate successfully the businesses and workforces of Frontier and Holly; ·the combined company may lose management personnel and other key employees and be unable to attract and retain such personnel and employees; ·the combined company may be unable to manage the expanded business successfully and monitor new operations and associated increased costs and complexity; and ·launching branding or rebranding initiatives may involve substantial costs and may not be favorably received by customers. Accordingly, there can be no assurance that the Merger will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect or that these benefits will be achieved within the anticipated timeframe.  Any delay in the consummation of the Merger or any uncertainty about the consummation of the Merger may adversely affect the future businesses, growth, revenue and results of operations of Holly, us or the combined company. The termination fee and restrictions on solicitation contained in the merger agreement may discourage other companies from trying to acquire us.  Until completion of the Merger, with limited exceptions, the merger agreement with Holly prohibits us from entering into an alternative acquisition transaction with, or soliciting any alternative acquisition proposal from, another party. We have agreed under certain circumstances to pay Holly a termination fee equal to $80.0 million, including where our board of directors withdraws its support of the merger to enter into a business combination with a third party. These provisions could discourage other companies from trying to acquire us even though those other companies might be willing to offer greater value to our shareholders than Holly has offered in the Merger.

ITEM 5. Other Information –   None.    

ITEM 6. Exhibits – 31.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   31.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   32.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   32.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   101 – The following materials from Frontier Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months ended March 31, 2011 and 2010, (ii) Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010, (iii) Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010, and (iv) Notes to Condensed Consolidated Financial Statements, tagged as a block of text*.   *  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

SIGNATURES

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

FRONTIER OIL CORPORATION
By:	/s/ Nancy J. Zupan
	Nancy J. Zupan
	Vice President and Chief Accounting Officer (principal accounting officer)

Date: May 5, 2011