Frontier Oil (FTO) 10-Q 2010 Q3 Quarterly report

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 SEPTEMBER 30, 2010

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 November 1, 2010:  105,720,064

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2010

INDEX

Item 1.             Financial Statements

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

Item 3.             Quantitative and Qualitative Disclosures About Market Risk

Item 4.             Controls and Procedures

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; 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)
	Nine Months Ended September 30,						Three Months Ended September 30,
	2010			2009 As Adjusted (Note 2)			2010			2009 As Adjusted (Note 2)
Revenues:
Refined products	$	4,215,546		$	3,147,210		$	1,419,997		$	1,196,899
Other		21,950			1,464			(3,525	)		3,683
Total revenues		4,237,496			3,148,674			1,416,472			1,200,582
Costs and expenses:
Raw material, freight and other costs		3,844,828			2,814,341			1,283,773			1,089,612
Refinery operating expenses, excluding depreciation		221,901			232,175			82,878			83,701
Selling and general expenses, excluding depreciation		35,390			38,937			13,194			13,650
Depreciation, amortization and accretion		61,156			54,226			20,309			18,099
Gain on sales of assets		(1	)		-			-			-
Total costs and expenses		4,163,274			3,139,679			1,400,154			1,205,062
Operating income (loss)		74,222			8,995			16,318			(4,480	)
Interest expense and other financing costs		24,306			21,046			9,025			6,709
Interest and investment income		(1,791	)		(1,948	)		(696	)		(661	)
Income (loss) before income taxes		51,707			(10,103	)		7,989			(10,528	)
Provision (benefit) for income taxes		17,549			(1,397	)		(319	)		(1,744	)
Net income (loss)	$	34,158		$	(8,706	)	$	8,308		$	(8,784	)
Comprehensive income (loss)	$	33,762		$	(8,827	)	$	8,177		$	(8,780	)
Basic earnings (loss) per share of common stock	$	0.33		$	(0.08	)	$	0.08		$	(0.08	)
Diluted earnings (loss) per share of common stock	$	0.32		$	(0.08	)	$	0.08		$	(0.08	)
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)
September 30, 2010 and December 31, 2009	2010			2009
ASSETS
Current assets:
Cash, including cash equivalents of $413,048 and $424,323 at 2010 and 2009,     respectively	$	413,651		$	425,280
Trade receivables, net of allowance of $1,000 at 2010 and 2009		170,280			95,261
Income taxes receivable		109,941			174,627
Other receivables, net		5,724			7,842
Inventory of crude oil, products and other		379,660			293,476
Deferred income tax assets - current		12,379			26,373
Other current assets		12,266			14,507
Total current assets		1,103,901			1,037,366
Property, plant and equipment, net		1,014,550			1,021,409
Deferred turnaround and catalyst costs, net		54,694			68,491
Deferred financing costs, net of accumulated amortization of $5,009 and $3,893 at     2010 and 2009, respectively		3,594			4,711
Intangible assets, net of accumulated amortization of $705 and $614 at 2010 and     2009, respectively		1,124			1,216
Deferred state income tax assets - noncurrent		10,717			10,767
Other assets		3,754			3,935
Total assets	$	2,192,334		$	2,147,895
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	513,124		$	474,377
Accrued liabilities and other		44,043			64,799
Total current liabilities		557,167			539,176
Long-term debt		347,699			347,485
Contingent income tax liabilities		30,558			29,348
Post-retirement employee liabilities		34,829			33,138
Long-term capital lease obligation		3,056			3,394
Other long-term liabilities		13,670			20,560
Deferred federal income tax liabilities		221,134			230,818
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		260,186			252,513
Retained earnings		1,064,369			1,030,203
Accumulated other comprehensive loss		(1,630	)		(1,234	)
Treasury stock, at cost, 26,130,292 and 27,165,400 shares at 2010 and 2009, respectively		(396,440	)		(395,242	)
Total shareholders' equity		984,221			943,976
Total liabilities and shareholders' equity	$	2,192,334		$	2,147,895
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 nine months ended September 30,
	2010			2009 As  Adjusted (Note 2)
Cash flows from operating activities:
Net income (loss)	$	34,158		$	(8,706	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation, amortization and accretion, including amortization    of deferred turnaround costs		75,265			69,194
Deferred income tax provision		4,346			14,335
Stock-based compensation expense		12,290			15,193
Excess income tax benefits of stock-based compensation		(152	)		(227	)
Amortization of debt issuance costs		1,116			1,117
Senior Notes discount amortization		214			196
Allowance for investment loss and bad debts		(184	)		500
Gain on sales of assets		(1	)		-
(Decrease) increase in other long-term liabilities		(4,952	)		10,734
Changes in deferred turnaround costs, deferred catalyst costs and other		(131	)		(8,133	)
Changes in working capital from operations		(61,940	)		52,863
Net cash provided by operating activities		60,029			147,066
Cash flows from investing activities:
Additions to property, plant and equipment		(61,291	)		(121,574	)
Proceeds from sales of assets		1			-
Net cash used in investing activities		(61,290	)		(121,574	)
Cash flows from financing activities:
Purchase of treasury stock		(3,582	)		(2,654	)
Proceeds from issuance of common stock		-			70
Dividends paid		(6,628	)		(19,071	)
Excess income tax benefits of stock-based compensation		152			227
Other		(310	)		(282	)
Net cash used in financing activities		(10,368	)		(21,710	)
(Decrease) increase in cash and cash equivalents		(11,629	)		3,782
Cash and cash equivalents, beginning of period		425,280			483,532
Cash and cash equivalents, end of period	$	413,651		$	487,314
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	21,354		$	17,227
Cash paid during the period for income taxes		15,054			36,150
Cash refunds of income taxes		63,619			51,593
Noncash investing activities - accrued capital expenditures, end of period		9,747			21,917
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 State s 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 wi th the financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2009.  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:

	Nine Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
Basic		104,196,169		103,536,988		104,452,369		103,746,632
Diluted		105,574,674		103,536,988		106,173,087		103,746,632

For the nine and three months ended September 30, 2010 and 2009, 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 nine and three months ended September 30, 2009, there were 1.2 million and 1.6 million, respectively, outstanding restricted stock and stock unit awards not included in the computation of diluted EPS due to the Company’s net loss in both periods.

The Company’s Board of Directors declared a quarterly cash dividend of $0.06 per share of common stock in November 2009, which was paid in January 2010.  As of September 30, 2010, the Company had $133.7 million and $309.4 million available to pay dividends under the restricted payments basket of its 6.625% Senior Notes and 8.5% Senior Notes, respectively (collectively, the “Senior Notes”) covenants; however, the Company is currently unable to pay dividends because of the inability to satisfy the incurrence of additional indebtedness test in the covenants of the Senior Notes.

Foreign currency transactions

The Company 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 nine and three months ended September 30, 2010, the Company recognized a loss in “Other Revenues” of $66,000 and $203,000, respectively, due to the translation of its foreign denominated assets and liabilities.  For the nine and three months ended September 30, 2009, the Company recognized a loss of $1.2 million and $313,00 0, respectively.

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 maximum term of one year.  The Company accounted for this balance in “Other Receivables” on the Condensed Consolidated Balance Sheets as of September 30, 2010.

New accounting pronouncements

In December 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-17 which amended guidance to ASC 810 “Consolidations,” specifically, the consolidation guidance that applies to variable interest entities (“VIEs”).  This statement amends current consolidation guidance to require companies to perform an analysis to determine whether a company’s variable interest or interests give it a controlling financial interest in a VIE and assess whether the company has implicit financial responsibility to ensure that the VIE operates as designed when determining if it has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance.  This st atement also amends current guidance to require companies to perform ongoing reassessments of whether the company is the primary beneficiary of a VIE.  This statement amends certain guidance for determining whether an entity is a VIE, and the application of this revised guidance may change a company’s assessment of its VIEs.  The statement is effective as of the beginning of the first fiscal year that begins after November 15, 2009.  The adoption of ASU 2009-17, in the first quarter of 2010, did not have a material impact on the Company’s financial statements and disclosures.

In June 2009, the FASB issued ASU 2009-16, additional guidance to ASC 860, “Transfers and Servicing” to improve financial reporting by eliminating the exceptions for qualifying special-purpose entities from the consolidating guidance and eliminating the exception that permitted sale accounting for certain mortgage securitizations when a transferor has not surrendered control over the transferred financial assets.  The statement also improves the comparability and consistency in accounting for transferred financial assets and enhances the information provided to financial statement users to provide greater transparency about transfers of financial assets and a transferor’s continuing involvement with transferred financial assets.  Under the new guidance, many types of transferred financial assets that would have been derecognized previously are no longer eligible for derecognition.  This new guidance enhances disclosures about the risks that a transferor continues to be exposed to because of its continuing involvement in transferred financial assets.  The statement is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  The adoption of this ASU did not have a material impact on the Company’s financial statements and disclosures.

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 o n 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 Company is evaluating the impact of the additional disclosures required for its 2011 filings relating to the Level 3 requirements.

In February 2010, the FASB issued ASU 2010-09, which amends ASC 855, “Subsequent Events” to address certain implementation issues related to the application of disclosure requirements under ASC 855.  This ASU requires filers to “evaluate subsequent events through the date the financial statements are issued.”  However, this ASU exempts filers from disclosing the date through which subsequent events have been evaluated, thus alleviating potential conflicts between ASC 850-10 and the SEC’s requirements.  This ASU is effective immediately for financial statements that are issued, available to be issued or revised.  As such, this revised guidance was effective for the Company in the first quarter 2010.  The adoption of this guidance did not have a material impact on the Company’s financial statement disclosures.

In July 2010, the FASB issued ASU 2010-20, which amends ASC 310, “Receivables” to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables.  This ASU will require an entity to disclose (1) the inherent credit risk in its financing receivables, (2) how the credit risk is analyzed and assessed in calculating the allowance for credit losses and (3) the changes and reasons for those changes in the allowance for credit losses.    The scope of this ASU applies to all of the Company’s financing receivables, excluding its short-term trade accounts receivables.  This ASU is effective for interim and annual reporting periods ending on or after December 31, 2010.  The Company does not expect a material impa ct in its 2010 annual report from the adoption of this ASU.

2.      Change in Accounting Principle – Inventory

During the fourth quarter of 2009, the Company changed its inventory valuation method for crude oil, unfinished products and finished products to the last-in, first-out (LIFO) method from the first-in, first-out (FIFO) method.  All of the Company’s other inventories will continue to be valued at the lower of average cost or market.  The Company believes the change to the LIFO method is preferable because it will improve matching of current costs with revenues and improve comparability with its industry peers.  The Company has retrospectively adjusted the previously reported condensed consolidated financial statements for the change for the comparative periods ended September 30, 2009.  The following condensed consolidated financial statement line items for the nine and three months ended Sept ember 30, 2009 were affected by the change in accounting principle.

	Nine months ended									Three months ended
	September 30, 2009									September 30, 2009
	As Originally Reported			As Adjusted			Change			As Originally Reported			As Adjusted			Change
	(in thousands - except per share data)
Condensed Consolidated Statements of Operations and Comprehensive Income:
Raw material, freight and other costs	$	2,631,548		$	2,814,341		$	182,793		$	1,097,559		$	1,089,612		$	(7,947	)
Operating income (loss)		191,788			8,995			(182,793	)		(12,427	)		(4,480	)		7,947
Income (loss) before income taxes		172,690			(10,103	)		(182,793	)		(18,475	)		(10,528	)		7,947
Provision (benefit) for income taxes		64,517			(1,397	)		(65,914	)		(3,348	)		(1,744	)		1,604
Net income (loss)	$	108,173		$	(8,706	)	$	(116,879	)	$	(15,127	)	$	(8,784	)	$	6,343
Comprehensive income (loss)	$	108,052		$	(8,827	)	$	(116,879	)	$	(15,123	)	$	(8,780	)	$	6,343
Basic earnings (loss) per share	$	1.04		$	(0.08	)	$	(1.12	)	$	(0.15	)	$	(0.08	)	$	0.07
Diluted earnings (loss) per share	$	1.03		$	(0.08	)	$	(1.11	)	$	(0.15	)	$	(0.08	)	$	0.07
Condensed Consolidated Statements of Cash Flows:										`
Net income (loss)	$	108,173		$	(8,706	)	$	(116,879	)
Adjustments to reconcile net income    to net cash from operating activities:
Deferred income tax provision		12,097			14,335			2,238
Changes in components of working    capital from operations		(61,778	)		52,863			114,641
Net cash provided by operating    activities	$	147,066		$	147,066		$	-

3.      Other Receivables

	September 30,		December 31,
	2010		2009
	(in thousands)
Investment fund receivable, net of allowance	$	-	$	2,143
Realized futures trading receivable		252		2,341
Interest rate swaps net interest receivable		668		310
Other		4,804		3,048
	$	5,724	$	7,842

The Company had a $32.7 million investment in a money market fund called the Reserve Primary Fund (“Fund”) that was deemed illiquid in September 2008.  The Fund is currently overseen by the SEC, which is determining the amount and timing of liquidation.  Prior to the freeze on the Fund’s assets, the Company requested its funds in their entirety and reclassed the $32.7 million investment out of “Cash and cash equivalents” to “Other receivables” on the Condensed Consolidated Balance Sheet.  At December 31, 2009, it was estimated that approximately 1.5% of the Company’s original investment was at-risk for recoverability, primarily due to the bankruptcy of Lehman Brothers, as the Fund had an investment in Lehman Brothers Holdings, Inc. commercial paper.   Therefore, an allowance of $499,000 was recorded as of December 31, 2009.  In addition, the Company received partial distributions through December 31, 2009 from the Fund totaling $30.1 million, resulting in a net investment fund receivable of $2.1 million.  During the nine and three months ended September 30, 2010, the Company received additional distributions totaling $2.3 million and $132,000, thus increasing total distributions to $32.4 million.  As the total distributions exceeded the net investment, during the nine and three months ended September 30, 2010, the Company reduced the previously recorded loss allowance on this investment by $184,000 and $132,000, which increased “Interest and Investment Income” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  While still awaiting final notice regarding proceeds from the Fund, the Company does not anticipate further distributions; thus, the Company has no remaining n et investment fund receivable as of September 30, 2010.  If there are any additional distributions received by the Company, they will be recorded in subsequent periods as income.

4.      Inventories

During the fourth quarter of 2009, the Company changed its inventory valuation method to the LIFO method from the FIFO method as previously disclosed.  See Note 2 “Change in Accounting Principle – Inventory” for additional information. Inventories of crude oil, unfinished products and all finished products are now 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, bl endstocks 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 September 30, 2010 and Decemb er 31, 2009 were as follows:

	September 30,			December 31,
	2010			2009
	(in thousands)
Crude oil	$	331,192		$	343,154
Unfinished products		140,206			101,436
Finished products		123,169			94,239
LIFO reserve - adjustment to inventories		(242,451	)		(272,634	)
		352,116			266,195
Process chemicals		857			1,162
Repairs and maintenance supplies and other		26,687			26,119
	$	379,660		$	293,476

5.      Other Current Assets

	September 30,		December 31,
	2010		2009
	(in thousands)
Margin deposits	$	6,918	$	10,898
Derivative assets		1,270		124
Prepaid insurance		746		1,705
Other		3,332		1,780
	$	12,266	$	14,507

6.      Property, Plant and Equipment

	September 30,			December 31,
	2010			2009
	(in thousands)
Refineries, pipelines and terminal equipment	$	1,439,400		$	1,389,351
Buildings		44,036			41,616
Land and land improvements		15,575			15,320
Furniture, fixtures and other equipment		17,675			17,284
Property, plant and equipment, at cost		1,516,686			1,463,571
Accumulated depreciation		(502,136	)		(442,162	)
Property, plant and equipment, net	$	1,014,550		$	1,021,409

7.      Accrued Liabilities and Other

	September 30,		December 31,
	2010		2009
	(in thousands)
Accrued compensation	$	14,911	$	26,093
Accrued environmental costs		2,521		7,599
Accrued dividends		344		6,979
Accrued property taxes		9,495		5,573
Accrued interest		5,760		7,638
Accrued income taxes		-		293
Derivative liabilities		6,706		6,551
Other		4,306		4,073
	$	44,043	$	64,799

8.      Long-term Debt

	September 30,			December 31,
	2010			2009
	(in thousands)
6.625% Senior Notes (Due October 1, 2011)	$	150,000		$	150,000
8.5% Senior Notes (Due September 15, 2016)		200,000			200,000
Less discount		(2,301	)		(2,515	)
8.5% Senior Notes, net		197,699			197,485
	$	347,699		$	347,485

9.      Other Long-term Liabilities

	September 30,		December 31,
	2010		2009
	(in thousands)
Environmental liabilities	$	5,326	$	12,237
Asset retirement obligations		4,693		4,474
Other		3,651		3,849
	$	13,670	$	20,560

10.      Income Taxes

The Company is currently under a U.S. Federal income tax examination for 2008.  Field work for U.S. Federal income tax examinations on the Company for 2007, 2006 and 2005 has been completed but certain issues have not yet been resolved. The Company was unsuccessful during the IRS appeals process for 2006 and 2005 proposed adjustments.  As such, the Company has received a Notice of Deficiency from the Internal Revenue Service for approximately $13.9 million of additional 2005 taxes and approximately $4.2 million of additional 2006 taxes both related to the deductibility for income tax purposes of certain stock-based compensation for executives.  The Company filed a petition for a redetermination of this deficiency with the U.S. Tax Court on September 22, 2010.  The Company has also received a notice of proposed adjustment from the Internal Revenue Service regarding approximately $711,000 of additional 2007 taxes also related to the deductibility for income tax purposes of certain stock-based compensation for executives.  The Company has submitted a protest of this 2007 amount and is in the appeals process.  The Company had recorded income tax contingencies in prior years for these items which are included in “Contingent income tax liabilities” as of September 30, 2010 and December 31, 2009, on the Condensed Consolidated Balance Sheets in the event it is unsuccessful in its tax court petition and/or appeal.  The Company continues to accrue interest on any unpaid amounts related to these deficiencies and proposed adjustments.

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.”  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:

	Nine months Ended September 30,						Three months Ended September 30,
	2010			2009			2010		2009
	(in thousands)
Balance beginning of period	$	23,854		$	24,278		$	23,788	$	24,278
Additions based on tax positions related to the current year		-			-			-		-
Additions for tax positions of prior years		81			-			-		-
Reductions for tax positions of prior years		-			(424	)		-		-
Settlements		-			-			-		-
Reductions due to lapse of applicable statutes of limitations		(66	)		-			-		-
Balance end of period	$	23,869		$	23,854		$	23,788	$	24,278

The total contingent income tax liabilities and accrued interest of $30.6 million and $29.3 million at September 30, 2010 and December 31, 2009, 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 $1.2 million and $1.3 million during the nine months ended September 30, 2010 and 2009, and $438,000 and $430,000 during the three months ended September 30, 2010 and 2009, respectively.

In October 2010, subsequent to the balance sheet date, the Company received a federal income tax refund of $73.5 million, reflected in “Income taxes receivable” on the Condensed Consolidated Balance Sheet at September 30, 2010.

11.      Treasury Stock

The Company accounts for its treasury stock under the cost method on a FIFO basis.  Through December 31, 2009, the Company’s Board of Directors had approved a total of $400.0 million for share repurchases, of which $299.8 million had been utilized (none in 2010), leaving remaining authorization of $100.2 million for future repurchases of shares; however, the Company currently is unable to repurchase shares because of the inability to satisfy the incurrence of additional indebtedness test in the covenants of the Senior Notes.  A rollforward of treasury stock for the nine months ended September 30, 2010 is as follows:

	Number of shares			Amount
	(in thousands except share amounts)
Balance as of December 31, 2009		27,165,400		$	395,242
Shares received to fund withholding taxes		265,541			3,582
Shares issued for stock grants and restricted stock grants, net of forfeits		(424,024	)		(779	)
Shares issued for conversion of stock unit awards		(876,625	)		(1,605	)
Balance as of September 30, 2010		26,130,292		$	396,440

 12.    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 nine and three months ended September 30, 2010 and 2009 were as follows:

	Nine Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Restricted shares and units	$	8,653	$	12,637	$	2,359	$	2,829
Stock options		-		304		-		-
Contingently issuable stock unit awards		3,637		2,252		1,318		1,611
Total stock-based compensation expense	$	12,290	$	15,193	$	3,677	$	4,440
Income tax benefit recognized in the income statement	$	4,670	$	5,774	$	1,397	$	1,688

Omnibus Incentive Compensation Plan.  The Company’s Omnibus Incentive Compensation Plan (the “Plan”) is a broad-based incentive plan that provides for granting stock options, stock appreciation rights (“SAR”), restricted stock awards, performance awards, stock units, bonus shares, dividend equivalent rights, other stock-based awards and substitute awards (“Awards”) to employees, consultants and non-employee directors of the Company.  At the annual meeting held on April 28, 2010, the shareholders of the Company approved the First Amendment to the Frontier Oil Corporation Omnibus Incentive Compensation Plan (the “Amendment”).  The Amendment increased the maximum aggregate number of shares that may be a llowed with respect to Awards granted under the plan by 7,100,000 shares.  The number of shares available for Awards under the new 7,100,000 share pool will be reduced by 1.6 times the shares for each stock award granted, other than an option or SAR under the Plan, and will be reduced by 1.0 times the number of options or SARs granted.  As of September 30, 2010, there were 7,331,418 shares available to be awarded under the Plan assuming maximum payout is achieved on the contingently issuable awards made in 2008, 2009 and 2010 (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 nine and three months ended September 30, 2010, treasury shares were re - -issued for stock and restricted stock awards.  The Company does not plan to repurchase additional treasury shares in 2010 strictly for issuing share Awards; however, treasury shares that are repurchased or are currently in treasury may be issued as share Awards in 2010.  The fair value of restricted stock awards is determined using the closing stock price of the Company on the date of grant.  As of September 30, 2010, there was $21.4 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 1.95 years.

Stock Options.  Stock option changes during the nine months ended September 30, 2010 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		-		-
Expired or forfeited		-		-
Outstanding at end of period		434,793	$	29.3850	$	-
Vested		434,793	$	29.3850	$	-
Exercisable at end of period		434,793	$	29.3850	$	-

There were no stock options exercised during the nine months ended September 30, 2010.  All outstanding stock options were vested and exercisable at September 30, 2010 with weighted average remaining contractual lives of 0.58 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 nine months ended September 30, 2010:

	Shares/Units			Weighted- Average Grant- Date Market Value
Nonvested at beginning of period		842,067		$	20.4173
Conversion of stock unit awards		625,582			12.7400
Granted		467,920			12.7356
Vested		(614,348	)		19.5130
Forfeited		(5,376	)		21.7598
Nonvested at end of period		1,315,845			14.4525

The total grant date fair value of restricted shares and restricted stock units which vested during the nine months ended September 30, 2010 was $12.0 million. The total intrinsic value of restricted shares and restricted stock units vested during the nine months ended September 30, 2010 was $8.4 million.  The Company recognized $3.2 million of income tax benefit related to these vestings, and reduced the Company’s available pool of excess income tax benefits by $1.4 million.  The total grant date fair value of restricted shares and restricted stock units which vested during the nine months ended September 30, 2009 was $16.4 million.  The total intrinsic value of restricted shares and restricted stock units that vested during the nine months ended September 30, 2009 was $8.1 million, and the Company re alized $3.1 million of income tax benefit related to these vestings, which reduced the Company’s available pool of excess income tax benefits by $3.2 million.

A member of the Company’s Board of Directors was awarded 9,630 unrestricted shares of common stock, valued at approximately $135,000, on April 27, 2010 related to his retirement.  In March 2010, following certification by the Compensation Committee of the Company’s Board of Directors that the specified performance criteria of the Company’s net income goal and return of capital employed versus that of a defined peer group had been achieved for the year ended December 31, 2009, the Company issued 625,582 shares of restricted stock in connection with the February 2009 grant of contingently issuable stock unit awards.  The following tables summarize the vesting schedules of the 625,582 stock unit awards converted to restricted stock and 467,920 shares of restricted stock shares and units granted, net of forfeitures, during the nine months ended September 30, 2010.

			Vesting Dates and Share Amounts
Conversion Date	Converted stock  unit awards		March 9,  2010(1)		June 21, 2010(1)		June 30, 2010		June 30, 2011		June 30, 2012
March 9, 2010		625,582		51,872		10,010		187,888		187,924		187,888

			Vesting Dates and Share Amounts
Grant Date	Shares/Units  Granted (Net of  Forfeits)		April 27, 2010(1)		December 31, 2010		March 13, 2011		March 13, 2012		March 13, 2013
January 26, 2010		57,780		9,630		48,150
February 23, 2010		409,640						102,410		102,410		204,820
September 7, 2010		500						125		125		250
Total		467,920		9,630		48,150		102,535		102,535		205,070
(1) Accelerated vesting due to termination or retirement of employees or members of the Company's Board of Directors.

Contingently Issuable Awards.  During the nine months ended September 30, 2010, the Company granted 307,230 contingently issuable stock unit awards, net of forfeitures, to be earned if certain return of capital employed versus that of a defined peer group goals are met for 2010.  Depending on achievement of the performance goal, awards earned could be between 0% and 125% of the base number of performance stock units.  If any portion of the performance goal is achieved for 2010 and certified by the Compensation Committee, these stock unit awards (or a portion thereof) will be converted into restricted stock during the first quarter of 2011.  One-third of these restricted shares will vest on June 30, 2011, one-third on June 30, 2012 and the fina l one-third on June 30, 2013.  As of September 30, 2010, the Company assumed for purposes of stock-based compensation expense for these awards granted in 2010 that the maximum (125%) level award (384,044 stock units, net of forfeitures) would be earned for the return of capital employed versus that of a defined peer group.  The stock unit awards were valued at the 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.

The Company also granted 307,230 stock unit awards, net of forfeitures, contingent upon certain share price performance versus the Company’s peers being met over a three-year period ending on December 31, 2012.  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.  For stock unit awards subject to such market-based vesting conditions, the grant date fair value of the award is estimated using a Monte Carlo valuation model.  The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.  Expected volatility was calculated using a weighted average of historical daily volatilities and implied volatility, and represents the extent to which the Company’s stock price performance, relative to the average stock price performance of the peer group, is expected to fluctuate during each of the three calendar periods of the award’s anticipated term ending December 31, 2012.  The risk-free rate is based on a U.S. Treasury rate consistent with the three-year vesting period.  The total grant date fair value of the market-based stock units as determined by the Monte Carlo valuation model is $3.5 million, net of forfeitures and will be recognized ratably over the three-year vesting period.  The key assumptions used in valuing these market-based restricted shares are as follows:

	2010
Number of simulations		100,000
Expected volatility		65.00	%
Risk-free rate		1.33	%

In February 2010, following certification by the Compensation Committee of the Company’s Board of Directors that the specified share price performance criteria in connection with the 2007 grant of contingently issuable stock unit awards to be met over a three-year period ended December 31, 2009 had been achieved, the Company issued 206,348 shares of stock to certain employees of the Company.  The total grant date fair value of these performance awards was $4.0 million and the total intrinsic value of these shares at issuance was $2.6 million.  The Company recognized $1.0 million of income tax benefit related to these vestings, which reduced the Company’s available pool of excess income tax benefits by $540,000.

In May 2010, the Compensation Committee of the Company’s Board of Directors approved that certain employees met the retirement criteria of the 2008 grant of contingently issuable stock unit awards to be originally met over a three-year period ending December 31, 2010.  The Company issued 44,695 shares of stock following certification by the Compensation Committee of the Company’s Board of Directors that the specified share price performance criteria through the employee’s retirement dates had been achieved.  The total grant date fair value of these performance awards was $1.4 million and the total intrinsic value of these shares at issuance was $690,000.  The Company recognized $263,000 of income tax benefit related to these vestings, which reduced the Company’s available pool of exce ss income tax benefits by $252,000.

As of September 30, 2010, the Company also had outstanding (net of forfeitures) 134,827 and 233,787 contingently issuable stock unit awards issued in 2008 and 2009, respectively, to be earned should certain share price criteria be met over a three-year period ending December 31, 2010 and 2011, respectively.  Depending on achievement of the performance goals, awards earned could be between 0% and 125% of the base number of performance stock units.  If any of the performance goals are achieved and certified by the Compensation Committee, these stock unit awards (or a portion thereof) will be converted intostock.

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.

13.      Employee Benefit Plans

Defined Benefit Plans

In April 2008, the Company’s Board of Directors approved the termination of the defined benefit cash balance pension plan.  In July 2009, the Company received, from the Internal Revenue Service, a letter stating the termination of the pension plan did not affect its qualification.  The Company terminated the plan in December 2009.  Plan participants received 100% of their account balance, including interest, in the fourth quarter of 2009.

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 September 30, 2010 and December 31, 2009.  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 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):

	Nine Months Ended September 30,					Three Months Ended September 30,
Pension Benefits	2010		2009			2010		2009
	(in thousands)
Components of net periodic benefit cost and other amounts recognized in other comprehensive income (loss):
Service cost	$	-	$	-		$	-	$	-
Interest cost		-		196			-		65
Expected return on plan assets		-		(134	)		-		(45	)
Amortization of prior service cost		-		426			-		213
Amortized net actuarial loss		-		-			-		-
Net periodic benefit cost		-		488			-		233
Changes in assets and benefit obligations recognized in other comprehensive income (loss):
Net loss		-		-			-		-
Amortization of prior service cost		-		(426	)		-		(213	)
Amortization of gain		-		-			-		-
Total recognized in other comprehensive income		-		(426	)		-		(213	)
Total recognized in net periodic benefit cost and other    comprehensive income (loss)	$	-	$	62		$	-	$	20

	Nine Months Ended September 30,						Three Months Ended September 30,
Post-retirement Healthcare and Other Benefits	2010			2009			2010			2009
	(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	$	570		$	535		$	190		$	179
Interest cost		1,553			1,417			518			472
Expected return on plan assets		-			-			-			-
Amortization of prior service cost		(1,407	)		(1,407	)		(469	)		(469	)
Amortized net actuarial loss		784			784			261			261
Net periodic benefit cost		1,500			1,329			500			443
Changes in assets and benefit obligations recognized in other comprehensive income (loss):
Net loss		20			-			6			-
Amortization of prior service cost		1,407			1,407			469			469
Amortization of loss		(784	)		(784	)		(261	)		(261	)
Total recognized in other comprehensive income		643			623			214			208
Total recognized in net periodic benefit cost and other    comprehensive income (loss)	$	2,143		$	1,952		$	714		$	651

14.      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 table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

Description	Level 1		Level 2		Level 3		Total
Derivative assets	$	-	$	1,270	$	-	$	1,270
Derivative liabilities		4,167		2,539		-		6,706

As of September 30, 2010, the Company’s derivative contracts giving rise to the liabilities measured under Level 1 are NYMEX crude oil contracts and thus are valued using quoted market prices at the end of each period.  The majority of the derivative contracts included in Level 2 valuations are interest rate swap contracts.  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, it was deemed as having Level 2 inputs.  The remaining derivative contracts giving rise to the assets under Level 2 are foreign currency forward contracts, valued using mo nth 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 also have Level 2 inputs.  The derivative liabilities included in Level 2 valuations are valued using pricing models based on NYMEX crude oil contracts.  The Company had no derivative contracts under Level 3 at September 30, 2010.  The Company’s crude call options during the quarter ended September 30, 2009 that related to crude oil purchased at the lease were measured under Level 3, meaning that the options were valued using internal contract pricing.  The following provides a reconciliation of the beginning and ending balances of the Company’s Level 3 derivative asset crude call options for the periods ended September 30, 2010 and 2009:

	Nine Months Ended September 30,					Three Months Ended September 30,
	2010		2009			2010		2009
	(in thousands)
Beginning derivative asset balance	$	-	$	-		$	-	$	85
Net increase in derivative assets		-		231			-		(18	)
Net settlements		-		(231	)		-		(67	)
Transfers in (out) of Level 3		-		-			-		-
Ending derivative asset balance	$	-	$	-		$	-	$	-

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 September 30, 2010 and December 31, 2009, the carrying amounts of the Company’s 6.625% Senior Notes were $150.0 million, and the estimated fair values were $150.6 million and $150.8 million, respectively.  At September 30, 2010 and December 31, 2009, the carrying amounts of the Company’s 8.5% Senior Notes were $197.7 million ($200.0 million less the unamortized discount of $2.3 million) and $197.5 million ($200.0 million less the unamortized discount of $2.5 million), and the estimated fair values were $208.0 million and $207.0 million, respectively. 
60;For cash and cash equivalents, the carrying amounts at September 30, 2010 and December 31, 2009 of $413.7 million and $425.3 million, respectively, are reasonable estimates of fair value.

15.      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, to fix margins on certain future production or to hedge interest rate risk.  The 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 accounted for as cash flow or fair value hedges and thus are accounted for under mark-to-market accounting with gains and losses recorded directly to earnings.  The Company has derivative contracts which it holds directly and also derivative contracts held indirectly in connection with its crude oil purchase and sale contract, held on Frontier’s behalf by Utexam Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland.  See Note 18, “New Crude Oil Purchase and Sale Contract”, for information on the replacement for the Utexam crude oil purchase and sale contract which occurred subsequent to quarter-end.  For additional fair value disclosures relating to the Company’s derivative contracts, see Note 14, “Fair Value Measurement.”  As of September 30, 2010, the Company had the following outstanding commodity derivative contracts:

Commodity	Number of barrels
	(in thousands)
Crude oil contracts to hedge crude purchases in-transit		717
Crude oil contracts to hedge excess intermediate, finished product and crude oil inventory		1,095

As of September 30, 2010, 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 5.599% and 5.594%, respectively, as of September 30, 2010.  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 $1.0 million and $323,000 for th e nine and three months ended September 30, 2010.  The Company received interest totaling $682,000 from the counterparty in April 2010 and has a receivable for accrued interest of $668,000, which is included in “Other Receivables” on the Condensed Consolidated Balance Sheet as of September 30, 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
	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
		Fair Value			Fair Value			Fair Value			Fair Value
	(in thousands)
Derivatives not designated    as hedging instruments
Commodity contracts		$	-		$	-		$	6,706		$	6,551
Foreign exchange contracts			7			-			-			-
Interest rate swap contracts			1,263			2			-			-
Other contracts			-			122			-			-
Total derivatives		$	1,270		$	124		$	6,706		$	6,551

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
		Nine Months Ended September 30,						Three Months Ended September 30,
		2010			2009			2010			2009
Derivatives not designated    as hedging instruments	Location in Statement    of Operations	(in thousands)
Commodity contracts	Other Revenues	$	21,888		$	(3,246	)	$	(3,417	)	$	4,227
Foreign exchange contracts	Other Revenues		(9	)		799			84			-
Other contracts	Other Revenues		(34	)		(40	)		-			(289	)
Interest rate swap contracts	Interest expense and other financing costs		1,261			-			(228	)		-

16.      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 two to five years through the redemption of currently owned or internally generated gasoline sulfur cre dits.  For long-term compliance, the Company expects to spend approximately $40.0 million ($17.7 million incurred as of September 30, 2010) 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 estimated as of September 30, 2010 for the El Dorado Refinery to comply with the final gasoline sulfur standard are approximately $95.0 million, including capitalized interest, and are expected to be completed in the fourth quarter of 2010 ($87.5 million incurred as of September 30, 201 0).  The estimated $95.0 million of expenditures primarily relates to the El Dorado Refinery’s gasoil hydrotreater revamp project.  The gasoil hydrotreater revamp project will address 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.  During the nine months ended September 30, 2009, Frontier sold sulfur credits for total proceeds of $1.9 million (none in the comparable 2010 period), which are recorded in “Other revenues” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

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 in anticipation of the finalization of the agreement, capital expenditures totaling approximately $45.0 million ($662,000 incurred as of September 30, 2010) at the Cheyenne Refinery and $6.0 million ($1.5 million incurred as of September 30, 2010) 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 complianc e 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.  If a stipulated penalty is requested, the Company will separately report that matter and the amount of the proposed penalty, if applicable.

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, will be exempt until January 1, 2011 from these requirements at which time it will begin 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.  During the nine months ended September 30, 2010 and 2009, the Company sold RIN credits for $128,000 and $3.2 million, respectively, which were recorded in “Other revenues” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  While not yet enacted or promulgated, other pending legislation or 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 U.S. Congress and the U.S. 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 climate change legislation is enacted or regulations 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 estimated, the Company anticipates that potentially material capital expenditures may be necessary to achieve compliance with the new regulation at its Cheyenne Refinery as discussed above.  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 owns terminals and pipelines in which various groundwater remediation and monitoring activities are underway.  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 September 30, 2010 and December 31, 2009, the Company had a $4.6 million accrual included on the Condensed Consolidated Balance Sheets related to the remediation program.  The accrual at September 30, 2010 reflects the estimated pr esent value of a $775,000 cost in 2010 and $575,000 in annual costs for 2011 through 2019, assuming a 3% inflation rate, ten more years of the ongoing groundwater remediation program, and discounted at a rate of 6.2%.  The Company estimates a total cost of $7.5 million for the cleanup of a waste water treatment pond located on land adjacent to the Cheyenne Refinery which the Company had historically leased from the landowner.  As of September 30, 2010 and December 31, 2009, the Company had remaining accruals of $300,000 and $5.7 million, respectively, for this cleanup.  Cleanup of the waste water pond pursuant to the aforementioned agreement with the State of Wyoming has been initiated and is anticipated to be completed in 2010 with various on-going monitoring for approximately two years.  Depending upon information collected during the cleanup, or by a subsequent administrative order or permit, additional remedial action and costs could be required.  Pursuan t to this agreement, in the fourth quarter of 2009, the Company completed an $11.3 million capital project for the installation of a groundwater boundary control system and associated groundwater recovery wells.

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 and proposing a penalty of $6.8 million in addition to requirement to clean and close the impoundment at issue.  Although not admitting violation, the Company has entered into a negotiated settlement agreement with the EPA. Based on this agreement, the total estimated settlement expense is $2.6 million.  This is comprised of a $900,000 penalty (paid in June 2010) and approximately $870,000 for pond closure expenses related to injunctive relief with the remaining costs being estimated legal and other costs.  The $6.8 million accrual, originally recorded in the third quart er of 2009, was adjusted downward in the second quarter of 2010 on the Condensed Consolidated Balance Sheets to reflect the new estimate of $2.6 million, and as of September 30, 2010, the Company’s remaining accrual was $874,000.  Expected capital costs for injunctive relief related to the removal and repair of the liner will be incurred after June 1, 2011 and are currently estimated at approximately $800,000.

The Company completed in 2007 the negotiation of a settlement of a Notice of Violation (“NOV”) from the Wyoming Department of Environmental Quality 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 $3.2 million and is estimated to be completed in late 2010.  In addition, the Company accrued a total of $2.2 million for additional work related to the corrective measures with remaining accruals of $618,000 and $1.2 million at September 30, 2010 and December 31, 2009, respectively.

The Company has received a draft wastewater discharge permit from the Wyoming Department of Environmental Quality (“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.  Costs for compliance with the new limits, which are currently drafted to become effective on January 1, 2013, are currently not estimatable.

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 barrie rs 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.

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.  In response to such studies, the U.S. Congress considered but has so far rejected legislation to reduce emissions of greenhouse gases.  In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases and there are several regional initiatives.  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 th e 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.  In April 2010, the EPA issued proposed ru les to require reporting of emissions data from several other industrial sectors.  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.  Legislation to prohibit or delay EPA regulation of greenhouse gases may be considered by the Senate later this year.  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 t hat it produces.

17.      Litigation

The Company is involved in various lawsuits and regulatory actions which are incidental to its business.  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.

18.      New Crude Oil Purchase and Sale Contract

On November 1, 2010, the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (collectively, “BNP”).  The maximum value of crude oil to be purchased under this Contract is $300.0 million.  Under this Contract, BNP purchases, transports and subsequently sells crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed.  Under this agreement, BNP is the owner of record of the crude oil as it is transported from the point of injection, typically Hardisty, Alberta, Canada, to the point of ultimate sale to FORC.  0;The Company has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract.  The Company accounts for the transactions under this Contract as a financing arrangement, whereby the inventory and the associated liability are recorded in the Company’s financial statements when the crude oil is injected into the pipeline in Canada.

This Contract replaces the Company’s crude oil purchase and sale contract with Utexam, a wholly-owned subsidiary of BNP Paribas Ireland, (“Utexam Contract”) which was terminated effective November 1, 2010.  However, in accordance with the Utexam Contract, the rights and obligations of both Utexam and the Company arising from transactions entered into prior to the termination date will be completed.   The Company anticipates any such transactions will be completed no later than the end of the first quarter of 2011.

19.      Consolidating Financial Statements

Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of the Company’s 6.625% Senior Notes and 8.5% Senior Notes.   Presented on the following pages are the Company’s condensed consolidating balance sheets, statements of income, 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 income, 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 wholly-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 Income
For the Nine Months Ended September 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	4,215,546		$	-		$	-		$	4,215,546
Other		(11	)		21,906			55			-			21,950
Total revenues		(11	)		4,237,452			55			-			4,237,496
Costs and expenses:
Raw material, freight and other costs		-			3,844,828			-			-			3,844,828
Refinery operating expenses, excluding     depreciation		-			221,901			-			-			221,901
Selling and general expenses, excluding     depreciation		13,719			21,671			-			-			35,390
Depreciation, amortization and     accretion		49			60,416			-			691			61,156
Gain on sales of assets		(1	)		-			-			-			(1	)
Total costs and expenses		13,767			4,148,816			-			691			4,163,274
Operating (loss) income		(13,778	)		88,636			55			(691	)		74,222
Interest expense and other financing    costs		19,853			5,887			-			(1,434	)		24,306
Interest and investment income		(1,487	)		(304	)		-			-			(1,791	)
Equity in earnings of subsidiaries		(83,939	)		-			-			83,939			-
Income before income taxes		51,795			83,053			55			(83,196	)		51,707
Provision for income taxes		17,637			28,999			71			(29,158	)		17,549
Net income (loss)	$	34,158		$	54,054		$	(16	)	$	(54,038	)	$	34,158

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Nine Months Ended September 30, 2009
As Adjusted (Note 2)
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	3,147,210		$	-	$	-		$	3,147,210
Other		(7	)		1,435			36		-			1,464
Total revenues		(7	)		3,148,645			36		-			3,148,674
Costs and expenses:
Raw material, freight and other costs		-			2,814,341			-		-			2,814,341
Refinery operating expenses, excluding     depreciation		-			232,175			-		-			232,175
Selling and general expenses, excluding     depreciation		16,196			22,741			-		-			38,937
Depreciation, amortization and     accretion		51			53,742			-		433			54,226
Total costs and expenses		16,247			3,122,999			-		433			3,139,679
Operating (loss) income		(16,254	)		25,646			36		(433	)		8,995
Interest expense and other financing    costs		22,175			2,968			-		(4,097	)		21,046
Interest and investment income		(1,569	)		(379	)		-		-			(1,948	)
Equity in earnings of subsidiaries		(26,437	)		-			-		26,437			-
(Loss) income before income taxes		(10,423	)		23,057			36		(22,773	)		(10,103	)
(Benefit) provision for income taxes		(1,717	)		8,500			33		(8,213	)		(1,397	)
Net (loss) income	$	(8,706	)	$	14,557		$	3	$	(14,560	)	$	(8,706	)

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,419,997		$	-		$	-		$	1,419,997
Other		-			(3,537	)		12			-			(3,525	)
Total revenues		-			1,416,460			12			-			1,416,472
Costs and expenses:
Raw material, freight and other costs		-			1,283,773			-			-			1,283,773
Refinery operating expenses, excluding     depreciation		-			82,878			-			-			82,878
Selling and general expenses, excluding     depreciation		4,932			8,262			-			-			13,194
Depreciation, amortization and     accretion		14			20,066			-			229			20,309
Total costs and expenses		4,946			1,394,979			-			229			1,400,154
Operating (loss) income		(4,946	)		21,481			12			(229	)		16,318
Interest expense and other financing    costs		6,877			2,652			-			(504	)		9,025
Interest and investment income		(550	)		(146	)		-			-			(696	)
Equity in earnings of subsidiaries		(19,261	)		-			-			19,261			-
Income before income taxes		7,988			18,975			12			(18,986	)		7,989
(Benefit) provision for income taxes		(320	)		3,792			30			(3,821	)		(319	)
Net (loss) income	$	8,308		$	15,183		$	(18	)	$	(15,165	)	$	8,308

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2009
As Adjusted (Note 2)
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,196,899		$	-		$	-		$	1,196,899
Other		-			3,674			9			-			3,683
Total revenues		-			1,200,573			9			-			1,200,582
Costs and expenses:
Raw material, freight and other costs		-			1,089,612			-			-			1,089,612
Refinery operating expenses, excluding     depreciation		-			83,701			-			-			83,701
Selling and general expenses, excluding     depreciation		5,230			8,420			-			-			13,650
Depreciation, amortization and     accretion		17			17,934			-			148			18,099
Total costs and expenses		5,247			1,199,667			-			148			1,205,062
Operating (loss) income		(5,247	)		906			9			(148	)		(4,480	)
Interest expense and other financing    costs		7,410			1,097			-			(1,798	)		6,709
Interest and investment income		(594	)		(67	)		-			-			(661	)
Equity in earnings of subsidiaries		(1,366	)		-			-			1,366			-
(Loss) income before income taxes		(10,697	)		(124	)		9			284			(10,528	)
(Benefit) provision for income taxes		(1,913	)		(102	)		23			248			(1,744	)
Net loss	$	(8,784	)	$	(22	)	$	(14	)	$	36		$	(8,784	)

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of September 30, 2010
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	214,265	$	199,386	$	-	$	-		$	413,651
Trade and other receivables, net		110,294		175,651		-		-			285,945
Inventory of crude oil, products and    other		-		379,660		-		-			379,660
Deferred income tax assets - current		12,379		10,642		2		(10,644	)		12,379
Other current assets		3,756		8,510		-		-			12,266
Total current assets		340,694		773,849		2		(10,644	)		1,103,901
Property, plant and equipment, net		342		991,010		-		23,198			1,014,550
Deferred turnaround and catalyst costs,    net		-		54,694		-		-			54,694
Deferred financing costs, net		2,270		1,324		-		-			3,594
Intangible assets, net		-		1,124		-		-			1,124
Deferred income tax assets - noncurrent		10,717		6,074		7		(6,081	)		10,717
Other assets		3,543		211		-		-			3,754
Receivable from affiliated companies (1)		-		22,535		567		(23,102	)		-
Investment in subsidiaries		1,239,617		-		-		(1,239,617	)		-
Total assets	$	1,597,183	$	1,850,821	$	576	$	(1,256,246	)	$	2,192,334
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	874	$	512,235	$	15	$	-		$	513,124
Accrued liabilities and other		9,236		34,807		-		-			44,043
Total current liabilities		10,110		547,042		15		-			557,167
Long-term debt		347,699		-		-		-			347,699
Contingent income tax liabilities		28,484		2,074		-		-			30,558
Long-term capital lease obligations		-		3,056		-		-			3,056
Other long-term liabilities		3,456		45,043		-		-			48,499
Deferred income tax liabilities		221,134		214,592		21		(214,613	)		221,134
Payable to affiliated companies		2,080		-		288		(2,368	)		-
Shareholders' equity		984,220		1,039,014		252		(1,039,265	)		984,221
Total liabilities and shareholders'    equity	$	1,597,183	$	1,850,821	$	576	$	(1,256,246	)	$	2,192,334
(1) FHI receivable to affiliated companies balance primarily relates to income taxes receivable from parent under a tax sharing agreement.

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2009
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	211,775	$	213,505	$	-	$	-		$	425,280
Trade and other receivables, net		174,843		102,887		-		-			277,730
Inventory of crude oil, products and    other		-		293,476		-		-			293,476
Deferred income tax assets - current		26,373		26,442		-		(26,442	)		26,373
Other current assets		926		13,581		-		-			14,507
Total current assets		413,917		649,891		-		(26,442	)		1,037,366
Property, plant and equipment, net		374		998,580		-		22,455			1,021,409
Deferred turnaround and catalyst costs,    net		-		68,491		-		-			68,491
Deferred financing costs, net		2,857		1,854		-		-			4,711
Intangible assets, net		-		1,216		-		-			1,216
Deferred income tax assets - noncurrent		10,767		7,702				(7,702	)		10,767
Other assets		3,665		270		-		-			3,935
Receivable from affiliated companies(1)		-		61,165		516		(61,681	)		-
Investment in subsidiaries		1,144,040		-		-		(1,144,040	)		-
Total assets	$	1,575,620	$	1,789,169	$	516	$	(1,217,410	)	$	2,147,895
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	906	$	473,456	$	15	$	-		$	474,377
Accrued liabilities and other		20,916		43,883		-		-			64,799
Total current liabilities		21,822		517,339		15		-			539,176
Long-term debt		347,485		-		-		-			347,485
Contingent income tax liabilities		27,267		2,081		-		-			29,348
Long-term capital lease obligations		-		3,394		-		-			3,394
Other long-term liabilities		3,578		50,120		-		-			53,698
Deferred income tax liabilities		230,818		224,680		-		(224,680	)		230,818
Payable to affiliated companies		674		-		234		(908	)		-
Shareholders' equity		943,976		991,555		267		(991,822	)		943,976
Total liabilities and shareholders'    equity	$	1,575,620	$	1,789,169	$	516	$	(1,217,410	)	$	2,147,895
(1) FHI receivable from affiliated companies balance relates to income taxes receivable from parent under a tax sharing agreement.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	34,158		$	54,054		$	(16	)	$	(54,038	)	$	34,158
Adjustments to reconcile net income    to net cash from operating activities:
Equity in earnings of subsidiaries		(83,939	)		-			-			83,939			-
Depreciation, amortization and    accretion, including amortization    of deferred turnaround costs		49			74,525			-			691			75,265
Deferred income tax provision		4,346			-			-			-			4,346
Stock-based compensation expense		12,290			-			-			-			12,290
Excess income tax benefits of    stock-based compensation		(152	)		-			-			-			(152	)
Intercompany income taxes		(18,482	)		47,574			66			(29,158	)		-
Intercompany dividends		6,200			-			-			(6,200	)		-
Other intercompany transactions		1,405			(1,355	)		(50	)		-			-
Amortization of debt issuance costs		587			529			-			-			1,116
Senior notes discount amortization		214			-			-			-			214
Allowance for investment loss and    bad debts		(15	)		(169	)		-			-			(184	)
Gain on sales of assets		(1	)		-			-			-			(1	)
Increase (decrease) in other long-term    liabilities		1,018			(5,970	)		-			-			(4,952	)
Changes in deferred turnaround costs,    deferred catalyst costs and other		122			(253	)		-			-			(131	)
Changes in working capital from    operations		54,748			(117,193	)		-			505			(61,940	)
Net cash provided by operating activities		12,548			51,742			-			(4,261	)		60,029
Cash flows from investing activities:
Additions to property, plant and    equipment		(1	)		(59,351	)		-			(1,939	)		(61,291	)
Proceeds from sales of assets		1			-			-			-			1
Net cash used in investing    activities		-			(59,351	)		-			(1,939	)		(61,290	)
Cash flows from financing activities:
Purchase of treasury stock		(3,582	)		-			-			-			(3,582	)
Dividends paid		(6,628	)		-			-			-			(6,628	)
Excess income tax benefits of    stock-based compensation		152			-			-			-			152
Debt issuance costs and other		-			(310	)		-			-			(310	)
Intercompany dividends		-			(6,200	)		-			6,200			-
Net cash used in financing activities		(10,058	)		(6,510	)		-			6,200			(10,368	)
Increase (decrease) in cash and cash    equivalents		2,490			(14,119	)		-			-			(11,629	)
Cash and cash equivalents, beginning of    period		211,775			213,505			-			-			425,280
Cash and cash equivalents, end of    period	$	214,265		$	199,386		$	-		$	-		$	413,651

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2009
As Adjusted (Note 2)
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(8,706	)	$	14,557		$	3		$	(14,560	)	$	(8,706	)
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(26,437	)		-			-			26,437			-
Depreciation, amortization and    accretion, including amortization    of deferred turnaround costs		51			68,710			-			433			69,194
Deferred income tax provision		14,335			-			-			-			14,335
Stock-based compensation expense		15,193			-			-			-			15,193
Excess income tax benefits of    stock-based compensation		(227	)		-			-			-			(227	)
Intercompany income taxes		26,000			(17,801	)		14			(8,213	)		-
Intercompany dividends		21,200			-			-			(21,200	)		-
Other intercompany transactions		3,030			(3,002	)		(28	)		-			-
Amortization of debt issuance costs		587			530			-			-			1,117
Senior notes discount amortization		196			-			-			-			196
Allowance for investment loss and    bad debts		-			500			-			-			500
Increase in other long-term liabilities		2,188			8,546			-			-			10,734
Changes in deferred turnaround costs,    deferred catalyst costs and other		(1,026	)		(7,107	)		-			-			(8,133	)
Changes in working capital from    operations		(1,169	)		53,142			11			879			52,863
Net cash provided by operating activities		45,215			118,075			-			(16,224	)		147,066
Cash flows from investing activities:
Additions to property, plant and    equipment		(147	)		(116,451	)		-			(4,976	)		(121,574	)
Net cash used in investing activities		(147	)		(116,451	)		-			(4,976	)		(121,574	)
Cash flows from financing activities:
Purchase of treasury stock		(2,654	)		-			-			-			(2,654	)
Proceeds from issuance of common stock		70			-			-			-			70
Dividends paid		(19,071	)		-			-			-			(19,071	)
Excess income tax benefits of    stock-based compensation		227			-			-			-			227
Debt issuance costs and other		2			(284	)		-			-			(282	)
Intercompany dividends		-			(21,200	)		-			21,200			-
Net cash used in financing activities		(21,426	)		(21,484	)		-			21,200			(21,710	)
Increase (decrease) in cash and cash    equivalents		23,642			(19,860	)		-			-			3,782
Cash and cash equivalents, beginning of    period		254,548			228,984			-			-			483,532
Cash and cash equivalents, end of    period	$	278,190		$	209,124		$	-		$	-		$	487,314

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.& #160; 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).  During the fourth quarter of 2009, the Company changed its inventory valuation method for crude oil, unfinished products and finished products to the last-in, first-out (LIFO) method from the first-in, first-out (FIFO) method as previously disclosed.  See “Change in Accounting Principle – Inventory” in Note 2 in the Condensed Consolidated Financial Statements for additional information.  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.

Nine months ended September 30, 2010 compared with the same period in 2009

(2009 as Adjusted, see Note 2 in the Condensed Consolidated Financial Statements)

Overview of Results

We had net income for the nine months ended September 30, 2010 of $34.2 million, or $0.32 per diluted share, compared to a net loss of $8.7 million, or $0.08 per share, in the same period in 2009.  Our operating income of $74.2 million for the nine months ended September 30, 2010 increased $65.2 million from the $9.0 million of operating income for the comparable period in 2009.  The increase in our operating income from the first nine months of 2009 to the first nine months of 2010 was due to the improvement of the diesel crack spread (from $8.64 per barrel in 2009 to $11.73 per barrel in 2010) and gasoline crack spread (from $8.66 per barrel in 2009 to $9.02 per barrel in 2010).  In addition, the favorable contango structure in the crude oil forward curve (current prices lower than future prices) benefited our results of operations in both periods.  The average laid-in crude oil differential decreased to $2.86 per barrel for the nine months ended September 30, 2010 from $3.53 in the same period in 2009 because of the stronger contango in 2009 which offset the improvement in the light/heavy and WTI/WTS crude oil differentials in 2010.  The light/heavy crude oil differential increased from $5.86 per barrel for the nine months ended September 30, 2009 to $8.21 per barrel for the comparable period of 2010.  The WTI/WTS crude oil differential increased from $1.44 per barrel for the nine months ended September 30, 2009 to $2.00 per barrel for the comparable period of 2010.  During the third quarter of 2010, we experienced a fire in the crude unit at the Cheyenne Refinery.  The crude unit was down 28 days with repair costs of approximately $6.1 million, during which time we also spent approximately $1.8 million on accelerated maintenance.

The poor refined product market conditions during the last two years have resulted in excess refining capacity in the U.S. and worldwide.  This over-capacity is likely to continue until demand for refined products increases or capacity is further reduced.  In the second and third quarters of 2010 we began to experience an improvement in the light/heavy crude oil differential as well as an increase in the demand for our diesel products.

Our Cheyenne Refinery is impacted more significantly by these market conditions because of its sensitivity to crude oil differentials.  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 have 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.  We are unable to project if recent improvements in margins and crude oil differentials will continue or what additional steps we may take if refining conditions deteriorate.

Specific Variances

Refined product revenues.  Refined product revenues increased $1.07 billion, or 34%, from $3.15 billion to $4.22 billion for the nine months ended September 30, 2010 compared to the same period in 2009.  This increase resulted primarily from higher crude oil prices, and correspondingly higher refined product prices in the nine months ended September 30, 2010 ($20.85 higher average price per sales barrel) and a 1% increase in sales volumes.

Manufactured product yields.  Yields increased 2,807 bpd at the El Dorado Refinery and decreased 804 bpd at the Cheyenne Refinery for the nine months ended September 30, 2010 compared to same period in 2009.  The decrease in the Cheyenne Refinery yields resulted from unplanned downtime due to the crude unit fire.

Other revenues.  Other revenues increased $20.5 million to a gain of $22.0 million for the months ended September 30, 2010, compared to a gain of $1.5 million for the same period in 2009, the primary source of this increase being $21.9 million in net realized and unrealized gains from derivative contracts to hedge in-transit crude oil and excess inventories in the nine months ended September 30, 2010, compared to $3.2 million of losses in the nine months ended September 30, 2009.  See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.  We had gasoline sulfur credit sales of $1.9 million during the nine months ended September 30, 2009 compared to none in the comparable 2010 p eriod, and $3.2 million of ethanol Renewable Identification Number (“RIN”) sales in 2009 versus $128,000 in the comparable period of 2010.

Raw material, freight and other costs.  Raw material, freight and other costs increased by $1.03 billion, from $2.81 billion in the nine months ended September 30, 2009 to $3.84 billion in the same period for 2010.  The increase in raw material, freight and other costs was due to higher average crude oil prices, increased overall crude oil charges, a lower average laid-in crude oil differential, and increased purchased product during the nine months ended September 30, 2010 when compared to the same period in 2009.

The Cheyenne Refinery raw material, freight and other costs of $76.98 per sales barrel for the nine months ended September 30, 2010 increased from $56.41 per sales barrel in the same period in 2009 due to higher average crude oil prices and increased purchased products offset by reduced crude oil charges and a higher average laid-in crude oil differential.  The average laid-in crude oil differential for the Cheyenne Refinery increased to $4.89 per barrel for the nine months ended September 30, 2010, due to the widening of the light/heavy crude oil differential, compared to $3.97 per barrel in the same period in 2009.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $10.18 per barrel in the nine months ended September 30, 2010 compared to $5.97 per barrel in the same period in 2009.   ;Despite the improvement in the light/heavy crude oil differential, there was not sufficient economic incentive to significantly increase our use of heavy crude oil in the majority of the nine months ended September 30, 2010, due in large part to substantial growth of domestic crude oil supply from areas like the Bakken shale.

The El Dorado Refinery raw material, freight and other costs of $76.34 per sales barrel for the nine months ended September 30, 2010 increased from $56.35 per sales barrel in the same period in 2009 primarily due to higher average crude oil prices and a lower average laid-in crude oil differential.  The average laid-in crude oil differential decreased to $2.24 per barrel for the nine months ended September 30, 2010 compared to $3.39 per barrel in the same period in 2009 due to a stronger contango market in 2009, despite improved light/heavy and WTI/WTS crude oil differentials.  The WTI/WTS crude oil differential increased from an average of $1.44 per barrel in the nine month period ended September 30, 2009 to $2.00 per barrel in the same period in 2010.  The light/heavy crude oil differential increased from an average of $5.71 per barrel in the nine month period ended September 30, 2009 to $7.07 per barrel in the same period in 2010.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $221.9 million in the nine months ended September 30, 2010 compared to $232.2 million in the comparable period of 2009.

The Cheyenne Refinery operating expenses, excluding depreciation, were $77.8 million for the nine months ended September 30, 2010 compared to $91.3 million in the comparable period of 2009.  The primary areas of decreased costs were: decreased environmental and legal expenses ($11.1 million, primarily due to a $6.8 million expense accrual recorded in September 2009 and a subsequent reversal of $4.5 million of that expense in June 2010 related to an EPA Complaint), decreased turnaround amortization ($3.7 million due to the deferral of certain turnarounds), decreased additives and chemicals costs ($2.3 million), and lower salaries and benefits ($2.0 million). These reduced costs were partially offset by increased natural gas costs ($4.2 million due to higher prices and volumes) and increased maintenance costs ($4.2 million net in crease of which approximately $6.1 million was attributable to the crude unit fire in July 2010 and $1.8 million was for accelerated maintenance during the crude unit outage, offset by $3.5 million in decreases for other maintenance previously reported).

The El Dorado Refinery operating expenses, excluding depreciation, were $144.1 million for the nine months ended September 30, 2010, increasing from $140.9 million in the same period of 2009.  Primary areas of increased costs and variance amounts for the 2010 period compared to the 2009 period were: natural gas costs ($6.3 million due to higher prices and significantly higher volumes), increased turnaround amortization ($2.8 million mainly due to the fall 2009 turnarounds), increased electricity costs ($1.7 million due to higher prices and volumes), and higher salaries and benefits ($1.0 million).  These increased costs were offset by lower maintenance costs ($3.7 million), lower additives and chemicals costs ($1.2 million), reduced consulting and legal expenses ($1.2 million), lower environmental expenses ($1.1 milli on), and reduced insurance costs ($1.0 million).

Selling and general expenses.  Selling and general expenses, excluding depreciation, decreased $3.5 million, or 9%, from $38.9 million for the nine months ended September 30, 2009 to $35.4 million for the nine months ended September 30, 2010, primarily due to lower salaries and benefits and stock-based compensation expense in 2010.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $6.9 million, or 13%, for the nine months ended September 30, 2010 compared to the same period in 2009 because of increased capital investments in our Refineries, including the catalytic cracker regenerator emission control project and reliability projects and a portion of the gasoil hydrotreater revamp, all of which were incurred by our El Dorado Refinery and placed into service in the fourth quarter of 2009.

Interest expense and other financing costs.  Interest expense and other financing costs of $24.3 million for the nine months ended September 30, 2010 increased from $21.0 million in the comparable period in 2009.  Items which increased interest expense and other financing costs during the nine months ended September 30, 2010 included $2.7 million less capitalized interest, $2.0 million higher revolving credit facility fees and $879,000 more interest expense under the Utexam arrangement for the nine months ended September 30, 2010 when compared to the same period in 2009.  Our interest expense for the nine months ended September 30, 2010 was reduced by $1.3 million and $1.0 million from gains and interest income, respectively, on our interest rate swap c ontracts.  The interest rate swaps did not impact the comparable period in 2009 since we entered into the contracts in the fourth quarter of 2009.

Average debt outstanding was $350.0 million for both the nine months ended September 30, 2010 and 2009 (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $157,000, from $1.9 million in the nine months ended September 30, 2009, to $1.8 million in the nine months ended September 30, 2010.

Provision (benefit) for income taxes.  The provision for income taxes for the nine months ended September 30, 2010 was $17.5 million on pretax income of $51.7 million (or 33.9%).  The 2010 period effective tax rate was reduced by 4.0% from the reduction by $5.8 million of the estimated environmental penalties recorded in 2009 to the negotiated amount.  Our benefit for income taxes for the nine months ended September 30, 2009 was $1.4 million on a pretax loss of $10.1 million (or 13.9%).  The 2009 period effective tax rate was distorted from the impact of a permanent book-tax difference (increasing taxable income) of $6.8 million for estimated environmental penalties on a small pre-tax loss (23.4% reduction of effective rate benefit).

Three months ended September 30, 2010 compared with the same period in 2009

(2009 as Adjusted, see Note 2 in the Condensed Consolidated Financial Statements)

Overview of Results

We had net income for the three months ended September 30, 2010 of $8.3 million, or $0.08 per diluted share, compared to a net loss of $8.8 million, or $0.08 per share, in the same period in 2009.  Our operating income of $16.3 million for the three months ended September 30, 2010 increased $20.8 million from the $4.5 million operating loss for the comparable period in 2009.  The increase in our operating income from the three months ended September 30, 2009 to the comparable period of 2010 was due to improvement of the diesel crack spread (from $7.94 per barrel in 2009 to $13.93 per barrel in 2010) and gasoline crack spread (from $7.92 per barrel in 2009 to $10.51 per barrel in 2010).  The average laid-in crude oil differential increased to $3.17 per barrel for the three months ended September 30, 2010 comp ared to $2.28 per barrel in the comparable period of 2009 due to improved light/heavy and WTI/WTS crude oil differentials.  The light/heavy crude oil differential increased from $6.33 per barrel for the three months ended September 30, 2009 to $10.39 per barrel for the comparable period of 2010.  The WTI/WTS crude oil differential increased from $1.62 per barrel for the three months ended September 30, 2009 to $2.13 per barrel for the comparable period of 2010. During the third quarter of 2010, we experienced a fire in the crude unit at the Cheyenne Refinery.  The crude unit was down 28 days with repair costs of approximately $6.1 million, at which time we also spent approximately $1.8 million on accelerated maintenance during the crude unit outage.

Specific Variances

Refined product revenues.  Refined product revenues increased $223.1 million, or 19%, from $1.20 billion to $1.42 billion for the three months ended September 30, 2010 compared to the same period in 2009.  This increase resulted primarily from higher crude oil prices, and correspondingly higher refined product prices in the three months ended September 30, 2010 ($10.59 higher average price per sales barrel), and a 4% increase in sales volumes.

Manufactured product yields.  Yields increased 11,848 bpd at the El Dorado Refinery and decreased 7,695 bpd at the Cheyenne Refinery for the three months ended September 30, 2010 compared to same period in 2009.  The increase in the El Dorado Refinery manufactured product yields for the third quarter of 2010, when compared to 2009, was primarily due to additional capacity from various projects completed in the fourth quarter of 2009.  The decrease in the Cheyenne Refinery manufactured product yields for the third quarter of 2010, when compared to 2009, was primarily due to the downtime from the crude unit fire in July 2010.

Other revenues.  Other revenues decreased $7.2 million to a loss of $3.5 million for the three months ended September 30, 2010, compared to a gain of $3.7 million for the same period in 2009, the primary source of this decrease being $3.4  million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories in the three months ended September 30, 2010, compared to $4.2 million of gains in the three months ended September 30, 2009.  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 $194.2 million, from $1.09 billion in the three months ended September 30, 2009 to $1.28 billion in the same period for 2010.  The increase in raw material, freight and other costs was due to higher average crude oil prices, increased overall crude oil charges, a lower average laid-in crude oil differential and increased purchased products during the three months ended September 30, 2010 when compared to the same period in 2009.

The Cheyenne Refinery raw material, freight and other costs of $74.13 per sales barrel for the three months ended September 30, 2010 increased from $64.37 per sales barrel in the same period in 2009 due to higher average crude oil prices and increased purchased products, partially offset by better crude oil differentials.  The average laid-in crude oil differential for the Cheyenne Refinery was $6.50 per barrel for the three months ended September 30, 2010 compared to $2.85 per barrel in the same period in 2009 due to an improved light/heavy crude oil differential in the third quarter of 2010.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $13.03 per barrel in the three months ended September 30, 2010 compared to $7.13 per barrel in the same period in 2009.

The El Dorado Refinery raw material, freight and other costs of $76.00 per sales barrel for the three months ended September 30, 2010 increased from $67.28 per sales barrel in the same period in 2009 primarily due to higher average crude oil prices. The average laid-in crude oil differential increased to $2.38 for the three months ended September 30, 2010 from $2.08 per barrel in the same period in 2009, with the increase resulting from higher WTI/WTS and light/heavy crude oil differentials in the third quarter of 2010.  The WTI/WTS crude oil differential increased from an average of $1.62 per barrel in the three month period ended September 30, 2009 to $2.13 per barrel in the same period in 2010.  The light/heavy crude oil differential increased from an average of $5.69 per barrel in the three month period ended Sept ember 30, 2009 to $8.88 per barrel in the same period in 2010.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $82.9 million in the three months ended September 30, 2010 compared to $83.7 million in the comparable period of 2009.

The Cheyenne Refinery operating expenses, excluding depreciation, were $32.9 million for the three months ended September 30, 2010 compared to $36.2 million in the comparable period of 2009.  The primary areas of decreased costs were: decreased environmental expenses ($5.7 million, which was primarily attributable to the $6.8 million EPA Complaint expense accrual recorded in the 2009 period), lower salaries and benefits ($1.4 million), and decreased turnaround amortization ($1.3 million due to the deferment of certain turnarounds).  These decreases were partially offset by increased maintenance costs ($7.7 million, of which approximately $6.1 million was due to the crude unit fire in July 2010 and $1.8 million was for accelerated maintenance during the crude unit outage).

The El Dorado Refinery operating expenses, excluding depreciation, were $50.0 million for the three months ended September 30, 2010, increasing from $47.5 million in the same three month period of 2009.  Primary areas of increased costs and variance amounts for the 2010 period compared to the 2009 period were: increased natural gas costs ($1.2 million due to higher prices and volumes), an increase in turnaround amortization ($863,000), increased additives and chemicals costs ($823,000), higher salaries and benefits ($781,000), and higher electricity costs ($427,000).  These increases were partially offset by reduced maintenance costs ($1.7 million primarily due to demolition work in 2009).

Selling and general expenses.  Selling and general expenses, excluding depreciation, decreased $456,000, or 3%, from $13.7 million for the three months ended September 30, 2009 to $13.2 million for the three months ended September 30, 2010, primarily due to lower stock-based compensation expense in the 2010 period.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $2.2 million, or 12%, for the three months ended September 30, 2010 compared to the same period in 2009 because of increased capital investments in our Refineries, including the catalytic cracker regenerator emission control project and reliability projects and a portion of the gasoil hydrotreater revamp, all of which were incurred by our El Dorado Refinery and placed into service in the fourth quarter of 2009.

Interest expense and other financing costs.  Interest expense and other financing costs of $9.0 million for the three months ended September 30, 2010 increased $2.3 million from $6.7 million in the comparable period in 2009.  Items which increased interest expense and other financing costs during the nine months ended September 30, 2010 included $1.3 million less capitalized interest, $1.3 million higher revolving credit facility fees and $301,000 more interest expense under the Utexam arrangement during the three months ended September 30, 2010 compared to the same period in 2009.  Our interest expense for the three months ended September 30, 2010 was reduced by $228,000 and $323,000 from gains and interest income, respectively, on our interest rate sw ap contracts.  The interest rate swaps did not impact the comparable period in 2009 since we entered into the contracts in the fourth quarter of 2009.

Average debt outstanding was $350.0 million for both the three months ended September 30, 2010 and 2009 (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income increased $35,000, from $661,000 in the three months ended September 30, 2009, to $696,000 in the three months ended September 30, 2010.

Provision (benefit) for income taxes.  The benefit for income taxes for the three months ended September 30, 2010 was $319,000 on a pretax income of $8.0 million resulting in a negative effective tax rate for the quarter of 4.0%.  Our benefit for income taxes for the three months ended September 30, 2009 was $1.7 million on a pretax loss of $10.5 million (or a 16.6% effective tax rate).  The effective tax rate for the three months ended September 30, 2010 was decreased 29.0% for the true-up of the actual carryback of the 2009 net operating loss to 2005 instead of 2007 (assumed during the second quarter of 2010 and which increased the second quarter provision).  This benefit was due to the lower Section 199 manufacturer’s deduction rate i n 2005 versus 2007.  The effective tax rate for the three months ended September 30, 2010 also benefited 8.6% from the current quarter’s estimated Section 199 manufacturer’s deduction.  The 2009 period effective tax rate was distorted from the impact of a permanent book-tax difference (increasing taxable income) of $6.8 million for estimated environmental penalties on a small pre-tax loss (22.4% reduction of effective rate benefit).

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities.  Net cash provided by operating activities was $60.0 million for the nine months ended September 30, 2010 compared to net cash provided by operating activities of $147.1 million during the nine months ended September 30, 2009.  Working capital changes were a use of cash during the 2010 period while providing cash during the same period in 2009.  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 $61.9 million of cash during the first nine months of 2010 compared to providing $52.9 million for the same period in 2009.  The $61.9 million net working capital uses for the 2010 period primarily resulted from increased inventory of $86.2 million, decreased current accrued liabilities of $15.5 million, and increased receivables of $8.0 million, offset by working capital provided by $45.6 million of increased payables (including a $54.5 million increase in crude payables) and $3.4 million of decreased other current assets.  In the first nine months of 2009, the working capital change of $52.9 million primarily resulted from a $144.0 million increase in payables and $31.5 million decrease in other current assets, offset by $84.2 million of increased inventory, and a $33.7 millio n increase in receivables.  During the nine months ended September 30, 2010, we received federal and state income tax refunds of $63.6 million.  In October 2010, subsequent to the balance sheet date, we received a federal income tax refund of $73.5 million, reflected in “Income taxes receivable” on the Condensed Consolidated Balance Sheet at September 30, 2010.  At September 30, 2010, we had $413.7 million of cash and cash equivalents, $546.7 million of working capital, no cash borrowings under our revolving credit facility, and $243.9 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 nine months of 2010 were $61.3 million, which included approximately $34.8 million for the El Dorado Refinery and $26.1 million for the Cheyenne Refinery. The $34.8 million of capital expenditures for our El Dorado Refinery included $14.2 million on the gasoil hydrotreater revamp and $2.2 million on the catalytic cracker regenerator emission control project as well as operational, payout, safety, administrative, environmental and optimization projects.  The $26.1 million of capital expenditures for our Cheyenne Refinery included $8.9 million for the FCCU gas hydrotreater project and $3.8 million for the liquefied petroleum gas recovery project as well as environmental, operational, sa fety, administrative and payout projects.

Cash flows from financing activities.  During the nine months ended September 30, 2010, treasury stock increased by 265,541 shares ($3.6 million) from stock surrendered by employees to pay withholding taxes on stock-based compensation which vested during the first nine months of 2010.  We also paid $6.6 million in dividends during the nine months ended September 30, 2010.

As of September 30, 2010, we had $347.7 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $256.1 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 September 30, 2010.  Shareholders’ equity as of September 30, 2010 was $984.2 million.

Our Board of Directors declared a cash dividend of $0.06 per share of common stock in November 2009, which was paid in January 2010.  During 2010 we have been unable to declare dividends because of our inability to satisfy the incurrence of additional indebtedness test of our 6.625% and 8.5% Senior Notes.  However, we intend to resume cash dividends when possible. In addition, we may declare one or more special distributions, including an amount that could reflect dividends we likely would have paid during the period we were otherwise restricted from paying dividends.  Any future dividends paid by the Company will be subject to the approval of our Board of Directors.

FUTURE CAPITAL EXPENDITURES

Significant future capital projects.  The gasoil hydrotreater revamp at the El Dorado Refinery is the key project to achieve gasoline sulfur compliance for our El Dorado Refinery and has a total estimated cost of $95.0 million ($87.3 million incurred as of September 30, 2010) (see “Environmental” in Note 16 in the Notes to Consolidated Financial Statements).  The project will also produce a significant yield improvement for the catalytic cracking unit, and the first phase was completed in the fourth quarter of 2009 with the second phase anticipated to be completed in the fourth quarter of 2010.  As of September 30, 2010, outstanding non-cancelable purchase commitments for the gasoil hydrotreater revamp were $2.3 million.

At the Cheyenne Refinery, the FCCU gas hydrotreater project has been deferred.  The estimated total cost of the project is $40.0 million of which approximately half will be spent by the end of 2011 ($17.7 million incurred as of September 30, 2010), with the remaining amount temporarily postponed.  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 Note 16 in the Notes to Condensed Consolidated Financial Statements).  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 ($9.3 million incurred as of September 30, 2010) and is estimated to be substantially completed by mid-2011.  At September 30, 2010, there was $1.4 million of outstanding non-cancellable purchase commitments related to the LPG recovery project.  The above amounts include estimated capitalized interest.

2010 capital expenditures.  Cash capital expenditures during 2010 aggregating approximately $92.0 million are currently forecasted ($61.3 million spent through September 30, 2010).  The 2010 capital expenditures include $43.0 million at our Cheyenne Refinery, $48.0 million at our El Dorado Refinery, $700,000 for our pipeline and product terminals and blending facility and $500,000 at our Denver and Houston offices.  The $43.0 million of forecasted capital expenditures for our Cheyenne Refinery includes $16.7 million for the LPG recovery project and $9.8 million for the FCCU gasoline hydrotreater project, both mentioned above, as well as environmental, operational, safety, payout and administrative projects.  The $48.0 million of forecasted cap ital expenditures for our El Dorado Refinery includes $22.6 million for the gasoil hydrotreater revamp project, as mentioned above, as well as environmental, operational, safety, payout and administrative projects.  We expect that our remaining 2010 capital expenditures will be funded with cash generated by our operations and/or by using a portion of our existing cash balance.  We will continue to review our capital expenditures in light of market conditions.  We may experience cost overruns and/or schedule delays or adjust the scope on any of these projects.

Operating Data

The following tables set forth the refining operating statistical information on a consolidatedbasis and for each Refinery for the nine and three months ended September 30, 2010 and 2009.  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:
	Nine Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
Charges (bpd)
Light crude		67,436		53,046		74,539		59,181
Heavy and intermediate crude		99,884		111,507		89,259		100,840
Other feed and blendstocks		14,020		15,886		16,807		17,720
Total		181,340		180,439		180,605		177,741
Manufactured product yields (bpd)
Gasoline		87,440		83,809		87,144		84,913
Diesel and jet fuel		69,983		70,649		69,603		67,167
Asphalt		2,659		1,967		1,039		2,450
Other		17,216		18,872		18,140		17,242
Total		177,298		175,297		175,926		171,772
Total product sales (bpd)
Gasoline		95,860		93,922		96,648		94,505
Diesel and jet fuel		69,676		70,226		69,314		66,009
Asphalt		2,727		1,760		1,891		2,679
Other		15,830		16,982		16,743		14,970
Total		184,093		182,890		184,596		178,163
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	83.88	$	63.03	$	83.61	$	73.02
Raw material, freight and other costs (1)		76.50		56.37		75.59		66.48
Refinery operating expenses, excluding depreciation		4.42		4.65		4.88		5.11
Depreciation, amortization and accretion		1.21		1.08		1.19		1.10
Average NYMEX WTI (per barrel)	$	77.58	$	57.09	$	76.05	$	68.25
Average laid-in crude oil differential (per barrel)		2.75		3.76		2.63		2.77
Average light/heavy differential (per barrel)		8.21		5.86		10.39		6.33
Average gasoline crack spread (per barrel)		9.02		8.66		10.51		7.92
Average diesel crack spread (per barrel)		11.73		8.64		13.93		7.94
Average sales price (per sales barrel)
Gasoline	$	87.54	$	67.69	$	87.21	$	77.66
Diesel and jet fuel		90.18		66.45		90.56		76.74
Asphalt		71.95		65.26		70.70		73.41
Other		36.00		22.92		35.56		27.29
(1) Prior period amounts are adjusted to reflect current year presentation on a LIFO inventory basis.

Cheyenne Refinery:
	Nine Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
Charges (bpd)
Light crude		26,498		18,551		20,494		24,485
Heavy and intermediate crude		12,467		22,459		11,029		16,324
Other feed and blendstocks		2,562		1,384		3,273		1,417
Total		41,527		42,394		34,796		42,226
Manufactured product yields (bpd)
Gasoline		20,012		19,179		17,032		20,578
Diesel		14,347		15,306		11,742		16,236
Asphalt		2,659		1,967		1,039		2,450
Other		2,920		4,290		3,193		1,437
Total		39,938		40,742		33,006		40,701
Total product sales (bpd)
Gasoline		26,639		26,578		24,217		27,396
Diesel		14,391		15,151		11,876		16,084
Asphalt		2,727		1,760		1,891		2,679
Other		2,370		4,106		2,591		3,159
Total		46,127		47,595		40,575		49,318
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	85.35	$	63.58	$	85.11	$	73.89
Raw material, freight and other costs (1)		76.98		56.41		74.13		64.37
Refinery operating expenses, excluding depreciation		6.18		7.03		8.80		7.99
Depreciation, amortization and accretion		1.81		1.69		1.99		1.61
Average laid-in crude oil differential (per barrel)	$	4.84	$	4.55	$	6.65	$	4.46
Average light/heavy crude oil differential (per barrel)		10.18		5.97		13.03		7.13
Average gasoline crack spread (per barrel)		10.69		8.60		15.12		8.42
Average diesel crack spread (per barrel)		14.41		10.18		17.30		8.95
Average sales price (per sales barrel)
Gasoline	$	88.07	$	67.78	$	89.14	$	77.92
Diesel		92.30		69.20		92.87		77.87
Asphalt		71.95		65.26		70.70		73.41
Other		27.98		14.99		22.40		19.04
(1) Prior period amounts are adjusted to reflect current year presentation on a LIFO inventory basis.

El Dorado Refinery:
	Nine Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
Charges (bpd)
Light crude		40,938		34,495		54,045		34,696
Heavy and intermediate crude		87,417		89,047		78,230		84,517
Other feed and blendstocks		11,458		14,502		13,535		16,303
Total		139,813		138,044		145,810		135,516
Manufactured product yields (bpd)
Gasoline		67,428		64,630		70,111		64,335
Diesel and jet fuel		55,637		55,342		57,861		50,931
Other		14,296		14,582		14,947		15,805
Total		137,361		134,554		142,919		131,071
Total product sales (bpd)
Gasoline		69,221		67,343		72,431		67,109
Diesel and jet fuel		55,286		55,075		57,438		49,924
Other		13,460		12,875		14,152		11,811
Total		137,967		135,293		144,021		128,844
Refinery operating margin information (per sales barrel)
Refined products revenue	$	83.39	$	62.84	$	83.19	$	72.69
Raw material, freight and other costs (1)		76.34		56.35		76.00		67.28
Refinery operating expenses, excluding depreciation		3.83		3.81		3.77		4.00
Depreciation, amortization and accretion		1.01		0.87		0.96		0.91
Average laid-in crude oil differential (per barrel)	$	2.11	$	3.50	$	1.66	$	2.18
Average WTI/WTS crude oil differential (per barrel)		2.00		1.44		2.13		1.62
Average light/heavy crude oil differential (per barrel)		7.07		5.71		8.88		5.69
Average gasoline crack spread (per barrel)		8.38		8.68		8.97		7.72
Average diesel crack spread (per barrel)		11.03		8.22		13.23		7.62
Average sales price (per sales barrel)
Gasoline	$	87.34	$	67.66	$	86.56	$	77.55
Diesel and jet fuel		89.63		65.69		90.08		76.37
Other		37.41		25.45		37.97		29.50
(1) Prior period amounts are adjusted to reflect current year presentation on a LIFO inventory basis.

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 (Lo ss) for each period.  When the derivative contracts are designated as fair value hedges for accounting purposes, the gains or losses are recognized in the related inventory in “Inventory of crude oil, products and other” on the Condensed Consolidated Balance Sheets and ultimately, when the inventory is charged or sold, in “Raw material, freight and other costs” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  See Note 15 “Price and Interest Risk Management Activities” in the “Notes to Condensed Consolidated Financial Statements.”

Our outstanding derivatives sale contracts and net unrealized losses as of September 30, 2010 are summarized below:

Commodity	Period	Volume (thousands of bbls)		Expected Close Out Date	Unrealized Net Losses (in thousands)
Crude Oil	November 2010		1,441	October 2010	$	(5,539	)
Crude Oil	December 2010		371	November 2010		(1,167	)

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 6.625% Senior Notes due 2011 and $200.0 million of 8.5% Senior Notes due 2016 that were outstanding at September 30, 2010 have fixed interest rates.  However, in the fourth quarter of 2009, based on  advantageous market conditions, the Company entered into fixed to floating interest rate swaps of $150.0 million to reduce exposure related to our 6.625% Senior Notes.  These interest rate swaps expose that portion of our long-term debt to ca sh 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 transa ctions using market prices and other economic data and assumptions were used to value our interest rate swaps.

	As of September 30, 2010
	Expected maturity dates																	Fair value
	2010		2011			2012		2013		2014		Thereafter			Total
	(in thousands)
Long-term debt:
Fixed rate	$	-	$	150,000		$	-	$	-	$	-	$	200,000		$	350,000		$	358,563
Average interest rate		-		6.625	%		-		-		-		8.500	%		7.696	%
Interest rate swaps:
Fixed to variable	$	-	$	150,000		$	-	$	-	$	-	$	-		$	150,000		$	1,263
Average pay rate		-		5.783	%		-		-		-		-			5.783	%
Average receive rate		-		6.625	%		-		-		-		-			6.625	%
	As of December 31, 2009
	Expected maturity dates																	Fair value
		2010		2011			2012		2013		2014	Thereafter			Total
	(in thousands)
Long-term debt:
Fixed rate	$	-	$	150,000		$	-	$	-	$	-	$	200,000		$	350,000		$	357,750
Average interest rate		-		6.625	%		-		-		-		8.500	%		7.696	%
Interest rate swaps:
Fixed to variable	$	-	$	150,000		$	-	$	-	$	-	$	-		$	150,000		$	2
Average pay rate		-		6.624	%		-		-		-		-			6.624	%
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 an d 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 16 and 17 in the Notes to Condensed Consolidated Financial Statements.

ITEM 1A.

Risk Factors – Our inventory risk management activities relating to hedging may generate substantial gains and losses. In order to manage our price risk exposure on certain of our inventories, we from time to time enter into derivative contracts to make forward sales or purchases of crude oil and refined products.  We may also use options or swaps to accomplish similar objectives.  Our inventory risk management strategy is to hedge price risk on inventory positions in excess of our base level of operating inventories in order to minimize the impact of crude oil price fluctuations on our cash flows.  This strategy generally produces losses when hedged crude oil or refined products increase in value and gains when hedged crude oil or refined products decrease in value.  Consequently, our inventory hedging results may fluctuate significantly from one reporting period to the next depending on commodity price fluctuatio ns.  For example, during the nine months ended September 30, 2010 and 2009, we incurred a pre-tax hedging gain of $21.9 million and a pre-tax hedging loss of $3.2 million, respectively, both recorded in “Other revenues” in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  During the three months ended September 30, 2010 and 2009, we incurred a pre-tax hedging loss of $3.4 million and a pre-tax hedging gain of $4.2 million, respectively.  See “Quantitative and Qualitative Disclosures about Market Risk in Part I, Item 3. On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law. This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared.  In addition, the legislation provides an exemption from mandatory clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission and the Securities and Exchange Commission for transactions by non-financial institutions to hedge or mitigate commercial risk.  At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk.  However, during drafting of the legislation, members of Congress ado pted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk.  Final rules on major provisions in the legislation, like new margin requirements, will be established through rulemakings and will not take effect until twelve months after the date of enactment.   Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.

ITEM 5. Other Information –   Effective November 1, 2010, Frontier Oil and Refining Company (“FORC”), a wholly-owned subsidiary of Frontier Oil Corporation (“FOC”) entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp. (collectively, “BNP”).  Under this Contract, BNP purchases, transports and subsequently sells crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed.  Under this agreement, BNP is the owner of record of the crude oil as it is transported from the point of injection, typically Hardisty, Alberta, Canada, to the point of ultimate sale to FORC.  FOC has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract.  A copy of this Contract and a copy of the guarantee made by FOC are filed as Exhibit 10.1 and Exhibit 10.2, respectively, to this Form 10-Q and incorporated herein by reference.

ITEM 6. Exhibits –   10.1 – Master Crude Oil Purchase and Sale Agreement, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation.   10.2 – Guaranty dated November 1, 2010 made by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP Paribas Energy Trading Canada Corp.   10.3 – Executive Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester.   10.4 – Executive Change in Control Severance Agreement, effective as of June 1, 2010 by and between Frontier Oil Corporation and Paige A. Kester.   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 September 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the nine and three months ended September 30, 2010 and 2009, (ii) Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009, (iii) Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009, 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: November 4, 2010