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, 2009

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  ¨  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 3, 2009:  104,666,043

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2009

INDEX

Item 1.             Financial Statements

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

Item 3.             Quantitative and Qualitative Disclosures About Market Risk

Item 4.             Controls and Procedures

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

PART I - FINANCIAL INFORMATION

ITEM 1.               FINANCIAL STATEMENTS

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited, in thousands, except per share data)
	Six Months Ended June 30,						Three Months Ended  June 30,
	2009			2008			2009			2008
Revenues:
Refined products	$	1,950,311		$	3,089,598		$	1,128,140		$	1,882,010
Other		(2,219	)		(137,259	)		(26,296	)		(115,454	)
		1,948,092			2,952,339			1,101,844			1,766,556
Costs and expenses:
Raw material, freight and other costs		1,533,989			2,574,026			914,092			1,574,898
Refinery operating expenses, excluding depreciation		148,474			168,594			72,598			81,034
Selling and general expenses, excluding depreciation		25,287			22,503			12,866			12,148
Depreciation, amortization and accretion		36,127			31,437			17,983			16,497
Gain on sales of assets		-			(44	)		-			(7	)
		1,743,877			2,796,516			1,017,539			1,684,570
Operating income		204,215			155,823			84,305			81,986
Interest expense and other financing costs		14,337			4,563			6,917			2,924
Interest and investment income		(1,287	)		(3,635	)		(771	)		(1,322	)
		13,050			928			6,146			1,602
Income before income taxes		191,165			154,895			78,159			80,384
Provision for income taxes		67,865			49,610			28,318			21,068
Net income	$	123,300		$	105,285		$	49,841		$	59,316
Comprehensive income	$	123,175		$	104,223		$	49,778		$	59,204
Basic earnings per share of common stock	$	1.19		$	1.02		$	0.48		$	0.58
Diluted earnings per share of common stock	$	1.18		$	1.02		$	0.47		$	0.57
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, 2009 and December 31, 2008	2009			2008
ASSETS
Current assets:
Cash, including cash equivalents of $480,152 and $482,415 at 2009 and 2008, respectively	$	488,357		$	483,532
Trade receivables, net of allowance of $1,000 and $500 at 2009 and 2008, respectively		166,588			84,110
Income taxes receivable		64,515			116,118
Other receivables		8,196			25,216
Inventory of crude oil, products and other		525,512			256,129
Deferred income taxes		6,905			8,841
Commutation account		-			6,319
Other current assets		25,600			37,038
Total current assets		1,285,673			1,017,303
Property, plant and equipment, at cost:
Refineries, pipeline and terminal equipment		1,362,392			1,291,106
Furniture, fixtures and other equipment		16,140			15,638
		1,378,532			1,306,744
Accumulated depreciation and amortization		(407,885	)		(373,301	)
Property, plant and equipment, net		970,647			933,443
Deferred turnaround costs		40,311			47,465
Deferred catalyst costs		7,860			9,726
Deferred financing costs, net of accumulated amortization of $3,149 and $2,404 at 2009 and 2008, respectively		5,455			6,201
Intangible assets, net of accumulated amortization of $553 and $492 at 2009 and 2008, respectively		1,277			1,338
Other assets		3,355			2,993
Total assets	$	2,314,578		$	2,018,469
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	462,060		$	308,867
Accrued liabilities and other		78,467			57,084
Total current liabilities		540,527			365,951
Long-term debt		347,350			347,220
Contingent income tax liabilities		28,482			28,057
Post-retirement employee liabilities		32,287			31,128
Long-term capital lease obligation		3,356			3,548
Other long-term liabilities		13,299			12,211
Deferred income taxes		182,014			179,214
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		243,086			236,183
Retained earnings		1,262,206			1,151,676
Accumulated other comprehensive loss		(848	)		(723	)
Treasury stock, at cost, 27,184,313 and 27,945,884 shares at 2009 and 2008, respectively		(394,917	)		(393,732	)
Total shareholders' equity		1,167,263			1,051,140
Total liabilities and shareholders' equity	$	2,314,578		$	2,018,469
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,
	2009			2008
Cash flows from operating activities:
Net income	$	123,300		$	105,285
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, amortization and accretion		46,041			39,786
Deferred income taxes		4,813			13,470
Stock-based compensation expense		10,753			9,802
Excess income tax benefits of stock-based compensation		(151	)		(3,935	)
Amortization of debt issuance costs		744			343
Senior Notes discount amortization		129			-
Allowance for investment loss and bad debts		500			-
Gain on sales of assets		-			(44	)
Amortization of long-term prepaid insurance		-			606
Increase in other long-term liabilities		2,890			1,888
Changes in deferred turnaround costs, deferred catalyst costs and other		(1,256	)		(29,260	)
Changes in working capital from operations		(91,019	)		(18,162	)
Net cash provided by operating activities		96,744			119,779
Cash flows from investing activities:
Additions to property, plant and equipment		(76,709	)		(115,021	)
Proceeds from sales of assets		-			45
El Dorado Refinery contingent earn-out payment		-			(7,500	)
Net cash used in investing activities		(76,709	)		(122,476	)
Cash flows from financing activities:
Purchase of treasury stock		(2,588	)		(66,403	)
Proceeds from issuance of common stock		70			126
Dividends paid		(12,660	)		(10,651	)
Excess income tax benefits of stock-based compensation		151			3,935
Debt issuance costs and other		(183	)		(469	)
Net cash used in financing activities		(15,210	)		(73,462	)
Increase (decrease) in cash and cash equivalents		4,825			(76,159	)
Cash and cash equivalents, beginning of period		483,532			297,399
Cash and cash equivalents, end of period	$	488,357		$	221,240
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	11,777		$	1,202
Cash paid during the period for income taxes		31,150			42,190
Cash refunds of income taxes		51,604			24,548
Noncash investing activities - accrued capital expenditures, end of period		23,302			18,069
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 also owns Ethanol Management Company (“EMC”), a products terminal and blending facility located near Denver, Colorado.  The Company utilizes the equity method of accounting for investments in entities in which it has the ability to exercise significant influence.  Entities in which the Company has the ability to exercise control are consolidated.  All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States.  The Rocky Mountain region includes the states of Colorado, Wyoming, western Nebraska, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and South Dakota.  The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke.  The operations of refining and marketing of petroleum products are considered part of one reporting segment.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and include all adjustments (comprised of only normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been condensed or omitted pursuant to such rules and regulations.  The Company believes that the disclosures contained herein are adequate to make the information presented not misleading.  The condensed consolidated financial statements included herein should be read in conjunction with the financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2008.  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.  The Company has evaluated subsequent events through the date the financial statements were issued and has no material subsequent events to report.

Earnings per share

The Company computes basic earnings per share (“EPS”) by dividing net income 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 outstanding during the period.  The basic and diluted average shares outstanding were as follows:

	Six Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009		2008
Basic		103,430,428		103,082,444		103,498,642		102,934,252
Diluted		104,696,801		103,619,761		104,999,187		103,470,989

For the six and three months ended June 30, 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.  For the six and three months ended June 30, 2008, there were 449,591 outstanding stock options that could potentially dilute EPS in future years that were not included in the computation of diluted EPS because they were anti-dilutive.

The Company’s Board of Directors declared quarterly cash dividends of $0.06 per share of common stock in November 2008, and February and April of 2009, which were paid in January, April and July of 2009, respectively.  The total cash required for the dividend declared in April 2009 was approximately $6.2 million and was reflected in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheet as of June 30, 2009.

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 generally accepted accounting principles 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 Income and Comprehensive Income.  For the six and three months ended June 30, 2009 the Company recognized a loss in “Other Revenues” of $875,000 and $764,000, respectively, due the translation of its foreign denominated assets and liabilities.

New accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued FAS No. 157, “Fair Value Measurements.”  FAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement.  Where applicable, this statement simplifies and codifies fair value related guidance previously issued within GAAP.  FAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  The Company partially adopted FAS No. 157 as of January 1, 2008, pursuant to FASB Staff Position (“FSP”) FAS No. 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of FAS No. 157 for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until fiscal years beginning after November 15, 2008.  FSP FAS No. 157-2 states that a measurement is recurring if it happens at least annually and defines non-financial assets and non-financial liabilities as all assets and liabilities other than those meeting the definition of a financial asset or financial liability in FAS No. 159.  The statement also notes that if FAS No. 157 is not applied in its entirety, the Company must disclose (1) that it has only partially adopted FAS No. 157 and (2) the categories of assets and liabilities recorded or disclosed at fair value to which the statement was not applied.  The Company chose to adopt FSP FAS No. 157-2 as of January 1, 2008.  Therefore, the Company did not apply FAS No. 157 to nonrecurring fair value measurements of non-financial assets and non-financial liabilities, including non-financial long-lived assets measured at fair value for an impairment assessment under FAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and asset retirement obligations initially measured at fair value under FAS No. 143, “Accounting for Asset Retirement Obligations.”  The Company is now required to apply FAS No. 157 to non-recurring financial and non-financial instruments effective January 1, 2009.  See Note 11 “Fair Value Measurement.”  The full adoption of FAS No. 157 did not have a material impact on the Company’s financial statements.

In March 2008, the FASB released FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.”  FAS No. 161 expands the disclosure requirements in FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” about an entity’s derivative instruments and hedging activities.  FAS No. 161’s disclosure provisions apply to all entities with derivative instruments subject to FAS No. 133 and its related interpretations.  The provisions also apply to related hedged items, bifurcated derivatives, and nonderivative instruments that are designated and qualify as hedging instruments.  Entities with instruments subject to FAS No. 161 must provide more robust qualitative disclosures and expanded quantitative disclosures.  The statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, thus the Company adopted FAS No. 161 on January 1, 2009.  See Note 12 “Price Risk Management Activities” for additional disclosures required under FAS No. 161.

In April 2009, the FASB issued FSP FAS 157-4, “Determining Whether a Market is Not Active and a Transaction is Not Distressed.”  This FSP provides additional guidance on determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements under FASB Statement No. 157, “Fair Value Measurements.”  This FSP is effective for interim and annual periods ending after June 15, 2009.  The adoption of this FSP did not have a material impact on the Company’s financial statements.

In April 2009, the FASB issued FSP FAS 115-2, FAS 124-2, and EITF 99-20-b, “Recognition and Presentation of Other-Than-Temporary Impairments.”  This FSP amends the other-than-temporary impairment guidance in GAAP to make the guidance more operational and to improve the presentation of other-than-temporary impairments in the financial statements. To avoid considering an impairment to be other than temporary, this FSP modifies the requirement that management must assert that it has both the intent and the ability to hold an impaired security for a period of time sufficient to allow for any anticipated recovery in fair value.  This FSP is effective for interim and annual reporting periods ending after June 15, 2009.  The adoption of this FSP did not have a material impact on the Company’s financial statements.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements.  This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in all interim financial statements.  This FSP is effective for interim and annual reporting periods ending after June 15, 2009.  The adoption of this FSP did not have a material impact on the Company’s financial statements.  See Note 11 “Fair Value Measurement” for additional disclosures required under FSP FAS 107-1.

In April 2009, the FASB issued FSP FAS 141(R)-1 to address concerns about the application of FAS No. 141(R) to assets and liabilities arising from contingencies in a business combination.  This FSP’s amendments establish a model similar to the one entities used under FAS No. 141 to account for preacquisition contingencies.  This FSP is effective for business combinations whose acquisition date is at or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The adoption of this FSP did not have a material impact on the Company’s financial statements.

In May 2009, the FASB issued FAS No. 165, “Subsequent Events.”  FAS No. 165 provides guidance on management’s assessment of subsequent events, which companies had historically relied upon U.S. auditing literature for guidance on assessing and disclosing subsequent events.  FAS No. 165 represents the inclusion of guidance on subsequent events in the accounting literature and is directed specifically to management.  FAS No. 165 is not expected to significantly change practice, but the new standard specifically clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” The statement is effective prospectively for interim or annual financial periods ending after June 15, 2009.  The Company’s adoption of FAS No. 165 in the period ending June 30, 2009 did not have a material impact on the Company’s financial statements.

In December 2008, the FASB released FSP No. FAS 132(R)-1, “Employers' Disclosures about Postretirement Benefit Plan Assets”, which amends FAS No. 132(R), “Employers' Disclosures about Pensions and Other Postretirement Benefits” (FASB ASC 715), to require disclosure of additional information about assets held in a defined benefit pension or other postretirement plan. Specifically, the additional disclosures cover (1) investment policies and strategies, (2) categories of plan assets, (3) fair value measurements of plan assets, and (4) significant concentrations of risk.  The additional disclosure requirements are effective for fiscal years ending after December 15, 2009, with earlier application permitted.  The Company is evaluating the effect that this statement will have on the Company’s financial statement disclosures.

 In June 2009, the FASB issued FAS No. 167, “Amendments to FASB Interpretation No. 46(R)” which amends the consolidation guidance that applies to variable interest entities (VIEs).  This statement amends FASB Interpretation 46(R), or FIN 46-R, 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 variable interest entity 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 statement amends FIN 46-R to require companies to perform ongoing reassessments of whether the company is the primary beneficiary of a variable interest entity.  This statement amends certain guidance in FIN 46-R for determining whether an entity is a variable interest entity, 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 Company is currently evaluating the potential impact of this statement on its financial statements and disclosures.

In June 2009, the FASB issued FAS No. 166, “Accounting for Transfers of Financial Assets” 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 FAS No. 166, many types of transferred financial assets that would have been derecognized previously are no longer eligible for derecognition.  FAS No. 166 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 Company is currently evaluating the potential impact of this statement on its financial statements and disclosures.

2.      Other Receivables

	June 30,		December 31,
	2009		2008
	(in thousands)
Investment fund receivable, net of allowance	$	2,781	$	6,418
Realized futures trading receivable		-		11,854
Other		5,415		6,944
	$	8,196	$	25,216

The Company had a $32.7 million money market 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.  In addition, it is currently estimated that approximately 1.5% of the Company’s original investment is at-risk for recoverability, primarily due to the bankruptcy of Lehman Brothers, as the Fund had an investment in Lehman Brothers Holdings, Inc. commercial paper.  Therefore, an allowance of $499,000 was recorded as of June 30, 2009 and December 31, 2008.  In addition, the Company received partial distributions through June 30, 2009 from the Fund totaling $29.4 million, resulting in a net investment fund receivable of $2.8 million.

3.      Inventories

Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market.  Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other costs.  Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned.  These include unfinished gasoline and diesel, blendstocks and other feedstocks.  Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products.  Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values.  Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts.  The net exchange balance is included in inventory.  Inventories of materials and supplies and process chemicals 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, 2009 and December 31, 2008 were as follows:

	June 30,		December 31,
	2009		2008
	(in thousands)
Crude oil	$	309,190	$	121,973
Unfinished products		105,431		55,915
Finished products		84,805		54,332
Process chemicals		1,281		1,385
Repairs and maintenance supplies and other		24,805		22,524
	$	525,512	$	256,129

4.      Other Current Assets

	June 30,		December 31,
	2009		2008
	(in thousands)
Margin deposits	$	20,731	$	18,323
Derivative assets		85		8,584
Prepaid insurance		3,445		8,374
Other		1,339		1,757
	$	25,600	$	37,038

5.         Accrued Liabilities and Other

	June 30,		December 31,
	2009		2008
	(in thousands)
Accrued compensation	$	8,145	$	12,606
Accrued Beverly Hills litigation settlement		-		10,000
Accrued environmental costs		5,923		10,040
Accrued interest		7,443		7,363
Accrued dividends		6,890		6,779
Accrued income taxes		35,153		326
Accrued property taxes		6,215		5,295
Derivative liabilities		4,815		-
Other		3,883		4,675
	$	78,467	$	57,084

6.      Long-term Debt

	June 30,			December 31,
	2009			2008
	(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		(2,650	)		(2,780	)
8.5% Senior Notes, net		197,350			197,220
	$	347,350		$	347,220

7.      Income Taxes

The Company is currently under a U.S. Federal income tax examination for 2005, 2006 and 2007.   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 $4.7 million of additional 2006 taxes 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 has requested an appeal conference.  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 FASB Interpretation No. 48, “Accounting for Uncertain Tax Positions – An Interpretation of FAS No. 109, Accounting for 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 (in thousands):

Balance beginning of period	$	24,278
Additions based on tax positions related to the current year		-
Additions for tax positions of prior years		-
Reductions for tax positions of prior years		(424	)
Settlements		-
Reductions due to lapse of applicable statutes of limitations		-
Balance end of period	$	23,854

The total contingent income tax liabilities and accrued interest of $28.5 million and $28.1 million at June 30, 2009 and December 31, 2008, respectively, are reflected in the Condensed Consolidated Balance Sheets under “Contingent income tax liabilities.”  The Company recognized interest expense on contingent income tax liabilities of $832,000 and $1.1 million during the six months ended June 30, 2009 and 2008 and $351,000 and $521,000 during the three months ended June 30, 2009 and 2008, respectively.

8.      Treasury Stock

The Company accounts for its treasury stock under the cost method on a FIFO basis.  Through December 31, 2008, the Company’s Board of Directors had approved a total of $400 million for share repurchases, of which $299.8 million had been utilized as of December 31, 2008.  During the six months ended June 30, 2009, the Company did not make any share repurchases in open market transactions, leaving remaining authorization of $100.2 million for future repurchases of shares.  A rollforward of treasury stock for the six months ended June 30, 2009 is as follows:

	Number of shares			Amount
	(in thousands except share amounts)
Balance as of December 31, 2008		27,945,884		$	393,732
Shares received to fund withholding taxes		188,338			2,588
Shares issued for stock option exercises		(15,000	)		(20	)
Shares issued for restricted stock grants, net of forfeits		(692,240	)		(1,038	)
Shares issued for conversion of stock unit awards		(242,669	)		(345	)
Balance as of June 30, 2009		27,184,313		$	394,917

 9.      Stock-based Compensation

Stock-based compensation costs and income tax benefits recognized in the Condensed Consolidated Statements of Income and Comprehensive Income for the six and three months ended June 30, 2009 and 2008 were as follows:

	Six Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009		2008
	(in thousands)
Restricted shares and units	$	9,808	$	5,447	$	3,794	$	2,815
Stock options		304		451		66		225
Contingently issuable stock unit awards		641		3,904		1,612		2,638
Total stock-based compensation expense	$	10,753	$	9,802	$	5,472	$	5,678
Income tax benefit recognized in the income statement	$	4,086	$	2,852	$	2,079	$	2,153

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.  As of June 30, 2009, 2,186,322 shares remained available to be awarded under the Plan assuming maximum payout is achieved on the contingently issuable awards made in 2007, 2008 and 2009 (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 months ended June 30, 2009, treasury shares were re-issued for stock awards, restricted stock awards and for shares issued due to the exercise of stock options.  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, 2009, there was $29.1 million of total unrecognized compensation cost related to Awards issued under the Plan, including costs for restricted stock, restricted stock units and contingently issuable awards.  This amount is expected to be recognized as expense over a weighted-average period of 2.18 years.

Stock Options.  Stock option changes during the six months ended June 30, 2009 are presented below:

	Number of awards			Weighted-Average Exercise Price		Aggregate Intrinsic Value of Options
	(in thousands)
Outstanding at beginning of period		464,591		$	28.5868
Granted		-			-
Exercised or issued		(15,000	)		4.6625
Expired or forfeited		(14,798	)		29.3850
Outstanding at end of period		434,793		$	29.3850	$	-
Vested at end of period		434,793		$	29.3850	$	-
Exercisable at end of period		434,793		$	29.3850	$	-

The Company received $70,000 of cash for stock options exercised during the six months ended June 30, 2009.  The total intrinsic value of stock options exercised during the six months ended June 30, 2009 was $160,000.  The Company realized $61,000 and $1.1 million of income tax benefit, nearly all of which was excess income tax benefit, for the six months ended June 30, 2009 and 2008, respectively, related to exercises of stock options.  Excess income tax benefits are the benefits from deductions that are allowed for income tax purposes in excess of the expenses recorded in the Company’s financial statements.  These excess income tax benefits are recorded as an increase to paid-in capital, and the majority of these amounts are reflected as cash flows from financing activities in the Condensed Consolidated Statements of Cash Flows.

The following table summarizes information about stock options outstanding as of June 30, 2009:

Stock Options Outstanding at June 30, 2009
Number Outstanding	Weighted-Average Remaining Contractual Life (Years)	Exercise Price	Exercisable	Vested
434,793	1.82	$29.3850	434,793	434,793

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, 2009:

	Shares/Units			Weighted-Average Grant-Date Market Value
Nonvested at beginning of period		571,479		$	29.2473
Conversion of stock unit awards		242,669			37.5632
Granted		744,800			13.6220
Vested		(580,967	)		27.6203
Forfeited		-			-
Nonvested at end of period		977,981			20.3775

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.  The Company realized $3.0 million of income tax benefit related to these vestings, and reduced the Company’s available pool of excess income tax benefits by $3.1 million.  The total grant date fair value of restricted shares and restricted stock units which vested during the six months ended June 30, 2008 was $22.9 million.  The total intrinsic value of restricted shares and restricted stock units that vested during the six months ended June 30, 2008 was $31.3 million, and the Company realized $10.7 million of income tax benefit related to these vestings, of which $2.8 million was excess income tax benefit.

In March 2009, following certification by the Compensation Committee of the Company’s Board of Directors that the specified performance criteria of the Company’s return of capital employed versus that of a defined peer group had been achieved for the year ended December 31, 2008, the Company issued 242,669 shares of restricted stock in connection with the February 2008 grant of contingently issuable stock unit awards.  The 2008 net income goal was not met; consequently, 242,680 contingently issuable shares awarded in 2008 were not issued.  The following tables summarize the vesting schedules of the 242,669 stock unit awards converted to restricted stock and 744,800 shares of restricted stock shares and units granted during the six months ended June 30, 2009.

		Vesting Dates and Share Amounts
Conversion Date	Converted stock unit awards	June 15, 2009(1)	June 30, 2009	June 30, 2010	June 30, 2011
March 25, 2009	242,669	54,762	62,635	62,637	62,635

			Vesting Dates and Share Amounts
Grant Date	Shares/Units Granted		March 25, 2009 (1)		December 31, 2009		March 13, 2010		March 13, 2011		March 13, 2012
January 30, 2009		52,560				52,560
February 24, 2009		318,591						79,648		79,648		159,295
March 25, 2009		365,225		124,370				60,218		60,224		120,413
April 28, 2009		8,424						2,106		2,106		4,212
Total		744,800		124,370		52,560		141,972		141,978		283,920
(1) Accelerated vesting due to retirement of employee.

Contingently Issuable Awards.  During the six months ended June 30, 2009, the Company granted 508,694 contingently issuable stock unit awards to be earned if certain net income and return of capital employed versus that of a defined peer group goals are met for 2009.  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 for 2009 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 2010.  One-third of these restricted shares will vest on June 30, 2010, one-third on June 30, 2011 and the final one-third on June 30, 2012.  As of June 30, 2009, the Company assumed for purposes of stock-based compensation expense for these awards granted in 2009 that the maximum target (125%) level award (317,935 stock units) would be earned for the net income contingent awards and the target (100%) level award (254,347 stock units) would be earned for the return of capital employed versus that of a defined peer group.

The Company also granted 254,341 stock unit awards contingent upon certain share price performance versus the Company’s peers being met over a three-year period ending on December 31, 2011.  Depending on achievement of the market-based performance goals, awards earned could be between 0% and 125% of the base number of market-based 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 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, 2011.  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 $2.6 million 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:

	2009
Number of simulations		100,000
Expected volatility		67.27	%
Risk-free rate		1.31	%

As of June 30, 2009, the Company also had outstanding (net of forfeitures) 183,661 and 194,125 contingently issuable stock unit awards issued in 2007 and 2008, respectively, to be earned should certain share price criteria be met over a three-year period ending December 31, 2009 and 2010, 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 into stock.

When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents (on the stock unit awards) and dividends (once the stock unit awards are converted to restricted stock) are accrued on the contingently issuable stock units and restricted stock but are not paid until the restricted stock vests.  The stock unit awards were valued at the market value on the date of grant and amortized to compensation expense on a straight-line basis over the nominal vesting period, adjusted for retirement-eligible employees, as required under FAS No. 123(R).

10.      Employee Benefit Plans

Defined Benefit Plans

The Company established a defined benefit cash balance pension plan, effective January 1, 2000, for eligible El Dorado Refinery employees to supplement retirement benefits that those employees lost upon the sale of the El Dorado Refinery to Frontier.  No other current or future employees will be eligible to participate in the plan and its funding status is in compliance with ERISA.

In April 2008, the Company’s Board of Directors approved the termination of the pension plan.  In July 2009, the Company received, from the Internal Revenue Service, a letter stating the termination of the pension plan does not affect its qualification.  The Company expects the termination will be completed in 2009.  Plan participants will receive 100% of their account balance, including interest, upon termination.

As of June 30, 2009, the fair market value of the pension plan assets was $11.0 million and the pension benefit obligation was $11.3 million.  The Company has increased its 2009 net periodic benefit cost accrual because of the expected termination.

The pension plan assets are held in a Trust Fund whose trustee is Frost National Bank.  The Company did not contribute to the Trust Fund during the first six months of 2009.  Frontier’s pension plan weighted-average asset allocations in the Trust Fund at June 30, 2009 and December 31, 2008, by asset category, were as follows:

	Percentage of Plan Assets at
Asset Category:	June 30, 2009			December 31, 2008
Cash and cash equivalents		89	%		89	%
Fixed income common trust funds		11	%		11	%
Total		100	%		100	%

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, 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 plan’s prescription drug benefits are at least equivalent to Medicare Part D benefits.  The plan was amended in the first quarter of 2008 to limit the employees’ pre-Medicare insurance premium to 125% of the active employee rate.

The following table sets forth the net periodic benefit costs recognized for these benefit plans in the Company’s Condensed Consolidated Statements of Income and Comprehensive Income:

	Six Months Ended  June 30,						Three Months Ended June 30,
Pension Benefits	2009			2008			2009			2008
	(in thousands)
Components of net periodic benefit cost and other amounts recognized in other comprehensive income:
Service cost	$	-		$	-		$	-		$	-
Interest cost		131			308			66			154
Expected return on plan assets		(89	)		(406	)		(44	)		(203	)
Amortization of prior service cost		213			-			106			-
Amortized net actuarial loss		-			-			-			-
Net periodic benefit cost		255			(98	)		128			(49	)
Changes in assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		-			-			-			-
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		$	(98	)	$	22		$	(49	)

	Six Months Ended  June 30,						Three Months Ended June 30,
Post-retirement Healthcare and Other Benefits	2009			2008			2009			2008
	(in thousands)
Components of net periodic benefit cost and other amounts recognized in other comprehensive income:
Components of net periodic benefit cost:
Service cost	$	356		$	380		$	178		$	190
Interest cost		945			870			473			435
Expected return on plan assets		-			-			-			-
Amortization of prior service cost		(938	)		(794	)		(469	)		(397	)
Amortized net actuarial loss		523			436			261			218
Net periodic benefit cost		886			892			443			446
Changes in assets and benefit obligations recognized in other comprehensive income:
Increase in benefit obligation for plan amendment		-			1,350			-			-
Amortization of prior service cost		938			794			469			397
Amortization of loss		(523	)		(436	)		(261	)		(218	)
Total recognized in other comprehensive income		415			1,708			208			179
Total recognized in net periodic benefit cost and other comprehensive income	$	1,301		$	2,600		$	651		$	625

11.      Fair Value Measurement

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

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

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

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

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

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2009, 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	$	-	$	-	$	85	$	85
Derivative liabilities		4,815				-		4,815

As of June 30, 2009, 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 Company’s crude call options, that relate to crude purchased from an oil lease, are measured under Level 3.  The following provides a reconciliation of the beginning and ending balances of the Company’s Level 3 derivative asset crude call options for the period ended June 30, 2009:

	Six Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)
Beginning derivative asset balance	$	-		$	-		$	370		$	-
Net increase in derivative assets		249			841			(166	)		841
Net settlements		(164	)		(194	)		(119	)		(194	)
Transfers in (out) of Level 3		-			-			-			-
Ending derivative asset balance	$	85		$	647		$	85		$	647

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, 2009 and December 31, 2008, the carrying amounts of the Company’s 6.625% Senior Notes were $150.0 million, and the estimated fair values were $146.6 million and $135.8 million, respectively.  At June 30, 2009 and December 31, 2008, the carrying amounts of the Company’s 8.5% Senior Notes were $197.4 million ($200.0 million less the unamortized discount of $2.6 million) and $197.2 million (unamortized discount of $2.8 million), and the estimated fair values were $201.5 million and $176.5 million.  For cash and cash equivalents, the carrying amounts at June 30, 2009 and December 31, 2008 of $488.4 million and $483.5 million, respectively, are reasonable estimates of fair value.

12.      Price Risk Management Activities

The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production.  The commodity derivative contracts used by the Company may take the form of futures contracts, forward contracts, collars or price 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, 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 11, “Fair Value Measurement.”  As of June 30, 2009, the Company had the following outstanding commodity derivative contracts:

Commodity	Number of barrels
	(in thousands)
Crude oil contracts to hedge excess intermediate, finished product and crude oil inventory		2,768

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, 2009			December 31, 2008			June 30, 2009			December 31, 2008
		Fair Value			Fair Value			Fair Value			Fair Value
	(in thousands)
Derivatives not designated as hedging instruments
Commodity contracts		$	-		$	8,584		$	4,815		$	-
Other contracts			85			-			-			-
Total derivatives		$	85		$	8,584		$	4,815		$	-

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

	Amount of Derivatives Gain or (Loss) Recognized in Other Revenues						Amount of Derivatives Gain or (Loss) Recognized in Other Revenues
	Six Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Derivatives not designated as hedging instruments
Commodity contracts	$	(7,473	)	$	(143,901	)	$	(29,653	)	$	(116,759	)
Foreign exchange contracts		799			-			795			-
Other contracts		249			841			(166	)		841

13.      Environmental

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

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 Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to meet the interim gasoline sulfur standard, which was required by January 1, 2004.  To meet final federal gasoline sulfur standards, the Company expects to spend approximately $40.0 million ($5.7 million incurred as of June 30, 2009) for the cat gasoline hydrotreater project comprised of new process unit capacity and intermediate inventory handling equipment at the Cheyenne Refinery.  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 estimating the total cost in connection with an overall compliance strategy for the Cheyenne Refinery.  Total capital expenditures estimated as of June 30, 2009 for the El Dorado Refinery to comply with the final gasoline sulfur standard are approximately $91.0 million, including capitalized interest, and are expected to be completed by 2010.  As of June 30, 2009, $55.6 million of the estimated $91.0 million had been incurred.  Substantially all of the estimated $91.0 million of expenditures relates to the El Dorado Refinery’s gasoil hydrotreater revamp project.  The gasoil hydrotreater revamp project will address most of the El Dorado Refinery’s modifications needed to achieve gasoline sulfur compliance.

The Company is a holder of gasoline sulfur credits, generated from prior years operations at both the Cheyenne and the El Dorado Refineries.  During the six and three months ended June 30, 2009, Frontier sold 47.0 billion (ppm-gallons) and 31.3 billion (ppm-gallons) sulfur credits for total proceeds of $1.9 million and $1.3 million, respectively, which was recorded in “Other revenues” on the Condensed Consolidated Statements of Income and Comprehensive Income.  During the six months ended June 30, 2008, the Company sold $4.3 million (33.9 billion (ppm-gallons)) of sulfur credits also included in “Other revenues” on the Condensed Consolidated Statements of Income and Comprehensive Income.

The EPA has embarked on a Petroleum Refining Enforcement Initiative (“Initiative”) alleging industry-wide noncompliance with certain long-standing regulatory programs.  These programs are:

●      New Source Review (“NSR”) – a program requiring permitting of certain facility modifications,

● New Source Performance Standards – a program establishing emission standards for new emission sources as defined in the regulations,

● Benzene Waste National Elimination System for Hazardous Air Pollutants (“NESHAPS”) – a program limiting the amount of benzene allowable in industrial wastewaters, and

● Leak Detection and Repair (“LDAR”) – a program designed to control hydrocarbon emissions from refinery pipes, pumps and valves.

The Initiative has caused many refiners to enter into consent decrees typically requiring substantial expenditures for penalties and the installation of additional pollution control equipment.  The Company’s settlement negotiations with the EPA and state regulatory agencies regarding the Initiative were completed in December 2008.  Final settlement agreements were entered into in March 2009 and are now in effect.  The Company now 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 $57.0 million at the Cheyenne Refinery and $10.0 million 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 anticipated regulatory settlements, many of these same expenditures are required for the Company to comply with preexisting regulatory requirements or to implement its planned facility expansions. As an example, a preexisting regulation known as Maximum Achievable Control Technology II (“MACT II”) will require the installation of a particulate scrubber at the El Dorado Refinery at an estimated cost of $34.0 million.  Consequently, the costs associated with this project and other more minor projects are not included in the totals above.  In addition to the capital costs described above, the EPA has assessed, and the Company paid in April 2009, a civil penalty in the amount of $1.9 million, discounted for a related $96,000 penalty and associated supplemental environment project (“SEP”) paid to the State of Wyoming in 2005 and further offset by $902,000 for the completion of additional mutually agreed SEPs.  The EPA also attached to this settlement resolution an enforcement action against the Company’s El Dorado Refinery related to alleged violations of certain requirements of the EPA Risk Management Program (“RMP”).  Negotiated civil penalties included in the aforementioned payment regarding resolution of this issue totaled approximately $484,000, which were reduced to $358,000 by completion of an approved SEP.  The Company accrued for the balance of these estimated penalties at December 31, 2008 with payment occurring in April of 2009.  In addition, the settlement agreement provides for stipulated penalties for violations.  Stipulated penalties under the decree are not automatic, but must be requested by one of the agency signatories.

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 increases the amount of renewable fuels that had been required by the 2005 legislation. The Company, as a small refiner, will be exempt until 2012 from these requirements.  The Company does have blending facilities and purchases ethanol with Renewable Identification Numbers (RINs) credits attached.  Ethanol RINs were created to assist in tracking the compliance with these EPA regulations for the blending of renewable fuels.  During the six months ended June 30, 2009 and 2008, the Company sold approximately 24.0 million and 24.4 million RIN gallons for $3.2 million and $950,000, respectively, which were recorded in “Other revenues” on the Condensed Consolidated Statements of Income and Comprehensive Income.  During the three months ended June 30, 2009 and 2008, the Company sold approximately 15.0 million and 4.3 million RIN gallons for $2.2 million and $213,000, 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 Company (see “Other Future Environmental Considerations” below).

On February 26, 2007, the EPA promulgated regulations limiting the amount of benzene in gasoline.  These regulations take effect for large refiners on January 1, 2011 and for small refiners, such as Frontier, on January 1, 2015.  While not yet estimated, the Company anticipates that potentially material capital expenditures may be necessary to achieve compliance with the new regulation at its Cheyenne Refinery as discussed above.  Gasoline manufactured at the El Dorado Refinery typically contains benzene concentrations near the new standard.  The Company therefore believes that necessary benzene compliance expenditures at the El Dorado Refinery will be substantially less than those at its Cheyenne Refinery.

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.  In addition, the Company estimates that an ongoing groundwater remediation program will be required for approximately ten more years.  As of June 30, 2009 and December 31, 2008, the Company had a $5.0 million accrual included on the Condensed Consolidated Balance Sheets related to the remediation program, reflecting the estimated present value of a $450,000 cost in the remainder of 2009 and $700,000 in annual costs for 2010 through 2018, assuming a 3% inflation rate and discounted at a rate of 7.5%.  The Company also had accrued a total of $4.3 million, as of June 30, 2009, and $4.7 million, as of December 31, 2008, 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.  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 2009.  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, the Company has also committed to the installation of a groundwater boundary control system to be constructed in 2009.  The Company has estimated the capital cost of the boundary control system at approximately $11.0 million.

Pursuant to an agreement with the City of Cheyenne, the Company will contribute $1.5 million toward a project (estimated to be completed in 2009) to relocate a city storm water conveyance pipe, which is presently located on Refinery property and therefore is potentially subject to contaminants from Refinery operations.

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

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.  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.  On April 2, 2007, the U.S. Supreme Court in Massachusetts, et al. v. EPA 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.  In July 2008, the EPA released an Advance Notice of Proposed Rulemaking regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts.  In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases.  Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future.  On April 17, 2009, the EPA proposed that certain greenhouse gases including carbon dioxide present a danger to public health or welfare.  If promulgated as expected, this finding will allow direct regulation of such greenhouse gases under the provisions and programs of the existing Clean Air Act. Thus, there may be restrictions imposed on the emission of greenhouse gases even if the U.S. Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  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 its business, financial condition and results of operations, including demand for the refined petroleum products that it produces.

14.      Litigation

The Company is involved in various lawsuits and Occupational Safety and Health Administration (“OSHA”) 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.

15.      Amendment of Crude Oil Purchase and Sale Contract

Effective March 10, 2006, the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with Utexam.  Under this Contract, Utexam purchases, transports and subsequently sells crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed.  Under this agreement, Utexam is the owner of record of the crude oil as it is transported from the point of injection, typically Hardisty, Alberta, Canada, to the point of ultimate sale to FORC.  The Company has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract.  The Company accounts for the transactions under this Contract as a financing arrangement, whereby the inventory and the associated liability are recorded in the Company’s financial statements when the crude oil is injected into the pipeline in Canada.

On July 1, 2009, the Company entered into the third amendment of this Contract, effective as of March 31, 2009, which decreased the maximum value of crude oil to be purchased under this contract from $250.0 million to $110.0 million and extends the maturity date of the contract to March 31, 2010.

16.      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.

The presentation of other intercompany transactions between parent and subsidiaries has been changed from a financing activity to an operating activity in the 2008 condensed consolidating statement of cash flows.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Six Months Ended June 30, 2009
(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	)
		(7	)		1,948,072			27		-			1,948,092
Costs and expenses:
Raw material, freight and other costs		-			1,533,989			-		-			1,533,989
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
		11,000			1,732,592			-		285			1,743,877
Operating income (loss)		(11,007	)		215,480			27		(285	)		204,215
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		(215,812	)		-			-		215,812			-
		(202,022	)		1,559			-		213,513			13,050
Income before income taxes		191,015			213,921			27		(213,798	)		191,165
Provision for income taxes		67,715			76,121			10		(75,981	)		67,865
Net income	$	123,300		$	137,800		$	17	$	(137,817	)	$	123,300

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Six Months Ended June 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	3,089,598		$	-	$	-		$	3,089,598
Other		-			(137,350	)		91		-			(137,259	)
		-			2,952,248			91		-			2,952,339
Costs and expenses:
Raw material, freight and other costs		-			2,574,026			-		-			2,574,026
Refinery operating expenses, excluding     depreciation		-			168,594			-		-			168,594
Selling and general expenses, excluding     depreciation		9,646			12,857			-		-			22,503
Depreciation, amortization and     accretion		27			31,359			-		51			31,437
Gain on sales of assets		(37	)		(7	)		-		-			(44	)
		9,636			2,786,829			-		51			2,796,516
Operating income (loss)		(9,636	)		165,419			91		(51	)		155,823
Interest expense and other financing    costs		6,286			2,136			-		(3,859	)		4,563
Interest and investment income		(2,264	)		(1,371	)		-		-			(3,635	)
Equity in earnings of subsidiaries		(168,313	)		-			-		168,313			-
		(164,291	)		765			-		164,454			928
Income before income taxes		154,655			164,654			91		(164,505	)		154,895
Provision for income taxes		49,370			52,481			32		(52,273	)		49,610
Net income	$	105,285		$	112,173		$	59	$	(112,232	)	$	105,285

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Three Months Ended June 30, 2009
(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	)
		-			1,101,817			27		-			1,101,844
Costs and expenses:
Raw material, freight and other costs		-			914,092			-		-			914,092
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
		5,396			1,012,001			-		142			1,017,539
Operating income (loss)		(5,396	)		89,816			27		(142	)		84,305
Interest expense and other financing    costs		7,329			927			-		(1,339	)		6,917
Interest and investment income		(648	)		(123	)		-		-			(771	)
Equity in earnings of subsidiaries		(90,086	)		-			-		90,086			-
		(83,405	)		804			-		88,747			6,146
Income before income taxes		78,009			89,012			27		(88,889	)		78,159
Provision for income taxes		28,168			32,349			10		(32,209	)		28,318
Net income	$	49,841		$	56,663		$	17	$	(56,680	)	$	49,841

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Three Months Ended June 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,882,010		$	-	$	-		$	1,882,010
Other		-			(115,520	)		66		-			(115,454	)
		-			1,766,490			66		-			1,766,556
Costs and expenses:
Raw material, freight and other costs		-			1,574,898			-		-			1,574,898
Refinery operating expenses, excluding     depreciation		-			81,034			-		-			81,034
Selling and general expenses, excluding     depreciation		5,411			6,737			-		-			12,148
Depreciation, amortization and     accretion		13			16,401			-		83			16,497
Gain on sales of assets		-			(7	)		-		-			(7	)
		5,424			1,679,063			-		83			1,684,570
Operating income (loss)		(5,424	)		87,427			66		(83	)		81,986
Interest expense and other financing    costs		3,102			1,197			-		(1,375	)		2,924
Interest and investment income		(704	)		(618	)		-		-			(1,322	)
Equity in earnings of subsidiaries		(88,016	)		-			-		88,016			-
		(85,618	)		579			-		86,641			1,602
Income before income taxes		80,194			86,848			66		(86,724	)		80,384
Provision for income taxes		20,878			23,648			23		(23,481	)		21,068
Net income	$	59,316		$	63,200		$	43	$	(63,243	)	$	59,316

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of June 30, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	281,463		$	206,894		$	-	$	-		$	488,357
Trade and other receivables, net		64,588			174,699			12		-			239,299
Inventory of crude oil, products and other		-			525,512			-		-			525,512
Deferred tax assets		6,905			10,930			-		(10,930	)		6,905
Other current assets		460			25,140			-		-			25,600
Total current assets		353,416			943,175			12		(10,930	)		1,285,673
Property, plant and equipment, at cost		1,203			1,364,934			-		12,395			1,378,532
Accumulated depreciation and amortization		(895	)		(414,349	)		-		7,359			(407,885	)
Property, plant and equipment, net		308			950,585			-		19,754			970,647
Deferred turnaround costs		-			40,311			-		-			40,311
Deferred catalyst costs		-			7,860			-		-			7,860
Deferred financing costs, net		3,249			2,206			-		-			5,455
Intangible assets, net		-			1,277			-		-			1,277
Other assets		3,016			339			-		-			3,355
Receivable from affiliated companies		-			7,374			493		(7,867	)		-
Investment in subsidiaries		1,425,288			-			-		(1,425,288	)		-
Total assets	$	1,785,277		$	1,953,127		$	505	$	(1,424,331	)	$	2,314,578
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	955		$	461,090		$	15	$	-		$	462,060
Accrued liabilities and other		50,438			28,029			-		-			78,467
Total current liabilities		51,393			489,119			15		-			540,527
Long-term debt		347,350			-			-		-			347,350
Contingent income tax liabilities		26,460			2,022			-		-			28,482
Long-term capital lease obligations		-			3,356			-		-			3,356
Other long-term liabilities		2,930			42,656			-		-			45,586
Deferred income taxes		182,014			177,016			-		(177,016	)		182,014
Payable to affiliated companies(1)		7,867			23,638			219		(31,724	)		-
Shareholders' equity		1,167,263			1,215,320			271		(1,215,591	)		1,167,263
Total liabilities and shareholders' equity	$	1,785,277		$	1,953,127		$	505	$	(1,424,331	)	$	2,314,578
(1) FHI payable to affiliated companies balance relates to income taxes payable to parent under a tax sharing agreement.

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	254,548		$	228,984		$	-	$	-		$	483,532
Trade and other receivables, net		120,265			105,169			10		-			225,444
Inventory of crude oil, products and other		-			256,129			-		-			256,129
Deferred tax assets		8,841			9,034			-		(9,034	)		8,841
Commutation account		6,319			-			-		-			6,319
Other current assets		643			36,395			-		-			37,038
Total current assets		390,616			635,711			10		(9,034	)		1,017,303
Property, plant and equipment, at cost		1,248			1,295,420			-		10,076			1,306,744
Accumulated depreciation and amortization		(998	)		(379,967	)		-		7,664			(373,301	)
Property, plant and equipment, net		250			915,453			-		17,740			933,443
Deferred turnaround costs		-			47,465			-		-			47,465
Deferred catalyst costs		-			9,726			-		-			9,726
Deferred financing costs, net		3,642			2,559			-		-			6,201
Intangible assets, net		-			1,338			-		-			1,338
Other assets		2,600			393			-		-			2,993
Receivable from affiliated companies(1)		646			25,733			468		(26,847	)		-
Investment in subsidiaries		1,235,678			-			-		(1,235,678	)		-
Total assets	$	1,633,432		$	1,638,378		$	478	$	(1,253,819	)	$	2,018,469
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,168		$	307,684		$	15	$	-		$	308,867
Accrued liabilities and other		26,071			31,013			-		-			57,084
Total current liabilities		27,239			338,697			15		-			365,951
Long-term debt		347,220			-			-		-			347,220
Contingent income tax liabilities		26,112			1,945			-		-			28,057
Long-term capital lease obligations		-			3,548			-		-			3,548
Other long-term liabilities		2,507			40,832			-		-			43,339
Deferred income taxes		179,214			174,597			-		(174,597	)		179,214
Payable to affiliated companies		-			1,114			209		(1,323	)		-
Shareholders' equity		1,051,140			1,077,645			254		(1,077,899	)		1,051,140
Total liabilities and shareholders' equity	$	1,633,432		$	1,638,378		$	478	$	(1,253,819	)	$	2,018,469
(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, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	123,300		$	137,800		$	17		$	(137,817	)	$	123,300
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(215,812	)		-			-			215,812			-
Depreciation, amortization and accretion		34			45,722			-			285			46,041
Deferred income taxes		4,813			-			-			-			4,813
Stock-based compensation expense		10,753			-			-			-			10,753
Excess income tax benefits of    stock-based compensation		(151	)		-			-			-			(151	)
Intercompany income taxes		26,000			49,971			10			(75,981	)		-
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			1,712			-			-			2,890
Changes in deferred turnaround costs,    deferred catalyst costs and other		(416	)		(840	)		-			-			(1,256	)
Changes in components of working    capital from operations		83,298			(173,857	)		(1	)		(459	)		(91,019	)
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

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	105,285		$	112,173		$	59		$	(112,232	)	$	105,285
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(168,313	)		-			-			168,313			-
Depreciation, amortization and accretion		27			39,708			-			51			39,786
Deferred income taxes		13,470			-			-			-			13,470
Stock-based compensation expense		9,802			-			-			-			9,802
Excess income tax benefits of    stock-based compensation		(3,935	)		-			-			-			(3,935	)
Intercompany income taxes		-			52,241			32			(52,273	)		-
Other intercompany transactions		(822	)		891			(69	)		-			-
Amortization of debt issuance costs		241			102			-			-			343
Allowance for investment loss
Gain on sales of assets		(37	)		(7	)		-			-			(44	)
Amortization of long-term prepaid insurance		606			-			-			-			606
Increase in other long-term liabilities		1,160			728			-			-			1,888
Changes in deferred turnaround costs,    deferred catalyst costs and other		67			(29,327	)		-			-			(29,260	)
Changes in components of working    capital from operations		19,328			(38,559	)		(22	)		1,091			(18,162	)
Net cash provided by (used in)     operating activities		(23,121	)		137,950			-			4,950			119,779
Cash flows from investing activities:
Additions to property, plant and    equipment		(67	)		(110,004	)		-			(4,950	)		(115,021	)
Proceeds from sale of assets		37			8			-			-			45
El Dorado Refinery contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Net cash used in investing activities		(30	)		(117,496	)		-			(4,950	)		(122,476	)
Cash flows from financing activities:
Purchase of treasury stock		(66,403	)		-			-			-			(66,403	)
Proceeds from issuance of common stock		126			-			-			-			126
Dividends paid		(10,651	)		-			-			-			(10,651	)
Excess income tax benefits of    stock-based compensation		3,935			-			-			-			3,935
Debt issuance costs and other		-			(469	)		-			-			(469	)
Net cash used in financing activities		(72,993	)		(469	)		-			-			(73,462	)
(Decrease) increase in cash and cash equivalents		(96,144	)		19,985			-			-			(76,159	)
Cash and cash equivalents, beginning of period		186,368			111,031			-			-			297,399
Cash and cash equivalents, end of period	$	90,224		$	131,016		$	-		$	-		$	221,240

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 182,000 barrels per day (“bpd”).  To assist in understanding our operating results, please refer to the operating data at the end of this analysis, which provides key operating information for our Refineries.  Refinery operating data is also included in our annual report on Form 10-K, our quarterly reports on Form 10-Q and on our web site at http://www.frontieroil.com.  We make our web site content available for informational purposes only.  The web site should not be relied upon for investment purposes nor is it incorporated by reference in this Form 10-Q.  We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, proxy statements, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.

Overview

The terms “Frontier,” “we” and “our” refer to Frontier Oil Corporation and its subsidiaries.  The four 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 and the WTI/WTS crude oil differential.  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).  Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in inventory valuation gains (lower cost of sales) when crude oil prices increase and inventory valuation losses (higher cost of sales) when crude oil prices decrease during the reporting period.  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, 2009 compared with the same period in 2008

Overview of Results

We had net income for the six months ended June 30, 2009 of $123.3 million, or $1.18 per diluted share, compared to net income of $105.3 million, or $1.02 per diluted share, earned in the same period in 2008.  Our operating income of $204.2 million for the six months ended June 30, 2009 increased $48.4 million from the $155.8 million for the comparable period in 2008.  Product yields and sales volumes were significantly higher during the six months ended June 30, 2009 because of a 20,000 bpd increase in capacity that resulted from the crude vacuum tower project and the major turnaround work completed at the El Dorado Refinery during the second quarter of 2008.  In addition, during the first quarter of 2009, we also received the benefit, primarily at our El Dorado Refinery, from purchasing discounted WTI crude oil versus a NYMEX WTI benchmark price because of the excess supply of crude oil at Cushing, Oklahoma.  This crude benefit has moderated since March 2009.  Our net income also benefited from a higher gasoline crack spread in the first six months of 2009 ($9.03 per barrel) compared to the first six months of 2008 ($5.11 per barrel).

Despite an increase in our net income from the first half of 2008 to the first half of 2009, certain indicators of our profitability continued to decline for the six months ended June 30, 2009, including the diesel crack spread ($24.83 per barrel in 2008 to $8.98 per barrel in 2009) and both the light/heavy and WTI/WTS crude oil differentials.  We expect the U.S. recession could continue to negatively impact our 2009 results by reducing demand for gasoline and diesel.  The decline in crude oil differentials has been caused by several factors, including the significant industry investment over the last few years to process these types of crudes and the declining availability of heavy/sour crude oil.  The light/heavy crude oil differential decreased from $16.62 per barrel for the six months ended June 30, 2008 to $5.52 per barrel for the comparable period of 2009.  The WTI/WTS crude oil differential decreased from $4.81 per barrel for the six months ended June 30, 2008 to $1.36 per barrel for the comparable period of 2009.

Specific Variances

Refined product revenues.  Refined product revenues decreased $1.14 billion, or 37%, from $3.09 billion to $1.95 billion for the six months ended June 30, 2009 compared to the same period in 2008.  This decrease resulted primarily from lower crude oil prices, and correspondingly lower refined product prices in the six months ended June 30, 2009 ($56.58 lower average per sales barrel), despite a significant increase in sales volumes.

Manufactured product yields.  Yields increased 38,113 bpd at the El Dorado Refinery and decreased 663 bpd at the Cheyenne Refinery for the six months ended June 30, 2009 compared to same period in 2008.  The increase in yields at the El Dorado Refinery was due primarily to the crude unit and vacuum tower expansion and planned major turnaround work on the coker and the reformer completed in the second quarter of 2008.

Other revenues.  Other revenues increased $135.0 million to a loss of $2.2 million for the six months ended June 30, 2009, compared to a loss of $137.3 million for the same period in 2008, the primary source of this increase being $7.5 million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories in the six months ended June 30, 2009, compared to $143.9 million in net realized and unrealized losses on derivative contracts to hedge in-transit crude oil and excess inventories in the six months ended June 30, 2008.  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 in the six months ended June 30, 2009 compared to $4.3 million in the comparable 2008 period, and $3.2 million of ethanol Renewable Identification Number (“RIN”) sales in 2009 versus $950,000 in the comparable period of 2008.

Raw material, freight and other costs.  Raw material, freight and other costs decreased by $1.04 billion, from $2.57 billion in the six months ended June 30, 2008 to $1.53 billion in the same period for 2009.  The decrease in raw material, freight and other costs was due to lower average crude oil prices and decreased purchased products, partially offset by increased overall crude oil charges and lower light/heavy and WTI/WTS crude oil differentials during the six months ended June 30, 2009 when compared to the same period in 2008.  For the six months ended June 30, 2009, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $99.9 million after tax ($161.2 million pretax, consisting of a $50.9 million gain at the Cheyenne Refinery and a $110.3 million gain at the El Dorado Refinery).  For the six months ended June 30, 2008, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $165.3 million after tax ($265.9 million pretax, comprised of a $69.2 million gain at the Cheyenne Refinery and a $196.7 million gain at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $46.05 per sales barrel for the six months ended June 30, 2009 decreased from $89.10 per sales barrel in the same period in 2008 due to lower average crude oil prices and decreased purchased products, partially offset by lower light/heavy crude oil differentials.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $5.39 per barrel in the six months ended June 30, 2009 compared to $19.45 per barrel in the same period in 2008.

The El Dorado Refinery raw material, freight and other costs of $45.63 per sales barrel for the six months ended June 30, 2009 decreased from $98.79 per sales barrel in the same period in 2008 primarily due to lower average crude oil prices; however, overall crude charges increased, and we experienced lower crude oil differentials.  The WTI/WTS crude oil differential decreased from an average of $4.81 per barrel in the six month period ended June 30, 2008 to $1.36 per barrel in the same period in 2009.  The light/heavy crude oil differential decreased from an average of $11.76 per barrel in the six month period ended June 30, 2008 to $5.72 per barrel in the same period in 2009.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $148.5 million in the six months ended June 30, 2009 compared to $168.6 million in the comparable period of 2008.

The Cheyenne Refinery operating expenses, excluding depreciation, were $55.1 million for the six months ended June 30, 2009 compared to $59.3 million in the comparable period of 2008.  The primary areas of decreased costs were: natural gas costs ($4.8 million due to decreased prices and lower volumes) and maintenance costs ($3.7 million due to various unplanned tank and coker repairs and outages incurred in 2008), partially offset by increased additives and chemicals costs ($1.1 million), increased salaries and benefits expenses ($1.8 million), and increased turnaround amortization ($921,000).

The El Dorado Refinery operating expenses, excluding depreciation, were $93.4 million for the six months ended June 30, 2009, decreasing from $109.3 million in the same six month period of 2008.  Primary areas of decreased costs and variance amounts for the 2009 period compared to the 2008 period were: natural gas costs ($15.3 million due to decreased prices and significantly lower volumes) and maintenance costs ($8.4 million lower, primarily due to demolition, catalyst and repair costs incurred during the March 2008 turnaround), partially offset by increased salaries and benefits expenses ($2.4 million), increased electricity ($1.8 million), increased additives and chemicals costs ($1.6 million), increased property and other taxes ($681,000), and an increase in turnaround amortization ($643,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, increased $2.8 million, or 12%, from $22.5 million for the six months ended June 30, 2008 to $25.3 million for the six months ended June 30, 2009, due to $3.0 million of higher salaries and benefit expenses (including stock-based compensation expense) in 2009.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $4.7 million, or 15%, for the six months ended June 30, 2009 compared to the same period in 2008 because of increased capital investments in our Refineries, including our El Dorado Refinery crude unit and vacuum tower expansion project that was placed into service in the second quarter of 2008.

Interest expense and other financing costs.  Interest expense and other financing costs of $14.3 million for the six months ended June 30, 2009 increased $9.8 million from $4.6 million in the comparable period in 2008.  Increases in interest expense related to an additional $8.5 million of interest incurred as a result of the 8.5% senior notes offering completed in the third quarter of 2008 and lower capitalized interest in 2009 compared to 2008.  Capitalized interest for the six months ended June 30, 2009 was $2.3 million compared to $4.1 million for the same period in 2008.  Average debt outstanding was $350.0 million and $155.3 during the six months ended June 30, 2009 and 2008, respectively (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $2.3 million, or 65%, from $3.6 million in the six months ended June 30, 2008, to $1.3 million in the six months ended June 30, 2009 because of lower interest rates during the 2009 period, partially offset by higher cash balances in 2009.

Provision for income taxes.  The provision for income taxes for the six months ended June 30, 2009 was $67.9 million on pretax income of $191.2 million (or 35.5%).  Our provision for income taxes for the six months ended June 30, 2008 was $49.6 million on pretax income of $154.9 million (or 32.0%).  The effective tax rate for the six months ended June 30, 2009 was higher than the effective tax rate in the comparable period in 2008 primarily due to a higher effective state income tax rate for the six months ended June 30, 2009.  The state income tax rate was higher in the 2009 period due to lower benefits from Kansas income tax credits.

Three months ended June 30, 2009 compared with the same period in 2008

Overview of Results

We had net income for the three months ended June 30, 2009 of $49.8 million, or $0.47 per diluted share, compared to net income of $59.3 million, or $0.57 per diluted share, earned in the same period in 2008.  Our operating income of $84.3 million for the three months ended June 30, 2009 increased $2.3 million from the $82.0 million for the comparable period in 2008.  Product yields and sales volumes were significantly higher during the three months ended June 30, 2009 because of a 20,000 bpd increase in capacity that resulted from the crude vacuum tower project and the major turnaround work completed at the El Dorado Refinery during the second quarter of 2008.  Our increased operating income benefited from a higher gasoline crack spread in the second quarter of 2009 ($10.85 per barrel) compared to the second quarter of 2009 ($5.85 per barrel).

Certain indicators of our profitability continued to decline for the three months ended June 30, 2009, including the diesel crack spread ($28.70 per barrel in 2008 to $6.28 per barrel in 2009) and both the light/heavy and WTI/WTS crude oil differentials.  We expect the U.S. recession could continue to negatively impact our 2009 results by reducing demand for gasoline and diesel.  The decline in crude oil differentials has been caused by several factors, including the significant industry investment over the last few years to process these types of crudes and the declining availability of heavy/sour crude oil.  The light/heavy crude oil differential decreased from $21.25 per barrel for the three months ended June 30, 2008 to $4.53 per barrel for the comparable period of 2009.  The WTI/WTS crude oil differential decreased from $4.98 per barrel for the three months ended June 30, 2008 to $1.02 per barrel for the comparable period of 2009.

Specific Variances

Refined product revenues.  Refined product revenues decreased $753.9 million, or 40%, from $1.88 billion to $1.13 billion for the three months ended June 30, 2009 compared to the same period in 2008.  This decrease resulted primarily from lower crude oil prices, and correspondingly lower refined product prices in the three months ended June 30, 2009 ($65.39 lower average per sales barrel), despite a significant increase in sales volumes.

Manufactured product yields.  Yields increased 16,812 bpd at the El Dorado Refinery and increased 1,556 bpd at the Cheyenne Refinery for the three months ended June 30, 2009 compared to same period in 2008.  The increase in yields at the El Dorado Refinery was due primarily to the crude unit and vacuum tower expansion and planned major turnaround work on the coker and the reformer completed during the second quarter of 2008.

Other revenues.  Other revenues increased $89.2 million to a loss of $26.3 million for the three months ended June 30, 2009, compared to a loss of $115.5 million for the same period in 2008.  In the three months ended June 30, 2009, the primary source of the loss was $29.7 million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories.  This compared to $116.8 million in net realized and unrealized losses on derivative contracts to hedge in-transit crude oil and excess inventories in the three months ended June 30, 2008.  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 in the three months ended June 30, 2009 (none in the comparable 2008 period), and $2.2 million of ethanol Renewable Identification Number (“RIN”) sales in 2009 versus $213,000 in the comparable period of 2008.

Raw material, freight and other costs.  Raw material, freight and other costs decreased by $660.8 million, from $1.57 billion in the three months ended June 30, 2008 to $914.1 million in the same period for 2009.  The decrease in raw material, freight and other costs was due to lower average crude oil prices and decreased purchased products, partially offset by increased overall crude oil charges and lower light/heavy and WTI/WTS crude oil differentials during the three months ended June 30, 2009 when compared to the same period in 2008.  For the three months ended June 30, 2009, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $78.6 million after tax ($126.9 million pretax, consisting of a $32.1 million gain at the Cheyenne Refinery and a $94.8 million gain at the El Dorado Refinery).  For the three months ended June 30, 2008, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $102.8 million after tax ($165.2 million pretax, comprised of a $48.3 million gain at the Cheyenne Refinery and a $116.9 million gain at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $52.83 per sales barrel for the three months ended June 30, 2009 decreased from $99.50 per sales barrel in the same period in 2008 due to lower average crude oil prices and decreased purchased products, partially offset by lower crude oil differentials.  The light/heavy crude oil differential for the Cheyenne Refinery averaged $4.93 per barrel in the three months ended June 30, 2009 compared to $20.54 per barrel in the same period in 2008.

The El Dorado Refinery raw material, freight and other costs of $52.48 per sales barrel for the three months ended June 30, 2009 decreased from $112.97 per sales barrel in the same period in 2008 primarily due to lower average crude oil prices; however, overall crude charges increased, and we experienced lower crude oil differentials.  The WTI/WTS crude oil differential decreased from an average of $4.98 per barrel in the three month period ended June 30, 2008 to $1.02 per barrel in the same period in 2009.  The light/heavy crude oil differential decreased from an average of $22.44 per barrel in the three month period ended June 30, 2008 to $3.90 per barrel in the same period in 2009.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $72.6 million in the three months ended June 30, 2009 compared to $81.0 million in the comparable period of 2008.

The Cheyenne Refinery operating expenses, excluding depreciation, were $26.8 million for the three months ended June 30, 2009 compared to $30.1 million in the comparable period of 2008.  The primary areas of decreased costs were: maintenance costs ($3.7 million due to various unplanned tank and coker repairs and outages incurred in 2008), and natural gas costs ($1.7 million due to decreased prices), partially offset by increased salaries and benefits expenses ($1.3 million), increased environmental expenses ($458,000) and increased electricity costs ($432,000).

The El Dorado Refinery operating expenses, excluding depreciation, were $45.8 million for the three months ended June 30, 2009, decreasing from $51.0 million in the same three month period of 2008.  Primary areas of decreased costs and variance amounts for the 2009 period compared to the 2008 period were: natural gas costs ($7.4 million due to decreased prices and significantly lower volumes) and maintenance costs ($1.8 million), partially offset by an increase in salaries and benefits expenses ($1.7 million), increased electricity costs ($713,000), increased environmental expenses ($612,000), increased additives and chemicals costs ($491,000), and increased turnaround amortization ($311,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, increased $718,000, or 6%, from $12.1 million for the three months ended June 30, 2008 to $12.9 million for the three months ended June 30, 2009, due to $1.1 million of higher salaries and benefit expenses (including stock-based compensation expense) in 2009.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $1.5 million, or 9%, for the three months ended June 30, 2009 compared to the same period in 2008 because of increased capital investments in our Refineries, including our El Dorado Refinery crude unit and vacuum tower expansion project that was placed into service in the second quarter of 2008.

Interest expense and other financing costs.  Interest expense and other financing costs of $6.9 million for the three months ended June 30, 2009 increased $4.0 million, from $2.9 million in the comparable period in 2008.  Increases in interest expense related to an additional $4.3 million of interest incurred as a result of the 8.5% senior notes offering completed in the third quarter of 2008 and lower capitalized interest in 2009 compared to 2008.  Capitalized interest for the three months ended June 30, 2009 was $1.3 million compared to $1.5 million for the same period in 2008.  Average debt outstanding was $350.0 million and $158.8 million during the three months ended June 30, 2009 and 2008, respectively (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $551,000, or 42%, from $1.3 million in the three months ended June 30, 2008, to $771,000 in the three months ended June 30, 2009, because of lower interest rates during the 2009 period, partially offset by a higher cash balance in 2009.

Provision for income taxes.  The provision for income taxes for the three months ended June 30, 2009 was $28.3 million on pretax income of $78.2 million (or 36.2%).  Our provision for income taxes for the three months ended June 30, 2008 was $21.1 million on pretax income of $80.4 million (or 26.2%).  The effective tax rate for the three months ended June 30, 2009 was higher than the effective tax rate in the comparable period in 2008 primarily due to a higher effective state income tax rate for the three months ended June 30, 2009.  The state income tax rate was higher in the 2009 period due to lower benefits from Kansas income tax credits.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities.  Net cash provided by operating activities was $96.7 million for the six months ended June 30, 2009 compared to net cash provided by operating activities of $119.8 million during the six months ended June 30, 2008.  Higher operating income attributed to higher cash flows during the 2009 period, but was offset by cash from working capital changes, which represented a larger use of cash in 2009 compared to the same period in 2008.  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 $91.0 million of cash during the first six months of 2009 compared to an $18.2 million use of cash for the same period in 2008.  The $91.0 million working capital changes for the 2009 period is primarily $269.4 million increase in inventory volumes and $14.4 million increase in receivables offset by $157.3 million of increased payables (primarily crude payables).  In the first six months of 2008 the working capital change of $18.2 million was primarily $260.2 million increase in inventory and $74.7 million increase in receivables, offset by $327.3 million of increased payables (primarily crude payables).  The variance between the six months ended 2009 and 2008 changes in working capital is due to significantly lower crude oil prices in 2009, and correspondingly lower 2009 refined product prices.  During the six months ended June 30, 2009, we received income tax refunds of $51.6 million, consisting mostly of our estimated federal and state income tax overpayments from 2008.  At June 30, 2009, we had $488.4 million of cash and cash equivalents, $745.1 million of working capital, and $334.7 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 2009 were $76.7 million, which included approximately $49.0 million for the El Dorado Refinery and $27.3 million for the Cheyenne Refinery.  The $49.0 million of capital expenditures for our El Dorado Refinery included $21.7 million on the gasoil hydrotreater revamp, $8.7 million on the catalytic cracker regenerator emission control project, $1.8 million for the catalytic cracker reliability project, $2.4 million on the coke drum replacement which was substantially completed in the third quarter of 2008, as well as operational, payout, safety, administrative, environmental and optimization projects.  The $27.3 million of capital expenditures for our Cheyenne Refinery included approximately $6.2 million on the new Cheyenne Refinery office and control buildings, and $2.6 million for the cat gas hydrotreater project, as well as environmental, operational, safety, administrative and payout projects.

Cash flows from financing activities.  During the six months ended June 30, 2009, treasury stock increased by 188,338 shares ($2.6 million) from stock surrendered by employees to pay withholding taxes on stock-based compensation which vested during the first six months of 2009.  We also paid $12.7 million in dividends during the six months ended June 30, 2009.

During the six months ended June 30, 2009, we issued 15,000 shares of common stock from our treasury stock in connection with a stock option exercise by a member of our Board of Directors, for which we received $70,000 in cash.  As of June 30, 2009, we had $347.4 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $119.8 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, 2009.  Shareholders’ equity as of June 30, 2009 was $1.17 billion.

Our Board of Directors declared regular quarterly cash dividends of $0.06 per share in November 2008, and February and April of 2009, which were paid in January, April and July of 2009, respectively.  The total cash required for the dividend declared in April 2009 was approximately $6.2 million and was included in “Accrued liabilities and other” on the June 30, 2009 Condensed Consolidated Balance Sheet.

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 $90 million ($55.6 million incurred as of June 30, 2009) (see “Environmental” in Note 13 in the “Notes to Condensed Consolidated Financial Statements”).  The project will also result in a significant yield improvement for the catalytic cracking unit and is anticipated to be completed in the second quarter of 2010.  As of June 30, 2009, outstanding non-cancelable purchase commitments for the gasoil hydrotreater revamp were $6.3 million.  The El Dorado Refinery’s catalytic cracker reliability project has a total estimated cost of $27.5 million ($7.1 million incurred as of June 30, 2009).  The project is anticipated to be completed in the fall of 2009 and had outstanding non-cancelable purchase commitments at June 30, 2009 of $3.4 million.  The El Dorado Refinery catalytic cracker regenerator emission control project, with a fall 2009 estimated completion date and total estimated cost of $34 million ($24.9 million incurred as of June 30, 2009), will add a scrubber to improve the environmental performance of the unit, specifically as it relates to flue-gas emissions.  This project is necessary to meet various EPA requirements (see “Environmental” in Note 13 in the “Notes to Condensed Consolidated Financial Statements”).  At June 30, 2009, the catalytic cracker regenerator emission control project had outstanding non-cancelable purchase commitments of $1.9 million.  At the Cheyenne Refinery, we plan to comply with the low sulfur gasoline requirements with the completion of the cat gasoline hydrotreater project (see “Environmental” in Note 13 in the “Notes to Condensed Consolidated Financial Statements”).  This project is expected to be completed during the fourth quarter of 2010 at an estimated total cost of $40.0 million.  The above amounts include estimated capitalized interest.

2009 capital expenditures.  Including the projects discussed above, 2009 capital expenditures aggregating approximately $206.1 million are currently planned, and include $135.3 million at our El Dorado Refinery, $68.1 million at our Cheyenne Refinery, $2.3 million at our products terminals, pipeline and blending facilities and $392,000 at our Denver and Houston offices.  The $135.3 million of planned capital expenditures for our El Dorado Refinery includes $47.2 million for the gasoil hydrotreater revamp project, $22.0 million for the catalytic cracker reliability project and $16.7 million for the catalytic cracker regenerator emission control project, as mentioned above, as well as environmental, operational, safety, payout and administrative projects.  The $68.1 million of planned capital expenditures for our Cheyenne Refinery includes $19.0 million for the cat gas hydrotreater project as well as other environmental, operational, safety, payout and administrative projects.  We expect that our 2009 capital expenditures will be funded with cash generated by our operations and by using a portion of our existing cash balance, if necessary.  We will continue to review our capital expenditures in light of market conditions.  We may experience cost overruns and/or schedule delays 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, 2009 and 2008.  The statistical information includes the following terms:

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

·  Charges - the quantity of crude oil and other feedstock processed through Refinery 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.

·  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.

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

·  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.

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

Consolidated:
	Six Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		49,928		21,499		64,663		31,939
Heavy and intermediate crude		116,928		101,568		103,935		110,323
Other feed and blendstocks		14,954		20,632		12,554		19,118
Total		181,810		143,699		181,152		161,380
Manufactured product yields (bpd)
Gasoline		83,248		69,351		83,723		73,203
Diesel and jet fuel		72,418		46,522		74,059		54,220
Asphalt		1,722		4,520		2,055		3,472
Other		19,701		19,247		14,948		25,520
Total		177,089		139,640		174,785		156,415
Total product sales (bpd)
Gasoline		93,625		78,742		95,231		82,155
Diesel and jet fuel		72,369		46,597		74,139		54,587
Asphalt		1,293		4,813		1,464		4,345
Other		18,004		17,806		20,272		17,679
Total		185,291		147,958		191,106		158,766
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	58.15	$	114.73	$	64.87	$	130.26
Raw material, freight and other costs		45.74		95.59		52.56		109.01
Refinery operating expenses, excluding depreciation		4.43		6.26		4.17		5.61
Depreciation, amortization and accretion		1.07		1.16		1.03		1.14
Average NYMEX WTI (per barrel) (1)	$	51.51	$	110.98	$	59.83	$	124.28
Average light/heavy differential (per barrel) (1)		5.52		16.62		4.53		21.25
Average gasoline crack spread (per barrel) (1)		9.03		5.11		10.85		5.85
Average diesel crack spread (per barrel) (1)		8.98		24.83		6.28		28.70
Average sales price (per sales barrel)
Gasoline	$	62.58	$	118.89	$	71.94	$	133.03
Diesel and jet fuel		61.68		141.20		66.72		156.45
Asphalt		56.68		45.60		65.60		59.57
Other		21.07		45.80		24.87		53.90
(1) The 2008 amounts are restated to reflect current year presentation measurement under NYMEX WTI.

Cheyenne Refinery:
	Six Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		15,536		7,615		19,149		7,089
Heavy and intermediate crude		25,578		34,119		22,765		33,229
Other feed and blendstocks		1,367		1,039		744		434
Total		42,481		42,773		42,658		40,752
Manufactured product yields (bpd)
Gasoline		18,468		18,726		18,588		16,981
Diesel		14,833		11,752		14,987		10,111
Asphalt		1,722		4,520		2,055		3,472
Other		5,740		6,428		5,051		8,561
Total		40,763		41,426		40,681		39,125
Total product sales (bpd)
Gasoline		26,163		27,277		24,424		25,519
Diesel		14,676		11,535		15,185		10,671
Asphalt		1,293		4,813		1,464		4,345
Other		4,588		5,309		4,151		6,216
Total		46,720		48,934		45,224		46,751
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	58.05	$	106.06	$	66.52	$	119.63
Raw material, freight and other costs		46.05		89.10		52.83		99.50
Refinery operating expenses, excluding depreciation		6.51		6.66		6.52		7.07
Depreciation, amortization and accretion		1.73		1.47		1.76		1.51
Average light/heavy crude oil differential (per barrel) (1)	$	5.39	$	19.45	$	4.93	$	20.54
Average gasoline crack spread (per barrel) (1)		8.69		4.37		12.95		6.17
Average diesel crack spread (per barrel) (1)		10.79		26.45		8.72		30.94
Average sales price (per sales barrel)
Gasoline	$	62.37	$	115.15	$	73.80	$	129.83
Diesel		64.36		140.27		69.41		159.93
Asphalt		56.68		45.60		65.60		59.57
Other		13.57		39.83		13.49		50.55
(1) The 2008 amounts are restated to reflect current year presentation measurement under NYMEX WTI.

El Dorado Refinery:
	Six Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		34,392		13,884		45,514		24,850
Heavy and intermediate crude		91,350		67,449		81,170		77,094
Other feed and blendstocks		13,587		19,593		11,810		18,684
Total		139,329		100,926		138,494		120,628
Manufactured product yields (bpd)
Gasoline		64,780		50,624		65,135		56,222
Diesel and jet fuel		57,585		34,770		59,071		44,110
Other		13,961		12,819		9,897		16,959
Total		136,326		98,213		134,103		117,291
Total product sales (bpd)
Gasoline		67,463		51,464		70,807		56,636
Diesel and jet fuel		57,693		35,062		58,955		43,916
Other		13,416		12,497		16,121		11,463
Total		138,572		99,023		145,883		112,015
Refinery operating margin information (per sales barrel)
Refined products revenue	$	58.19	$	119.02	$	64.36	$	134.70
Raw material, freight and other costs		45.63		98.79		52.48		112.97
Refinery operating expenses, excluding depreciation		3.72		6.06		3.45		5.00
Depreciation, amortization and accretion		0.85		1.01		0.80		0.98
Average WTI/WTS crude oil differential (per barrel)	$	1.36	$	4.81	$	1.02	$	4.98
Average light/heavy crude oil differential (per barrel) (1)		5.72		11.76		3.90		22.44
Average gasoline crack spread (per barrel) (1)		9.16		5.50		10.13		5.70
Average diesel crack spread (per barrel) (1)		8.52		24.30		5.65		28.16
Average sales price (per sales barrel)
Gasoline	$	62.66	$	120.87	$	71.29	$	134.48
Diesel and jet fuel		61.00		141.50		66.02		155.61
Other		23.64		48.33		27.80		55.72
(1) The 2008 amounts are restated to reflect current year presentation measurement under NYMEX WTI.

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.

Under our FIFO inventory accounting method, crude oil price movements can cause significant fluctuations in the valuation of our crude oil, unfinished products and finished products inventories, typically resulting in inventory valuation gains when crude oil prices increase and inventory valuation losses when crude oil prices decrease during the reporting period.

Price Risk Management Activities.  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 Income and Comprehensive Income 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 Income and Comprehensive Income.  See Note 12 “Price Risk Management Activities” in the “Notes to Condensed Consolidated Financial Statements.”

Our outstanding derivatives sell contracts and net unrealized losses as of June 30, 2009 are summarized below:

Commodity	Period	Volume (thousands of bbls)	Expected Close Out Date	Unrealized Net (Loss) Gain (in thousands)
Crude Oil	August 2009	1,791	July 2009	$(5,043)
Crude Oil	September 2009	977	August 2009	228

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 million 8.5% Senior Notes due 2016 that were outstanding at June 30, 2009 have fixed interest rates.  Thus, our long-term debt is not exposed to cash flow risk from interest rate changes.  Our long-term debt, however, is exposed to fair value risk.  The estimated fair value of our 6.625% Senior Notes was $146.6 million and our 8.5% Senior Notes was $201.5 million at June 30, 2009.

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 President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, the  effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act.  Based on that evaluation, our 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 Note 14 in the Notes to Condensed Consolidated Financial Statements.

ITEM 1A.

Risk Factors – Our operations involve environmental risks that may require us to make substantial capital expenditures to remain in compliance or that could give rise to material liabilities. Our results of operations may be affected by increased costs of complying with the extensive environmental laws to which our business is subject and from any possible contamination of our facilities as a result of accidental spills, discharges or other releases of petroleum or hazardous substances. Our operations are subject to extensive federal, state and local environmental and health and safety laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the air and water, product specifications and the generation, treatment, storage, transportation, disposal or remediation of solid and hazardous waste and materials.  Environmental laws and regulations that affect the operations, processes and margins for our refined products are extensive and have become progressively more stringent.  Additional legislation or regulatory requirements or administrative policies could be imposed with respect to our products or activities.  Compliance with more stringent laws or regulations or more vigorous enforcement policies of the regulatory agencies could adversely affect our financial position and results of operations and could require us to make substantial expenditures.  Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities.  For examples of existing and potential future regulations and their possible effects on us, please see “Environmental” in Note 13 in the “Notes to the Condensed Consolidated Financial Statements.” Our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances. Past or future spills related to any of our operations, including our Refineries, pipelines or product terminals, could give rise to liability (including potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law.  This could involve contamination associated with facilities that we currently own or operate, facilities that we formerly owned or operated and facilities to which we sent wastes or by-product for treatment or disposal and other contamination.  Accidental discharges could occur in the future, future action may be taken in connection with past discharges, governmental agencies may assess penalties against us in connection with past or future contamination and third parties may assert claims against us for damages allegedly arising out of any past or future contamination.  The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations. We may have labor relations difficulties with some of our employees represented by unions. Approximately 56 percent of our employees were covered by collective bargaining agreements at June 30, 2009.  Our El Dorado Refinery union contract expires in early 2012; the prior contract expired in early 2009.  Our Cheyenne Refinery union contracts expired in June and July of 2009.  New union contracts were ratified in June and July of 2009 between the Cheyenne Refinery and its unions that have expiration dates in 2012.  Employees may conduct a strike at some time in the future, which may increase our costs or result in an interruption of our business, both of which could adversely affect our operations.

ITEM 4. Submission of Matters to a Vote of Security Holders –    The annual shareholders meeting of the Company was held on April 29, 2009, with 96,733,302 of the Company’s shares present or represented by proxy at the meeting.  This represented nearly 93% of the Company’s shares outstanding as of the record date of the meeting.  The shareholders of the Company took the following actions:    1.Election of Directors:  Elected the following seven directors for terms of office expiring at the annual meeting of shareholders in 2010:

Name	For	Withheld
James R. Gibbs	85,624,176	769,414
Douglas Y. Bech	84,018,661	2,374,929
G. Clyde Buck	85,206,494	1,187,096
T. Michael Dossey	85,301,317	1,092,273
Michael C. Jennings	85,351,302	1,042,288
James H. Lee	85,442,178	951,412
Paul B. Loyd, Jr.	84,230,800	2,162,790
Michael E. Rose	84,699,465	1,694,125

 2.The shareholders authorized the Second Amended and Restated Articles of Incorporation of the Company.  The effect of this amendment is to modernize the Company’s Articles of Incorporation and make them consistent with Wyoming law, the Company’s bylaws and current practice. The amendment amends or eliminates several ambiguous or obsolete provisions. The amendment does not, however, alter the number of shares or classes of the Company’s authorized capital stock.  The number of votes cast for the amendment was 94,780,111 with 1,513,797 against, 439,394 abstentions and no broker non-votes.

 3. The shareholder ratified the appointment of Deloitte & Touch LLP as the Company’s auditors for the year ending December 31, 2009.  The number of votes cast for the appointment was 95,654,087 with 810,998 against, 268,217 abstentions and no broker non-votes.

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.

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 6, 2009