Frontier Oil (FTO) 10-Q 2010 Q2 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 JUNE 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 August 2, 2010:  105,674,869

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010

INDEX

FORWARD-LOOKING STATEMENTS

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

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

  ● statements relating to future financial performance, future capital sources and other matters; 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)
	Six Months Ended June 30,						Three Months Ended June 30,
	2010			2009 As Adjusted (Note 2)			2010			2009 As Adjusted (Note 2)
Revenues:
Refined products	$	2,795,549		$	1,950,311		$	1,520,510		$	1,128,140
Other		25,475			(2,219	)		28,370			(26,296	)
Total revenues		2,821,024			1,948,092			1,548,880			1,101,844
Costs and expenses:
Raw material, freight and other costs		2,561,055			1,724,729			1,337,291			1,081,103
Refinery operating expenses, excluding depreciation		139,023			148,474			64,038			72,598
Selling and general expenses, excluding depreciation		22,196			25,287			11,220			12,866
Depreciation, amortization and accretion		40,847			36,127			20,340			17,983
Gain on sales of assets		(1	)		-			-			-
Total costs and expenses		2,763,120			1,934,617			1,432,889			1,184,550
Operating income (loss)		57,904			13,475			115,991			(82,706	)
Interest expense and other financing costs		15,281			14,337			8,046			6,917
Interest and investment income		(1,095	)		(1,287	)		(568	)		(771	)
Income (loss) before income taxes		43,718			425			108,513			(88,852	)
Provision (benefit) for income taxes		17,868			347			42,399			(30,980	)
Net income (loss)	$	25,850		$	78		$	66,114		$	(57,872	)
Comprehensive income (loss)	$	25,585		$	(47	)	$	65,982		$	(57,935	)
Basic earnings (loss) per share of common stock	$	0.25		$	-		$	0.63		$	(0.56	)
Diluted earnings (loss) per share of common stock	$	0.25		$	-		$	0.63		$	(0.56	)
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)
June 30, 2010 and December 31, 2009	2010			2009
ASSETS
Current assets:
Cash, including cash equivalents of $442,510 and $424,323 at 2010 and 2009,  respectively	$	444,240		$	425,280
Trade receivables, net of allowance of $1,000 at 2010 and 2009		174,095			95,261
Income taxes receivable		127,973			174,627
Other receivables, net		2,045			7,842
Inventory of crude oil, products and other		335,348			293,476
Deferred income tax assets - current		6,268			26,373
Other current assets		10,417			14,507
Total current assets		1,100,386			1,037,366
Property, plant and equipment, net		1,013,800			1,021,409
Deferred turnaround and catalyst costs, net		58,772			68,491
Deferred financing costs, net of accumulated amortization of $4,637 and $3,893 at 2010 and 2009, respectively		3,967			4,711
Intangible assets, net of accumulated amortization of $675 and $614 at 2010 and 2009, respectively		1,155			1,216
Deferred state income tax assets - noncurrent		11,219			10,767
Other assets		3,255			3,935
Total assets	$	2,192,554		$	2,147,895
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	530,005		$	474,377
Accrued liabilities and other		37,370			64,799
Total current liabilities		567,375			539,176
Long-term debt		347,626			347,485
Contingent income tax liabilities		30,120			29,348
Post-retirement employee liabilities		34,337			33,138
Long-term capital lease obligation		3,171			3,394
Other long-term liabilities		13,070			20,560
Deferred federal income tax liabilities		224,408			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		256,591			252,513
Retained earnings		1,056,060			1,030,203
Accumulated other comprehensive loss		(1,499	)		(1,234	)
Treasury stock, at cost, 26,130,792 and 27,165,400 shares at 2010 and 2009, respectively		(396,441	)		(395,242	)
Total shareholders' equity		972,447			943,976
Total liabilities and shareholders' equity	$	2,192,554		$	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 six months ended June 30,
	2010			2009 As Adjusted (Note 2)
Cash flows from operating activities:
Net income	$	25,850		$	78
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, amortization and accretion, including amortization    of deferred turnaround costs		50,346			46,041
Deferred income tax provision		13,145			4,522
Stock-based compensation expense		8,613			10,753
Excess income tax benefits of stock-based compensation		(101	)		(151	)
Amortization of debt issuance costs		744			744
Senior Notes discount amortization		141			129
Allowance for investment loss and bad debts		(52	)		500
Gain on sales of assets		(1	)		-
(Decrease) increase in other long-term liabilities		(6,187	)		2,475
Changes in deferred turnaround costs, deferred catalyst costs and other		900			(1,256	)
Changes in working capital from operations		(23,516	)		32,909
Net cash provided by operating activities		69,882			96,744
Cash flows from investing activities:
Additions to property, plant and equipment		(40,744	)		(76,709	)
Proceeds from sales of assets		1			-
Net cash used in investing activities		(40,743	)		(76,709	)
Cash flows from financing activities:
Purchase of treasury stock		(3,582	)		(2,588	)
Proceeds from issuance of common stock		-			70
Dividends paid		(6,493	)		(12,660	)
Excess income tax benefits of stock-based compensation		101			151
Other		(205	)		(183	)
Net cash used in financing activities		(10,179	)		(15,210	)
Increase in cash and cash equivalents		18,960			4,825
Cash and cash equivalents, beginning of period		425,280			483,532
Cash and cash equivalents, end of period	$	444,240		$	488,357
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	13,298		$	11,777
Cash paid during the period for income taxes		51			31,150
Cash refunds of income taxes		43,932			51,604
Noncash investing activities - accrued capital expenditures, end of period		9,348			23,302
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.  On July 28, 2010, the Company had a fire in the crude unit at its Cheyenne Refinery.  Fortunately, no recordable injuries occurred as a result of the fire.  The crude unit is expected to be out of service for repairs for two to three weeks from the incident date and repair costs are not expected to exceed $5.0 million.

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:

	Six Months Ended June 30,				Three Months Ended June 30,
	2010		2009		2010		2009
Basic		104,065,946		103,430,428		104,196,131		103,498,642
Diluted		105,315,679		104,696,801		105,578,151		103,498,642

For the six and three months ended June 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.  In addition, for the three months ended June 30, 2009, there were 1.5 million outstanding restricted stock and stock unit awards that could potentially dilute EPS in future periods that were not included in the computation of diluted EPS as they were anti-dilutive due to the Company’s net loss.

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 June 30, 2010, the Company had $129.5 million available to pay dividends under the restricted payments basket of its 6.625% and 8.5% Senior Notes (“Senior Notes”) covenants; however, the Company is currently unable to pay dividends because of the inability to satisfy the interest rate coverage ratio 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 six and three months ended June 30, 2010, the Company recognized gains in “Other Revenues” of $137,000 and $176,000, respectively, due to the translation of its foreign denominated assets and liabilities.  For the six and three months ended June 30, 2009, the Company recognized losses of $875,000 and $764,000, 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.

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.

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 June 30, 2009.  The following condensed consolidated financial statement line items for the six and three months ended June 30, 2 009 were affected by the change in accounting principle.

	Six months ended									Three months ended
	June 30, 2009									June 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	$	1,533,989		$	1,724,729		$	190,740		$	914,092	$	1,081,103		$	167,011
Operating income (loss)		204,215			13,475			(190,740	)		84,305		(82,706	)		(167,011	)
Income (loss) before income taxes		191,165			425			(190,740	)		78,159		(88,852	)		(167,011	)
Provision (benefit) for income taxes		67,865			347			(67,518	)		28,318		(30,980	)		(59,298	)
Net income (loss)	$	123,300		$	78		$	(123,222	)	$	49,841	$	(57,872	)	$	(107,713	)
Comprehensive income (loss)	$	123,175		$	(47	)	$	(123,222	)	$	49,778	$	(57,935	)	$	(107,713	)
Basic earnings (loss) per share	$	1.19		$	-		$	(1.19	)	$	0.48	$	(0.56	)	$	(1.04	)
Diluted earnings (loss) per share	$	1.18		$	-		$	(1.18	)	$	0.47	$	(0.56	)	$	(1.03	)
Condensed Consolidated Statements of Cash Flows:										`
Net income	$	123,300		$	78		$	(123,222	)
Adjustments to reconcile net income    to net cash from operating activities:
Deferred income tax provision		4,813			4,522			(291	)
Changes in components of working    capital from operations		(90,604	)		32,909			123,513
Net cash provided by operating    activities	$	96,744		$	96,744		$	-

3.      Other Receivables

	June 30,		December 31,
	2010		2009
	(in thousands)
Investment fund receivable, net of allowance	$	-	$	2,143
Realized futures trading receivable		-		2,341
Interest rate swaps net interest receivable		345		310
Other		1,700		3,048
	$	2,045	$	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.  T herefore, 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 six months ended June 30, 2010, the Company received an additional distribution totaling $2.2 million, thus increasing total distributions to $32.3 million.  As the total distributions exceeded the net investment, during the six months ended June 30, 2010, the Company reduced the previously recorded loss allowance on this investment by $52,000, which increased “Interest and Investment Income” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  In July 2010, subsequent to the balance sheet date, the Company received another $132,000 in partial distributions, which will be included as income in the third quarter, increasing its total distributions to $32.4 mi llion.  While still awaiting final notice regarding proceeds from the Fund, the Company does not anticipate further distributions; thus, the Company has no remaining net investment fund receivable as of June 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 June 30, 2010 and December 31 , 2009 were as follows:

	June 30,			December 31,
	2010			2009
	(in thousands)
Crude oil	$	298,647		$	343,154
Unfinished products		128,286			101,436
Finished products		123,399			94,239
LIFO reserve - adjustment to inventories		(243,473	)		(272,634	)
		306,859			266,195
Process chemicals		1,072			1,162
Repairs and maintenance supplies and other		27,417			26,119
	$	335,348		$	293,476

5.      Other Current Assets

	June 30,		December 31,
	2010		2009
	(in thousands)
Margin deposits	$	2,852	$	10,898
Derivative assets		3,353		124
Prepaid insurance		1,106		1,705
Other		3,106		1,780
	$	10,417	$	14,507

6.      Property, Plant and Equipment

	June 30,			December 31,
	2010			2009
	(in thousands)
Refineries, pipelines and terminal equipment	$	1,418,940		$	1,389,351
Buildings		43,740			41,616
Land and land improvements		15,553			15,320
Furniture, fixtures and other equipment		17,573			17,284
Property, plant and equipment, at cost		1,495,806			1,463,571
Accumulated depreciation		(482,006	)		(442,162	)
Property, plant and equipment, net	$	1,013,800		$	1,021,409

7.      Accrued Liabilities and Other

	June 30,		December 31,
	2010		2009
	(in thousands)
Accrued compensation	$	10,294	$	26,093
Accrued environmental costs		4,444		7,599
Accrued dividends		478		6,979
Accrued property taxes		6,617		5,573
Accrued interest		7,515		7,638
Accrued income taxes		4,116		293
Derivative liabilities		92		6,551
Other		3,814		4,073
	$	37,370	$	64,799

8.      Long-term Debt

	June 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		(2,374	)		(2,515	)
8.5% Senior Notes, net		197,626			197,485
	$	347,626		$	347,485

9.      Other Long-term Liabilities

	June 30,		December 31,
	2010		2009
	(in thousands)
Environmental liabilities	$	5,281	$	12,237
Asset retirement obligations		4,615		4,474
Other		3,174		3,849
	$	13,070	$	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 has received a notice of proposed adjustment from the Internal Revenue Service regarding approximately $14.4 million of additional 2005 taxes and approximately $4.3 million of additional 2006 taxes both related to the deductibility for income tax purposes of certain stock-based compensation for executives.  The Company has submitted a protest of these amounts and is in the appeals process.  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 de ductibility for income tax purposes of certain stock-based compensation for executives.  Any appeals decision for 2006 and 2005 is expected to also apply to the 2007 tax year.  The Company has recorded income tax contingencies for these amounts on the Condensed Consolidated Balance Sheets in the event it is unsuccessful in its appeal.

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:

	Six months Ended June 30,						Three months Ended June 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			-			81		-
Reductions for tax positions of prior years		-			(424	)		-		(424	)
Settlements		-			-			-		-
Reductions due to lapse of applicable statutes of limitations		(66	)		-			-		-
Balance end of period	$	23,869		$	23,854		$	23,869	$	23,854

The total contingent income tax liabilities and accrued interest of $30.1 million and $29.3 million at June 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 $761,000 and $832,000 during the six months ended June 30, 2010 and 2009, and $360,000 and $351,000 during the three months ended June 30, 2010 and 2009, respectively.

In July 2010, subsequent to the balance sheet date, we received federal and state income tax refunds of $19.7 million, reflected in “Income taxes receivable” on the Condensed Consolidated Balance Sheet at June 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 has 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 interest rate coverage ratio test in the covenants of the Senior Notes.  A rollforward of treasury stock for the six months ended June 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		(423,524	)		(778	)
Shares issued for conversion of stock unit awards		(876,625	)		(1,605	)
Balance as of June 30, 2010		26,130,792		$	396,441

 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 six and three months ended June 30, 2010 and 2009 were as follows:

	Six Months Ended June 30,				Three Months Ended  June 30,
	2010		2009		2010		2009
	(in thousands)
Restricted shares and units	$	6,294	$	9,808	$	3,383	$	3,794
Stock options		-		304		-		66
Contingently issuable stock unit awards		2,319		641		1,510		1,612
Total stock-based compensation expense	$	8,613	$	10,753	$	4,893	$	5,472
Income tax benefit recognized in the income statement	$	3,273	$	4,086	$	1,859	$	2,079

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 June 30, 2010, there were 7,332,268 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 six and three months ended June 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 June 30, 2010, there was $24.1 million of total unrecognized compensation cost related to the Plan, including costs for restricted stock and performance-based awards, which is expected to be recognized over a weighted-average period of 2.10 years.

Stock Options.  Stock option changes during the six months ended June 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 six months ended June 30, 2010.  All outstanding stock options were vested and exercisable at June 30, 2010 with weighted average remaining contractual lives of 0.82 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 six months ended June 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		467,420			12.7358
Vested		(614,348	)		19.5130
Forfeited		(5,376	)		21.7598
Nonvested at end of period		1,315,345			14.4532

The total grant date fair value of restricted shares and restricted stock units which vested during the six months ended June 30, 2010 was $12.0 million. The total intrinsic value of restricted shares and restricted stock units vested during the six months ended June 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 six months ended June 30, 2009 was $16.0 million.  The total intrinsic value of restricted shares and restricted stock units that vested during the six months ended June 30, 2009 was $7.9 million, and the Company realized $3.0 million of i ncome tax benefit related to these vestings, which reduced the Company’s available pool of excess income tax benefits by $3.1 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 467,420 shares of restricted stock shares and units granted, n et of forfeitures, during the six months ended June 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
Total		467,420		9,630		48,150		102,410		102,410		204,820
(1) Accelerated vesting due to termination or retirement of employees or members of the Company's Board of Directors.

Contingently Issuable Awards.  During the six months ended June 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 final one- third on June 30, 2013.  As of June 30, 2010, the Company assumed for purposes of stock-based compensation expense for these awards granted in 2010 that the target (100%) level award (307,230 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 $539,000.

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 $251,000.

As of June 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 June 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 table sets forth the net periodic benefit costs recognized for these benefit plans in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss):

	Six Months Ended June 30,					Three Months Ended June 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		-		131			-		66
Expected return on plan assets		-		(89	)		-		(44	)
Amortization of prior service cost		-		213			-		106
Amortized net actuarial loss		-		-			-		-
Net periodic benefit cost		-		255			-		128
Changes in assets and benefit obligations recognized in other comprehensive income (loss):
Net loss		-		-			-		-
Amortization of prior service cost		-		(213	)		-		(106	)
Amortization of gain		-		-			-		-
Total recognized in other comprehensive income		-		(213	)		-		(106	)
Total recognized in net periodic benefit cost and other    comprehensive income	$	-	$	42		$	-	$	22

	Six Months Ended June 30,						Three Months Ended June 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	$	380		$	356		$	190		$	178
Interest cost		1,035			945			518			473
Expected return on plan assets		-			-			-			-
Amortization of prior service cost		(938	)		(938	)		(469	)		(469	)
Amortized net actuarial loss		523			523			261			261
Net periodic benefit cost		1,000			886			500			443
Changes in assets and benefit obligations recognized in other comprehensive income (loss):
Increase in benefit obligation for plan amendment		-			-			-			-
Net loss		14			-			7			-
Amortization of prior service cost		938			938			469			469
Amortization of loss		(523	)		(523	)		(261	)		(261	)
Total recognized in other comprehensive income		429			415			215			208
Total recognized in net periodic benefit cost and other    comprehensive income	$	1,429		$	1,301		$	715		$	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 June 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	$	2,155	$	1,198	$	-	$	3,353
Derivative liabilities		-		92		-		92

As of June 30, 2010, the Company’s derivative contracts giving rise to the assets 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 asset 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 valued using pricing models based on NYMEX crude oil co ntracts.  The derivative liabilities included in Level 2 valuations are foreign currency forward contracts, valued using month end exchange rates and the variation from each contracts strike price.  Due to the variety of sources available to price month end exchange rates, these contracts were deemed to also have Level 2 inputs.  The Company had no derivative contracts under Level 3 at June 30, 2010.  The Company’s crude call options during the quarter ended June 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 June 30, 2010 and 2009:

	Six Months Ended June 30,					Three Months Ended June 30,
	2010		2009			2010		2009
	(in thousands)
Beginning derivative asset balance	$	-	$	-		$	-	$	370
Net increase in derivative assets		-		249			-		(166	)
Net settlements		-		(164	)		-		(119	)
Transfers in (out) of Level 3		-		-			-		-
Ending derivative asset balance	$	-	$	85		$	-	$	85

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 June 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 June 30, 2010 and December 31, 2009, the carrying amounts of the Company’s 8.5% Senior Notes were $197.6 million ($200.0 million less the unamortized discount of $2.4 million) and $197.5 million ($200.0 million less the unamortized discount of $2.5 million), and the estimated fair values were $202.5 million and $207.0 million, respectively.  Fo r cash and cash equivalents, the carrying amounts at June 30, 2010 and December 31, 2009 of $444.2 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.  For additional fair value disclosures relating to the Company’s derivative contracts, see Note 14, “Fair Value Measurement.”  As of June 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		275
Crude oil contracts to hedge excess intermediate, finished product and crude oil inventory		1,335

As of June 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 5.815% and 5.809%, respectively, as of June 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 $717,000 and $345,000 for the six and three months ended June 30, 2010.  The Company received interest totaling $682,000 from the counterparty in April 2010 and currently has a receivable for accrued interest of $345,000, which is included in “Other Receivables” on the Condensed Consolidated Balance Sheet as of June 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
	June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009
		Fair Value			Fair Value			Fair Value			Fair Value
	(in thousands)
Derivatives not designated    as hedging instruments
Commodity contracts		$	2,318		$	-		$	-		$	6,551
Foreign exchange contracts			-			-			92			-
Interest rate swap contracts			1,035			2			-			-
Other contracts			-			122			-			-
Total derivatives		$	3,353		$	124		$	92		$	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
		Six Months Ended June 30,						Three Months Ended June 30,
		2010			2009			2010			2009
Derivatives not designated    as hedging instruments	Location in Statement    of Operations	(in thousands)
Commodity contracts	Other Revenues	$	25,305		$	(7,473	)	$	28,145		$	(29,653	)
Foreign exchange contracts	Other Revenues		(92	)		799			(92	)		795
Other contracts	Other Revenues		(34	)		249			-			(166	)
Interest rate swap contracts	Interest expense and other financing costs		1,033			-			182			-

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 ($17.3 million incurred as of June 30, 2010) for the cat 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 June 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 ($80.9 million incurred as of June 30, 2010).  T he estimated $95.0 million of expenditures primarily relates to the estimated $94.0 million 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 six and three months ended June 30, 2009, Frontier sold sulfur credits for total proceeds of $1.9 million and $1.3 million, respectively (none in the comparable 2010 periods), 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 June 30, 2010) at the Cheyenne Refinery and $6.0 million ($1.5 million incurred as of June 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 compliance strategy .  Notwithstanding these settlements, many of these same expenditures are required for the Company to comply with preexisting regulatory requirements or to implement its planned facility expansions.  Consequently, the costs associated with these other projects are not included in the totals above.  In addition, the settlement agreement provides for stipulated penalties for violations, which are periodically reported by the Company.  Stipulated penalties under the decree are not automatic but must be requested by one of the agency signatories.  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 six and three months ended June 30, 2010, the Company sold RIN credits for $128,000, which were recorded in “Other revenues” on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  During the six and three months ended June 30, 2009, the Company sold RIN credits for $3.2 million and $2.2 million, respectively.  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.  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 Com pany (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 June 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 June 30, 2010 reflects the estimated present valu e 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 $6.7 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 June 30, 2010 and December 31, 2009, the Company had remaining accruals of $2.2 million 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.  Depending upon information collected during the cleanup, or by a subsequent administrative order or permit, additional remedial action and costs could be required.  Pursuant to this agreement, in the fourth quarter of 2009, the Company complete d 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 Agency. Based on this agreement, the total estimated settlement expense is $2.6 million.  This is comprised of $900,000 penalty (paid in June 2010) and approximately $850,000 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 quar ter 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 June 30, 2010, the Company’s remaining accrual was $870,000.  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 $1.4 million for additional work related to the corrective measures with remaining  accruals of $606,000 and $1.2 million at June 30, 2010 and December 31, 2009, respectively.

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 has been actively considering legislation to reduce emissions of greenhouse gases.  To that end, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” (HR 2454) which would, if subsequently adopted by the U.S. Senate and signed into law by the President, establish a “cap and trade” system with the intent of reducing future greenhouse gas emissions. 0; If enacted, the Company could be required to purchase and surrender allowances for greenhouse gas emissions resulting from its operations and from combustion of fuels that it produces.  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 the federal Clean Air Act and that the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources such as cars and trucks.  On April 17, 2009, the EPA proposed that certain greenhouse gases, including carbon dioxide, present a danger to public health or welfare.  The proposed “endangerment finding” was promulgated on December 7, 2009, opening the door to direct regulation of such greenhouse gases unde r 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 rules 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 that 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.      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 Six Months Ended June 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,795,549		$	-	$	-		$	2,795,549
Other		(11	)		25,443			43		-			25,475
Total revenues		(11	)		2,820,992			43		-			2,821,024
Costs and expenses:
Raw material, freight and other costs		-			2,561,055			-		-			2,561,055
Refinery operating expenses, excluding     depreciation		-			139,023			-		-			139,023
Selling and general expenses, excluding     depreciation		8,787			13,409			-		-			22,196
Depreciation, amortization and     accretion		35			40,350			-		462			40,847
Gain on sales of assets		(1	)		-			-		-			(1	)
Total costs and expenses		8,821			2,753,837			-		462			2,763,120
Operating (loss) income		(8,832	)		67,155			43		(462	)		57,904
Interest expense and other financing    costs		12,976			3,235			-		(930	)		15,281
Interest and investment income		(937	)		(158	)		-		-			(1,095	)
Equity in earnings of subsidiaries		(64,678	)		-			-		64,678			-
Income before income taxes		43,807			64,078			43		(64,210	)		43,718
Provision for income taxes		17,957			25,207			41		(25,337	)		17,868
Net income	$	25,850		$	38,871		$	2	$	(38,873	)	$	25,850

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Six Months Ended June 30, 2009
As Adjusted (Note 2)
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,950,311		$	-	$	-		$	1,950,311
Other		(7	)		(2,239	)		27		-			(2,219	)
Total revenues		(7	)		1,948,072			27		-			1,948,092
Costs and expenses:
Raw material, freight and other costs		-			1,724,729			-		-			1,724,729
Refinery operating expenses, excluding     depreciation		-			148,474			-		-			148,474
Selling and general expenses, excluding     depreciation		10,966			14,321			-		-			25,287
Depreciation, amortization and     accretion		34			35,808			-		285			36,127
Total costs and expenses		11,000			1,923,332			-		285			1,934,617
Operating (loss) income		(11,007	)		24,740			27		(285	)		13,475
Interest expense and other financing    costs		14,765			1,871			-		(2,299	)		14,337
Interest and investment income		(975	)		(312	)		-		-			(1,287	)
Equity in earnings of subsidiaries		(25,071	)		-			-		25,071			-
Income before income taxes		274			23,181			27		(23,057	)		425
Provision for income taxes		196			8,602			10		(8,461	)		347
Net income	$	78		$	14,579		$	17	$	(14,596	)	$	78

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,520,510		$	-		$	-		$	1,520,510
Other		-			28,356			14			-			28,370
Total revenues		-			1,548,866			14			-			1,548,880
Costs and expenses:
Raw material, freight and other costs		-			1,337,291			-			-			1,337,291
Refinery operating expenses, excluding     depreciation		-			64,038			-			-			64,038
Selling and general expenses, excluding     depreciation		4,265			6,955			-			-			11,220
Depreciation, amortization and     accretion		15			20,095			-			230			20,340
Total costs and expenses		4,280			1,428,379			-			230			1,432,889
Operating (loss) income		(4,280	)		120,487			14			(230	)		115,991
Interest expense and other financing    costs		6,803			1,648			-			(405	)		8,046
Interest and investment income		(550	)		(18	)		-			-			(568	)
Equity in earnings of subsidiaries		(119,042	)		-			-			119,042			-
Income before income taxes		108,509			118,857			14			(118,867	)		108,513
Provision for income taxes		42,395			46,225			30			(46,251	)		42,399
Net (loss) income	$	66,114		$	72,632		$	(16	)	$	(72,616	)	$	66,114

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2009
As Adjusted (Note 2)
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,128,140		$	-	$	-		$	1,128,140
Other		-			(26,323	)		27		-			(26,296	)
Total revenues		-			1,101,817			27		-			1,101,844
Costs and expenses:
Raw material, freight and other costs		-			1,081,103			-		-			1,081,103
Refinery operating expenses, excluding     depreciation		-			72,598			-		-			72,598
Selling and general expenses, excluding     depreciation		5,378			7,488			-		-			12,866
Depreciation, amortization and     accretion		18			17,823			-		142			17,983
Total costs and expenses		5,396			1,179,012			-		142			1,184,550
Operating (loss) income		(5,396	)		(77,195	)		27		(142	)		(82,706	)
Interest expense and other financing    costs		7,329			927			-		(1,339	)		6,917
Interest and investment income		(648	)		(123	)		-		-			(771	)
Equity in losses of subsidiaries		76,926			-			-		(76,926	)		-
(Loss) income before income taxes		(89,003	)		(77,999	)		27		78,123			(88,852	)
(Benefit) provision for income taxes		(31,131	)		(26,947	)		10		27,088			(30,980	)
Net (loss) income	$	(57,872	)	$	(51,052	)	$	17	$	51,035		$	(57,872	)

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of June 30, 2010
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	238,647	$	205,593	$	-	$	-		$	444,240
Trade and other receivables, net		128,929		175,184		-		-			304,113
Inventory of crude oil, products and other		-		335,348		-		-			335,348
Deferred income tax assets - current		6,268		6,664		-		(6,664	)		6,268
Other current assets		2,865		7,552		-		-			10,417
Total current assets		376,709		730,341		-		(6,664	)		1,100,386
Property, plant and equipment, net		330		990,547		-		22,923			1,013,800
Deferred turnaround and catalyst costs, net		-		58,772		-		-			58,772
Deferred financing costs, net		2,466		1,501		-		-			3,967
Intangible assets, net		-		1,155		-		-			1,155
Deferred income tax assets - noncurrent		11,219		7,450		-		(7,450	)		11,219
Other assets		3,040		215		-		-			3,255
Receivable from affiliated companies (1)		-		54,057		554		(54,611	)		-
Investment in subsidiaries		1,202,088		-		-		(1,202,088	)		-
Total assets	$	1,595,852	$	1,844,038	$	554	$	(1,247,890	)	$	2,192,554
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	832	$	529,158	$	15	$	-		$	530,005
Accrued liabilities and other		14,488		22,882		-		-			37,370
Total current liabilities		15,320		552,040		15		-			567,375
Long-term debt		347,626		-		-		-			347,626
Contingent income tax liabilities		28,074		2,046		-		-			30,120
Long-term capital lease obligations		-		3,171		-		-			3,171
Other long-term liabilities		2,953		44,454		-		-			47,407
Deferred income tax liabilities		224,408		218,366		-		(218,366	)		224,408
Payable to affiliated companies		5,024		-		270		(5,294	)		-
Shareholders' equity		972,447		1,023,961		269		(1,024,230	)		972,447
Total liabilities and shareholders' equity	$	1,595,852	$	1,844,038	$	554	$	(1,247,890	)	$	2,192,554
(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 Six Months Ended June 30, 2010
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	25,850		$	38,871		$	2		$	(38,873	)	$	25,850
Adjustments to reconcile net income    to net cash from operating activities:
Equity in earnings of subsidiaries		(64,678	)		-			-			64,678			-
Depreciation, amortization and    accretion, including amortization    of deferred turnaround costs		35			49,849			-			462			50,346
Deferred income tax provision		13,145			-			-			-			13,145
Stock-based compensation expense		8,613			-			-			-			8,613
Excess income tax benefits of    stock-based compensation		(101	)		-			-			-			(101	)
Intercompany income taxes		-			25,301			36			(25,337	)		-
Intercompany dividends		6,200			-			-			(6,200	)		-
Other intercompany transactions		4,350			(4,312	)		(38	)		-			-
Amortization of debt issuance costs		391			353			-			-			744
Senior notes discount amortization		141			-			-			-			141
Allowance for investment loss and    bad debts		(4	)		(48	)		-			-			(52	)
Gain on sales of assets		(1	)		-			-			-			(1	)
Increase (decrease) in other long-term    liabilities		105			(6,292	)		-			-			(6,187	)
Changes in deferred turnaround costs,    deferred catalyst costs and other		625			275			-			-			900
Changes in working capital from    operations		42,165			(65,874	)		-			193			(23,516	)
Net cash provided by operating activities		36,836			38,123			-			(5,077	)		69,882
Cash flows from investing activities:
Additions to property, plant and    equipment		9			(39,630	)		-			(1,123	)		(40,744	)
Proceeds from sales of assets		1			-			-			-			1
Net cash provided by (used in) investing    activities		10			(39,630	)		-			(1,123	)		(40,743	)
Cash flows from financing activities:
Purchase of treasury stock		(3,582	)		-			-			-			(3,582	)
Dividends paid		(6,493	)		-			-			-			(6,493	)
Excess income tax benefits of    stock-based compensation		101			-			-			-			101
Debt issuance costs and other		-			(205	)		-			-			(205	)
Intercompany dividends		-			(6,200	)		-			6,200			-
Net cash used in financing activities		(9,974	)		(6,405	)		-			6,200			(10,179	)
Increase (decrease) in cash and cash    equivalents		26,872			(7,912	)		-			-			18,960
Cash and cash equivalents, beginning of    period		211,775			213,505			-			-			425,280
Cash and cash equivalents, end of    period	$	238,647		$	205,593		$	-		$	-		$	444,240

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 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	$	78		$	14,579		$	17		$	(14,596	)	$	78
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(25,071	)		-			-			25,071			-
Depreciation, amortization and    accretion, including amortization    of deferred turnaround costs		34			45,722			-			285			46,041
Deferred income tax provision		4,522			-			-			-			4,522
Stock-based compensation expense		10,753			-			-			-			10,753
Excess income tax benefits of    stock-based compensation		(151	)		-			-			-			(151	)
Intercompany income taxes		26,000			(17,549	)		10			(8,461	)		-
Other intercompany transactions		8,514			(8,488	)		(26	)		-			-
Amortization of debt issuance costs		391			353			-			-			744
Senior notes discount amortization		129			-			-			-			129
Allowance for investment loss and    bad debts		-			500			-			-			500
Increase in other long-term liabilities		1,178			1,297			-			-			2,475
Changes in deferred turnaround costs,    deferred catalyst costs and other		(416	)		(840	)		-			-			(1,256	)
Changes in working capital from    operations		16,070			17,299			(1	)		(459	)		32,909
Net cash provided by operating activities		42,031			52,873			-			1,840			96,744
Cash flows from investing activities:
Additions to property, plant and    equipment		(91	)		(74,778	)		-			(1,840	)		(76,709	)
Net cash used in investing activities		(91	)		(74,778	)		-			(1,840	)		(76,709	)
Cash flows from financing activities:
Purchase of treasury stock		(2,588	)		-			-			-			(2,588	)
Proceeds from issuance of common stock		70			-			-			-			70
Dividends paid		(12,660	)		-			-			-			(12,660	)
Excess income tax benefits of    stock-based compensation		151			-			-			-			151
Debt issuance costs and other		2			(185	)		-			-			(183	)
Net cash used in financing activities		(15,025	)		(185	)		-			-			(15,210	)
Increase (decrease) in cash and cash    equivalents		26,915			(22,090	)		-			-			4,825
Cash and cash equivalents, beginning of    period		254,548			228,984			-			-			483,532
Cash and cash equivalents, end of    period	$	281,463		$	206,894		$	-		$	-		$	488,357

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.

Six months ended June 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 six months ended June 30, 2010 of $25.9 million, or $0.25 per diluted share, compared to net income of $78,000, or $0.00 per diluted share, earned in the same period in 2009.  Our operating income of $57.9 million for the six months ended June 30, 2010 increased $44.4 million from the $13.5 million of operating income for the comparable period in 2009.  The increase in our operating income from the first six months of 2009 to the first six months of 2010 was due to the improvement of the diesel crack spread (from $8.98 per barrel in 2009 to $10.61 per barrel in 2010).  In addition, the favorable contango markets 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 differ ential decreased to $2.81 per barrel for the six months ended June 30, 2010 from $4.24 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 $5.52 per barrel for the six months ended June 30, 2009 to $7.11 per barrel for the comparable period of 2010.  The WTI/WTS crude oil differential increased from $1.36 per barrel for the six months ended June 30, 2009 to $1.94 per barrel for the comparable period of 2010.  These improvements to operating income were offset by a decrease in the gasoline crack spread (from $9.03 per barrel in 2009 to $8.20 per barrel in 2010) during the six months ended June 30, 2010.

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.  However, in the second quarter of 2010 we experienced an improvement in the light/heavy crude oil differential as well as an increase in product demand.  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 inclu de 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.  In the first half of 2010, we continued to process a higher percentage of light crude oils and reduced controllable refinery operating expenses.  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, which is also necessary to accomplish a portion of these goals.  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 when industry conditions will improve or what additional steps we may take in r esponse to the currently difficult refining conditions.  We will continue to evaluate the need to impair any of our assets should market conditions justify this action.

Specific Variances

Refined product revenues.  Refined product revenues increased $845.2 million, or 43%, from $1.95 billion to $2.80 billion for the six months ended June 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 six months ended June 30, 2010 ($25.86 higher average price per sales barrel), despite a 1% decrease in sales volumes.

Manufactured product yields.  Yields decreased 1,791 bpd at the El Dorado Refinery and increased 2,699 bpd at the Cheyenne Refinery for the six months ended June 30, 2010 compared to same period in 2009.

Other revenues.  Other revenues increased $27.7 million to a gain of $25.5 million for the six months ended June 30, 2010, compared to a loss of $2.2 million for the same period in 2009, the primary source of this increase being $25.3 million in net realized and unrealized gains from derivative contracts to hedge in-transit crude oil and excess inventories in the six  months ended June 30, 2010, compared to $7.5 million of losses in the six months ended June 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 six months ended June 30, 2009 compared to none in the comparable 2010 period, a nd $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 $836.3 million, from $1.72  billion in the six months ended June 30, 2009 to $2.56 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 six months ended June 30, 2010 when compared to the same period in 2009.

The Cheyenne Refinery raw material, freight and other costs of $78.19 per sales barrel for the six months ended June 30, 2010 increased from $52.14 per sales barrel in the same period in 2009 due to higher average crude oil prices, higher crude oil charges, a lower average laid-in crude oil differential and increased purchased products.  The average laid-in crude oil differential for the Cheyenne Refinery decreased to $4.17 per barrel for the six months ended June 30, 2010, which reflected the higher percentage of light crude oil charged in 2010, compared to $4.60 per barrel in the same period in 2009.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $8.76 per barrel in the six months ended June 30, 2010 compared to $5.39 per barrel in the same period in 2009.  Despite the improveme nt in the light/heavy crude oil differential, it did not justify increased use of heavy crude oil in the six months ended June 30, 2010.

The El Dorado Refinery raw material, freight and other costs of $76.52 per sales barrel for the six months ended June 30, 2010 increased from $51.18 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, partially offset by lower crude oil charges.  The average laid-in crude oil differential decreased to $2.34 per barrel for the six months ended June 30, 2010 compared to $4.13 per barrel in the same period in 2009.  The WTI/WTS crude oil differential increased from an average of $1.36 per barrel in the six month period ended June 30, 2009 to $1.94 per barrel in the same period in 2010.  The light/heavy crude oil differential increased from an average of $5.72 per barrel in the six month period ended June 30, 2009 to $6. 16 per barrel in the same period in 2010.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $139.0 million in the six months ended June 30, 2010 compared to $148.5 million in the comparable period of 2009.

The Cheyenne Refinery operating expenses, excluding depreciation, were $44.9 million for the six months ended June 30, 2010 compared to $55.1 million in the comparable period of 2009.  The primary areas of decreased costs were: decreased environmental and legal expenses ($5.3 million, of which $4.5 million was attributable to the EPA Complaint expense adjustment), reduced maintenance costs ($3.5 million due to planned and unplanned repairs and outages incurred in 2009 and certain improved efficiencies in 2010), decreased turnaround amortization ($2.4 million due to deferring turnarounds), decreased additives and chemicals costs ($2.3 million), and lower salaries and benefits ($593,000), partially offset by increased natural gas costs ($4.6 million due to higher prices and volumes).

The El Dorado Refinery operating expenses, excluding depreciation, were $94.1 million for the six months ended June 30, 2010, increasing from $93.4 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 ($5.1 million due to significantly higher prices and volumes), increased turnaround amortization ($2.0 million mainly due to the fall 2009 turnarounds), and electricity ($1.3 million due higher volumes), mostly offset by lower maintenance costs ($2.0 million), lower additives and chemicals costs ($2.0 million), lower environmental expenses ($1.1 million), reduced consulting and legal expenses ($940,000),  reduced insurance costs ($725,000), and lower property and other taxes ($219,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, decreased $3.1 million, or 12%, from $25.3 million for the six months ended June 30, 2009 to $22.2 million for the six months ended June 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 $4.7 million, or 13%, for the six months ended June 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 $15.3 million for the six months ended June 30, 2010 increased from $14.3 million in the comparable period in 2009.  Capitalized interest for the six months ended June 30, 2010 was $931,000 compared to $2.3 million for the same period in 2009.  Average debt outstanding was $350.0 million for both the six months ended June 30, 2010 and 2009 (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $192,000, from $1.3 million in the six months ended June 30, 2009, to $1.1 million in the six months ended June 30, 2010.

Provision for income taxes.  The provision for income taxes for the six months ended June 30, 2010 was $17.9 million on pretax income of $43.7 million (or 40.9%).  Our provision for income taxes for the six months ended June 30, 2009 was $347,000 on pretax income of $425,000 (or 81.7%).  The 2009 period effective tax rate was distorted due to the impact of $1.5 million in permanent book-tax differences (increasing taxable income) on a small pre-tax income. The planned carryback of the 2009 net operating loss to 2007 increased the effective tax rate for the six months ended June 30, 2010 by approximately 6.0% from the estimated reduction of the Section 199 manufacturer’s deduction.

Three months ended June 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 June 30, 2010 of $66.1 million, or $0.63 per diluted share, compared to a net loss of $57.9 million, or $0.56 per diluted share, in the same period in 2009.  Our operating income of $116.0 million for the three months ended June 30, 2010 increased $198.7 million from the $82.7 million operating loss for the comparable period in 2009.  The increase in our operating income from the three months ended June 30, 2009 to the comparable period of 2010 was due to improvement of the diesel crack spread (from $6.28 per barrel in 2009 to $13.81 per barrel in 2010) and an increase in the light/heavy and WTI/WTS crude oil differentials.  The average laid-in crude oil differential improved to $3.66 per barrel for the three months ended June 30, 2010 compared to $2.41 per barrel in the comparable period of 2009 due to the improved light/heavy and WTI/WTS crude oil differentials and a stronger contango market in 2010.  The light/heavy crude oil differential increased from $4.53 per barrel for the three months ended June 30, 2009 to $9.33 per barrel for the comparable period of 2010.  The WTI/WTS crude oil differential increased from $1.02 per barrel for the three months ended June 30, 2009 to $2.11 per barrel for the comparable period of 2010. The improvements in net income were offset by a lower gasoline crack spread (from $10.85 per barrel in 2009 to $10.02 per barrel in 2010) during the three months ended June 30, 2010.

Specific Variances

Refined product revenues.  Refined product revenues increased $392.4 million, or 35%, from $1.13 billion to $1.52 billion for the three months ended June 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 June 30, 2010 ($20.76 higher average price per sales barrel), and a 2% increase in sales volumes.

Manufactured product yields.  Yields increased 6,036 bpd at the El Dorado Refinery and increased 5,990 bpd at the Cheyenne Refinery for the three months ended June 30, 2010 compared to same period in 2009.  The increase in the El Dorado Refinery manufactured product yields for the second quarter of 2010, when compared to 2009, was due to significant operational downtime from a storm in May of 2009.  The increase in the Cheyenne Refinery manufactured product yields for the second quarter of 2010, when compared to 2009, was due to various non-recurring unit slowdowns and shutdowns that occurred in the second quarter of 2009.

Other revenues.  Other revenues increased $54.7 million to a gain of $28.4 million for the three months ended June 30, 2010, compared to a loss of $26.3 million for the same period in 2009, the primary source of this increase being $28.1 million in net realized and unrealized gains from derivative contracts to hedge in-transit crude oil and excess inventories in the three months ended June 30, 2010, compared to $29.7 million of losses in the three months ended June 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 $1.3 million during the three months ended June 30, 2009 compared to none in the comparable 2010 period, an d $2.2 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 $256.2 million, from $1.08 billion in the three months ended June 30, 2009 to $1.34 billion in the same period for 2010.  The increase in raw material, freight and other costs was due to higher average crude oil prices, and increased overall crude oil charges, partially offset by higher crude oil differentials and decreased purchased products during the three months ended June 30, 2010 when compared to the same period in 2009.

The Cheyenne Refinery raw material, freight and other costs of $75.86 per sales barrel for the three months ended June 30, 2010 increased from $62.84 per sales barrel in the same period in 2009 due to higher average crude oil prices and higher crude oil charges, partially offset by decreased purchased products and higher crude oil differentials.  The average laid-in crude oil differential for the Cheyenne Refinery was $5.45 per barrel for the three months ended June 30, 2010 compared to $3.42 per barrel in the same period in 2009 due to an improved light/heavy crude oil differential in the second quarter of 2010.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $11.06 per barrel in the three months ended June 30, 2010 compared to $4.93 per barrel in the same period in 2009.

The El Dorado Refinery raw material, freight and other costs of $75.12 per sales barrel for the three months ended June 30, 2010 increased from $61.96 per sales barrel in the same period in 2009 primarily due to higher average crude oil prices and higher crude oil charges, partially offset by higher crude oil differentials.  The average laid-in crude oil differential increased to $3.04 for the three months ended June 30, 2010 from $2.07 per barrel in the same period in 2009, with the increase resulting from the improved contango market and higher WTI/WTS and light/heavy crude oil differentials in the second quarter of 2010.  The WTI/WTS crude oil differential increased from an average of $1.02 per barrel in the three month period ended June 30, 2009 to $2.11 per barrel in the same period in 2010.  The light/ heavy crude oil differential increased from an average of $3.90 per barrel in the three month period ended June 30, 2009 to $8.37 per barrel in the same period in 2010.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $64.0 million in the three months ended June 30, 2010 compared to $72.6 million in the comparable period of 2009.

The Cheyenne Refinery operating expenses, excluding depreciation, were $19.2 million for the three months ended June 30, 2010 compared to $26.8 million in the comparable period of 2009.  The primary areas of decreased costs were: decreased environmental and legal expenses ($4.9 million, of which $4.2 million was attributable to the EPA Complaint expense adjustment), decreased additives and chemicals costs ($1.4 million), decreased turnaround amortization ($1.4 million due to deferring turnarounds), reduced maintenance costs ($858,000 due to planned and unplanned repairs and outages incurred in 2009 and certain improved efficiencies in 2010), and lower salaries and benefits ($558,000), partially offset by increased natural gas costs ($1.6 million due to higher prices and volumes).

The El Dorado Refinery operating expenses, excluding depreciation, were $44.8 million for the three months ended June 30, 2010, decreasing from $45.8 million in the same three month period of 2009.  Primary areas of decreased costs and variance amounts for the 2010 period compared to the 2009 period were: reduced maintenance costs ($2.0 million primarily due to storm damage that occurred in 2009), lower additives and chemicals costs ($726,000), reduced consulting and legal expenses ($543,000), partially offset by increased natural gas costs ($1.6 million due to higher prices and volumes), an increase in turnaround amortization ($886,000), and higher electricity costs ($811,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, decreased $1.6 million, or 13%, from $12.9 million for the three months ended June 30, 2009 to $11.2 million for the three months ended June 30, 2010, primarily due to lower salaries and benefits and stock-based compensation expense in the 2010 period.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $2.4 million, or 13%, for the three months ended June 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 $8.0 million for the three months ended June 30, 2010 increased $1.1 million from $6.9 million in the comparable period in 2009.  Capitalized interest for the three months ended June 30, 2010 was $405,000 compared to $1.3 million for the same period in 2009.  Average debt outstanding was $350.0 million for both the three months ended June 30, 2010 and 2009 (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $203,000, from $771,000 in the three months ended June 30, 2009, to $568,000 in the three months ended June 30, 2010.

Provision (benefit) for income taxes.  The provision for income taxes for the three months ended June 30, 2010 was $42.4 million on pretax income of $108.5 million (or 39.1%).  Our benefit for income taxes for the three months ended June 30, 2009 was $31.0 million on a pretax loss of $88.9 million (or 34.9%).  The planned carryback of the 2009 net operating loss to 2007 increased the effective tax rate for the three months ended June 30, 2010 by approximately 2.4% from the estimated reduction of the Section 199 manufacturer’s deduction.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities.  Net cash provided by operating activities was $69.9 million for the six months ended June 30, 2010 compared to net cash provided by operating activities of $96.7 million during the six months ended June 30, 2009.  Working capital changes contributed to lower cash flows from operations during the 2010 period.  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 $23.5 million of cash during the first six months of 2010 compared to providing $32.9 million for the same period in 2009.  The $23.5 million working capital change for the 2010 period primarily resulted from increased inventory of $41.9 million, increased receivables of $26.3 million, and decreased current accrued liabilities of $22.6 million, offset by $63.2 million of increased payables (primarily crude payables).  In the first six months of 2009, the working capital change of $32.9 million primarily resulted from a $157.3 million increase in payables, offset by $78.6 million of increased inventory, and a $49.7 million decrease in receivables.  During the six months ended June 30, 2010, we received federal and state income tax refunds of $43.9 million.  In July 2010, subsequent to the balance sheet date, we received federal and state income tax refunds of $19.7 million.  At June 30, 2010, we had $444.2 million of cash and cash equivalents, $533.0 million of working capital, no cash borrowings under our revolving credit facility, and $259.7 million of borrowing base availability for cash borrowings under our $500.0 million revolving credit facility.

Cash flows used in investing activities.  Capital expenditures during the first six months of 2010 were $40.7 million, which included approximately $21.2 million for the El Dorado Refinery and $19.2 million for the Cheyenne Refinery. The $21.2 million of capital expenditures for our El Dorado Refinery included $7.0 million on the gasoil hydrotreater revamp, $1.9 million on the catalytic cracker regenerator emission control project as well as operational, payout, safety, administrative, environmental and optimization projects.  The $19.2 million of capital expenditures for our Cheyenne Refinery included $8.3 million for the cat gas hydrotreater project, $2.4 million for the liquefied petroleum gas recovery project as well as environmental, operational, safety, adm inistrative and payout projects.

Cash flows from financing activities.  During the six months ended June 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 six months of 2010.  We also paid $6.5 million in dividends during the six months ended June 30, 2010.

As of June 30, 2010, we had $347.6 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $240.3 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 June 30, 2010.  Shareholders’ equity as of June 30, 2010 was $972.4 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 interest rate coverage ratio 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 Frontier 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 $94.0 million ($80.7 million incurred as of June 30, 2010) (see “Environmental” in Note 16 in the “Notes to Consolidated Financial Statements”).  The project will also result in 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 June 30, 2010, outstanding non-cancelable purchase commitments for the gasoil hydrotreater revamp were $1.6 million.  At the Cheyenne Refinery, the cat 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 ($17.3 million incurred as of June 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 cat 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 ($4.4 million incurred as of June 30, 2010) and is estimated to be substantially completed b y mid-2011.  At June 30, 2010, there were no material outstanding non-cancellable purchase commitments related to the cat gas hydrotreater project and the LPG recovery project.  The above amounts include estimated capitalized interest.

2010 cash capital expenditures.  Cash capital expenditures during 2010 aggregating approximately $113.0 million are currently planned ($40.7 million spent through June 30, 2010).  The 2010 capital expenditures include $59.0 million at our Cheyenne Refinery, $52.0 million at our El Dorado Refinery, $1.6 million for our pipeline and product terminals and blending facility and $620,000 at our Denver and Houston offices.  The $59.0 million of planned capital expenditures for our Cheyenne Refinery includes $28.0 million for the LPG recovery project and $10.0 million for the cat gasoline hydrotreater project, both mentioned above, as well as environmental, operational, safety, payout and administrative projects.  The $52.0 million of planned capital expenditures for our El Dorado Refinery includes $23.0 million for the gasoil hydrotreater revamp project, as mentioned above, as well as environmental, operational, safety, payout and administrative projects.  We expect that our 2010 capital expenditures will be funded with cash generated by our operations and/or by using a portion of our existing cash balance or additional borrowings, if necessary.  We 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 six and three months ended June 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:
	Six Months Ended June 30,				Three Months Ended June 30,
	2010		2009		2010		2009
Charges (bpd)
Light crude		63,826		49,928		63,519		64,663
Heavy and intermediate crude		105,285		116,928		115,084		103,934
Other feed and blendstocks		12,603		14,954		12,414		12,554
Total		181,714		181,810		191,017		181,151
Manufactured product yields (bpd)
Gasoline		87,590		83,248		92,167		83,723
Diesel and jet fuel		70,177		72,418		74,215		74,059
Asphalt		3,483		1,722		3,187		2,055
Other		16,747		19,701		17,241		14,948
Total		177,997		177,089		186,810		174,785
Total product sales (bpd)
Gasoline		95,460		93,625		101,310		95,231
Diesel and jet fuel		69,861		72,369		73,761		74,139
Asphalt		3,152		1,293		3,463		1,464
Other		15,366		18,004		16,586		20,272
Total		183,839		185,291		195,120		191,106
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	84.01	$	58.15	$	85.63	$	64.87
Raw material, freight and other costs (1)		76.97		51.43		75.32		62.17
Refinery operating expenses, excluding depreciation		4.18		4.43		3.61		4.17
Depreciation, amortization and accretion		1.22		1.07		1.14		1.03
Average NYMEX WTI (per barrel)	$	78.35	$	51.51	$	78.16	$	59.83
Average laid-in crude oil differential (per barrel)		2.81		4.24		3.66		2.41
Average light/heavy differential (per barrel)		7.11		5.52		9.33		4.53
Average gasoline crack spread (per barrel)		8.20		9.03		10.02		10.85
Average diesel crack spread (per barrel)		10.61		8.98		13.81		6.28
Average sales price (per sales barrel)
Gasoline	$	87.72	$	62.58	$	89.17	$	71.94
Diesel and jet fuel		89.99		61.68		92.40		66.72
Asphalt		72.32		56.68		72.96		65.60
Other		36.25		21.07		36.63		24.87
(1) Prior period amounts are adjusted to reflect current year presentation on a LIFO inventory basis.

Cheyenne Refinery:
	Six Months Ended June 30,					Three Months Ended June 30,
	2010			2009		2010		2009
Charges (bpd)
Light crude		29,550			15,536		32,334		19,149
Heavy and intermediate crude		13,198			25,578		13,907		22,765
Other feed and blendstocks		2,201			1,367		2,200		744
Total		44,949			42,481		48,441		42,658
Manufactured product yields (bpd)
Gasoline		21,526			18,468		22,879		18,588
Diesel		15,671			14,833		16,553		14,987
Asphalt		3,483			1,722		3,187		2,055
Other		2,782			5,740		4,052		5,051
Total		43,462			40,763		46,671		40,681
Total product sales (bpd)
Gasoline		27,870			26,163		29,339		24,424
Diesel		15,669			14,676		16,457		15,185
Asphalt		3,152			1,293		3,463		1,464
Other		2,257			4,588		2,351		4,151
Total		48,948			46,720		51,610		45,224
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	85.45		$	58.05	$	87.24	$	66.52
Raw material, freight and other costs (1)		78.19			52.14		75.86		62.84
Refinery operating expenses, excluding depreciation		5.07			6.51		4.09		6.52
Depreciation, amortization and accretion		1.73			1.73		1.59		1.76
Average laid-in crude oil differential (per barrel)	$	4.17		$	4.60	$	5.45	$	3.42
Average light/heavy crude oil differential (per barrel)		8.76			5.39		11.06		4.93
Average gasoline crack spread (per barrel)		8.47			8.69		10.88		12.95
Average diesel crack spread (per barrel)		12.96			10.79		16.16		8.72
Average sales price (per sales barrel)
Gasoline	$	87.60	��	$	62.37	$	89.15	$	73.80
Diesel		92.08			64.36		94.72		69.41
Asphalt		72.32			56.68		72.96		65.60
Other		31.23			13.57		32.11		13.49
(1) Prior period amounts are adjusted to reflect current year presentation on a LIFO inventory basis.

El Dorado Refinery:
	Six Months Ended June 30,				Three Months Ended June 30,
	2010		2009		2010		2009
Charges (bpd)
Light crude		34,275		34,392		31,185		45,514
Heavy and intermediate crude		92,087		91,350		101,177		81,170
Other feed and blendstocks		10,402		13,587		10,213		11,810
Total		136,764		139,329		142,575		138,494
Manufactured product yields (bpd)
Gasoline		66,064		64,780		69,288		65,135
Diesel and jet fuel		54,506		57,585		57,662		59,071
Other		13,965		13,961		13,189		9,897
Total		134,535		136,326		140,139		134,103
Total product sales (bpd)
Gasoline		67,589		67,463		71,971		70,807
Diesel and jet fuel		54,192		57,693		57,304		58,955
Other		13,109		13,416		14,235		16,121
Total		134,890		138,572		143,510		145,883
Refinery operating margin information (per sales barrel)
Refined products revenue	$	83.49	$	58.19	$	85.06	$	64.36
Raw material, freight and other costs (1)		76.52		51.18		75.12		61.96
Refinery operating expenses, excluding depreciation		3.85		3.72		3.43		3.45
Depreciation, amortization and accretion		1.04		0.85		0.98		0.80
Average laid-in crude oil differential (per barrel)	$	2.34	$	4.13	$	3.04	$	2.07
Average WTI/WTS crude oil differential (per barrel)		1.94		1.36		2.11		1.02
Average light/heavy crude oil differential (per barrel)		6.16		5.72		8.37		3.90
Average gasoline crack spread (per barrel)		8.09		9.16		9.67		10.13
Average diesel crack spread (per barrel)		9.93		8.52		13.13		5.65
Average sales price (per sales barrel)
Gasoline	$	87.77	$	62.66	$	89.17	$	71.29
Diesel and jet fuel		89.39		61.00		91.73		66.02
Other		37.11		23.64		37.38		27.80
(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 gains as of June 30, 2010 are summarized below:

Commodity	Period	Volume  (thousands of bbls)		Expected Close  Out Date	Unrealized Net Gains (in thousands)
Crude Oil	August 2010		1,156	July 2010	$	1,871
Crude Oil	September 2010		454	August 2010		447

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 June 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 cash fl ow 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 transaction s using market prices and other economic data and assumptions were used to value our interest rate swaps.

	As of June 30, 2010
	Expected maturity dates																	Fair
	2010		2011			2012		2013		2014		Thereafter			Total			value
	(in thousands)
Long-term debt:
Fixed rate	$	-	$	150,000		$	-	$	-	$	-	$	200,000		$	350,000		$	353,063
Average interest rate		-		6.625	%		-		-		-		8.500	%		7.696	%
Interest rate swaps:
Fixed to variable	$	-	$	150,000		$	-	$	-	$	-	$	-		$	150,000		$	1,035
Average pay rate		-		6.073	%		-		-		-		-			6.073	%
Average receive rate		-		6.625	%		-		-		-		-			6.625	%
	As of December 31, 2009
	Expected maturity dates																	Fair
		2010		2011			2012		2013		2014	Thereafter			Total				value
	(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 six and three months ended June 30, 2010, we incurred pre-tax hedging gains of $25.3 million and $28.1 million, compared to $7.5 million and $29.7 million in pre-tax hedging losses in the comparable period of 2009, recorded in “Other revenues” in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  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 6. Exhibits –   31.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   31.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   32.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   32.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   101 – The following materials from Frontier Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the six and three months ended June 30, 2010 and 2009, (ii) Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009, (iii) Condensed Consolidated Statements of Cash Flows for the six months ended June 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: August 5, 2010