Frontier Oil (FTO) 10-Q 2009 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 2, 2009:  104,663,411

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

INDEX

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

PART I - FINANCIAL INFORMATION

ITEM 1.               FINANCIAL STATEMENTS

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited, in thousands, except per share data)
	Nine Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
Revenues:
Refined products	$	3,147,210		$	5,184,204		$	1,196,899		$	2,094,606
Other		1,464			(33,563	)		3,683			103,696
		3,148,674			5,150,641			1,200,582			2,198,302
Costs and expenses:
Raw material, freight and other costs		2,631,548			4,565,992			1,097,559			1,991,966
Refinery operating expenses, excluding depreciation		232,175			244,861			83,701			76,267
Selling and general expenses, excluding depreciation		38,937			32,379			13,650			9,876
Depreciation, amortization and accretion		54,226			48,072			18,099			16,635
Gain on sales of assets		-			(44	)		-			-
		2,956,886			4,891,260			1,213,009			2,094,744
Operating income (loss)		191,788			259,381			(12,427	)		103,558
Interest expense and other financing costs		21,046			7,043			6,709			2,480
Interest and investment income		(1,948	)		(4,691	)		(661	)		(1,056	)
		19,098			2,352			6,048			1,424
Income (loss) before income taxes		172,690			257,029			(18,475	)		102,134
Provision (benefit) for income taxes		64,517			79,421			(3,348	)		29,811
Net income (loss)	$	108,173		$	177,608		$	(15,127	)	$	72,323
Comprehensive income (loss)	$	108,052		$	176,135		$	(15,123	)	$	71,912
Basic earnings (loss) per share of common stock	$	1.04		$	1.72		$	(0.15	)	$	0.70
Diluted earnings (loss) per share of common stock	$	1.03		$	1.71		$	(0.15	)	$	0.70
The accompanying notes are an integral part of these condensed consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands except share data)
September 30, 2009 and December 31, 2008	2009			2008
ASSETS
Current assets:
Cash, including cash equivalents of $486,178 and $482,415 at 2009 and 2008,     respectively	$	487,314		$	483,532
Trade receivables, net of allowance of $1,000 and $500 at 2009 and 2008, respectively		135,780			84,110
Income taxes receivable		64,723			116,118
Other receivables		6,452			25,216
Inventory of crude oil, products and other		523,104			256,129
Deferred income taxes		10,625			8,841
Commutation account		-			6,319
Other current assets		4,249			37,038
Total current assets		1,232,247			1,017,303
Property, plant and equipment, at cost:
Refineries, pipeline and terminal equipment		1,405,578			1,291,106
Furniture, fixtures and other equipment		16,658			15,638
		1,422,236			1,306,744
Accumulated depreciation and amortization		(425,807	)		(373,301	)
Property, plant and equipment, net		996,429			933,443
Deferred turnaround costs		38,204			47,465
Deferred catalyst costs		11,214			9,726
Deferred financing costs, net of accumulated amortization of $3,520 and $2,404 at     2009 and 2008, respectively		5,083			6,201
Intangible assets, net of accumulated amortization of $583 and $492 at 2009 and     2008, respectively		1,246			1,338
Other assets		3,931			2,993
Total assets	$	2,288,354		$	2,018,469
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	448,729		$	308,867
Accrued liabilities and other		62,947			57,084
Total current liabilities		511,676			365,951
Long-term debt		347,416			347,220
Contingent income tax liabilities		28,912			28,057
Post-retirement employee liabilities		32,823			31,128
Long-term capital lease obligation		3,502			3,548
Other long-term liabilities		20,894			12,211
Deferred income taxes		193,020			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		247,498			236,183
Retained earnings		1,240,701			1,151,676
Accumulated other comprehensive loss		(845	)		(723	)
Treasury stock, at cost, 27,186,945 and 27,945,884 shares at 2009 and 2008, respectively		(394,979	)		(393,732	)
Total shareholders' equity		1,150,111			1,051,140
Total liabilities and shareholders' equity	$	2,288,354		$	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)
	Nine Months Ended September 30,
	2009			2008
Cash flows from operating activities:
Net income	$	108,173		$	177,608
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, amortization and accretion		69,194			61,082
Deferred income taxes		12,097			15,684
Stock-based compensation expense		15,193			13,736
Excess income tax benefits of stock-based compensation		(227	)		(4,201	)
Amortization of debt issuance costs		1,117			603
Senior Notes discount amortization		196			8
Allowance for investment loss and bad debts		500			411
Gain on sales of assets		-			(44	)
Amortization of long-term prepaid insurance		-			909
Increase (decrease) in other long-term liabilities		11,357			(1,331	)
Changes in deferred turnaround costs, deferred catalyst costs and other		(8,133	)		(30,817	)
Changes in working capital from operations		(62,401	)		(13,258	)
Net cash provided by operating activities		147,066			220,390
Cash flows from investing activities:
Additions to property, plant and equipment		(121,574	)		(160,219	)
Proceeds from sales of assets		-			45
El Dorado Refinery contingent earn-out payment		-			(7,500	)
Net cash used in investing activities		(121,574	)		(167,674	)
Cash flows from financing activities:
Proceeds from issuance of 8.5% Senior Notes, net of discount		-			197,160
Purchase of treasury stock		(2,654	)		(66,403	)
Proceeds from issuance of common stock		70			265
Dividends paid		(19,071	)		(16,938	)
Excess income tax benefits of stock-based compensation		227			4,201
Debt issuance costs and other		(282	)		(4,372	)
Net cash (used in) provided by financing activities		(21,710	)		113,913
Increase in cash and cash equivalents		3,782			166,629
Cash and cash equivalents, beginning of period		483,532			297,399
Cash and cash equivalents, end of period	$	487,314		$	464,028
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	17,227		$	2,053
Cash paid during the period for income taxes		36,150			59,690
Cash refunds of income taxes		51,593			24,559
Noncash investing activities - accrued capital expenditures, end of period		21,917			17,450
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.

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:

	Nine Months Ended September 30,				Three Months Ended September 30,
	2009		2008		2009		2008
Basic		103,536,988		103,114,161		103,746,632		103,176,904
Diluted		104,688,166		103,784,836		103,746,632		103,919,817

For the nine months ended September 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.  Basic and diluted shares were the same for the three months ended September 30, 2009 because a loss was incurred and therefore the impact of outstanding stock options was anti-dilutive.  For the nine and three months ended September 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, April and September 2009, which were paid in January, April, July and October 2009, respectively.  The total cash required for the dividend declared in September 2009 was approximately $6.2 million and was reflected in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheet as of September 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 nine and three months ended September 30, 2009, the Company recognized a loss in “Other Revenues” of $1.2 million and $313,000, respectively, and none in 2008 due to the translation of its foreign denominated assets and liabilities.

New accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 820, “Fair Value Measurements and Disclosures.”  ASC 820 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.  ASC 820 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  The Company was required to apply ASC 820 to non-recurring financial and non-financial instruments effective January 1, 2009 in addition to all other financial instruments.  See Note 11 “Fair Value Measurement” for related disclosures.

In March 2008, the FASB released additional disclosure requirements for derivative instruments and hedging activities under ASC 815-10-50.  ASC 815-10-50 disclosure provisions apply to all entities with derivative instruments subject to current guidance under GAAP.  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 ASC 815-10-50 must provide more robust qualitative disclosures and expanded quantitative disclosures.  The disclosure requirements are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008; thus, the Company adopted ASC 815-10-50 on January 1, 2009.  See Note 12 “Price Risk Management Activities” for additional disclosures required under ASC 815-10-50.

In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.”  This issuance by the FASB 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 ASC 820, “Fair Value Measurements and Disclosures.”  The additional requirements were effective for interim and annual periods ending after June 15, 2009.  The adoption of these requirements did not have a material impact on the Company’s financial statements.

In April 2009, the FASB issued additional guidance under ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments.”  This guidance 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 guidance 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 guidance is effective for interim and annual reporting periods ending after June 15, 2009.  The adoption of this new guidance did not have a material impact on the Company’s financial statements.

In April 2009, the FASB issued additional guidance under ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This additional guidance amends current fair value guidance within GAAP, to require disclosures about the fair value of financial instruments in interim financial statements as well as in annual financial statements.  The new guidance is effective for interim and annual reporting periods ending after June 15, 2009.  The adoption of this guidance did not have a material impact on the Company’s financial statements.  See Note 11 “Fair Value Measurement” for additional disclosures required under this guidance.

In April 2009, the FASB issued additional guidance under ASC 805-20 to address concerns about the application of current guidance to assets and liabilities arising from contingencies in a business combination.  The new guidance amendments establish a model similar to the one entities used under current guidance to account for preacquisition contingencies.  This new guidance 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 new guidance did not have a material impact on the Company’s financial statements.

In May 2009, the FASB issued ASC 855, “Subsequent Events.”  ASC 855 provides guidance on management’s assessment of subsequent events.  Companies had historically relied upon U.S. auditing literature for guidance on assessing and disclosing subsequent events.  ASC 855 represents the inclusion of guidance on subsequent events in the accounting literature and is directed specifically to management.  ASC 855 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 ASC 855 did not have a material impact on the Company’s financial statements.

In December 2008, the FASB released ASC 715-20-65-2, “Employers' Disclosures about Postretirement Benefit Plan Assets,” which amends current guidance in ASC 715-20, “Compensation-Retirement Benefits, Defined Benefit Plans,” 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 amended guidance to ASC 810 “Consolidation” which amends the consolidation guidance that applies to variable interest entities (“VIEs”).  This statement amends current consolidation guidance to require companies to perform an analysis to determine whether a company’s variable interest or interests give it a controlling financial interest in a VIE and assess whether the company has implicit financial responsibility to ensure that the VIE operates as designed when determining if it has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance.  This statement also amends current guidance to require companies to perform ongoing reassessments of whether the company is the primary beneficiary of a VIE.  This statement amends certain guidance for determining whether an entity is a VIE, and the application of this revised guidance may change a company’s assessment of its VIEs.  The statement is effective as of the beginning of the first fiscal year that begins after November 15, 2009.  The Company is currently evaluating the potential impact of this statement on its financial statements and disclosures.

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

In June 2009, the FASB issued ASC 105 “Generally Accepted Accounting Principles” effectively establishing the Accounting Standards Codification as the source of authoritative U.S. GAAP recognized by the FASB to be applied to rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants.  The Codification, established as part of ASC 105, supersedes existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force and related literature.  All guidance within the Codification has equal authority and all other accounting literature is considered non-authoritative.  ASC 105 was adopted by the Company during the period ended September 30, 2009.  The adoption of ASC 105 changed the way the Company cites authoritative guidance within the Company’s financial statements and accounting policies, however, the impact was not material.

In August 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-05 to provide guidance on measuring the fair value of liabilities under ASC 820.  This ASU clarifies that the quoted price for the identical liability, when traded as an asset in the active market, is also a Level 1 measurement for that liability when no adjustment is made to the quoted price.  This ASU was effective immediately after its release.  The adoption of this ASU did not have a material impact on the Company's financial statements or disclosures.

2.      Other Receivables

	September 30,		December 31,
	2009		2008
	(in thousands)
Investment fund receivable, net of allowance	$	2,781	$	6,418
Realized futures trading receivable		1,247		11,854
Other		2,424		6,944
	$	6,452	$	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.  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 September 30, 2009 and December 31, 2008.  In addition, the Company received partial distributions through September 30, 2009 from the Fund totaling $29.4 million, resulting in a net investment fund receivable of $2.8 million.  In October 2009, subsequent to the balance sheet date, the Company received another $638,000 partial distribution, increasing its total distributions to $30.1 million and resulting in a remaining net investment fund receivable of $2.2 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.  Inventory as of September 30, 2009 and December 31, 2008 was reduced by $12.4 million and $19.8 million in lower of cost or market adjustments.  The components of inventory as of September 30, 2009 and December 31, 2008 were as follows:

	September 30,		December 31,
	2009		2008
	(in thousands)
Crude oil	$	278,903	$	121,973
Unfinished products		121,335		55,915
Finished products		96,744		54,332
Process chemicals		1,241		1,385
Repairs and maintenance supplies and other		24,881		22,524
	$	523,104	$	256,129

4.      Other Current Assets

	September 30,		December 31,
	2009		2008
	(in thousands)
Margin deposits	$	1,439	$	18,323
Derivative assets		549		8,584
Prepaid insurance		887		8,374
Other		1,374		1,757
	$	4,249	$	37,038

5.         Accrued Liabilities and Other

	September 30,		December 31,
	2009		2008
	(in thousands)
Accrued compensation	$	11,689	$	12,606
Accrued Beverly Hills litigation settlement		-		10,000
Accrued environmental costs		5,467		10,040
Accrued interest		5,678		7,363
Accrued dividends		6,856		6,779
Accrued income taxes		19,744		326
Accrued property taxes		9,322		5,295
Derivative liabilities		745		-
Other		3,446		4,675
	$	62,947	$	57,084

6.      Long-term Debt

	September 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		(2,584	)		(2,780	)
8.5% Senior Notes, net		197,416			197,220
	$	347,416		$	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 ASC 740 “Income Taxes.”  A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding accrued interest and the federal income tax benefit of state contingencies, is as follows (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 $28.9 million and $28.1 million at September 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 $1.3 million and $339,000 during the nine months ended September 30, 2009 and 2008, and $430,000 and a credit of $785,000 during the three months ended September 30, 2009 and 2008, respectively.  Both the nine and three months ended September 30, 2008 included a reversal of accrued interest expense on contingent income tax liabilities of $1.3 million due to the lapse of applicable statutes of limitations.

8.      Treasury Stock

The Company accounts for its treasury stock under the cost method on a FIFO basis.  Through September 30, 2009, the Company’s Board of Directors has approved a total of $400 million for share repurchases, of which $299.8 million had been utilized (none in 2009), leaving remaining authorization of $100.2 million for future repurchases of shares.  A rollforward of treasury stock for the nine months ended September 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		193,234			2,654
Shares issued for stock option exercises		(15,000	)		(20	)
Shares issued for restricted stock grants, net of forfeits		(694,504	)		(1,042	)
Shares issued for conversion of stock unit awards		(242,669	)		(345	)
Balance as of September 30, 2009		27,186,945		$	394,979

 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 nine and three months ended September 30, 2009 and 2008 were as follows:

		Nine Months Ended September 30,				Three Months Ended September 30,
		2009		2008		2009		2008
	(in thousands)
Restricted shares and units		$	12,637	$	8,206	$	2,829	$	2,759
Stock options			304		677		-		226
Contingently issuable stock unit awards			2,252		4,853		1,611		949
Total stock-based compensation expense		$	15,193	$	13,736	$	4,440	$	3,934
Income tax benefit recognized in the income statement		$	5,774	$	4,348	$	1,688	$	1,496

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 September 30, 2009, 2,184,081 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 nine months ended September 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 September 30, 2009, there was $24.7 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 2.01 years.

Stock Options.  Stock option changes during the nine months ended September 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 nine months ended September 30, 2009.  The total intrinsic value of stock options exercised during the nine months ended September 30, 2009 was $160,000.  The Company realized $61,000 and $1.3 million of income tax benefit, nearly all of which was excess income tax benefit, for the nine months ended September 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.  All outstanding stock options were vested and exercisable at September 30, 2009 with weighted average remaining contractual lives of 1.57 years.

Restricted Shares and Restricted Stock Units.  The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the nine months ended September 30, 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		752,300			13.6143
Vested		(596,704	)		27.5376
Forfeited		(5,236	)		12.7200
Nonvested at end of period		964,508			20.2935

The total grant date fair value of restricted shares and restricted stock units which vested during the nine months ended September 30, 2009 was $16.4 million. The total intrinsic value of restricted shares and restricted stock units that vested during the nine months ended September 30, 2009 was $8.1 million.  The Company realized $3.1 million of income tax benefit related to these vestings, and reduced the Company’s available pool of excess income tax benefits by $3.2 million.  The total grant date fair value of restricted shares and restricted stock units which vested during the nine months ended September 30, 2008 was $22.9 million.  The total intrinsic value of restricted shares and restricted stock units that vested during the nine months ended September 30, 2008 was $31.3 million, and the Company realized $10.8 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 747,064 shares of restricted stock shares and units granted, net of forfeitures, during the nine months ended September 30, 2009.

			Vesting Dates and Share Amounts
Conversion Date	Converted stock unit awards		June 15, 2009(1)		June 30, 2009		August 10, 2009(1)		June 30, 2010		June 30, 2011
March 25, 2009		242,669		54,762		62,635		3,968		60,653		60,651

			Vesting Dates and Share Amounts
Grant Date	Shares/Units Granted (Net of Forfeits)		March 25, 2009 (1)		August 10, 2009 (1)		December 31, 2009		March 13, 2010		March 13, 2011		March 13, 2012
January 30, 2009		52,560						52,560
February 24, 2009		313,355				5,684				76,918		76,918		153,835
March 25, 2009		365,225		124,370		1,039				59,958		59,964		119,894
April 28, 2009		8,424								2,106		2,106		4,212
September 9, 2009		7,500								1,875		1,875		3,750
Total		747,064		124,370		6,723		52,560		140,857		140,863		281,691
(1) Accelerated vesting due to retirement or termination of employees.

Contingently Issuable Awards.  During the nine months ended September 30, 2009, the Company granted 512,216 contingently issuable stock unit awards, net of forfeitures, 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, with the exception of restricted shares related to a severance agreement that will vest immediately upon certification.  As of September 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 (320,136 stock units, net of forfeitures) would be earned for the net income contingent awards and the target (100%) level award (256,108 stock units, net of forfeitures) would be earned for the return of capital employed versus that of a defined peer group.

The Company also granted 253,155 stock unit awards, net of forfeitures, contingent upon certain share price performance versus the Company’s peers being met over a three-year period ending on December 31, 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 September 30, 2009, the Company also had outstanding (net of forfeitures) 182,916 and 191,779 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 GAAP.

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 September 30, 2009, the fair market value of the pension plan assets was $11.4 million and the pension benefit obligation was $11.5 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 contributed $500,000 to the Trust Fund during the first nine months of 2009.  Frontier’s pension plan weighted-average asset allocations in the Trust Fund at September 30, 2009 and December 31, 2008, by asset category, were as follows:

	Percentage of Plan Assets at
Asset Category:	September 30, 2009			December 31, 2008
Cash and cash equivalents		100	%		89	%
Fixed income common trust funds		0	%		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 September 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:

	Nine Months Ended September 30,						Three Months Ended September 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		196			463			65			155
Expected return on plan assets		(134	)		(609	)		(45	)		(203	)
Amortization of prior service cost		426			-			213			-
Amortized net actuarial loss		-			200			-			200
Net periodic benefit cost		488			54			233			152
Changes in assets and benefit obligations recognized in other comprehensive income:
Net loss		-			484			-			484
Amortization of prior service cost		(426	)		-			(213	)		-
Amortization of gain		-			-			-			-
Total recognized in other comprehensive income		(426	)		484			(213	)		484
Total recognized in net periodic benefit cost and other comprehensive income	$	62		$	538		$	20		$	636

	Nine Months Ended September 30,						Three Months Ended September 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	$	535		$	568		$	179		$	188
Interest cost		1,417			1,306			472			436
Expected return on plan assets		-			-			-			-
Amortization of prior service cost		(1,407	)		(1,190	)		(469	)		(396	)
Amortized net actuarial loss		784			653			261			216
Net periodic benefit cost		1,329			1,337			443			444
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		1,407			1,190			469			396
Amortization of loss		(784	)		(653	)		(261	)		(217	)
Total recognized in other comprehensive income		623			1,887			208			179
Total recognized in net periodic benefit cost and other comprehensive income	$	1,952		$	3,224		$	651		$	623

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 September 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	$	549	$	-	$	-	$	549
Derivative liabilities		-		745		-		745

As of September 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 derivative contracts giving rise to the assets under Level 2 are valued using pricing models based on NYMEX crude oil contracts.  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 September 30, 2009:

	Nine Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Beginning derivative asset balance	$	-		$	-		$	85		$	647
Net increase in derivative assets		231			437			(18	)		(474	)
Net settlements		(231	)		(437	)		(67	)		(173	)
Transfers in (out) of Level 3		-			-			-			-
Ending derivative asset balance	$	-		$	-		$	-		$	-

The fair value of the Company’s Senior Notes was estimated based on quotations obtained from broker-dealers who make markets in these and similar securities.  At September 30, 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 $150.0 million and $135.8 million, respectively.  At September 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 $205.0 million and $176.5 million.  For cash and cash equivalents, the carrying amounts at September 30, 2009 and December 31, 2008 of $487.3 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, to fix margins on certain future production or to hedge interest rate risk.  The commodity derivative contracts used by the Company may take the form of futures contracts, forward contracts, collars or price or interest rate swaps.  The Company, also at times, enters into foreign exchange contracts to manage its exposure to foreign currency fluctuations on its purchases of foreign crude oil.  The Company believes that there is minimal credit risk with respect to its counterparties.  The Company’s commodity derivative contracts and foreign exchange contracts, while economic hedges are not 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 September 30, 2009, the Company had the following outstanding commodity derivative contracts:

Commodity	Number of barrels
	(in thousands)
Crude purchases in-transit		837
Crude oil contracts to hedge excess intermediate, finished product and crude oil inventory		1,166

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

	Asset Derivatives in Other Current Assets							Liability Derivatives in Accrued Liabilities and Other
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
		Fair Value			Fair Value			Fair Value			Fair Value
	(in thousands)
Derivatives not designated    as hedging instruments
Commodity contracts		$	347		$	8,584		$	745		$	-
Other contracts			202			-			-			-
Total derivatives		$	549		$	8,584		$	745		$	-

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 (Loss) Recognized in Other Revenues						Amount of Derivatives Gain (Loss) Recognized in Other Revenues
	Nine Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Derivatives not designated as hedging    instruments
Commodity contracts	$	(3,246	)	$	(39,906	)	$	4,227		$	103,995
Foreign exchange contracts		799			174			-			174
Other contracts		(40	)		367			(289	)		(474	)

On October 1, 2009, subsequent to the balance sheet date, the Company entered into a $75.0 million interest rate swap transaction.  This swap effectively converts a portion of our interest expense from fixed to variable rate debt.   Under this swap contract, interest on the $75.0 million notional amount is computed using 30-day LIBOR plus a spread of 5.34%, which equaled an effective interest rate of 5.59% as of the transaction date.  On October 28, 2009, the Company entered into an additional $75 million interest rate swap transaction using 30-day LIBOR plus a spread of 5.335%, which equaled an effective interest rate of 5.58% as of the transaction date.  The maturity of both swap transactions is October 1, 2011, corresponding to the maturity of the Company’s 6.625% Senior Notes.

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.  To meet final federal gasoline sulfur standards at the Cheyenne Refinery, the Company expects to spend approximately $40.0 million ($7.2 million incurred as of September 30, 2009) for the cat gasoline hydrotreater project comprised of new process unit capacity and intermediate inventory handling equipment.  In addition, new federal benzene regulations and anticipated state requirements for reduction in gasoline Reid Vapor Pressure (“RVP”) suggest that additional capital expenditures may be required for environmental compliance projects.  The Company is presently evaluating projects and the total potential cost in connection with an overall compliance strategy for the Cheyenne Refinery.  Total capital expenditures estimated as of September 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 September 30, 2009, $67.5 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 year’s operations at both the Cheyenne and the El Dorado Refineries.  During the nine months ended September 30, 2009, Frontier sold 47.0 billion (ppm-gallons) sulfur credits for total proceeds of $1.9 million which was recorded in “Other revenues” on the Condensed Consolidated Statements of Income and Comprehensive Income.  There were no sulfur credit sales during the three months ended September 30, 2009.  During the nine and three months ended September 30, 2008, the Company sold $4.6 million (38.9 billion (ppm-gallons)) and $250,000 (5.0 billion (ppm-gallons)) of sulfur credits, respectively, 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, and payment occurred in April 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 increased 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 nine months ended September 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.  There were no sales of RINs during the three months ended September 30, 2009 or 2008.  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 September 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 $4.2 million, as of September 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 $11.5 million.

Frontier Refining Inc. (the Cheyenne Refinery) has been served with a Complaint from Region 8 of the EPA alleging unlawful storage of untreated or partially treated refinery wastewater in an on-site surface impoundment and proposing a penalty of $6.8 million.  The EPA stated in the accompanying press release that the Complaint was part of a national enforcement initiative.  Frontier Refining Inc. does not agree with the EPA’s allegations and is preparing a formal response to the Complaint; however, the Company did accrue for the proposed penalty during the third quarter of 2009 and which is included in “Other long-term liabilities” on the September 30, 2009 Condensed Consolidated Balance Sheet.

Pursuant to an agreement with the City of Cheyenne, the Company will contribute a total of $1.5 million toward a project (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 ($1.3 million had been incurred as of September 30, 2009).

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.

In July 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 to conform to current year presentation.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Nine Months Ended September 30, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	3,147,210		$	-	$	-		$	3,147,210
Other		(7	)		1,435			36		-			1,464
		(7	)		3,148,645			36		-			3,148,674
Costs and expenses:
Raw material, freight and other costs		-			2,631,548			-		-			2,631,548
Refinery operating expenses, excluding     depreciation		-			232,175			-		-			232,175
Selling and general expenses, excluding     depreciation		16,196			22,741			-		-			38,937
Depreciation, amortization and     accretion		51			53,742			-		433			54,226
		16,247			2,940,206			-		433			2,956,886
Operating income (loss)		(16,254	)		208,439			36		(433	)		191,788
Interest expense and other financing    costs		22,175			2,968			-		(4,097	)		21,046
Interest and investment income		(1,569	)		(379	)		-		-			(1,948	)
Equity in earnings of subsidiaries		(209,230	)		-			-		209,230			-
		(188,624	)		2,589			-		205,133			19,098
Income before income taxes		172,370			205,850			36		(205,566	)		172,690
Provision for income taxes		64,197			74,330			33		(74,043	)		64,517
Net income	$	108,173		$	131,520		$	3	$	(131,523	)	$	108,173

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Nine Months Ended September 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	5,184,204		$	-	$	-		$	5,184,204
Other		(7	)		(33,704	)		148		-			(33,563	)
		(7	)		5,150,500			148		-			5,150,641
Costs and expenses:
Raw material, freight and other costs		-			4,565,992			-		-			4,565,992
Refinery operating expenses, excluding     depreciation		-			244,861			-		-			244,861
Selling and general expenses, excluding     depreciation		13,613			18,766			-		-			32,379
Depreciation, amortization and     accretion		39			47,875			-		158			48,072
Gain on sales of assets		(37	)		(7	)		-		-			(44	)
		13,615			4,877,487			-		158			4,891,260
Operating income (loss)		(13,622	)		273,013			148		(158	)		259,381
Interest expense and other financing    costs		8,719			3,824			-		(5,500	)		7,043
Interest and investment income		(2,494	)		(2,197	)		-		-			(4,691	)
Equity in earnings of subsidiaries		(275,883	)		-			-		275,883			-
		(269,658	)		1,627			-		270,383			2,352
Income before income taxes		256,036			271,386			148		(270,541	)		257,029
Provision for income taxes		78,428			87,081			58		(86,146	)		79,421
Net income	$	177,608		$	184,305		$	90	$	(184,395	)	$	177,608

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Three Months Ended September 30, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,196,899		$	-		$	-		$	1,196,899
Other		-			3,674			9			-			3,683
		-			1,200,573			9			-			1,200,582
Costs and expenses:
Raw material, freight and other costs		-			1,097,559			-			-			1,097,559
Refinery operating expenses, excluding     depreciation		-			83,701			-			-			83,701
Selling and general expenses, excluding     depreciation		5,230			8,420			-			-			13,650
Depreciation, amortization and     accretion		17			17,934			-			148			18,099
		5,247			1,207,614			-			148			1,213,009
Operating income (loss)		(5,247	)		(7,041	)		9			(148	)		(12,427	)
Interest expense and other financing    costs		7,410			1,097			-			(1,798	)		6,709
Interest and investment income		(594	)		(67	)		-			-			(661	)
Equity in earnings of subsidiaries		6,582			-			-			(6,582	)		-
		13,398			1,030			-			(8,380	)		6,048
Income (loss) before income taxes		(18,645	)		(8,071	)		9			8,232			(18,475	)
Provision (benefit) for income taxes		(3,518	)		(1,791	)		23			1,938			(3,348	)
Net income (loss)	$	(15,127	)	$	(6,280	)	$	(14	)	$	6,294		$	(15,127	)

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Three Months Ended September 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,094,606		$	-	$	-		$	2,094,606
Other		(7	)		103,646			57		-			103,696
		(7	)		2,198,252			57		-			2,198,302
Costs and expenses:
Raw material, freight and other costs		-			1,991,966			-		-			1,991,966
Refinery operating expenses, excluding     depreciation		-			76,267			-		-			76,267
Selling and general expenses, excluding     depreciation		3,967			5,909			-		-			9,876
Depreciation, amortization and     accretion		12			16,516			-		107			16,635
		3,979			2,090,658			-		107			2,094,744
Operating income (loss)		(3,986	)		107,594			57		(107	)		103,558
Interest expense and other financing    costs		2,433			1,688			-		(1,641	)		2,480
Interest and investment income		(230	)		(826	)		-		-			(1,056	)
Equity in earnings of subsidiaries		(107,570	)		-			-		107,570			-
		(105,367	)		862			-		105,929			1,424
Income before income taxes		101,381			106,732			57		(106,036	)		102,134
Provision for income taxes		29,058			34,600			26		(33,873	)		29,811
Net income	$	72,323		$	72,132		$	31	$	(72,163	)	$	72,323

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of September 30, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	278,190		$	209,124		$	-	$	-		$	487,314
Trade and other receivables, net		64,939			142,016			-		-			206,955
Inventory of crude oil, products and    other		-			523,104			-		-			523,104
Deferred tax assets		10,625			13,782			-		(13,782	)		10,625
Other current assets		376			3,873			-		-			4,249
Total current assets		354,130			891,899			-		(13,782	)		1,232,247
Property, plant and equipment, at cost		1,251			1,406,793			-		14,192			1,422,236
Accumulated depreciation and    amortization		(905	)		(432,113	)		-		7,211			(425,807	)
Property, plant and equipment, net		346			974,680			-		21,403			996,429
Deferred turnaround costs		-			38,204			-		-			38,204
Deferred catalyst costs		-			11,214			-		-			11,214
Deferred financing costs, net		3,053			2,030			-		-			5,083
Intangible assets, net		-			1,246			-		-			1,246
Other assets		3,626			305			-		-			3,931
Receivable from affiliated companies		-			1,888			496		(2,384	)		-
Investment in subsidiaries		1,397,512			-			-		(1,397,512	)		-
Total assets	$	1,758,667		$	1,921,466		$	496	$	(1,392,275	)	$	2,288,354
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	926		$	447,788		$	15	$	-		$	448,729
Accrued liabilities and other		34,410			28,537					-			62,947
Total current liabilities		35,336			476,325			15		-			511,676
Long-term debt		347,416			-			-		-			347,416
Contingent income tax liabilities		26,860			2,052			-		-			28,912
Long-term capital lease obligations		-			3,502			-		-			3,502
Other long-term liabilities		3,540			50,177			-		-			53,717
Deferred income taxes		193,020			187,672			-		(187,672	)		193,020
Payable to affiliated companies(1)		2,384			13,895			223		(16,502	)		-
Shareholders' equity		1,150,111			1,187,843			258		(1,188,101	)		1,150,111
Total liabilities and shareholders'    equity	$	1,758,667		$	1,921,466		$	496	$	(1,392,275	)	$	2,288,354
(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 Nine Months Ended September 30, 2009
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	108,173		$	131,520		$	3		$	(131,523	)	$	108,173
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(209,230	)		-			-			209,230			-
Depreciation, amortization and    accretion		51			68,710			-			433			69,194
Deferred income taxes		12,097			-			-			-			12,097
Stock-based compensation expense		15,193			-			-			-			15,193
Excess income tax benefits of    stock-based compensation		(227	)		-			-			-			(227	)
Intercompany income taxes		26,000			48,029			14			(74,043	)		-
Intercompany dividends		21,200			-			-			(21,200	)		-
Other intercompany transactions		3,030			(3,002	)		(28	)		-			-
Amortization of debt issuance costs		587			530			-			-			1,117
Senior notes discount amortization		196			-			-			-			196
Allowance for investment loss and    bad debts		-			500			-			-			500
Increase in other long-term liabilities		2,188			9,169			-			-			11,357
Changes in deferred turnaround costs,    deferred catalyst costs and other		(1,026	)		(7,107	)		-			-			(8,133	)
Changes in components of working    capital from operations		66,983			(130,274	)		11			879			(62,401	)
Net cash provided by operating activities		45,215			118,075			-			(16,224	)		147,066
Cash flows from investing activities:
Additions to property, plant and    equipment		(147	)		(116,451	)		-			(4,976	)		(121,574	)
Net cash used in investing activities		(147	)		(116,451	)		-			(4,976	)		(121,574	)
Cash flows from financing activities:
Purchase of treasury stock		(2,654	)		-			-			-			(2,654	)
Proceeds from issuance of common stock		70			-			-			-			70
Dividends paid		(19,071	)		-			-			-			(19,071	)
Excess income tax benefits of    stock-based compensation		227			-			-			-			227
Debt issuance costs and other		2			(284	)		-			-			(282	)
Intercompany dividends		-			(21,200	)		-			21,200			-
Net cash used in financing activities		(21,426	)		(21,484	)		-			21,200			(21,710	)
Increase (decrease) in cash and cash    equivalents		23,642			(19,860	)		-			-			3,782
Cash and cash equivalents, beginning of    period		254,548			228,984			-			-			483,532
Cash and cash equivalents, end of    period	$	278,190		$	209,124		$	-		$	-		$	487,314

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2008
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	177,608		$	184,305		$	90		$	(184,395	)	$	177,608
Adjustments to reconcile net income to    net cash from operating activities:
Equity in earnings of subsidiaries		(275,883	)		-			-			275,883			-
Depreciation, amortization and    accretion		39			60,885			-			158			61,082
Deferred income taxes		15,684			-			-			-			15,684
Stock-based compensation expense		13,736			-			-			-			13,736
Excess income tax benefits of    stock-based compensation		(4,201	)		-			-			-			(4,201	)
Intercompany income taxes		-			86,088			58			(86,146	)		-
Other intercompany transactions		1,214			(1,061	)		(153	)					-
Amortization of debt issuance costs		375			228			-			-			603
Senior notes discount amortization		8			-			-			-			8
Allowance for investment loss and    bad debts		34			377			-			-			411
Gain on sales of assets		(37	)		(7	)		-			-			(44	)
Amortization of long-term prepaid    insurance		909			-			-			-			909
Increase in other long-term liabilities		(2,989	)		1,658			-			-			(1,331	)
Changes in deferred turnaround costs,    deferred catalyst costs and other		385			(31,202	)		-			-			(30,817	)
Changes in components of working    capital from operations		31,010			(43,723	)		5			(550	)		(13,258	)
Net cash provided by (used in)     operating activities		(42,108	)		257,548			-			4,950			220,390
Cash flows from investing activities:
Additions to property, plant and    equipment		(82	)		(155,187	)		-			(4,950	)		(160,219	)
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		(45	)		(162,679	)		-			(4,950	)		(167,674	)
Cash flows from financing activities:
Proceeds from issuance of 8.5%    Senior Notes		197,160			-			-			-			197,160
Purchase of treasury stock		(66,403	)		-			-			-			(66,403	)
Proceeds from issuance of common stock		265			-			-			-			265
Dividends paid		(16,938	)		-			-			-			(16,938	)
Excess income tax benefits of    stock-based compensation		4,201			-			-			-			4,201
Debt issuance costs and other		(2,081	)		(2,291	)		-			-			(4,372	)
Net cash provided by (used in) financing    activities		116,204			(2,291	)		-			-			113,913
Increase in cash and cash equivalents		74,051			92,578			-			-			166,629
Cash and cash equivalents, beginning of    period		186,368			111,031			-			-			297,399
Cash and cash equivalents, end of    period	$	260,419		$	203,609		$	-		$	-		$	464,028

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.

Nine months ended September 30, 2009 compared with the same period in 2008

Overview of Results

We had net income for the nine months ended September 30, 2009 of $108.2 million, or $1.03 per diluted share, compared to net income of $177.6 million, or $1.71 per diluted share, earned in the same period in 2008.  Our operating income of $191.8 million for the nine months ended September 30, 2009 decreased $67.6 million from the $259.4 million for the comparable period in 2008.  The decrease in our net income from the first nine months of 2008 to the first nine months of 2009 was due to the decline of certain profitability indicators during the nine months ended September 30, 2009, including the diesel crack spread ($25.52 per barrel in 2008 to $8.64 per barrel in 2009) and both the light/heavy and WTI/WTS crude oil differentials.  We expect the U.S. recession, which has reduced demand for gasoline and diesel, could continue to negatively impact our 2009 and 2010 results.  The decline in crude oil differentials has been caused by several factors, including the significant industry investment over the last few years to process heavy/sour crude oil and the declining availability of these types of crudes.  The light/heavy crude oil differential decreased from $18.15 per barrel for the nine months ended September 30, 2008 to $5.85 per barrel for the comparable period of 2009.  The WTI/WTS crude oil differential decreased from $4.13 per barrel for the nine months ended September 30, 2008 to $1.44 per barrel for the comparable period of 2009.

Product yields and sales volumes were significantly higher during the nine months ended September 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 slightly from a higher gasoline crack spread in the first nine months of 2009 ($8.66 per barrel) compared to the first nine months of 2008 ($6.66 per barrel).

Specific Variances

Refined product revenues.  Refined product revenues decreased $2.04 billion, or 39%, from $5.18 billion to $3.15  billion for the nine months ended September 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 nine months ended September 30, 2009 ($56.88 lower average price per sales barrel), despite a 16% increase in sales volumes.

Manufactured product yields.  Yields increased 27,277 bpd at the El Dorado Refinery (as described above) and decreased 1,420 bpd at the Cheyenne Refinery for the nine months ended September 30, 2009 compared to same period in 2008.

Other revenues.  Other revenues increased $35.0 million to a gain of $1.5 million for the nine months ended September 30, 2009, compared to a loss of $33.6 million for the same period in 2008, the primary source of this increase being $3.2 million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories in the nine months ended September 30, 2009, compared to $39.9 million of such losses in the nine months ended September 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 nine months ended September 30, 2009 compared to $4.6 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 $1.93 billion, from $4.57 billion in the nine months ended September 30, 2008 to $2.63 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 nine months ended September 30, 2009 when compared to the same period in 2008.  For the nine months ended September 30, 2009, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $108.5 million after tax ($175.1 million pretax, consisting of a $48.6 million gain at the Cheyenne Refinery and a $126.5 million gain at the El Dorado Refinery).  For the nine months ended September 30, 2008, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $87.8 million after tax ($140.8 million pretax, comprised of a $34.4 million gain at the Cheyenne Refinery and a $106.4 million gain at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $53.43 per sales barrel for the nine months ended September 30, 2009 decreased from $98.70 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 $5.96 per barrel in the nine months ended September 30, 2009 compared to $17.64 per barrel in the same period in 2008.

The El Dorado Refinery raw material, freight and other costs of $52.45 per sales barrel for the nine months ended September 30, 2009 decreased from $108.77 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 $4.13 per barrel in the nine month period ended September 30, 2008 to $1.44 per barrel in the same period in 2009.  The light/heavy crude oil differential decreased from an average of $19.15 per barrel in the nine month period ended September 30, 2008 to $5.71 per barrel in the same period in 2009.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $232.2 million in the nine months ended September 30, 2009 compared to $244.9 million in the comparable period of 2008.

The Cheyenne Refinery operating expenses, excluding depreciation, were $91.3 million for the nine months ended September 30, 2009 compared to $86.8 million in the comparable period of 2008.  The primary areas of increased costs were: higher environmental expenses ($6.9 million, primarily due to proposed EPA penalty accrual), increased salaries and benefits expenses ($3.0 million, primarily due to bonus accruals and higher health insurance costs ), increased additives and chemicals costs ($1.6 million), increased utilities costs ($1.5 million) and increased turnaround amortization ($1.2 million) partially offset by reduced maintenance costs ($4.9 million due to various unplanned tank and coker repairs and outages incurred in 2008), and decreased natural gas costs ($4.2 million due to decreased prices and lower volumes).

The El Dorado Refinery operating expenses, excluding depreciation, were $140.9 million for the nine months ended September 30, 2009, decreasing from $158.1 million in the same nine 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 ($20.3 million due to significantly lower prices and volumes) and maintenance costs ($6.9 million lower, primarily due to demolition, catalyst and repair costs incurred during the March 2008 turnaround), partially offset by increased salaries and benefits expenses ($4.5 million, primarily due to bonus accruals and employee benefit plan costs), increased electricity costs ($2.1 million), higher environmental expenses ($871,000), increased property and other taxes ($804,000), an increase in turnaround amortization ($784,000), and higher insurance costs ($749,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, increased $6.6 million, or 20%, from $32.4 million for the nine months ended September 30, 2008 to $38.9 million for the nine months ended September 30, 2009, due to $6.7 million of higher salaries and benefit expenses (including stock-based compensation expense) in 2009.

Depreciation, amortization and accretion.  Depreciation, amortization and accretion increased $6.2 million, or 13%, for the nine months ended September 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 $21.0 million for the nine months ended September 30, 2009 increased $14.0 million from $7.0 million in the comparable period in 2008.  Increases in interest expense related to an additional $12.1 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 nine months ended September 30, 2009 was $4.1 million compared to $5.7 million for the same period in 2008.  Average debt outstanding was $350.0 million and $248.1 during the nine months ended September 30, 2009 and 2008, respectively (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $2.7 million, or 58%, from $4.7 million in the nine months ended September 30, 2008, to $1.9 million in the nine months ended September 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 nine months ended September 30, 2009 was $64.5 million on pretax income of $172.7 million (or 37.4%).  Our provision for income taxes for the nine months ended September 30, 2008 was $79.4 million on pretax income of $257.0 million (or 30.9%).  The effective tax rate for the nine months ended September 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 nine months ended September 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 September 30, 2009 compared with the same period in 2008

Overview of Results

We had a net loss for the three months ended September 30, 2009 of $15.1 million, or $0.15 per share, compared to net income of $72.3 million, or $0.70 per diluted share, in the same period in 2008.  Our operating loss of $12.4 million for the three months ended September 30, 2009 decreased $116.0 million from the $103.6 million of operating income for the comparable period in 2008.

Certain indicators of our profitability continued to decline for the three months ended September 30, 2009, including the diesel crack spread ($26.76 per barrel in 2008 to $7.94 per barrel in 2009), gas crack spread ($9.42 per barrel in 2008 to $7.92 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 $14.10 per barrel for the three months ended September 30, 2008 to $6.34 per barrel for the comparable period of 2009.  The WTI/WTS crude oil differential decreased from $2.77 per barrel for the three months ended September 30, 2008 to $1.62 per barrel for the comparable period of 2009.

Specific Variances

Refined product revenues.  Refined product revenues decreased $897.7 million, or 43%, from $2.09 billion to $1.20  billion for the three months ended September 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 September 30, 2009 ($55.45 lower average price per sales barrel).

Manufactured product yields.  Yields increased 5,862 bpd at the El Dorado Refinery and decreased 2,913 bpd at the Cheyenne Refinery for the three months ended September 30, 2009 compared to same period in 2008.  The lower yields at the El Dorado Refinery in the 2008 period were due to the August 2008 Coker shutdown to tie in the new coke drums.

Other revenues.  Other revenues decreased $100.0 million to a gain of $3.7 million for the three months ended September 30, 2009, compared to a gain of $103.7 million for the same period in 2008.  In the three months ended September 30, 2009, the primary source of the gain was $4.2 million in net realized and unrealized gains from derivative contracts to hedge in-transit crude oil and excess inventories.  This compared to $104.0 million in net realized and unrealized gains on derivative contracts to hedge in-transit crude oil and excess inventories in the three months ended September 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 $250,000 in the three months ended September 30, 2008 (none in the comparable 2009 period).

Raw material, freight and other costs.  Raw material, freight and other costs decreased by $894.4 million, from $1.99 billion in the three months ended September 30, 2008 to $1.10 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 three months ended September 30, 2009 when compared to the same period in 2008.  For the three months ended September 30, 2009, we realized a reduction in raw material, freight and other costs as a result of inventory valuation gains of approximately $8.6 million after tax ($13.9 million pretax, consisting of a $2.3 million loss at the Cheyenne Refinery and a $16.2 million gain at the El Dorado Refinery).  For the three months ended September 30, 2008, we realized an increase in raw material, freight and other costs as a result of inventory valuation losses of approximately $77.5 million after tax ($125.1 million pretax, comprised of a $34.8 million loss at the Cheyenne Refinery and a $90.3 million loss at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $67.18 per sales barrel for the three months ended September 30, 2009 decreased from $117.09 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 $7.11 per barrel in the three months ended September 30, 2009 compared to $14.02 per barrel in the same period in 2008.

The El Dorado Refinery raw material, freight and other costs of $66.88 per sales barrel for the three months ended September 30, 2009 decreased from $124.20 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 $2.77 per barrel in the three month period ended September 30, 2008 to $1.62  per barrel in the same period in 2009.  The light/heavy crude oil differential decreased from an average of $14.33 per barrel in the three month period ended September 30, 2008 to $5.69 per barrel in the same period in 2009.

Refinery operating expenses.  Refinery operating expenses, excluding depreciation, were $83.7 million in the three months ended September 30, 2009 compared to $76.3 million in the comparable period of 2008.

The Cheyenne Refinery operating expenses, excluding depreciation, were $36.2 million for the three months ended  September 30, 2009 compared to $27.6 million in the comparable period of 2008.  The primary areas of increased costs were: higher environmental expenses ($6.5 million, primarily due to a $6.8 million proposed EPA penalty accrual), increased salaries and benefits expenses ($1.2 million), increased utilities costs ($633,000), higher natural gas costs ($589,000), increased additives and chemicals costs ($488,000), and increased turnaround amortization ($252,000), partially offset by lower maintenance costs ($1.2 million).

The El Dorado Refinery operating expenses, excluding depreciation, were $47.5 million for the three months ended September 30, 2009, decreasing from $48.7 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 ($5.0 million due to significantly lower prices and decreased volumes), and decreased additives and chemicals costs ($1.1 million), partially offset by an increase in salaries and benefits expenses ($2.1 million), maintenance costs ($1.6 million), increased electricity costs ($304,000), increased insurance costs ($244,000), and increased turnaround amortization ($141,000) and higher property and other taxes ($123,000).

Selling and general expenses.  Selling and general expenses, excluding depreciation, increased $3.8 million, or 38%, from $9.9 million for the three months ended September 30, 2008 to $13.7 million for the three months ended September 30, 2009, due to $3.7 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 September 30, 2009 compared to the same period in 2008 because of increased capital investments in our Refineries.

Interest expense and other financing costs.  Interest expense and other financing costs of $6.7 million for the three months ended September 30, 2009 increased $4.2 million, from $2.5 million in the comparable period in 2008.  Increases in interest expense related to an additional $3.6 million of interest incurred as a result of the 8.5% senior notes offering completed in the third quarter of 2008.  Capitalized interest for the three months ended September 30, 2009 was $1.8 million compared to $1.6 million for the same period in 2008.  Average debt outstanding was $350.0 million and $200.0 million during the three months ended September 30, 2009 and 2008, respectively (excluding amounts payable to Utexam under the Utexam Arrangement).

Interest and investment income.  Interest and investment income decreased $395,000, or 37%, from $1.1 million in the three months ended September 30, 2008, to $661,000 in the three months ended September 30, 2009, because of lower interest rates during the 2009 period, partially offset by a $411,000 loss on an at-risk investment in the 2008 period.

Provision (benefit) for income taxes.  The provision for income taxes for the three months ended September 30, 2009 was a $3.3 million benefit on a pretax loss of $18.5 million (or 18.1%).  Our provision for income taxes for the three months ended September 30, 2008 was $29.8 million on pretax income of $102.1 million (or 29.2%).  The effective tax rate for the three months ended September 30, 2009 was lower than the effective tax rate in the comparable period in 2008 primarily due to permanent differences of $7.9 million (including a $6.8 million proposed environmental penalty accrual) on a pretax loss of $18.5 million during the 2009 period resulting in an atypical effective tax rate for the three months ended September 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 $147.1 million for the nine months ended September 30, 2009 compared to net cash provided by operating activities of $220.4 million during the nine months ended September 30, 2008.  Significantly lower operating income and a higher use of cash for working capital purposes contributed to lower cash flows from operations during the 2009 period.  Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risks.”

Working capital changes used a total of $62.4 million of cash during the first nine months of 2009 compared to $13.3 million for the same period in 2008.  The $62.4 million working capital change for the 2009 period primarily resulted from a $267.0 million increase in inventory (due to both volume and price increases) offset by $144.0 million of increased payables (primarily crude payables).  In the first nine months of 2008, the working capital change of $13.3 million primarily resulted from a $137.0 million increase in inventory and a $96.6 million increase in receivables, offset by $257.1 million of increased payables (primarily crude payables).  During the nine months ended September 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 September 30, 2009, we had $487.3 million of cash and cash equivalents, $720.6 million of working capital, no cash borrowings under our revolving credit facility, and $339.1 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 nine months of 2009 were $121.6 million, which included approximately $80.3 million for the El Dorado Refinery and $38.7 million for the Cheyenne Refinery. The $80.3 million of capital expenditures for our El Dorado Refinery included $33.3 million on the gasoil hydrotreater revamp, $12.8 million on the catalytic cracker regenerator emission control project, $5.6 million for the catalytic cracker reliability project, as well as operational, payout, safety, administrative, environmental and optimization projects.  The $38.7 million of capital expenditures for our Cheyenne Refinery included approximately $7.7 million on the new Cheyenne Refinery office and control buildings, $4.9 million for the waste water treatment plant flotation system, and $4.7 million for the cat gas hydrotreater project, as well as environmental, operational, safety, administrative and payout projects.

Cash flows from financing activities.  During the nine months ended September 30, 2009, treasury stock increased by 193,234 shares ($2.7 million) from stock surrendered by employees to pay withholding taxes on stock-based compensation which vested during the first nine months of 2009.  We also paid $19.1 million in dividends during the nine months ended September 30, 2009.

During the nine months ended September 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 September 30, 2009, we had $347.4 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $109.2 million of letters of credit outstanding under our revolving credit facility.  We were in compliance with the financial covenants of our revolving credit facility as of September 30, 2009.  Shareholders’ equity as of September 30, 2009 was $1.15 billion.

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

FUTURE CAPITAL EXPENDITURES

Significant future capital projects.  The gasoil hydrotreater revamp at the El Dorado Refinery is the project to achieving gasoline sulfur compliance for our El Dorado Refinery and has a total estimated cost of $90 million ($67.4 million incurred as of September 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 mid-2010.  As of September 30, 2009, outstanding non-cancelable purchase commitments for the gasoil hydrotreater revamp were $5.2 million.  The El Dorado Refinery’s catalytic cracker reliability project has a total estimated cost of $26.7 million ($12.7 million incurred as of September 30, 2009).  The project is anticipated to be completed in the fourth quarter of 2009 and had outstanding non-cancelable purchase commitments at September 30, 2009 of $2.5 million.  The El Dorado Refinery catalytic cracker regenerator emission control project, with a fourth quarter 2009 estimated completion date and total estimated cost of $34 million ($28.6 million incurred as of September 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 September 30, 2009, the catalytic cracker regenerator emission control project had outstanding non-cancelable purchase commitments of $1.5 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 ($7.2 million incurred as of September 30, 2009).  The above amounts include estimated capitalized interest.

2009 capital expenditures.  Including the projects discussed above, 2009 capital expenditures aggregating approximately $190.0 million are currently planned, and include $129.4 million at our El Dorado Refinery, $57.4 million at our Cheyenne Refinery, $2.4 million at our products terminals, pipeline and blending facilities and $781,000 at our Denver and Houston offices.  The $129.4 million of planned capital expenditures for our El Dorado Refinery includes $43.2 million for the gasoil hydrotreater revamp project, $21.3 million for the catalytic cracker reliability project and $17.3 million for the catalytic cracker regenerator emission control project, as mentioned above, as well as environmental, operational, safety, payout and administrative projects.  The $57.4 million of planned capital expenditures for our Cheyenne Refinery includes $11.3 million for the cat gas hydrotreater project and $8.0 million for the boundary control system, 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 or additional borrowings, if necessary.  We will continue to review our capital expenditures in light of market conditions.  We may experience cost overruns and/or schedule delays on any of these projects.

Operating Data

The following tables set forth the refining operating statistical information on a consolidatedbasis and for each Refinery for the nine and three months ended September 30, 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:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		52,863		27,109		58,637		38,207
Heavy and intermediate crude		111,690		107,312		101,384		118,676
Other feed and blendstocks		15,886		19,436		17,720		17,071
Total		180,439		153,857		177,741		173,954
Manufactured product yields (bpd)
Gasoline		83,809		72,508		84,913		78,755
Diesel and jet fuel		70,649		53,205		67,167		66,424
Asphalt		1,967		4,449		2,450		4,306
Other		18,872		19,277		17,242		19,337
Total		175,297		149,439		171,772		168,822
Total product sales (bpd)
Gasoline		93,922		81,923		94,505		88,217
Diesel and jet fuel		70,226		52,793		66,009		65,049
Asphalt		1,760		4,826		2,679		4,853
Other		16,982		18,240		14,970		19,100
Total		182,890		157,782		178,163		177,219
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	63.03	$	119.91	$	73.02	$	128.47
Raw material, freight and other costs		52.71		105.62		66.96		122.18
Refinery operating expenses, excluding depreciation		4.65		5.66		5.11		4.68
Depreciation, amortization and accretion		1.08		1.11		1.10		1.02
Average NYMEX WTI (per barrel) (1)	$	57.09	$	113.49	$	68.25	$	118.52
Average light/heavy differential (per barrel) (1)		5.85		18.15		6.34		14.10
Average gasoline crack spread (per barrel) (1)		8.66		6.66		7.92		9.42
Average diesel crack spread (per barrel) (1)		8.64		25.52		7.94		26.76
Average sales price (per sales barrel)
Gasoline	$	67.69	$	123.41	$	77.66	$	131.38
Diesel and jet fuel		66.45		143.33		76.74		146.36
Asphalt		65.26		64.14		73.41		100.51
Other		22.92		51.21		27.29		61.20
(1) The 2008 amounts are restated to reflect current year presentation measurement under NYMEX WTI.

Cheyenne Refinery:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		18,368		7,970		23,941		8,673
Heavy and intermediate crude		22,642		34,578		16,867		35,484
Other feed and blendstocks		1,384		930		1,417		715
Total		42,394		43,478		42,225		44,872
Manufactured product yields (bpd)
Gasoline		19,179		18,621		20,578		18,413
Diesel		15,306		12,543		16,236		14,107
Asphalt		1,967		4,449		2,450		4,306
Other		4,290		6,549		1,437		6,788
Total		40,742		42,162		40,701		43,614
Total product sales (bpd)
Gasoline		26,578		26,729		27,396		25,643
Diesel		15,151		12,089		16,084		13,185
Asphalt		1,760		4,826		2,679		4,853
Other		4,106		5,815		3,159		6,816
Total		47,595		49,459		49,318		50,497
Refinery operating margin information    (per sales barrel)
Refined products revenue	$	63.58	$	113.11	$	73.89	$	126.63
Raw material, freight and other costs		53.43		98.70		67.18		117.09
Refinery operating expenses, excluding depreciation		7.03		6.41		7.99		5.93
Depreciation, amortization and accretion		1.69		1.43		1.61		1.36
Average light/heavy crude oil differential (per barrel) (1)	$	5.96	$	17.64	$	7.11	$	14.02
Average gasoline crack spread (per barrel) (1)		8.60		8.01		8.42		15.31
Average diesel crack spread (per barrel) (1)		10.18		28.89		8.95		33.78
Average sales price (per sales barrel)
Gasoline	$	67.78	$	121.59	$	77.92	$	135.16
Diesel		69.20		146.31		77.87		156.76
Asphalt		65.26		64.14		73.41		100.51
Other		14.99		45.74		19.04		54.85
(1) The 2008 amounts are restated to reflect current year presentation measurement under NYMEX WTI.

El Dorado Refinery:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Charges (bpd)
Light crude		34,495		19,139		34,696		29,534
Heavy and intermediate crude		89,047		72,735		84,517		83,193
Other feed and blendstocks		14,502		18,506		16,303		16,355
Total		138,044		110,380		135,516		129,082
Manufactured product yields (bpd)
Gasoline		64,630		53,887		64,335		60,342
Diesel and jet fuel		55,342		40,662		50,931		52,317
Other		14,582		12,728		15,805		12,550
Total		134,554		107,277		131,071		125,209
Total product sales (bpd)
Gasoline		67,343		55,194		67,109		62,574
Diesel and jet fuel		55,075		40,704		49,924		51,864
Other		12,875		12,425		11,811		12,284
Total		135,293		108,323		128,844		126,722
Refinery operating margin information (per sales barrel)
Refined products revenue	$	62.84	$	123.02	$	72.69	$	129.20
Raw material, freight and other costs		52.45		108.77		66.88		124.20
Refinery operating expenses, excluding depreciation		3.81		5.32		4.00		4.18
Depreciation, amortization and accretion		0.87		0.96		0.91		0.88
Average WTI/WTS crude oil differential (per barrel)	$	1.44	$	4.13	$	1.62	$	2.77
Average light/heavy crude oil differential (per barrel) (1)		5.71		19.15		5.69		14.33
Average gasoline crack spread (per barrel) (1)		8.68		6.00		7.72		7.00
Average diesel crack spread (per barrel) (1)		8.22		24.52		7.62		24.98
Average sales price (per sales barrel)
Gasoline	$	67.66	$	124.28	$	77.55	$	129.83
Diesel and jet fuel		65.69		142.45		76.37		143.72
Other		25.45		53.77		29.50		64.72
(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 September 30, 2009 are summarized below:

Commodity	Period	Volume  (thousands  of bbls)		Expected Close Out Date	Unrealized Net Loss (in thousands)
Crude Oil	November 2009		1,614	October 2009	$	(29	)
Crude Oil	December 2009		389	November 2009		(370	)

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 September 30, 2009 have fixed interest rates.  Through September 30, 2009, 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 $150.0 million and our 8.5% Senior Notes was $205.0 million at September 30, 2009.  However, in October 2009, due to current advantageous market conditions, the Company entered into fixed to floating interest rate swaps of $150.0 million to reduce exposure related to our 6.625% Senior Notes.

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 Notes 13 and 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 September 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 – None.

ITEM 6. Exhibits – 31.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   31.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   32.1 – Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   32.2 – Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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

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

Date: November 5, 2009