Frontier Oil (FTO) 10-Q 2006 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, 2006

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

(Check one)

Large accelerated filer þ     Accelerated filer ¨     Non-accelerated filer ¨

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, 2006: 110,331,402

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2006

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
(Unaudited, in thousands except per share data)
	Nine Months Ended						Three Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Revenues:
Refined products	$	3,683,584		$	2,851,935		$	1,360,875		$	1,187,607
Other		25,110			(1,085	)		20,260			(1,677	)
		3,708,694			2,850,850			1,381,135			1,185,930
Costs and expenses:
Raw material, freight and other costs		2,939,309			2,282,546			1,110,214			931,495
Refinery operating expenses, excluding depreciation		211,703			173,877			68,188			58,702
Selling and general expenses, excluding depreciation		36,823			25,118			15,094			8,677
Merger termination and legal costs		-			47			-			10
Depreciation, accretion and amortization		30,046			26,661			11,138			9,796
		3,217,881			2,508,249			1,204,634			1,008,680
Operating income		490,813			342,601			176,501			177,250
Interest expense and other financing costs		8,898			8,335			3,616			2,359
Interest and investment income		(12,393	)		(3,864	)		(5,937	)		(2,137	)
		(3,495	)		4,471			(2,321	)		222
Income before income taxes		494,308			338,130			178,822			177,028
Provision for income taxes		172,462			128,548			57,938			67,843
Net income	$	321,846		$	209,582		$	120,884		$	109,185
Basic earnings per share of common stock	$	2.87		$	1.90		$	1.09		$	0.98
Diluted earnings per share of common stock	$	2.85		$	1.85		$	1.08		$	0.95
The accompanying notes are an integral part of these condensed consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2006 and December 31, 2005	2006			2005
	(in thousands except share data)
ASSETS
Current assets:
Cash, including cash equivalents of $379,083 and $345,641 in 2006 and 2005, respectively	$	396,455		$	356,065
Trade receivables, net of allowance of $500 in both years		112,820			122,051
Other receivables		9,521			7,584
Inventory of crude oil, products and other		377,853			247,621
Deferred tax assets		8,610			6,819
Other current assets		15,984			7,935
Total current assets		921,243			748,075
Property, plant and equipment, at cost:
Refineries and pipelines		755,011			657,612
Furniture, fixtures and other equipment		10,805			10,510
		765,816			668,122
Less - accumulated depreciation and amortization		266,679			238,184
		499,137			429,938
Deferred financing costs, net of amortization of $1,543 and $945 in 2006 and 2005, respectively		2,951			3,549
Commutation account		9,135			12,606
Prepaid insurance, net of amortization		2,422			3,331
Other intangible asset, net of amortization of $237 and $158 in 2006 and 2005, respectively		1,342			1,422
Other assets		7,220			2,588
Total assets	$	1,443,450		$	1,201,509
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	384,013		$	359,577
Accrued turnaround cost		14,535			12,696
Accrued interest		5,088			2,485
Accrued El Dorado Refinery contingent earn-out payment		7,500			7,500
Accrued dividends		3,478			58,726
Accrued liabilities and other		48,536			44,827
Total current liabilities		463,150			485,811
Long-term debt		150,000			150,000
Long-term accrued turnaround cost		19,911			15,122
Post-retirement employee liabilities		28,008			24,497
Other long-term liabilities		16,158			10,293
Deferred income taxes		74,969			70,727
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, 134,495,786 and 133,629,396 shares issued in 2006 and 2005, respectively		57,802			57,780
Paid-in capital		175,966			157,910
Retained earnings		632,048			319,150
Accumulated other comprehensive income		27			27
Treasury stock, at cost, 23,810,084 and 20,930,828
shares in 2006 and 2005, respectively		(174,589	)		(86,870	)
Deferred compensation		-			(2,938	)
Total shareholders’ equity		691,254			445,059
Total liabilities and shareholders’ equity	$	1,443,450		$	1,201,509
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)
	For the nine months ended September 30,
	2006			2005
	(in thousands)
Cash flows from operating activities:
Net income	$	321,846		$	209,582
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, accretion and amortization		30,046			26,661
Deferred income taxes		2,451			23,593
Stock-based compensation expense		12,882			1,118
Income tax benefits of stock compensation		10,102			19,778
Excess income tax benefits of share-based payment arrangements		(8,796	)		-
Deferred financing cost amortization		598			718
Amortization of long-term prepaid insurance		909			908
Long-term commutation account		3,471			3,409
Increase in long-term accrued liabilities		13,204			1,175
Other		(4,137	)		425
Changes in working capital from operations		(99,163	)		(47,625	)
Net cash provided by operating activities		283,413			239,742
Cash flows from investing activities:
Additions to property, plant and equipment		(93,618	)		(73,175	)
El Dorado Refinery contingent earn-out payment		(7,500	)		(7,500	)
Proceeds from sale of assets		8			-
Net proceeds from insurance - involuntary conversion claim		-			2,142
Net cash used in investing activities		(101,110	)		(78,533	)
Cash flows from financing activities:
Proceeds from issuance of common stock		3,644			18,576
Purchase of treasury stock		(90,147	)		(11,989	)
Dividends paid		(64,196	)		(5,522	)
Excess income tax benefits of share-based payment arrangements		8,796			-
Debt issue costs and other		(10	)		(110	)
Net cash (used in) provided by financing activities		(141,913	)		955
Increase in cash and cash equivalents		40,390			162,164
Cash and cash equivalents, beginning of period		356,065			124,389
Cash and cash equivalents, end of period	$	396,455		$	286,553
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	4,145		$	3,919
Cash paid during the period for income taxes		160,995			58,061
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 a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming, both of which are accounted for as undivided interests. Each asset, liability, revenue and expense is reported on a proportionate gross basis. In addition, the equity method of accounting is utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar. The Company’s investment in 8901 Hangar, Inc. was $99,000 and $95,000 at September 30, 2006 and December 31, 2005, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. The Company utilizes the equity method of accounting for investments in entities in which it does not have the ability to exercise control. Entities in which the Company has the ability to exercise significant influence and control are consolidated. The Company also owned, until its sale as of November 30, 2005, FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska. The activities of FGI, LLC were included in the Company’s consolidated financial statements since December 1, 2003, when the Company increased its ownership from 50% to 100%, through November 30, 2005. 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, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, 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 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, 2005 and the Company’s quarterly reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications have no effect on previously reported net income.

Stock split and increase of cash dividend

The Company announced on April 27, 2006 that its Board of Directors had approved a 2-for-1 stock split by means of a stock dividend on the Company’s common stock. Effective with the stock split, the Board of Directors also approved an increase in the regular cash dividend to $0.12 per share annually from the previous split-adjusted level of $0.08 per share annually. The increased cash dividend will be paid at the quarterly rate of $0.03 per share on a post-split basis. The stock split was subject to shareholder approval of an amendment to the Company’s articles of incorporation to increase the number of authorized shares from 90 million to 180 million, and the amendment was approved at a special shareholders’ meeting on June 9, 2006. The stock dividend was issued on June 26, 2006 to shareholders of record as of the close of business on June 19, 2006. All prior period share related numbers included in this report (except if indicated) have been revised to reflect the stock split.

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		Three Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
Basic	111,963,168	110,119,338	111,319,766	111,903,126
Diluted	113,025,073	113,398,228	112,323,919	114,605,652

For the nine months and three months ended September 30, 2006, 493,226 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS. For the nine months and three months ended September 30, 2005, there were no outstanding stock options that could potentially dilute EPS in future years that were not included in the computation of diluted EPS.

The Company’s Board of Directors declared both a special cash dividend of $0.50 per share and a regular quarterly cash dividend of $0.02 per share in December 2005, which were paid in January 2006. In addition, a quarterly cash dividend of $0.02 per share was declared in March 2006 and paid in April 2006 and quarterly cash dividends of $0.03 per share were declared in June 2006 and September 2006, and paid in July 2006 and October 2006, respectively. The total cash required for the dividend declared in September 2006 was approximately $3.3 million and was reflected in “Accrued dividends” on the Condensed Consolidated Balance Sheet as of September 30, 2006.

Related party transaction

As of December 31, 2005, the Company had an outstanding relocation-related loan to a non-officer employee in the amount of $300,000, which is included in “Other receivables” on the December 31, 2005 Condensed Consolidated Balance Sheet. This loan was paid in full in May 2006.

New accounting pronouncements

The Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 04-13 (“Issue”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the Financial Accounting Standards Board (“FASB”) ratified it on September 28, 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The consensus in this Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. The Company has certain crude oil procurement and product exchange transactions that it accounts for on a net cost basis. Neither the Company’s revenues nor its cost of sales are materially affected by applying the Issue’s consensus.

On September 30, 2005, the FASB issued a revision for an Exposure Draft issued on December 15, 2003, that would amend Financial Accounting Standards (“FAS”) No. 128, “Earnings per Share,” to clarify guidance for mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares, and contingently issuable shares. The exposure draft indicated that the statement would be effective for interim and annual periods ending after June 15, 2006; however as of October 31, 2006, the final statement had not been issued. The Company does not expect this proposed statement, when issued, to have any material effect on its earnings per share calculations.

In June 2006, the FASB issued “FASB Interpretation No. 48, “Accounting for Uncertain Tax Positions - An Interpretation of FAS No. 109, Accounting for Income Taxes” (“FIN 48”). The interpretation clarifies the accounting for income taxes recognized and presents direction on measurement for the financial statements and tax position taken or expected to be taken. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The tax position is evaluated with a two step process. The first step is recognition: to determine whether it is “more likely than not” that a tax position will uphold upon examination. The second step is measurement: if the position meets the “more likely than not” criteria in step one, step two is to determine the impact on the financial statements and tax position to be taken. This interpretation will apply to fiscal years beginning after December 15, 2006. The Company is currently evaluating FIN 48 and the effect it will have on the Company’s financial statements. 

On September 8, 2006, the FASB issued FASB Staff Position (“FSP”) No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” This FSP addresses the accounting for planned major maintenance activities (“turnarounds”). Currently there are four alternative accounting methods for turnarounds: direct expense, built-in overhaul, deferral and accrual. The FSP eliminates the accrual method of accounting for turnarounds and requires the adoption of the provisions as a change in accounting principle through retrospective application as described in SFAS 154, “Accounting Changes and Error Corrections.” The FSP has an effective date for fiscal years beginning after December 15, 2006 with earlier adoption allowed. The Company currently accounts for turnarounds on the accrual method and this FSP will require the Company to adopt an alternate method. The Company is currently evaluating the acceptable accounting methods and plans to adopt the new accounting method by the end of 2006.

In September 2006, the FASB issued FAS No. 157,“Fair Value Measurements” which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. FAS No. 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price).” The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the effect that this statement will have on the Company’s financial statements and any other factors influencing the overall business environment.

In September 2006, the FASB issued FAS No. 158,“Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”This statement requires an employer to: 1) recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value and the benefit obligation) in its statement of financial position, 2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net period benefit cost, 3) measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position, and 4) disclose in the notes to the financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations. Frontier will be required to initially recognize the funded status of a defined benefit plan and to provide the required disclosures as of the year ending December 31, 2006. The Company is currently evaluating the effect that this statement will have on the Company’s financial statements.

The Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108 on September 13, 2006. SAB No. 108 was issued to address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. Registrants are to reflect the effects of applying the guidance issued in SAB No. 108 in annual financial statements covering the first fiscal year ending after November 15, 2006. The Company is currently evaluating SAB No. 108 and the effect that it will have on the Company’s financial statements.

2.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 cost. 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, blend stocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished product inventory values have components of raw material, 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 (see Note 1 “New accounting pronouncements” above for a discussion of EITF Issue No. 04-13). 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.

Components of inventory
	September 30,		December 31,
	2006		2005
	(in thousands)
Crude oil	$	163,178	$	97,766
Unfinished products		102,191		53,200
Finished products		91,158		75,790
Process chemicals		4,432		5,441
Repairs and maintenance supplies and other		16,894		15,424
	$	377,853	$	247,621

3.Treasury Stock

The Company accounts for its treasury stock under the cost method on a FIFO basis. The Company’s Board of Directors has approved a stock repurchase program for up to 32 million shares of the Company’s common stock. On November 30, 2005, the Company’s Board of Directors confirmed utilizing up to $100 million for share repurchases under this program. The Company may repurchase its common stock under this program from time to time in the open market depending on price, market conditions and other factors. As of September 30, 2006, $91.1 million (3,519,388 shares) of the $100 million had been utilized for repurchases, of which $83.5 million (3,127,788 shares) was purchased in the nine months ended September 30, 2006. An additional $1.9 million of cash was paid during early 2006 to settle purchases made at the end of 2005. Through September 30, 2006, 22,038,852 shares of common stock had been purchased under the stock repurchase program.

During the nine months ended September 30, 2006, the Company received 141,314 shares ($4.8 million) of its stock, which became treasury stock, from stock surrendered by employees or members of the Board of Directors to pay withholding taxes on stock options exercised and on restricted stock and restricted stock units that vested during the period. The Company issued 389,846 shares of its treasury stock as restricted stock (see Note 4 “Stock-based Compensation” below) during the nine months ended September 30, 2006. As of September 30, 2006, the Company had 23,810,084 shares of treasury stock.

4.Stock-based Compensation

Effective January 1, 2006, the Company adopted FAS No. 123(R), “Share-Based Payment,” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. The Company adopted FAS No. 123(R) using the modified prospective application method, and accordingly, prior period amounts have not been retrospectively adjusted. Upon adoption of FAS No. 123(R), deferred compensation recorded as contra-equity in prior periods was eliminated against the appropriate equity accounts. The Company evaluated the need for a cumulative effect of a change in accounting principle as of January 1, 2006, related to previously recognized compensation expense for previously forfeited awards or in recognition of an assumption for future forfeits, and determined that none was necessary. In 2006, the adoption of FAS No. 123(R) resulted in incremental stock-based compensation expense of $5.0 million and $2.0 million for the nine months and three months ended September 30, 2006, respectively. This incremental stock-based compensation reduced the Company’s net income by $3.1 million ($0.02 per diluted share) and $1.3 million ($0.01 per diluted share) for the nine months and three months ended September 30, 2006, respectively. Cash provided by operating activities decreased $8.8 million and cash provided by financing activities increased by the same amount for the nine months ended September 30, 2006, due to excess income tax benefits from stock-based payment arrangements.

Stock-based compensation costs and income tax benefits recognized in the Condensed Consolidated Statements of Income for the nine months and three months ended September 30, 2006 and 2005 are as follows:

	Nine Months Ended September 30,				Three Months Ended September 30,
	2006		2005		2006		2005
	(in thousands)				(in thousands)
Restricted shares and units	$	6,702	$	1,117	$	1,974	$	421
Stock options		1,534		-		575		-
Performance-based awards		4,556		-		2,734		-
Stock grant to retiring executive		90		-		-		-
Total stock-based compensation expense	$	12,882	$	1,117	$	5,283	$	421
Income tax benefit recognized in the income statement	$	4,895	$	424	$	2,008	$	160

Previously, the Company accounted for stock-based compensation in accordance with APB Opinion No. 25. Had compensation costs for share awards been determined based on the fair value at grant dates and amortized over the vesting period pursuant to FAS No. 123, the Company’s income and EPS would have been the pro forma amounts listed in the following table for the nine months and three months ended September 30, 2005. The pro forma compensation expense for the nine months and three months ended September 30, 2005 includes amortization for options granted in 2004, 2003 and 2002.

	Nine Months Ended September 30, 2005			Three Months Ended September 30, 2005
	(in thousands, except per share amounts)
Net income as reported	$	209,582		$	109,185
Pro forma compensation expense, net of tax		(1,028	)		(234	)
Pro forma net income	$	208,554		$	108,951
Basic EPS:
As reported	$	1.90		$	0.98
Pro forma		1.89			0.97
Diluted EPS:
As reported	$	1.85		$	0.95
Pro forma		1.84			0.95

Omnibus Incentive Compensation Plan. The shareholders of the Company approved the Frontier Oil Corporation Omnibus Incentive Compensation Plan (the “Plan”) at the Annual Meeting of Shareholders held on April 26, 2006. 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. The Plan amends and restates the Company’s previously approved 1999 Stock Plan and the Company’s Restricted Stock Plan, both of which were merged into the Omnibus Plan. The maximum number of shares of the Company’s common stock that may be issued under the Plan with respect to Awards is 12,000,000 shares, subject to certain adjustments as provided by the Plan. Awards issued under the prior plans between December 31, 2005 and April 26, 2006 reduced the number of shares available for Awards as though the awards had been issued after April 26, 2006. The number of shares available for Awards will be reduced by 1.7 times the number of shares for each stock-denominated award granted, other than an option or a SAR under the Plan, and will be reduced by 1.0 times the number of option shares or SARs granted. As of September 30, 2006, 7,514,254 shares were available to be awarded under the Plan assuming maximum payout is achieved on the performance awards made in 2006 for which restricted stock will be issued in 2007 (see “Performance 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. As of September 30, 2006, there was $26.0 million of total unrecognized compensation cost related to the Plan including costs for stock options, restricted stock, restricted stock units and performance-based awards, which is expected to be recognized over a weighted-average period of 2.33 years.

Stock Options. Stock options are issued at the current market price of the Company’s common stock on the date of grant and generally vest ratably over three years and expire after five years. The grant date fair value is calculated using the Black-Scholes option pricing model. The Company uses historical employee exercise data, including post-vesting termination behavior, to estimate the expected life of the options. Expected volatility is calculated using the historical volatility of the price of the Company’s common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. The $9.615 per share fair value of the five-year options granted during the nine months ended September 30, 2006 was estimated with the following assumptions: risk-free interest rate of 4.89%, expected volatility of 37.3%, expected life of 3.33 years and no dividend yield. For the weighted-average assumptions used in the Black-Scholes option pricing model for grants made in 2004 and prior years, please refer to the Company’s annual report on Form 10-K for the year ended December 31, 2005. For the stock options granted in 2006, when common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued but not paid until the options are vested. After vesting, dividend equivalents will be paid concurrently with common stock dividends until the options are exercised or expire. Stock options issued prior to 2006 do not have any dividend equivalent rights.

Stock option changes during the nine months ended September 30, 2006 are presented below:

	Number of Awards			Weighted-Average Exercise Price		Aggregate Intrinsic Value of Options (in thousands)
Outstanding at beginning of period		1,381,700		$	4.3515
Granted		493,226			29.3850
Exercised or issued		(837,800	)		4.3499
Expired		-			-
Outstanding at end of period		1,037,126			16.2581	$	12,089
Exercisable at endof period		506,400			4.3313	$	11,267
Weighted-average fair value of options granted during the period	$	9.615			-

The Company received $3.6 million of cash for stock options exercised during the nine months ended September 30, 2006. The total intrinsic value of stock options exercised during the nine months ended September 30, 2006 was $22.3 million. The Company realized $8.4 million of income tax benefits, $8.1 million of which was excess income tax benefits, during the nine months ended September 30, 2006, related to the exercises of stock options. Excess income tax benefits are the benefits from additional deductions allowed for income tax purposes in excess of expenses recorded in the financial statements. These excess income tax benefits are recorded as an increase to paid-in capital and the majority of these amounts, beginning in 2006 (as provided for in FAS No. 123(R)), are reflected as cash flows from financing activities in the Condensed Consolidated Statements of Cash Flows.

The following table summarizes information about stock options outstanding at September 30, 2006:

Stock Options Outstanding at September 30, 2006
Number Outstanding	Weighted-Average Remaining Contractual Life (Years)	Exercise Price	Exercisable
493,226	4.57	$ 29.3850	-
105,000	2.41	4.6625	67,500
399,100	1.39	4.1625	399,100
39,800	0.54	5.4625	39,800

        Restricted Shares and Restricted Stock Units. Restricted shares and restricted stock units, when granted, are valued at the closing market value of the Company’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the nominal vesting period of the stock, and for awards issued subsequent to the adoption of FAS No. 123(R), adjusted for retirement-eligible employees, as required. For awards granted prior to the adoption of FAS No. 123(R), $1.2 million and $297,000 of compensation costs were recognized during the nine months and three months ended September 30, 2006, respectively, and continue to be recognized over the nominal vesting period. The restricted shares and restricted stock units have vesting dates up to three years from the issue date. When common stock dividends are declared by the Company’s Board of Directors, dividends are accrued on the issued restricted shares but are not paid until the shares vest. When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued on the restricted stock units and paid when the common stock dividends are paid.

The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the nine months ended September 30, 2006.

Restricted Share Awards	Shares/Units	Weighted-Average Grant-Date Market Value
Nonvested at January 1, 2006	415,692	$    8.887
Granted	459,956	26.477
Vested	(154,152)	15.576
Forfeited	-	-
Nonvested at September 30, 2006	721,496	18.672

The total fair value of restricted shares and restricted stock units which vested during the nine months ended September 30, 2006 was $4.3 million, and the Company realized $1.6 million of income tax benefits related to these vestings, of which $710,000 was excess income tax benefits.

Performance Awards. On April 26, 2006, the Company granted up to 657,243 stock unit awards. If performance goals are achieved for 2006, then the stock unit awards will be converted into restricted stock as of January 1, 2007, one-third of which vests on June 30, 2007, one-third on June 30, 2008 and the final one-third on June 30, 2009. 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 but are not paid until the restricted stock vests. Based on the Company’s financial performance through September 30, 2006, the Company considers it likely that the performance goals will be achieved. The stock unit awards were valued at the market value at the date of grant and amortized to compensation expense on a straight-line basis over the nominal vesting period, adjusted for retirement-eligible employees, as required under FAS No. 123(R).

5.Employee 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 purchase of the El Dorado Refinery by Frontier. No other current or future employees are eligible to participate in the plan. This plan had assets of $8.3 million at December 31, 2005, and its funding status is in compliance with ERISA.

The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are those 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 had no assets as of September 30, 2006 or December 31, 2005. The post-retirement health care plan requires retirees to pay between 20% and 40% of total health care costs based on age and length of service. The plan’s prescription drug benefits are at least equivalent to the Medicare Part D benefits.

The following tables set forth the amounts recognized for these benefit plans in the Company’s Condensed Consolidated Statements of Income for the nine months and three months ended September 30, 2006 and 2005:

	Nine Months Ended						Three Months Ended
	September 30,						September 30,
Pension benefits	2006			2005			2006			2005
Components of net periodic benefit cost:	(in thousands)
Service cost	$	-		$	-		$	-		$	-
Interest cost		407			474			135			158
Expected return on plan assets		(502	)		(359	)		(167	)		(120	)
Amortization of prior service cost		-			-			-			-
Recognized net actuarial loss		-			16			-			6
Net periodic benefit cost	$	(95	)	$	131		$	(32	)	$	44

	Nine Months Ended				Three Months Ended
Post-retirement healthcare and	September 30,				September 30,
other benefits	2006		2005		2006		2005
Components of net periodic benefit cost:	(in thousands)
Service cost	$	940	$	647	$	313	$	216
Interest cost		1,661		1,095		554		365
Expected return on plan assets		-		-		-		-
Amortization of prior service cost		-		-		-		-
Recognized net actuarial loss		1,113		368		371		122
Net periodic benefit cost	$	3,714	$	2,110	$	1,238	$	703

As of September 30, 2006, the Company had contributed $540,000 to its cash balance pension plan in 2006 and expects to contribute $152,000 in the fourth quarter of 2006.

6.Price Risk Management Activities

The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by the Company may take the form of futures contracts, collars or price swaps and are entered into with creditworthy counterparties. The Company believes that there is minimal credit risk with respect to its counterparties. The Company accounts for its commodity derivative contracts under the hedge (or deferral) method of accounting when the derivative contracts are designated as hedges for accounting purposes, or mark-to-market accounting if the Company elects not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized on the Condensed Consolidated Statements of Income in “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” at each period end. The Company has derivative contracts which it holds directly and also derivative contracts held on Frontier’s behalf by Utexam Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland, in connection with the Master Crude Oil Purchase and Sale Contract (see Note 10 “New Crude Oil Purchase and Sale Contract”). The market value of open derivative contracts is included on the Condensed Consolidated Balance Sheets in “Other current assets” when the unrealized value is a gain ($12.4 million at September 30, 2006), or in “Accrued liabilities and other” when the unrealized value is a loss ($854,000 at December 31, 2005).

Mark-to-market activities

During the nine months ended September 30, 2006 and 2005, the Company (directly or indirectly) had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the Condensed Consolidated Statements of Income:

·   Crude purchases in-transit. As of September 30, 2006, the Company had open derivative contracts held on Frontier’s behalf by Utexam on 918,000 barrels of crude oil to hedge in-transit Canadian crude oil costs. As of September 30, 2006, these positions had unrealized gains of $3.7 million. During the nine months and three months ended September 30, 2006, the Company reported in ��Other revenues” $9.5 million and $7.6 million, respectively (both amounts include the previously mentioned $3.7 million unrealized amount), in net gains on positions to hedge in-transit crude oil, mainly Canadian crude oil for the El Dorado Refinery. During the nine months ended September 30, 2005, the Company had no derivative activity to hedge crude purchases in-transit.

·   Derivative contracts on crude oil to hedge excess intermediate, normal butane, finished product and excess crude oil inventory for both the Cheyenne and El Dorado Refineries. As of September 30, 2006, the Company had open derivative contracts on 797,000 barrels of crude oil to hedge crude oil, intermediate and finished product inventories. At September 30, 2006, these positions had net unrealized gains of $8.7 million. During the nine months and three months ended September 30, 2006, the Company reported in “Other revenues” $9.9 million and $12.6 million, respectively (both amounts include the previously mentioned $8.7 million unrealized amount), on these types of positions. During the nine months and three months ended September 30, 2005, the Company recorded $1.3 million and $1.8 million in net losses, respectively, on these types of positions.

Hedging activities

During the nine months ended September 30, 2006, the Company had the following derivatives which were appropriately designated and accounted for as hedges:

·   Crude purchases in-transit. During the nine months ended September 30, 2006, the Company recorded $10.9 million in net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery, of which $15.0 million increased crude costs (“Raw material, freight and other costs”) and $4.1 million increased income which was reflected in “Other revenues” in the Condensed Consolidated Statements of Income for the ineffective portion of these hedges. During the three months ended September 30, 2006, crude costs (“Raw material, freight and other costs”) increased by $2.1 million due to net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery.

During the nine months ended September 30, 2005, the Company had no derivative contracts that were designated and accounted for as hedges.

7.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 continues through 2008, with special provisions for small business refiners. Because the Company qualifies as a small business refiner, Frontier has elected to extend its small refinery interim gasoline sulfur standard at each of the Refineries until 2011 and complied with the highway diesel sulfur standard by June 2006, as discussed below. The Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to meet the interim gasoline sulfur standard, which was required by January 1, 2004. An additional $9.0 million in estimated costs to meet the final standard, and $6.0 million for facilities to handle intermediate inventories, for the Cheyenne Refinery are expected to be incurred between 2008 and 2010. Total capital expenditures estimated as of September 30, 2006, for the El Dorado Refinery to comply with the final gasoline sulfur standard are approximately $70.0 million and are expected to be incurred between 2006 and 2009. Substantially all of the estimated $70.00 million of expenditures is included in the Company’s potential El Dorado gasoil hydrotreater revamp project. The gasoil hydrotreater revamp project will achieve gasoline sulfur compliance as well as additional economic benefit to the El Dorado Refinery.

The EPA has promulgated regulations that limit the sulfur content of highway diesel fuel beginning in mid-2006. As indicated above, Frontier elected to comply with the highway diesel sulfur standard by June 2006 and had completed the necessary capital projects to achieve the standard at both Refineries by early June. As of September 30, 2006, capital costs, including capitalized interest, for the ultra low sulfur diesel projects through September 30, 2006 (including 2004, 2005 and the first nine months of 2006 expenditures) were $105.4 million (including $26.5 million paid in the first nine months of 2006 and $996,000 accrued as of September 30, 2006) at the El Dorado Refinery and $16.8 million (including $10.2 million paid in the first nine months of 2006 and $433,000 accrued as of September 30, 2006) at the Cheyenne Refinery. Certain provisions of the American Jobs Creation Act of 2004 are providing federal income tax benefits to Frontier by allowing the Company an accelerated depreciation deduction on 75% of these qualified capital costs in the years incurred and by providing a $0.05 per gallon income tax credit on compliant diesel fuel produced up to an amount equal to the remaining 25% of these qualified capital costs.

On June 29, 2004, the EPA promulgated regulations designed to reduce emissions from the combustion of diesel fuel in non-road applications such as mining, agriculture, locomotives and marine vessels. Prior to June 30, 2006, the Company participated in this market through the manufacture and sale of approximately 6,000 barrels per day (“bpd”) of non-road diesel fuel from the El Dorado Refinery. The new regulations require refiners to reduce the sulfur content of non-road diesel fuel from 5,000 parts per million (“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for all but locomotive and marine uses. Diesel fuel used in locomotives and marine operations will be required to meet the 15 ppm sulfur standard in 2012. Small refiners, such as Frontier, will be allowed to either postpone the new sulfur limits or, if the small refiner chooses to meet the new limit on the national schedule, to increase their gasoline sulfur limits by 20%. Frontier chose to install equipment to desulfurize all of its diesel fuel, including non-road, to the 15 ppm sulfur standard by June 1, 2006, resulting in early compliance with the non-road standard. This gives the Company the option of selling its historic non-road diesel fuel volume into either the current non-road market or the 15 ppm sulfur on-road market, depending on economics. The new regulation also clarifies that EPA-approved small business refiners will be allowed to exceed both the small refiner maximum capacity and/or employee criteria through merger with or acquisition of another approved small business refiner without loss of small refiner regulatory status. The loss of such status through merger, acquisition or non-compliance with the enabling regulations could result in the loss of the benefits described in the above paragraphs and the possible acceleration of certain associated expenditures.

The EPA has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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 resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. In anticipation of such a consent decree, the Company has undertaken certain modifications at each of the Company’s refineries. At the Cheyenne Refinery, the Company has spent $4.6 million on the flare system, of which $223,000 was spent in 2004, $4.1 million in 2005 and the remaining $315,000 was incurred in the first nine months of 2006. At the El Dorado Refinery, the Company spent $1.2 million in prior years, and it expects to spend $3.3 million during 2006, on the flare system. In addition to Frontier’s expenditures, Shell Oil Products US (“Shell”) will reimburse Frontier $5.0 million in the fourth quarter of 2006 (included in “Other receivables” on the Condensed Consolidated Balance Sheet as of September 30, 2006) for modification of the El Dorado Refinery flare system in accordance with certain provisions of the 1999 asset purchase and sale agreement for the El Dorado Refinery entered into between Frontier and Shell. Settlement negotiations with the EPA and state regulatory agencies regarding additional regulatory issues associated with the Initiative are underway. The Company now estimates that, in addition to the flare gas recovery systems discussed above, capital expenditures totaling approximately $48 million at the Cheyenne Refinery and $65 million at the El Dorado Refinery will be required prior to 2015 to satisfy these issues. Notwithstanding these anticipated legal settlements, many of these same expenditures would be required for the Company to implement its planned facility expansions. Previous settlements between the EPA and other refiners have required monetary penalties in addition to capital expenditures. While the EPA has not yet proposed monetary penalties for Frontier, it is possible that such penalties may be imposed; however, the amount of any potential penalties is not currently estimable.

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 totaling approximately $4.0 million. In addition, the Company estimates that an ongoing groundwater remediation program averaging approximately $200,000 in annual operating and maintenance costs will be required for approximately ten more years. As of September 30, 2006 and December 31, 2005, the Company had a reserve included on the Condensed Consolidated Balance Sheets in “Other long-term liabilities” of $1.5 million in environmental liabilities reflecting the estimated present value of these expenditures ($2.0 million, discounted at a rate of 5.0%). In addition to this reserve, the Company had accrued $5.0 million as of September 30, 2006, also included in “Other long-term liabilities,” for the cleanup of a waste water treatment pond located on land historically leased from an adjacent landowner. The Company allowed the lease to expire and ceased use of the pond on the scheduled expiration date of June 30, 2006. The waste water pond will be cleaned up pursuant to the aforementioned agreement with the State of Wyoming. Depending upon the results of the ongoing investigation, or by a subsequent administrative order or permit, additional remedial action and costs could be required.

The Company is negotiating the settlement of a Notice of Violation (“NOV”) from the Wyoming Department of Environmental Quality alleging non-compliance with certain refinery waste management requirements. The Company has estimated that the capital cost for required corrective measures will be approximately $1.5 million. In addition, the Company had accrued an additional $1.2 million for expense work as of September 30, 2006 (included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets) and December 31, 2005 (included in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheets). As of September 30, 2006, the anticipated timing of these expenditures had changed from that anticipated as of December 31, 2005, resulting in reclassing the liability from a short-term liability to a long-term liability. A penalty in the amount of $631,000 has been negotiated as part of the settlement of this NOV. This amount had been accrued by the Company as of September 30, 2006, and was included in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheets as of September 30, 2006.

The Company has agreed to contribute $750,000 toward a City of Cheyenne project (estimated to take place in the next twelve months) to relocate a city storm water conveyance pipe, which is presently located on Refinery property and therefore potentially subject to contaminants from Refinery operations. This amount was accrued as of December 31, 2005 and is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheet as of December 31, 2005 and in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheet as of September 30, 2006.

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, 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. The Company intends to assume management of the existing groundwater remediation activities from Shell as soon as practicable. Shell will continue to fund these existing activities per its contractual obligation.

8.Litigation

Beverly Hills Lawsuits. A Frontier subsidiary, Wainoco Oil & Gas Company, owned and operated an interest in an oil field in the Los Angeles, California metropolitan area from 1985 to 1995. The production facilities for that interest in the oil field are located at the campus of the Beverly Hills High School. In April 2003, a law firm began filing claims with the Beverly Hills Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company and Frontier have been named in seven such suits: Moss et al. v. Venoco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Venoco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Venoco, Inc. et al., filed in January 2004; Steiner et al. v. Venoco, Inc. et al., filed in May 2004; and Kalcic et al. v. Venoco, Inc. et al., filed in April 2005. Of the approximately 1,025 plaintiffs in the seven lawsuits, Wainoco Oil & Gas Company and Frontier are named as defendants by approximately 450 of those plaintiffs. Other defendants in these lawsuits include the Beverly Hills Unified School District, the City of Beverly Hills, three other oil and gas companies (and their related companies), and one company involved in owning or operating a power plant adjacent to the Beverly Hills High School and its related companies. The lawsuits include claims for personal injury, wrongful death, loss of consortium and/or fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The seven pending lawsuits have been consolidated and are pending before a judge on the complex civil litigation panel in the Superior Court of the State of California for the County of Los Angeles. A case management order has been entered in the case pursuant to which 12 plaintiffs have been selected as the initial group of plaintiffs to go to trial and discovery is complete. On October 27, 2006, the court granted summary judgment in favor of the parent, Frontier Oil Corporation. As a result of this order, the plaintiffs can no longer prosecute claims against Frontier Oil Corporation, either for Frontier Oil Corporation’s alleged direct liability or for any of the plaintiffs’ claims against its subsidiary. The court’s order, which may be appealed by the plaintiffs, pertains only to the claims against Frontier Oil Corporation and not its subsidiary, which remains a defendant. The order does not affect unresolved indemnity claims asserted by or against Frontier Oil Corporation. The claims against Frontier’s subsidiary have been set for trial on November 27, 2006.

The oil production site operated by Frontier’s subsidiary was a modern facility and was operated with a high level of safety and responsibility. Frontier believes that its subsidiary’s activities did not cause any health problems for anyone, including former Beverly Hills High School students, school employees or area residents. Nevertheless, as a matter of prudent risk management, Frontier purchased insurance in 2003 from a highly-rated insurance company covering the existing claims described above and any similar claims for bodily injury or property damage asserted during the five-year period following the policy’s September 30, 2003 commencement date. The claims are covered, whether asserted directly against the insured parties or as a result of contractual indemnity. In October 2003, the Company paid $6.25 million to the insurance company for loss mitigation insurance and also funded with the insurance company a commutation account of approximately $19.5 million, which is funding the first costs incurred under the policy including, but not limited to, the costs of defense of the claims. The policy covers defense costs and any payments made to claimants, up to an aggregate limit of $120 million, including coinsurance by Frontier of up to $3.9 million of the coverage between $40 million and $120 million. As of September 30, 2006, the commutation account balance was approximately $9.1 million. Frontier has the right to terminate the policy at any time prior to September 30, 2008, and receive a refund of the unearned portion of the premium (approximately $2.2 million as of September 30, 2006, and declining by approximately $270,000 each quarter) plus any unspent balance in the commutation account plus accumulated interest. While the policy is in effect, the insurance company will manage the defense of the claims. The Company also has been seeking coverage with respect to the Beverly Hills, California claims from the insurance companies that provided policies to Frontier during the 1985 to 1995 period. The Company has reached a settlement on some of the policies and is continuing to pursue coverage efforts on other policies. 

In accordance with FAS No. 5, “Accounting for Contingencies,” Frontier has not accrued for a loss contingency relating to the Beverly Hills litigation because Frontier believes that, although unfavorable outcomes in the proceedings may be reasonably possible, Frontier does not consider them to be probable or reasonably estimable. Frontier believes that neither the claims that have been made, the seven pending lawsuits, nor other potential future litigation, by which similar or related claims may be asserted against Frontier or its subsidiary, will result in any material liability or have any material adverse effect upon Frontier.

Other. The Company is also involved in various other lawsuits 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.

9.Other Contingencies

El Dorado Earn-out Payments. On November 16, 1999, Frontier acquired the 110,000 bpd El Dorado Refinery from Shell. Under the provisions of the purchase and sale agreement, the Company is required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year, up to $7.5 million annually, of the El Dorado Refinery’s annual revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million. Any contingency payment will be recorded as additional acquisition cost when the payment is considered probable and estimable. A contingent earn-out payment of $7.5 million was required based on 2005 results and was accrued as of December 31, 2005 and paid in early 2006. Including the payment made in early 2006, the Company has paid a total of $22.5 million to date for contingent earn-out payments. Based on the results of operations for the nine months ended September 30, 2006, it is probable that a payment will be required in early 2007, and the entire $7.5 million was accrued as of September 30, 2006.

Income Tax Contingencies. The Company recognizes liabilities for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due. As of September 30, 2006, amounts reserved for such contingencies were $28.0 million (including interest) and are included in “Accrued liabilities and other” on the Condensed Consolidated Balance Sheets. Interest expensed during the nine months and three months ended September 30, 2006 for these contingencies was $1.1 million and $445,000, respectively, and is included in “Interest expense and other financing costs” on the Condensed Consolidated Statements of Income.

10.New 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 will purchase, transport and subsequently sell crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed. Utexam will be the owner of record of the crude oil as it is transported from the point of injection, which is expected to be 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. As of September 30, 2006, FORC and Utexam had entered into certain commitments to purchase and sell crude oil in October 2006 under this Contract; however, neither party has a continuing commitment to purchase or sell crude oil in the future. 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 upon injection in the pipeline in Canada.

11.Consolidating Financial Statements

Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of Frontier Oil Corporation’s (“FOC”) 6⅝% Senior Notes. Presented on the following pages are the Company’s consolidating balance sheets, statements of operations, and 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, statement of operations, and cash flows presented below 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, 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. Each subsidiary calculates its income tax provisions on a separate company basis, which are eliminated in the consolidation process.

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Nine Months Ended September 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	3,683,584		$	-	$	-		$	3,683,584
Other		12			25,043			55		-			25,110
		12			3,708,627			55		-			3,708,694
Costs and expenses:
Raw material, freight and other costs		-			2,939,309			-		-			2,939,309
Refinery operating expenses, excluding depreciation		-			211,703			-		-			211,703
Selling and general expenses, excluding depreciation		21,083			15,740			-		-			36,823
Depreciation, accretion and amortization		65			30,293			-		(312	)		30,046
		21,148			3,197,045			-		(312	)		3,217,881
Operating income (loss)		(21,136	)		511,582			55		312			490,813
Interest expense and other financing costs		8,912			2,807			-		(2,821	)		8,898
Interest and investment income		(8,479	)		(3,914	)		-		-			(12,393	)
Equity in earnings of subsidiaries		(515,282	)		-			-		515,282			-
		(514,849	)		(1,107	)		-		512,461			(3,495	)
Income before income taxes		493,713			512,689			55		(512,149	)		494,308
Provision for income taxes		171,867			178,768			19		(178,192	)		172,462
Net income	$	321,846		$	333,921		$	36	$	(333,957	)	$	321,846

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Nine Months Ended September 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,851,935		$	-	$	-		$	2,851,935
Other		(1	)		(1,150	)		66		-			(1,085	)
		(1	)		2,850,785			66		-			2,850,850
Costs and expenses:
Raw material, freight and other costs		-			2,282,546			-		-			2,282,546
Refinery operating expenses, excluding depreciation		-			173,877			-		-			173,877
Selling and general expenses, excluding depreciation		14,238			10,880			-		-			25,118
Merger termination and legal costs		47			-			-		-			47
Depreciation, accretion and amortization		50			27,028			-		(417	)		26,661
		14,335			2,494,331			-		(417	)		2,508,249
Operating income (loss)		(14,336	)		356,454			66		417			342,601
Interest expense and other financing costs		7,822			1,633			-		(1,120	)		8,335
Interest and investment income		(3,056	)		(808	)		-		-			(3,864	)
Equity in earnings of subsidiaries		(356,803	)		-			-		356,803			-
		(352,037	)		825			-		355,683			4,471
Income before income taxes		337,701			355,629			66		(355,266	)		338,130
Provision for income taxes		128,119			132,230			-		(131,801	)		128,548
Net income	$	209,582		$	223,399		$	66	$	(223,465	)	$	209,582

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,360,875		$	-	$	-		$	1,360,875
Other		8			20,224			28		-			20,260
		8			1,381,099			28		-			1,381,135
Costs and expenses:
Raw material, freight and other costs		-			1,110,214			-		-			1,110,214
Refinery operating expenses, excluding depreciation		-			68,188			-		-			68,188
Selling and general expenses, excluding depreciation		9,119			5,975			-		-			15,094
Depreciation, accretion and amortization		22			11,182			-		(66	)		11,138
		9,141			1,195,559			-		(66	)		1,204,634
Operating income (loss)		(9,133	)		185,540			28		66			176,501
Interest expense and other financing costs		2,998			1,070			-		(452	)		3,616
Interest and investment income		(3,741	)		(2,196	)		-		-			(5,937	)
Equity in earnings of subsidiaries		(186,927	)		-			-		186,927			-
		(187,670	)		(1,126	)		-		186,475			(2,321	)
Income before income taxes		178,537			186,666			28		(186,409	)		178,822
Provision for income taxes		57,653			60,997			19		(60,731	)		57,938
Net income	$	120,884		$	125,669		$	9	$	(125,678	)	$	120,884

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended September 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,187,607		$	-	$	-		$	1,187,607
Other		7			(1,712	)		28		-			(1,677	)
		7			1,185,895			28		-			1,185,930
Costs and expenses:
Raw material, freight and other costs		-			931,495			-		-			931,495
Refinery operating expenses, excluding depreciation		-			58,702			-		-			58,702
Selling and general expenses, excluding depreciation		4,242			4,435			-		-			8,677
Merger termination and legal costs		10			-			-		-			10
Depreciation and amortization		18			9,917			-		(139	)		9,796
		4,270			1,004,549			-		(139	)		1,008,680
Operating income (loss)		(4,263	)		181,346			28		139			177,250
Interest expense and other financing costs		2,607			568			-		(816	)		2,359
Interest and investment income		(1,575	)		(562	)		-		-			(2,137	)
Equity in earnings of subsidiaries		(182,135	)		-			-		182,135			-
		(181,103	)		6			-		181,319			222
Income before income taxes		176,840			181,340			28		(181,180	)		177,028
Provision for income taxes		67,655			66,997			-		(66,809	)		67,843
Net income	$	109,185		$	114,343		$	28	$	(114,371	)	$	109,185

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of September 30, 2006
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	243,371	$	153,084	$	-		$	-		$	396,455
Trade and other receivables		497		121,844		-			-			122,341
Receivable from affiliated companies		-		2,617		244			(2,861	)		-
Inventory		-		377,853		-			-			377,853
Deferred tax assets		8,610		12,496		-			(12,496	)		8,610
Other current assets		2,450		13,534		-			-			15,984
Total current assets		254,928		681,428		244			(15,357	)		921,243
Property, plant and equipment, at cost		1,301		770,419		-			(5,904	)		765,816
Less - accumulated depreciation and amortization		1,031		273,894		-			(8,246	)		266,679
		270		496,525		-			2,342			499,137
Deferred financing costs, net		2,413		538		-			-			2,951
Commutation account		9,135		-		-			-			9,135
Prepaid insurance, net		2,422		-		-			-			2,422
Other intangible asset, net		-		1,342		-			-			1,342
Other assets		3,015		4,205		-			-			7,220
Investment in subsidiaries		692,548		-		-			(692,548	)		-
Total assets	$	964,731	$	1,184,038	$	244		$	(705,563	)	$	1,443,450
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	895	$	383,118	$	-		$	-		$	384,013
Payable to affiliated companies		2,861		-		-			(2,861	)		-
Accrued turnaround cost		-		14,535		-			-			14,535
Accrued interest		4,969		119		-			-			5,088
Accrued income taxes		3,097		-		-			-			3,097
Accrued liabilities and other		33,775		22,373		269			-			56,417
Total current liabilities		45,597		420,145		269			(2,861	)		463,150
Long-term debt		150,000		-		-			-			150,000
Long-term accrued and other liabilities		2,911		61,166		-			-			64,077
Deferred income taxes		74,969		77,412		-			(77,412	)		74,969
Payable to affiliated companies		-		28,030		19			(28,049	)		-
Shareholders’ equity		691,254		597,285		(44	)		(597,241	)		691,254
Total liabilities and shareholders’ equity	$	964,731	$	1,184,038	$	244		$	(705,563	)	$	1,443,450

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2005
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	244,357	$	111,708	$	-		$	-		$	356,065
Trade and other receivables		6,381		123,254		-			-			129,635
Receivable from affiliated companies		-		4,556		189			(4,745	)		-
Inventory		-		247,621		-			-			247,621
Deferred tax assets		6,819		7,514		-			(7,514	)		6,819
Other current assets		499		7,436		-			-			7,935
Total current assets		258,056		502,089		189			(12,259	)		748,075
Property, plant and equipment, at cost		1,235		675,639		-			(8,752	)		668,122
Less - accumulated depreciation and amortization		988		245,157		-			(7,961	)		238,184
		247		430,482		-			(791	)		429,938
Deferred financing costs, net		2,775		774		-			-			3,549
Commutation account		12,606		-		-			-			12,606
Prepaid insurance, net		3,331		-		-			-			3,331
Other intangible asset, net		-		1,422		-			-			1,422
Other assets		2,508		80		-			-			2,588
Investment in subsidiaries		483,766		-		-			(483,766	)		-
Total assets	$	763,289	$	934,847	$	189		$	(496,816	)	$	1,201,509
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,480	$	357,097	$	-		$	-		$	359,577
Accrued dividends		58,726		-		-			-			58,726
Accrued turnaround cost		-		12,696		-			-			12,696
Accrued interest		2,485		-		-			-			2,485
Accrued liabilities and other		26,853		25,205		269			-			52,327
Total current liabilities		90,544		394,998		269			-			485,811
Long-term debt		150,000		-		-			-			150,000
Long-term accrued and other liabilities		2,214		47,698		-			-			49,912
Deferred income taxes		70,727		71,563		-			(71,563	)		70,727
Payable to affiliated companies		4,745		7,026		-			(11,771	)		-
Shareholders’ equity		445,059		413,562		(80	)		(413,482	)		445,059
Total liabilities and shareholders’ equity	$	763,289	$	934,847	$	189		$	(496,816	)	$	1,201,509

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	321,846		$	333,921		$	36		$	(333,957	)	$	321,846
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(515,282	)		-			-			515,282			-
Depreciation, accretion and amortization		65			30,293			-			(312	)		30,046
Stock-based compensation expense		12,882			-			-			-			12,882
Income tax benefits of stock compensation		10,102			-			-			-			10,102
Excess income tax benefits of share-based payment arrangements		(8,796	)		-			-			-			(8,796	)
Deferred income taxes		2,451			-			-			-			2,451
Income taxes eliminated in consolidation		-			178,173			19			(178,192	)		-
Deferred financing cost amortization		362			236			-			-			598
Amortization of long-term prepaid insurance		909			-			-			-			909
Long-term commutation account		3,471			-			-			-			3,471
Increase in long-term accrued liabilities		-			13,204			-			-			13,204
Other		(12	)		(4,125	)		-			-			(4,137	)
Changes in working capital from operations		8,383			(106,185	)		-			(1,361	)		(99,163	)
Net cash provided by (used in) operating activities		(163,619	)		445,517			55			1,460			283,413
Cash flows from investing activities:
Additions to property, plant and equipment		(88	)		(92,070	)		-			(1,460	)		(93,618	)
El Dorado Refinery contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Proceeds from sale of assets		8			-			-			-			8
Net cash used in investing activities		(80	)		(99,570	)		-			(1,460	)		(101,110	)
Cash flows from financing activities:
Proceeds from issuance of common stock		3,644			-			-			-			3,644
Purchase of treasury stock		(90,147	)		-			-			-			(90,147	)
Dividends paid		(64,196	)		-			-			-			(64,196	)
Excess income tax benefits of share-based payment arrangements		8,796			-			-			-			8,796
Other		-			(10	)		-			-			(10	)
Intercompany transactions		304,616			(304,561	)		(55	)		-			-
Net cash provided by (used in) financing activities		162,713			(304,571	)		(55	)		-			(141,913	)
(Decrease) increase in cash and cash equivalents		(986	)		41,376			-			-			40,390
Cash and cash equivalents, beginning of period		244,357			111,708			-			-			356,065
Cash and cash equivalents, end of period	$	243,371		$	153,084		$	-		$	-		$	396,455

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Nine Months Ended September 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	209,582		$	223,399		$	66		$	(223,465	)	$	209,582
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(356,803	)		-			-			356,803			-
Depreciation and amortization		50			27,028			-			(417	)		26,661
Stock-based compensation expense		1,118			-			-			-			1,118
Income tax benefits of stock compensation		19,778			-			-			-			19,778
Deferred income taxes		23,593			-			-			-			23,593
Income taxes eliminated in consolidation		-			131,801			-			(131,801	)		-
Deferred financing cost amortization		362			356			-			-			718
Amortization of long-term prepaid insurance		908			-			-			-			908
Long-term commutation account		3,409			-			-			-			3,409
Increase in long-term accrued liabilities		-			1,175			-			-			1,175
Other		490			(65	)		-			-			425
Changes in working capital from operations		32,487			(80,112	)		-			-			(47,625	)
Net cash provided by (used in) operating activities		(65,026	)		303,582			66			1,120			239,742
Cash flows from investing activities:
Additions to property, plant and equipment		(129	)		(71,926	)		-			(1,120	)		(73,175	)
El Dorado Refinery contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Involuntary conversion - net of insurance proceeds		-			2,142			-			-			2,142
Net cash used in investing activities		(129	)		(77,284	)		-			(1,120	)		(78,533	)
Cash flows from financing activities:
Proceeds from issuance of common stock		18,576			-			-			-			18,576
Purchase of treasury stock		(11,989	)		-			-			-			(11,989	)
Dividends paid		(5,522	)		-			-			-			(5,522	)
Debt issue costs and other		(100	)		(10	)		-			-			(110	)
Intercompany transactions		109,671			(109,605	)		(66	)		-			-
Net cash provided by (used in) financing activities		110,636			(109,615	)		(66	)		-			955
Decrease in cash and cash equivalents		45,481			116,683			-			-			162,164
Cash and cash equivalents, beginning of period		105,409			18,980			-			-			124,389
Cash and cash equivalents, end of period	$	105,890		$	135,663		$	-		$	-		$	286,553

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

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 combined Refineries. Data for each Refinery is 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. 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. Our Refineries have a total annual average permitted crude capacity of 162,000 barrels per day (“bpd”). The four significant indicators of our profitability, 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 turnaround, or planned maintenance activity). We typically do not use derivative instruments to offset price risk on our base level of operating inventories. 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 FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of futures trading.

The NYMEX crude oil price began 2006 at $61.04 per barrel, ended the first quarter of 2006 at $66.63 per barrel, ended the second quarter of 2006 at $73.93 per barrel and ended the third quarter of 2006 at $62.91 per barrel. The crude oil market fundamentals and geopolitical considerations continued to support prices higher than historic averages. The increase in crude oil prices, along with additional production of heavy and/or sour crude oil, increased our crude oil differentials during both the nine months and three months ended September 30, 2006, when compared to the same periods in 2005. During the first nine months of 2006, our average gasoline and diesel crack spreads were the highest in our history. Higher demand for gasoline and diesel along with product supply constraints produced higher gasoline and diesel crack spreads.

We announced on April 27, 2006 that our Board of Directors had approved a 2-for-1 stock split by means of a stock dividend on our common stock. Effective with the stock split, our Board of Directors also approved an increase in the regular cash dividend to $0.12 per share annually from the previous split-adjusted level of $0.08 per share annually. The increased quarterly cash dividend will be paid at the rate of $0.03 per share on a post-split basis. The stock split was subject to shareholder approval of an amendment to our articles of incorporation to increase the number of authorized shares from 90 million to 180 million, and the amendment was approved at a special shareholders’ meeting on June 9, 2006. The stock dividend was issued on June 26, 2006 to shareholders of record as of the close of business on June 19, 2006. All prior period share related numbers included in this report (except as indicated) have been revised to reflect the effect of the stock split.

Nine months ended September 30, 2006 compared with the same period in 2005

Overview of Results

We had net income for the nine months ended September 30, 2006 of $321.8 million, or $2.85 per diluted share, compared to net income of $209.6 million, or $1.85 per diluted share, earned in the same period in 2005. Our operating income of $490.8 million for the nine months ended September 30, 2006 was an increase of $148.2 million from the $342.6 million for the comparable period in 2005. The average diesel and gasoline crack spreads were higher during the first nine months of 2006 ($21.73 and $16.14 per barrel, respectively) than in the first nine months of 2005 ($14.60 and $12.67 per barrel, respectively), and both the light/heavy and WTI/WTS crude oil differentials increased for the nine months ended September 30, 2006 compared to the same period in 2005. Our El Dorado Refinery also benefited from the light/heavy crude oil differential when it began receiving and processing heavy Canadian crude oil in March 2006.

Specific Variances

Refined product revenues. Refined product revenues increased $831.7 million, or 29%, from $2.9 billion to $3.7 billion for the nine months ended September 30, 2006 compared to the same period in 2005. This increase was due to increased sales prices ($16.18 higher average per sales barrel), which resulted from higher crude oil prices and continued tight product availability, as well as higher sales volumes in 2006 (4,417 more bpd).

Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distillation of crude oil and the operations of other refinery process units. Yields increased 8,831 bpd at the El Dorado Refinery while decreasing 4,129 bpd at the Cheyenne Refinery for the nine months ended September 30, 2006 compared to same period in 2005. A Cheyenne Refinery turnaround in April 2006 caused yields to be lower this year than in the comparable period in 2005, and an El Dorado Refinery turnaround from March 1 through April 5, 2005 caused yields to be lower in 2005 than the comparable period in 2006.

Other revenues. Other revenues increased $26.2 million to $25.1 million for the nine months ended September 30, 2006, compared to a loss of $1.1 million for the same period in 2005, the sources of which were $23.5 million in net gains from derivative contracts in the nine months ended September 30, 2006 compared to net derivative losses of $1.2 million for the same period in 2005 and $1.5 million in gasoline sulfur credit sales in 2006 (none in 2005). See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blend stocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. Raw material, freight and other costs increased by $656.8 million, from $2.3 billion in the nine months ended September 30, 2005, to $2.9 billion in the same period for 2006. The increase in raw material, freight and other costs was due to greater crude oil charges, higher average crude oil prices and a smaller FIFO inventory gain in the nine months ended September 30, 2006, compared to the same period in 2005. We also benefited from improved crude oil differentials during the nine months ended September 30, 2006 when compared to the same period in 2005. For the nine months ended September 30, 2006, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $7.9 million after tax (nearly $13.0 million pretax, comprised of a $12.0 million gain at the Cheyenne Refinery and a $1.0 million gain at the El Dorado Refinery). For the nine months ended September 30, 2005, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $43.7 million after tax ($70.7 million pretax, comprised of $18.2 million at the Cheyenne Refinery and $52.5 million at the El Dorado Refinery) due to increasing crude oil and refined product prices.

The Cheyenne Refinery raw material, freight and other costs of $58.78 per sales barrel for the nine months ended September 30, 2006 increased from $46.44 per sales barrel in the same period in 2005 due to higher crude oil prices offset by an improved light/heavy crude oil differential. The light/heavy crude oil differential for the Cheyenne Refinery averaged $16.82 per barrel in the nine months ended September 30, 2006 compared to $14.39 per barrel in the same period in 2005.

The El Dorado Refinery raw material, freight and other costs of $64.71 per sales barrel for the nine months ended September 30, 2006 increased from $52.02 per sales barrel in the same period in 2005 due to higher average crude oil prices offset by an improved WTI/WTS crude oil differential and in 2006, the benefit of processing Canadian heavy crude oil. The WTI/WTS crude oil differential increased from an average of $4.16 per barrel in the nine-month period ended September 30, 2005, to $5.34 per barrel in the same period in 2006. For the nine months ended September 30, 2006, the light/heavy crude oil differential averaged $19.91 per barrel.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, includes both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $211.7 million in the nine months ended September 30, 2006 compared to $173.9 million in the comparable period of 2005.

The Cheyenne Refinery operating expenses, excluding depreciation, were $84.3 million in the nine months ended September 30, 2006 compared to $55.2 million in the comparable period of 2005. The primary areas of increased costs were in higher maintenance costs ($7.5 million, with $3.0 million of the costs related to a plant-wide steam outage in February 2006, $585,000 related to a September 2006 coker outage and $577,000 related to a butamer unit outage), environmental expenditures ($6.5 million, with an estimated $5.0 million related to a waste water pond clean up), turnaround related costs ($7.9 million, primarily due to the alkylation plant spring turnaround in April 2006 and an increase in the accrual for the spring 2007 turnarounds), increased usage of natural gas ($2.1 million), higher salaries ($1.8 million, including $1.0 million in increased stock-based compensation costs) and chemical and additive costs ($1.3 million).

The El Dorado Refinery operating expenses, excluding depreciation, were $127.4 million in the nine months ended September 30, 2006, increasing from $118.7 million in the same nine-month period of 2005. The primary areas of increased costs were in electricity ($3.3 million), chemicals and additives ($3.1 million), maintenance ($2.7 million, with $1.8 million due to a fire on a distillate hydrotreater unit), salaries and benefits ($1.5 million, including $606,000 in increased stock-based compensation costs), lease and rental equipment ($1.1 million), environmental ($915,000), insurance ($784,000), non-maintenance contractors ($544,000), turnaround accruals ($526,000) and property taxes ($366,000). Reduced costs resulted from lower turnaround costs in excess of accruals ($2.9 million), consulting and legal ($818,000) and a $3.4 million reduction in natural gas costs as consumption was reduced in 2006 because we did not purchase natural gas for the cogeneration facility. Electricity costs were higher during the nine months ended September 30, 2006, compared to the same period in 2005, as we produced electricity from our cogeneration facility in 2005 and did not do so in 2006.

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $11.7 million, or 47%, from $25.1 million for the nine months ended September 30, 2005 to $36.8 million for the nine months ended September 30, 2006, primarily due to an increase in salaries and benefits expense, which resulted from the adoption of FAS No. 123(R), the issuance of additional stock-based compensation awards, and the vesting of stock compensation upon the retirement of an executive officer as of March 31, 2006. Stock-based compensation expense was $11.3 million for the nine months ended September 30, 2006 compared to $1.0 million for the comparable period in 2005.

Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $3.4 million, or 13%, for the nine months ended September 30, 2006 compared to the same period in 2005 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects.

Interest expense and other financing costs. Interest expense and other financing costs of $8.9 million for the nine months ended September 30, 2006 increased $563,000, or 7%, from $8.3 million in the comparable period in 2005. The increase was due to $1.1 million in accrued interest expense for income tax contingencies in 2006 (none in 2005) and $1.3 million in facility costs and financing expenses related to the Utexam Master Crude Oil Purchase and Sale Contract entered into in March 2006 (“Utexam Arrangement”) (see Note 10 in the “Notes to Condensed Consolidated Financial Statements”), offset by $2.9 million of interest cost being capitalized in the nine months ended September 30, 2006, compared to only $1.5 million of interest cost being capitalized in the nine months ended September 30, 2005. Average debt outstanding decreased to $152.2 million during the nine months ended September 30, 2006 from $164.0 million for the same period in 2005 (excluding amounts payable to Utexam under the Utexam Arrangement during the 2006 period in which it has been utilized).

Interest and investment income. Interest and investment income increased $8.5 million from $3.9 million in the nine months ended September 30, 2005, to $12.4 million in the nine months ended September 30, 2006, because we had more cash available to invest and because of higher interest rates on invested cash.

Provision for income taxes. The provision for income tax for the nine months ended September 30, 2006 was $172.5 million on pretax income of $494.3 million (or 34.9%) reflecting a benefit of the “American Jobs Creation Act of 2004” (the “Act”) production activities deduction for manufacturers. The income tax provision for the nine months ended September 30, 2006 also included the benefit of a $14.6 million credit for production of ultra low sulfur diesel fuel. Our current estimated effective tax rate excluding both of these benefits is 37.8%. Our provision for income taxes for the nine months ended September 30, 2005, was $128.6 million on pretax income of $338.1 million (or 38.0%).

Three months ended September 30, 2006 compared with the same period in 2005

Overview of Results

We had net income for the three months ended September 30, 2006 of $120.9 million, or $1.08 per diluted share, compared to net income of $109.2 million, or $0.95 per diluted share, in the same period in 2005. Our operating income of $176.5 million for the three months ended September 30, 2006 was a decrease of $749,000 from the $177.3 million of operating income for the comparable period in 2005. The average diesel and gasoline crack spreads were higher during the third quarter of 2006 ($26.21 and $18.38 per barrel, respectively) than in the third quarter of 2005 ($18.38 and $18.11 per barrel, respectively), and both the light/heavy and WTI/WTS crude oil differentials increased for the quarter ended September 30, 2006 compared to the same period in 2005. However, we realized a FIFO inventory loss of $25.3 million (pre-tax) in the three months ended September 30, 2006 compared to a $40.9 million pretax gain for the same period in 2005.

Specific Variances

Refined product revenues. Refined product revenues increased $173.3 million, or 15%, from $1.2 billion to $1.4 billion for the three months ended September 30, 2006 compared to the same period in 2005. This increase was due to increased sales prices ($11.78 higher average per sales barrel), largely the result of higher crude oil prices and continued tight product availability, offset by less sales volumes in 2006 (2,393 less bpd).

Manufactured product yields. Yields increased 2,603 bpd at the El Dorado Refinery for the three months ended September 30, 2006, compared to the same period in 2005, partially due to new process unit capacity resulting from the ultra low sulfur diesel project completed in the second quarter of 2006. Yields decreased 4,431 bpd at the Cheyenne Refinery for the three months ended September 30, 2006, compared to same period in 2005, due to a reformer regeneration and fractionator problems during the 2006 period.

Other revenues. Other revenues increased nearly $22.0 million to $20.3 million for the three months ended September 30, 2006, compared to a loss of $1.7 million for the same period in 2005, the source of which was $20.2 million in net gains from derivative contracts in the three months ended September 30, 2006 compared to net derivative losses of $1.7 million for the same period in 2005. See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs. Raw material, freight and other costs increased by $178.7 million, from $931.5 million in the three months ended September 30, 2005, to $1.1 billion in the same period for 2006. The increase in raw material, freight and other costs was due to higher average crude prices and a net FIFO inventory loss in the three months ended September 30, 2006, compared to a net FIFO inventory gain in the three months ended September 30, 2005. We benefited from improved crude oil differentials during the three months ended September 30, 2006 compared to the same period in 2005. For the three months ended September 30, 2006, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $15.7 million after tax ($25.3 million pretax loss, comprised of a $6.0 million loss at the Cheyenne Refinery and a $19.3 million loss at the El Dorado Refinery). For the three months ended September 30, 2005, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $25.4 million after tax ($40.9 million pretax, comprised of $9.4 million at the Cheyenne Refinery and $31.5 million at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $65.56 per sales barrel for the three months ended September 30, 2006 increased from $52.49 per sales barrel in the same period in 2005 due to higher crude oil prices offset by an improved light/heavy crude oil differential. The light/heavy crude oil differential for the Cheyenne Refinery averaged $16.30 per barrel in the three months ended September 30, 2006 compared to $14.93 per barrel in the same period in 2005.

The El Dorado Refinery raw material, freight and other costs of $70.54 per sales barrel for the three months ended September 30, 2006 increased from $59.47 per sales barrel in the same period in 2005 due to higher average crude oil prices offset by an improved WTI/WTS crude oil differential and in 2006, the benefit of processing Canadian heavy crude oil. The WTI/WTS crude oil differential increased from an average of $3.13 per barrel in the three-month period ended September 30, 2005, to $4.69 per barrel in the same period in 2006. For the three months ended September 30, 2006, the light/heavy crude oil differential averaged $12.83 per barrel.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, were $68.2 million in the three months ended September 30, 2006 compared to $58.7 million in the comparable period of 2005.

The Cheyenne Refinery operating expenses, excluding depreciation, were $27.5 million in the three months ended September 30, 2006 compared to $21.0 million in the comparable period of 2005. The primary areas of increase were higher maintenance costs ($1.1 million), turnaround costs in excess of accruals and turnaround accruals ($2.6 million, primarily related to the increased accruals for the spring 2007 turnarounds), environmental expenditures and accruals ($1.1 million, partially due to $410,000 in accrued penalties), salaries and benefits ($864,000) and additives and chemicals ($530,000).

The El Dorado Refinery operating expenses, excluding depreciation, were $40.7 million in the three months ended September 30, 2006, increasing from $37.7 million in the same three-month period of 2005. The primary areas of increased costs were salaries and benefits ($1.2 million), maintenance ($1.0 million), electricity ($911,000), chemicals and additives ($507,000), environmental ($650,000), insurance ($454,000) and lease and rental equipment ($434,000). We also realized a net $2.9 million reduction in natural gas costs, a result of both lower consumption (due to not purchasing natural gas for the cogeneration facility) and lower prices in the three months of 2006 compared to the same period in 2005. Electricity costs were higher during the three months ended September 30, 2006, compared to the same period in 2005, as we produced electricity from our cogeneration facility in 2005 and did not do so in 2006.

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $6.4 million, or 74%, from $8.7 million for the three months ended September 30, 2005 to $15.1 million for the three months ended September 30, 2006, primarily due to an increase in salaries and benefits expense, which resulted from the adoption of FAS No. 123(R) and the issuances of additional stock-based compensation awards. Stock-based compensation expense was $4.6 million for the three months ended September 30, 2006 compared to $392,000 for the comparable period in 2005. Beverly Hills litigation expenses of $2.3 million were recorded for the quarter ended September 30, 2006 compared to $920,000 in the comparable period in 2005.

Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $1.3 million, or 14%, for the three months ended September 30, 2006 compared to the same period in 2005 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects completed during the second quarter of 2006.

Interest expense and other financing costs. Interest expense and other financing costs of $3.6 million for the three months ended September 30, 2006 increased approximately $1.2 million, or 53%, from $2.4 million in the comparable period in 2005. The increase was due to lower capitalized interest ($452,000 being capitalized in the three months ended September 30, 2006, compared to $824,000 in 2005), $596,000 in facility and financing costs related to the Utexam Arrangement (see Note 10 in the “Notes to Condensed Consolidated Financial Statements”) and $445,000 in accrued interest on income tax contingencies during the three months ended September 30, 2006. Average debt outstanding was $150.0 million during each of the three month periods ended September 30, 2006 and 2005 (excluding the payables to Utexam under the Utexam Arrangement during the 2006 period in which it has been utilized).

Interest and investment income. Interest and investment income increased by $3.8 million from $2.1 million in the three months ended September 30, 2005, to $5.9 million in the three months ended September 30, 2006, because we had more cash available to invest and because of higher interest rates on invested cash.

Provision for income taxes. The provision for income tax for the three months ended September 30, 2006 was $57.9 million on pretax income of $178.8 million (or 32.4%) reflecting the benefit of a $10.6 million credit for the production of ultra low sulfur diesel fuel and a benefit from the Act’s production activities deduction for manufacturers. The provision for income taxes for the three months ended September 30, 2005, was $67.8 million on pretax income of $177.0 million (or 38.3%).

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities. Net cash provided by operating activities was $283.4 million for the nine months ended September 30, 2006 compared to net cash provided by operating activities of $239.7 million during the nine months ended September 30, 2005. Improved results of operations increased cash flow significantly but were offset by higher uses of cash for working capital. 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 $99.2 million of cash in the nine months ended September 30, 2006 while using $47.6 million of cash in the comparable period in 2005. The most significant uses of cash for working capital changes during the nine-month period of 2006 were an increase in inventories of $130.2 million compared to an increase in inventories of $113.4 million in the 2005 comparable period. The increase in inventories during the nine months ended September 30, 2006, was due to a significant increase in crude oil in-transit inventories, primarily Canadian crude in-transit for the El Dorado Refinery, as well as other increased inventory levels and higher prices. The significant sources of cash from working capital changes during the nine months ended September 30, 2006 included an increase in crude and other payables of $29.9 million and an increase in accrued liabilities of $1.7 million, compared to an increase in crude and other payables of $96.9 million and increases in accrued liabilities of $25.4 million in the comparable period in 2005.

At September 30, 2006, we had $396.5 million of cash and cash equivalents, working capital of $458.1 million and $173.5 million of borrowing base availability for cash borrowings under our $225.0 million revolving credit facility.

Cash flows used in investing activities. Capital expenditures during the first nine months of 2006 were $93.6 million, which included approximately $52.3 million for the El Dorado Refinery and $41.6 million for the Cheyenne Refinery. The $52.3 million of capital expenditures for our El Dorado Refinery included $26.5 million for the ultra low sulfur diesel project and $17.6 million for the crude unit and vacuum tower expansion as well as operational, payout, safety, administrative, environmental and optimization projects. The $41.6 million of capital expenditures for our Cheyenne Refinery included approximately $10.2 million for the ultra low sulfur diesel project and $14.9 million for the coker expansion as well as environmental, operational, safety, administrative and payout projects.

Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we have made, and may be required to make, contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60.0 million per year of the El Dorado Refinery’s annual revenues less material costs and operating costs, other than depreciation. Such contingency payments are recorded as an additional acquisition cost when the payment is considered probable and estimable. The total amount of these contingent payments is capped at $40.0 million, with an annual cap of $7.5 million. Payments of $7.5 million each were paid in early 2005 and 2006, based on 2004 and 2005 results, and were accrued as of December 31, 2004 and 2005, respectively. Including the payment made in early 2006, we have paid a total of $22.5 million to date for contingent earn-out payments. Based on the results of operations for the nine months ended September 30, 2006, it is probable that a payment will be required in early 2007, and $7.5 million was accrued as of September 30, 2006.

During the first quarter of 2005, we received the remaining payments of $2.1 million from our insurance companies for claims related to the 2004 coker fire at the Cheyenne Refinery.

Cash flows used in financing activities. During the nine months ended September 30, 2006, we used $85.4 million to repurchase stock, of which $1.9 million was for the settlement of stock purchased in December 2005 and $83.5 million was for the purchase of 3,127,788 shares in the first nine months of 2006 (both of which were made under the authorization of the stock repurchase program discussed below). Payments totaling $64.2 million in dividends during the nine months ended September 30, 2006 were our second largest use of cash for financing activities. We also increased our treasury stock by 141,314 shares ($4.8 million) from stock surrendered by employees or members of the Board of Directors to pay their withholding taxes on stock-based compensation which vested during the first nine months of 2006.

We have authorization from our Board of Directors to repurchase up to 32 million shares of our common stock. Through September 30, 2006, we had purchased 22,038,852 shares of common stock under this stock repurchase program and had authorization remaining under this program to purchase an additional 9,961,148 shares. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases under this program. Through September 30, 2006, $91.1 million (3,519,388 shares) of the $100 million had been utilized for repurchases. During early October 2006, we utilized an additional $8.8 million for share repurchases, thereby bringing the total amount repurchased to $99.9 million of the $100 million authorized.

During the nine months ended September 30, 2006, we issued 837,800 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $3.6 million in cash.

As of September 30, 2006, we had $150.0 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $51.5 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, 2006. Shareholder’s equity as of September 30, 2006 stood at an all-time high of $691.3 million.

Our Board of Directors declared both a special cash dividend of $0.50 per share and a regular quarterly cash dividend of $0.02 per share in December 2005, both of which were paid in January 2006. In addition, a quarterly cash dividend of $0.02 per share was declared in March 2006 and paid in April 2006, quarterly cash dividends of $0.03 per share were declared in June 2006 and September 2006 and paid in July 2006 and October 2006, respectively. The total cash required for the dividend declared in September 2006 was approximately $3.3 million and was included in “Accrued dividends” on the September 30, 2006 Condensed Consolidated Balance Sheet.

We announced on April 27, 2006 that our Board of Directors had approved a 2-for-1 stock split by means of a stock dividend on our common stock. Effective with the stock split, the Board also approved a 50% increase in the regular quarterly dividend to $0.03 per share ($0.12 annualized) from the current split-adjusted level of $0.02 per share. The stock split was subject to shareholder approval of an amendment to our articles of incorporation to increase the number of authorized shares from 90 million to 180 million, and the amendment was approved at a special shareholders’ meeting on June 9, 2006. The stock dividend was issued on June 26, 2006 to shareholders of record as of the close of business on June 19, 2006.

Future capital expenditures. Capital expenditures aggregating approximately $180 million are currently planned for 2006 (including the $93.6 million paid during the first nine months), and include $98 million at our El Dorado Refinery, $81 million at our Cheyenne Refinery, and $650,000 for capital expenditures in our Denver and Houston offices, and for our share of crude oil pipeline projects. The $98 million of planned capital expenditures for our El Dorado Refinery includes approximately $28 million for the ultra low sulfur diesel project discussed above, $47 million for the crude unit and vacuum tower expansion, discussed below, as well as environmental, operational, safety, administrative and payout projects. The $81 million of planned capital expenditures for our Cheyenne Refinery includes approximately $11 million for the ultra low sulfur diesel project, $33 million for the coker expansion, $6 million for a new amine unit and $5 million for the crude fractionation project, which are discussed below, as well as environmental, operational, safety, administrative and payout projects. Our 2006 capital expenditures are being funded with cash generated by our operations and by using our existing cash, as necessary.

There are four major capital projects which have been approved by our Board of Directors and which we expect to complete between 2006 and 2008. These projects include a $150.0 million crude unit and vacuum expansion with an associated $6.0 million metallurgy upgrade in order to run higher levels of high acid crude oils at our El Dorado Refinery and, at our Cheyenne Refinery, a $78.0 million coker expansion and revamp, a $7.5 million new amine unit and an $8.0 million crude fractionation project. The above amounts include estimated capitalized interest. At September 30, 2006, outstanding purchase commitments for the crude unit and vacuum tower expansion project at our El Dorado Refinery were $7.9 million. At our Cheyenne Refinery, the coker expansion project’s outstanding commitments at September 30, 2006 were $8.0 million.

The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a significantly greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project will likely be brought online in the spring of 2008 during the next planned turnaround for the crude/vacuum unit complex. The coker expansion at the Cheyenne Refinery, which is anticipated to be completed in 2007, will significantly decrease the amount of asphalt produced and increase the amount of higher margin products. The new amine unit at the Cheyenne Refinery is intended to result in improved alkylation unit reliability and provide a partial backup unit if the main amine unit is not operating. The project is expected to be substantially completed during the latter half of 2006, with start-up occurring in April 2007 in conjunction with a turnaround. The crude fractionation project at the Cheyenne Refinery will allow us to improve the recovery of diesel from the crude charged to the Refinery. We expect to fund these projects with existing cash and internally generated cash flow.

We are currently evaluating additional potential capital expansion projects which approximate $190 million in total spending. The potential Cheyenne Refinery project is a saturated gas plant. The El Dorado Refinery potential projects include a coker expansion, a catalytic cracker expansion and a gasoil hydrotreater revamp (which includes the necessary work to meet the low sulfur gasoline standard as discussed in Note 7 “Environmental” in the Notes to Condensed Consolidated Financial Statements). The Energy Tax Incentives Act of 2005 (the “Energy Act”) contains provisions that may affect certain of our financial or operational considerations in the future. The Energy Act includes a provision that allows a refiner to expense capital costs associated with expansion of refining capacity, as determined by the manufacture of liquid products other than asphalt and lube oil, in excess of 5% above previously produced volumes. The Energy Act also requires that refiners, importers and blenders ensure that renewable fuel (e.g., ethanol) is blended into the nation’s gasoline pool at escalating, prescribed rates beginning with a 4.0 billion gallon requirement in 2006 and increasing to 7.5 billion gallons in 2012. We are currently evaluating the potential consequence that these and other provisions of the Energy Act may have on our future operations.

CONTRACTUAL OBLIGATIONS

We entered into a definitive agreement with Rocky Mountain Pipeline System LLC (“Rocky Mountain”) on March 31, 2006 to support construction of a new crude pipeline from Guernsey, Wyoming to Rocky Mountain’s Fort Laramie, Wyoming tank farm and then to our Cheyenne Refinery. We made a ten-year commitment to ship 35,000 bpd based on a filed tariff on the new pipeline and will concurrently lease approximately 300,000 barrels of dedicated storage capacity in the Rocky Mountain tank farm. The pipeline, which is designed to transport 55,000 bpd of heavy crude and is expandable to 90,000 bpd, is expected to first transport crude oil in the second quarter of 2007, shortly after our planned Cheyenne Refinery coker expansion from 10,000 bpd to 13,500 bpd.

On February 22, 2006, our Compensation Committee of the Board of Directors approved the Executive Retiree Medical Benefit Plan. The Executive Retiree Medical Benefit Plan provides a post-retirement medical benefit for certain of our executive officers. Due to the plan design, the amount to be contributed by the retirees is expected to cover approximately the full cost of the plan.

In September 2006, we notified Enbridge Energy Company that we were exercising our option to increase our crude oil shipping commitment from 20,000 bpd to 38,000 bpd on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma (which we utilize to transport Canadian crude oil to our El Dorado Refinery). This increased commitment will begin in November 2006, and our Spearhead Pipeline tariff commitments will be approximately $2.3 million for the remainder of 2006, an average of $11.1 million for each of the years 2007 through 2010, an average of $12.1 million for each of the years 2011 through 2015 and $2.1 million in 2016.

Operating Data

The following tables set forth the refining operating statistical information on a consolidatedbasis and for each Refinery for the nine months and three months ended September 30, 2006 and 2005. The statistical information includes the following terms:

·   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 WTI crude oil priced at Cushing, Oklahoma.

·   Cheyenne Refinery light/heavy crude oil differential - the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil delivered to the Cheyenne Refinery.

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

·   El Dorado Refinery light/heavy crude oil differential - the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the Canadian heavy crude oil delivered to the El Dorado Refinery.

Consolidated:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		39,627		39,220		36,568		43,768
Intermediate crude		68,221		73,875		73,650		77,593
Heavy crude		46,011		38,259		47,789		40,055
Other feed and blend stocks		17,356		14,895		17,900		15,150
Total		171,215		166,249		175,907		176,566
Manufactured product yields (bpd)
Gasoline		80,877		80,449		79,298		85,827
Diesel and jet fuel		56,575		54,216		62,137		55,409
Asphalt		6,069		7,070		7,525		9,119
Other		22,596		19,682		20,529		20,962
Total		166,117		161,417		169,489		171,317
Total product sales (bpd)
Gasoline		89,965		87,711		88,122		94,426
Diesel and jet fuel		56,113		53,405		61,220		54,591
Asphalt		6,228		7,549		6,766		10,967
Other		18,767		17,991		18,695		17,212
Total		171,073		166,656		174,803		177,196
Refinery operating margin information (per sales barrel)
Refined products revenue	$	78.87	$	62.69	$	84.63	$	72.85
Raw material, freight and other costs (FIFO inventory accounting)		62.94		50.17		69.04		57.14
Refinery operating expenses, excluding depreciation		4.53		3.82		4.24		3.60
Depreciation, accretion and amortization		0.64		0.58		0.69		0.60
Average WTI crude oil priced at Cushing, OK	$	67.09	$	54.48	$	69.86	$	62.03
Average gasoline crack spread (per barrel)	$	16.14	$	12.67	$	18.38	$	18.11
Average diesel crack spread (per barrel)	$	21.73	$	14.60	$	26.21	$	18.38
Average sales price (per sales barrel)
Gasoline	$	85.24	$	68.92	$	91.06	$	81.10
Diesel and jet fuel		89.23		69.44		95.93		80.23
Asphalt		37.14		25.98		44.37		28.09
Other		31.25		27.67		31.81		32.74

Cheyenne Refinery:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		11,983		8,342		12,486		10,359
Heavy crude		33,207		38,260		35,932		40,055
Other feed and blend stocks		1,522		4,214		1,462		3,994
Total		46,712		50,816		49,880		54,408
Manufactured product yields (bpd)
Gasoline		18,401		20,517		19,438		20,863
Diesel		13,814		14,595		14,924		15,065
Asphalt		6,069		7,070		7,525		9,119
Other		6,404		6,635		5,971		7,242
Total		44,688		48,817		47,858		52,289
Total product sales (bpd)
Gasoline		26,499		26,690		27,035		27,563
Diesel		13,560		14,359		14,540		14,254
Asphalt		6,228		7,549		6,766		10,967
Other		4,773		6,514		4,372		6,346
Total		51,060		55,112		52,713		59,130
Refinery operating margin information (per sales barrel)
Refined products revenue	$	77.43	$	59.02	$	84.81	$	67.04
Raw material, freight and other costs (FIFO inventory accounting)		58.78		46.44		65.56		52.49
Refinery operating expenses, excluding depreciation		6.05		3.67		5.67		3.85
Depreciation, accretion and amortization		1.00		0.91		0.98		0.91
Average light/heavy crude oil differential (per barrel)	$	16.82	$	14.39	$	16.30	$	14.93
Average gasoline crack spread (per barrel)	$	18.12	$	13.42	$	23.12	$	19.04
Average diesel crack spread (per barrel)	$	24.74	$	16.52	$	28.77	$	21.11
Average sales price (per sales barrel)
Gasoline	$	88.82	$	70.19	$	97.51	$	82.92
Diesel		93.01		71.36		100.22		83.01
Asphalt		37.14		25.98		44.37		28.09
Other		22.48		24.40		17.54		29.43

El Dorado Refinery:
	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		27,644		30,878		24,082		33,409
Intermediate crude		68,221		73,875		73,650		77,593
Heavy crude		12,804		-		11,858		-
Other feed and blend stocks		15,834		10,681		16,438		11,156
Total		124,503		115,434		126,028		122,158
Manufactured product yields (bpd)
Gasoline		62,476		59,932		59,860		64,965
Diesel and jet fuel		42,762		39,621		47,213		40,344
Other		16,193		13,047		14,558		13,719
Total		121,431		112,600		121,631		119,028
Total product sales (bpd)
Gasoline		63,466		61,021		61,087		66,862
Diesel and jet fuel		42,553		39,046		46,680		40,337
Other		13,994		11,476		14,323		10,865
Total		120,013		111,543		122,090		118,064
Refinery operating margin information (per sales barrel)
Refined products revenue		79.49	$	64.49	$	84.55	$	75.77
Raw material, freight and other costs (FIFO inventory accounting)		64.71		52.02		70.54		59.47
Refinery operating expenses, excluding depreciation		3.89		3.90		3.62		3.48
Depreciation, accretion and amortization		0.49		0.42		0.56		0.44
WTI/WTS crude oil differential (per barrel)	$	5.34	$	4.16	$	4.69	$	3.13
Average light/heavy crude oil differential (per barrel)	$	19.91		-	$	12.83		-
Average gasoline crack spread (per barrel)	$	15.32	$	12.34	$	16.28	$	17.73
Average diesel crack spread (per barrel)	$	20.77	$	13.90	$	25.41	$	17.41
Average sales price (per sales barrel)
Gasoline	$	83.74	$	68.36	$	88.20	$	80.35
Diesel and jet fuel		88.03		68.73		94.60		79.24
Other		34.24		29.52		36.17		34.67

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Impact of Changing Prices. Our earnings and cash flows and 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 price at which we can sell gasoline and other refined products is 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, resulting in inventory gains when crude oil prices increase and inventory 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. Gains or losses on commodity derivative contracts accounted for as hedges are recognized in the Condensed Consolidated Statements of Income as “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” in the Condensed Consolidated Statements of Income at each period end. See Note 6 “Price Risk Management Activities” in the “Notes to Condensed Consolidated Financial Statements.”

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 6⅝% Senior Notes that were outstanding at September 30, 2006, and due 2011, have a fixed interest rate. Thus, our long-term debt is not exposed to cash flow risk from interest rate changes. Our long-term debt, however, is exposed to fair value risk. The estimated fair value of our 6⅝% Senior Notes at September 30, 2006 was $149.3 million.

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. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President, Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President, Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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

PART II - OTHER INFORMATION

ITEM 1.	Legal Proceedings - See Note 8 in the Notes to Condensed Consolidated Financial Statements.
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (c) Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased		Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2)
July 1, 2006 to July 31, 2006	-		-	-	11,636,148
August 1, 2006 to August 31, 2006	75,000	$	33.418	75,000	11,561,148
September 1, 2006 to September 30, 2006	1,600,000		27.857	1,600,000	9,961,148
Total third quarter	1,675,000	$	28.106	1,675,000	9,961,148

(1)

Shares were purchased under a stock repurchase program which authorizes repurchases up to thirty-two million shares. The program has no expiration date but may be terminated by the Board of Directors at any time. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases under this program, and as of September 30, 2006, $91.1 million (3,519,388 shares) of the $100 million had been utilized for repurchases. During early October 2006, an additional $8.8 million was utilized for share repurchases, thereby bringing the total amount repurchased to $99.9 million of the $100 million authorized. No shares were purchased during the periods shown other than through publicly-announced programs.

(2)

Shares shown in this column reflect authorized shares remaining which may be repurchased under the stock repurchase program referenced in note 1 above

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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 - Certification 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 - Controller (principal accounting officer)

Date: November 7, 2006