Frontier Oil (FTO) 10-Q 2006 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 August 1, 2006: 112,107,278

FRONTIER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 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
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited, in thousands except per share data)
	Six Months Ended						Three Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues:
Refined products	$	2,322,709		$	1,664,328		$	1,315,246		$	971,109
Other		4,850			592			120			1,171
		2,327,559			1,664,920			1,315,366			972,280
Costs and expenses:
Raw material, freight and other costs		1,829,095			1,351,051			995,608			792,728
Refinery operating expenses, excluding depreciation		143,515			115,175			74,611			53,824
Selling and general expenses, excluding depreciation		21,729			16,478			12,815			9,435
Depreciation, accretion and amortization		18,908			16,865			10,041			8,605
		2,013,247			1,499,569			1,093,075			864,592
Operating income		314,312			165,351			222,291			107,688
Interest expense and other financing costs		5,282			5,976			2,847			2,939
Interest and investment income		(6,456	)		(1,727	)		(3,910	)		(990	)
		(1,174	)		4,249			(1,063	)		1,949
Income before income taxes		315,486			161,102			223,354			105,739
Provision for income taxes		114,524			60,705			80,012			39,778
Net income	$	200,962		$	100,397		$	143,342		$	65,961
Basic earnings per share of common stock	$	1.79		$	0.92		$	1.28		$	0.60
Diluted earnings per share of common stock	$	1.78		$	0.89		$	1.26		$	0.58

The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, 2006 and December 31, 2005	2006			2005
	(in thousands except share data)
ASSETS
Current assets:
Cash, including cash equivalents of $335,437 and $345,641 in 2006 and 2005, respectively	$	350,014		$	356,065
Trade receivables, net of allowance of $500 in both years		161,530			122,051
Other receivables		5,274			7,584
Inventory of crude oil, products and other		371,783			247,621
Deferred tax assets		6,724			6,819
Other current assets		3,628			7,935
Total current assets		898,953			748,075
Property, plant and equipment, at cost:
Refineries and pipelines		736,130			657,612
Furniture, fixtures and other equipment		11,016			10,510
		747,146			668,122
Less - accumulated depreciation and amortization		256,457			238,184
		490,689			429,938
Deferred financing costs, net of amortization of $1,343 and $945 in 2006 and 2005, respectively		3,151			3,549
Commutation account		10,826			12,606
Prepaid insurance, net of amortization		2,725			3,331
Other intangible asset, net of amortization of $211 and $158 in 2006 and 2005, respectively		1,369			1,422
Other assets		5,735			2,588
Total assets	$	1,413,448		$	1,201,509
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	397,260		$	359,577
Accrued income taxes		52,952			20,395
Accrued turnaround cost		10,367			12,696
Accrued interest		2,624			2,485
Accrued El Dorado Refinery contingent earn-out payment		7,500			7,500
Accrued dividends		3,513			58,726
Accrued liabilities and other		37,292			24,432
Total current liabilities		511,508			485,811
Long-term debt		150,000			150,000
Long-term accrued turnaround cost		17,829			15,122
Post-retirement employee liabilities		27,086			24,497
Other long-term liabilities		15,013			10,293
Deferred income taxes		75,271			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, 134,145,116 and 133,629,396 shares issued in 2006 and 2005, respectively		57,793			57,780
Paid-in capital		168,421			157,910
Retained earnings		514,484			319,150
Accumulated other comprehensive income		27			27
Treasury stock, at cost, 22,037,838 and 20,930,828
shares in 2006 and 2005, respectively		(123,984	)		(86,870	)
Deferred compensation		-			(2,938	)
Total shareholders’ equity		616,741			445,059
Total liabilities and shareholders’ equity	$	1,413,448		$	1,201,509
The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	For the six months ended  June 30,
	2006			2005
	(in thousands)
Cash flows from operating activities:
Net income	$	200,962		$	100,397
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, accretion and amortization		18,908			16,865
Deferred income taxes		4,639			17,758
Stock-based compensation expense		7,599			696
Income tax benefits of stock compensation		4,992			7,138
Excess income tax benefits of share-based payment arrangements		(4,876	)		-
Deferred financing cost amortization		398			478
Amortization of long-term prepaid insurance		606			606
Long-term commutation account		1,780			2,293
Other		(2,851	)		427
Changes in working capital from operations		(70,100	)		(47,494	)
Net cash provided by operating activities		162,057			99,164
Cash flows from investing activities:
Additions to property, plant and equipment		(67,301	)		(53,017	)
El Dorado Refinery contingent earn-out payment		(7,500	)		(7,500	)
Net proceeds from insurance - involuntary conversion claim		-			2,142
Net cash used in investing activities		(74,801	)		(58,375	)
Cash flows from financing activities:
Proceeds from issuance of common stock		2,206			12,201
Purchase of treasury stock		(39,542	)		(5,986	)
Dividends paid		(60,841	)		(3,289	)
Excess income tax benefits of share-based payment arrangements		4,876			-
Debt issue costs and other		(6	)		(107	)
Net cash (used in) provided by financing activities		(93,307	)		2,819
(Decrease) increase in cash and cash equivalents		(6,051	)		43,608
Cash and cash equivalents, beginning of period		356,065			124,389
Cash and cash equivalents, end of period	$	350,014		$	167,997
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for interest, excluding capitalized interest	$	3,592		$	4,734
Cash paid during the period for income taxes		54,210			17,401
The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006

(Unaudited)

1.Financial Statement Presentation

The 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 June 30, 2006 and December 31, 2005, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. 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 have been included in the 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 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 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 report on Form 10-Q for the quarter ended March 31, 2006.

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.

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.

Earnings per share

Earnings per share (“EPS”) has been computed based on the weighted average number of common shares out-standing. No adjustments to income are used in the calculation of earnings per share. The basic and diluted average shares outstanding are as follows:

	Six Months Ended		Three Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Basic	112,290,201	109,212,662	112,390,030	109,959,338
Diluted	113,210,753	112,779,736	113,335,964	113,640,336

For the six months and three months ended June 30, 2006, 493,226 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS as the exercise prices were greater than the average market price for the period. For the six months and three months ended June 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 (as the exercise prices were all less than the average market price for the period).

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 a quarterly cash dividend of $0.03 per share was declared in June 2006 and paid in July 2006. The total cash required for the dividend declared in June 2006 was approximately $3.4 million and was reflected in “Accrued dividends” on the Consolidated Balance Sheet as of June 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 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 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 Financial Accounting Standards Board (“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 July 31, 2006, the final statement had not been issued. The Company is currently evaluating the potential effect that this proposed statement would have 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”. The interpretation is intended to reduce the significant diversity in practice associated with recognition and measurement of income taxes by establishing consistent criteria for evaluating uncertain tax positions in the areas of recognition, measurement, derecognition, financial statement classification and disclosure. This interpretation is for fiscal years beginning after December 15, 2006. The Company is currently evaluating this interpretation, but does not believe it will have a material effect on the Company’s financial statements.

On May 31, 2006, the FASB issued an updated proposed FASB Staff Position (“FSP”) to address 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 proposed FSP eliminates the accrual method of accounting for turnarounds and would require the adoption of the provisions as a change in accounting principle through retrospective application as described in SFAS 154 “Accounting Changes and Error Corrections.” If the proposed FSP is finalized it will have an effective date for fiscal years beginning after December 15, 2006. The Company currently accounts for turnarounds on the accrual method and is currently evaluating the provisions of this proposed FSP, which will require the Company to adopt an alternative method should the FSP be finalized.

The FASB issued an exposure draft on March 31, 2006, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which includes proposed amendments to FAS No. 87, “Employers’ Accounting for Pensions,” FAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” and FAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” The comment period for this exposure draft ended May 31, 2006. The objective of this project is to comprehensively reconsider guidance in order to improve the reporting of pensions and other postretirement benefit plans in the financial statements by making information more useful and transparent for investors, creditors, employees, retirees, donors, and other users. The first phase includes improving the reporting of employers’ obligations for pensions and other postretirement benefits by recognizing the over- or under-funded status of defined postretirement plans as an asset or a liability in the statement of financial position. Currently, the exposure draft does not change how plan assets and benefit obligations are measured under FAS No. 87 and FAS No. 106, or the basic approach for measuring the amount of annual net benefit cost reported in earnings. The FASB expects the effective date for the first phase to be for fiscal years ending after December 15, 2006. The Company is currently evaluating the provisions of this exposure draft.

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
	June 30,		December 31,
	2006		2005
	(in thousands)
Crude oil	$	152,719	$	97,766
Unfinished products		117,106		53,200
Finished products		82,435		75,790
Process chemicals		2,815		5,441
Repairs and maintenance supplies and other		16,708		15,424
	$	371,783	$	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 June 30, 2006, $44.0 million (1,844,388 shares) of the $100 million had been utilized for repurchases, of which $36.4 million (1,452,788 shares) was purchased in the six months ended June 30, 2006. An additional $1.9 million of cash was paid during early 2006 to settle purchases made at the end of 2005. Through June 30, 2006, 20,363,852 shares of common stock had been purchased under the stock repurchase program.

During the six months ended June 30, 2006, the Company received 44,068 shares ($1.2 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 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 six months ended June 30, 2006. As of June 30, 2006, the Company had 22,037,838 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 $2.9 million and $2.0 million for the six months and three months ended June 30, 2006, respectively. This incremental stock-based compensation reduced the Company’s net income by $1.8 million ($0.01 per diluted share) and $1.3 million ($0.02 per diluted share), for the six months and three months ended June 30, 2006, respectively. Cash provided by operating activities decreased $4.9 million and cash provided by financing activities increased by the same amount for the six months ended June 30, 2006, due to excess income tax benefits from stock-based payment arrangements.

Compensation costs and income tax benefits recognized in the consolidated statements of income for the six months ended and three months ended June 30, 2006 and 2005 are as follows:

	Six Months Ended June 30,				Three Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)				(in thousands)
Restricted shares and units	$	4,728	$	696	$	2,495	$	430
Stock options		958		-		722		-
Performance-based awards		1,823		-		1,823		-
Stock grant to retiring executive		90		-		-		-
Total compensation expense	$	7,599	$	696	$	5,040	$	430
Income tax benefit recognized
In the income statement	$	2,888	$	264	$	1,915	$	163

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 six months and three months ended June 30, 2005. The pro forma compensation expense for the six months and three months ended June 30, 2005 includes amortization for options granted in 2004, 2003 and 2002.

	Six Months Ended June 30, 2005			Three Months Ended June 30, 2005
	(in thousands, except per share amounts)
Net income as reported	$	100,397		$	65,961
Pro forma compensation expense, net of tax		(794	)		(316	)
Pro forma net income	$	99,603		$	65,645
Basic EPS:
As reported	$	0.92		$	0.60
Pro forma		0.91			0.60
Diluted EPS:
As reported	$	0.89		$	0.58
Pro forma		0.88			0.58

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 shall be reduced by 1.0 times the number of option or SAR shares granted. As of June 30, 2006, 8,631,568 shares were available to be awarded. 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 June 30, 2006 there was $31.3 million of total unrecognized compensation cost related to the Plan, including stock options, restricted stock, restricted stock units and performance-based awards, which are expected to be recognized over a weighted-average period of 2.54 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 six months ended June 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.

Stock option changes during the six months ended June 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		(495,600	)		4.4739
Expired		-			-
Outstanding at end of period		1,379,326			13.2593	$	26,401
Exercisable at endof period		848,600			4.2666	$	23,874
Available for grant at end of period		158,385
Weighted-average fair value of options granted during the period	$	9.615			-

The Company received $2.2 million of cash for stock options exercised during the six months ended June 30, 2006. The total intrinsic value of stock options exercised during the six months ended June 30, 2006 was $11.3 million. The Company realized $4.3 million of income tax benefits during the six months ended June 30, 2006, related to the exercises of stock options, nearly all of which was excess income tax benefits. 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.

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

Stock Options Outstanding at June 30, 2006
Number  Outstanding	Weighted- Average Remaining Contractual Life  (Years)	Exercise  Price	Exercisable
493,226	4.82	$ 29.3850	-
105,000	2.66	4.6625	67,500
739,100	1.64	4.1625	739,100
42,000	0.79	5.4625	42,000

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 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), $862,000 and $297,000 of compensation costs were recognized during the six months and three months ended June 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.

The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the six months ended June 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	(145,682)	14.783
Forfeited	-	- -
Nonvested at June 30, 2006	729,966	18.794

The total fair value of restricted shares and restricted stock units which vested during the six months ended June 30, 2006 was $4.1 million, and the Company realized $1.6 million of income tax benefits related to these vestings, of which $740,000 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. Based on net income through June 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.

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 June 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 new Medicare Part D benefits.

The following tables set forth the amounts recognized for these benefit plans in the Company’s consolidated statements of income for the six months and three months ended June 30, 2006 and 2005:

	Six Months Ended						Three Months Ended
	June 30,						June 30,
Pension benefits	2006			2005			2006			2005
Components of net periodic benefit cost:	(in thousands)
Service cost	$	-		$	-		$	-		$	-
Interest cost		272			316			136			158
Expected return on plan assets		(335	)		(240	)		(168	)		(120	)
Amortization of prior service cost		-			-			-			-
Recognized net actuarial loss		-			11			-			5
Net periodic benefit cost	$	(63	)	$	87		$	(32	)	$	43

	Six Months Ended				Three Months Ended
Post-retirement healthcare and	June 30,				June 30,
other benefits	2006		2005		2006		2005
Components of net periodic benefit cost:	(in thousands)
Service cost	$	627	$	431	$	314	$	216
Interest cost		1,128		730		564		365
Expected return on plan assets		-		-		-		-
Amortization of prior service cost		-		-		-		-
Recognized net actuarial loss		742		245		371		122
Net periodic benefit cost	$	2,497	$	1,406	$	1,249	$	703

As of June 30, 2006, the Company had contributed $540,000 to its cash balance pension plan in 2006 and expects to make additional contributions in the subsequent quarters 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 credit worthy 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 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 market value of open derivative contracts held directly by the Company is included on the Consolidated Balance Sheets in “Accrued liabilities and other” when the unrealized value is a loss ($1.7 million and $854,000 at June 30, 2006 and December 31, 2005, respectively) or in “Other current assets” when the unrealized value is a gain.

Mark-to-market activities

During the six months ended June 30, 2006 and 2005, the Company 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 Consolidated Statements of Income:

·   Crude purchases in-transit. As of June 30, 2006, the Company had no open derivative contracts to hedge in-transit Canadian crude oil costs. During the six months and three months ended June 30, 2006, the Company recorded $1.9 million and $518,000, respectively, in net gains on positions to hedge in-transit Canadian crude oil, mainly for the El Dorado Refinery. During the six months ended June 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 June 30, 2006, the Company had open derivative contracts on 697,000 barrels of crude oil to hedge crude oil, intermediate and finished product inventories. At June 30, 2006, these positions had net unrealized losses of $1.7 million. During the six months and three months ended June 30, 2006, the Company recorded $2.7 million and $3.0 million, respectively, in net losses, on these types of positions. During the six months and three months ended June 30, 2005, the Company recorded a $540,000 net gain and a $3.0 net loss, respectively, on these types of positions.

Hedging activities

During the six months ended June 30, 2006, the Company had the following derivatives which were appropriately designated and accounted for as hedges.

·   Crude purchases in-transit. During the six months ended June 30, 2006, the Company recorded $10.7 million in net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery, of which $12.9 million increased crude costs (“Raw material, freight and other costs”), $1.9 million increased the associated crude oil or crude oil intransit inventories and $4.1 million which increased income and was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of these hedges. During the three months ended June 30, 2006, the Company recorded $6.2 million in net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery, of which $12.4 million increased crude costs (“Raw material, freight and other costs”), $5.1 million decreased the associated crude oil or crude oil intransit inventories and $1.1 million increased income and was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of these hedges.

During the six months ended June 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 installation of certain air pollution control devices at the Refineries during the next several years. The Environmental Protection Agency (“EPA”) has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. The Company, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, has determined that Frontier will incur expenditures totaling approximately $9.2 million to further reduce emissions from the Refineries’ flare systems. At the Cheyenne Refinery, the Company has spent $4.7 million on the flare system, of which $223,000 was spent in 2004, $4.1 million in 2005 and the remaining $350,000 was incurred in the first quarter of 2006. At the El Dorado Refinery, the Company spent $1.2 million in prior years, and it estimates incurring $3.3 million during 2006, on the flare system. In addition to Frontier’s expenditures, Shell Oil Products US (“Shell”) is expected to contribute $5.0 million 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.

Although the Company has not received any formal notice of any violation of any of the following regulatory requirements, EPA Headquarters has recently stated its expectation that all domestic refineries, including both of the Company’s Refineries, enter into Consent Decrees to address all four of the EPA’s “marquee” 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.

Settlement negotiations with the EPA and state regulatory agencies regarding these items are underway. The Company now estimates that capital expenditures totaling approximately $30 million at each of its Refineries, in addition to the flare gas recovery projects discussed above, will be required prior to 2013 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.

The 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 $7.0 million in estimated costs to meet the final standard, and an additional $6.0 million for facilities to handle intermediate inventories, for the Cheyenne Refinery are expected to be incurred between 2008 and 2010. The total capital expenditures estimated as of June 30, 2006, for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $21.0 million, and are expected to be incurred between 2007 and 2009.

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 work to achieve the standard at both Refineries by early June. As of June 30, 2006, capital costs, including capitalized interest, for the ultra low sulfur diesel projects through June 30, 2006 (including 2004, 2005 and the first six months of 2006 expenditures) were $105.4 million (including $23.8 million paid in the first six months of 2006 and $3.8 million accrued as of June 30, 2006) at the El Dorado Refinery and $16.8 million (including $7.3 million paid in the first six months of 2006 and $3.3 million accrued as of June 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 the capability 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 and giving the Company the option of selling the 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.

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 June 30, 2006, the Company had a reserve included 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 June 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 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, with an additional $1.2 million of expense work, which was accrued as of June 30, 2006 and December 31, 2005. Although still in negotiation, the Company believes any penalty incurred will be largely offset by a supplemental environmental project proposed by the Company. However, an estimated remaining penalty amount of $250,000 was accrued as of December 31, 2005 and is included in “Accrued liabilities and other” on the Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005.

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 Consolidated Balance Sheet as of December 31, 2005 and in “Accrued liabilities and other” on the Consolidated Balance Sheet as of June 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, discovery is ongoing and a trial date has been set for October 30, 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 June 30, 2006, the commutation account balance was approximately $10.8 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 $2.4 million as of June 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. 

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 six months ended June 30, 2006, it is probable that a payment will be required in early 2007, and the entire $7.5 million was accrued as of June 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 June 30, 2006, amounts reserved for such contingencies were $23.2 million (including interest) and are included in “Accrued liabilities and other” on the Consolidated Balance Sheet. Interest expensed during the six months and three months ended June 30, 2006 for these contingencies was $623,000 and $379,000, respectively.

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 Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland. 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 June 30, 2006, FORC and Utexam had entered into certain commitments to purchase and sell crude oil in July 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 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 Six Months Ended June 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,322,709		$	-	$	-		$	2,322,709
Other		4			4,819			27		-			4,850
		4			2,327,528			27		-			2,327,559
Costs and expenses:
Raw material, freight and other costs		-			1,829,095			-		-			1,829,095
Refinery operating expenses, excluding depreciation		-			143,515			-		-			143,515
Selling and general expenses, excluding depreciation		11,964			9,765			-		-			21,729
Depreciation, accretion and amortization		43			19,111			-		(246	)		18,908
		12,007			2,001,486			-		(246	)		2,013,247
Operating income (loss)		(12,003	)		326,042			27		246			314,312
Interest expense and other financing costs		5,914			1,737			-		(2,369	)		5,282
Interest and investment income		(4,738	)		(1,718	)		-		-			(6,456	)
Equity in earnings of subsidiaries		(328,355	)		-			-		328,355			-
		(327,179	)		19			-		325,986			(1,174	)
Income before income taxes		315,176			326,023			27		(325,740	)		315,486
Provision for income taxes		114,214			117,771			-		(117,461	)		114,524
Net income	$	200,962		$	208,252		$	27	$	(208,279	)	$	200,962

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Six Months Ended June 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,664,328		$	-	$	-		$	1,664,328
Other		(8	)		562			38		-			592
		(8	)		1,664,890			38		-			1,664,920
Costs and expenses:
Raw material, freight and other costs		-			1,351,051			-		-			1,351,051
Refinery operating expenses, excluding depreciation		-			115,175			-		-			115,175
Selling and general expenses, excluding depreciation		10,033			6,445			-		-			16,478
Depreciation, accretion and amortization		32			17,111			-		(278	)		16,865
		10,065			1,489,782			-		(278	)		1,499,569
Operating income (loss)		(10,073	)		175,108			38		278			165,351
Interest expense and other financing costs		5,215			1,065			-		(304	)		5,976
Interest and investment income		(1,481	)		(246	)		-		-			(1,727	)
Equity in earnings of subsidiaries		(174,668	)		-			-		174,668			-
		(170,934	)		819			-		174,364			4,249
Income before income taxes		160,861			174,289			38		(174,086	)		161,102
Provision for income taxes		60,464			65,233			-		(64,992	)		60,705
Net income	$	100,397		$	109,056		$	38	$	(109,094	)	$	100,397

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,315,246		$	-		$	-		$	1,315,246
Other		-			135			(15	)		-			120
		-			1,315,381			(15	)		-			1,315,366
Costs and expenses:
Raw material, freight and other costs		-			995,608			-			-			995,608
Refinery operating expenses, excluding depreciation		-			74,611			-			-			74,611
Selling and general expenses, excluding depreciation		7,841			4,974			-			-			12,815
Depreciation, accretion and amortization		22			10,126			-			(107	)		10,041
		7,863			1,085,319			-			(107	)		1,093,075
Operating income (loss)		(7,863	)		230,062			(15	)		107			222,291
Interest expense and other financing costs		2,985			771			-			(909	)		2,847
Interest and investment income		(3,065	)		(845	)		-			-			(3,910	)
Equity in earnings of subsidiaries		(230,827	)		-			-			230,827			-
		(230,907	)		(74	)		-			229,918			(1,063	)
Income before income taxes		223,044			230,136			(15	)		(229,811	)		223,354
Provision for income taxes		79,702			82,356			-			(82,046	)		80,012
Net income	$	143,342		$	147,780		$	(15	)	$	(147,765	)	$	143,342

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Three Months Ended June 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	971,109		$	-	$	-		$	971,109
Other		(2	)		1,147			26		-			1,171
		(2	)		972,256			26		-			972,280
Costs and expenses:
Raw material, freight and other costs		-			792,728			-		-			792,728
Refinery operating expenses, excluding depreciation		-			53,824			-		-			53,824
Selling and general expenses, excluding depreciation		5,277			4,158			-		-			9,435
Depreciation and amortization		16			8,728			-		(139	)		8,605
		5,293			859,438			-		(139	)		864,592
Operating income (loss)		(5,295	)		112,818			26		139			107,688
Interest expense and other financing costs		2,606			565			-		(232	)		2,939
Interest and investment income		(828	)		(162	)		-		-			(990	)
Equity in earnings of subsidiaries		(112,592	)		-			-		112,592			-
		(110,814	)		403			-		112,360			1,949
Income before income taxes		105,519			112,415			26		(112,221	)		105,739
Provision for income taxes		39,558			42,074			-		(41,854	)		39,778
Net income	$	65,961		$	70,341		$	26	$	(70,367	)	$	65,961

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of June 30, 2006
(Unaudited, in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	217,151	$	132,863	$	-		$	-		$	350,014
Trade and other receivables		2,322		164,482		-			-			166,804
Receivable from affiliated companies		802		-		216			(1,018	)		-
Inventory		-		371,783		-			-			371,783
Deferred tax assets		6,724		10,837		-			(10,837	)		6,724
Other current assets		387		3,241		-			-			3,628
Total current assets		227,386		683,206		216			(11,855	)		898,953
Property, plant and equipment, at cost		1,266		752,236		-			(6,356	)		747,146
Less - accumulated depreciation and amortization		1,031		263,606		-			(8,180	)		256,457
		235		488,630		-			1,824			490,689
Deferred financing costs, net		2,534		617		-			-			3,151
Commutation account		10,826		-		-			-			10,826
Prepaid insurance, net		2,725		-		-			-			2,725
Other intangible asset, net		-		1,369		-			-			1,369
Other assets		2,808		2,927		-			-			5,735
Investment in subsidiaries		682,121		-		-			(682,121	)		-
Total assets	$	928,635	$	1,176,749	$	216		$	(692,152	)	$	1,413,448
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	800	$	396,460	$	-		$	-		$	397,260
Payable to affiliated companies		-		1,018		-			(1,018	)		-
Accrued turnaround cost		-		10,367		-			-			10,367
Accrued interest		2,484		140		-			-			2,624
Accrued income taxes		52,952		-		-			-			52,952
Accrued liabilities and other		27,683		20,353		269			-			48,305
Total current liabilities		83,919		428,338		269			(1,018	)		511,508
Long-term debt		150,000		-		-			-			150,000
Long-term accrued and other liabilities		2,704		57,224		-			-			59,928
Deferred income taxes		75,271		76,484		-			(76,484	)		75,271
Payable to affiliated companies		-		92,889		-			(92,889	)		-
Shareholders’ equity		616,741		521,814		(53	)		(521,761	)		616,741
Total liabilities and shareholders’ equity	$	928,635	$	1,176,749	$	216		$	(692,152	)	$	1,413,448

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 Six Months Ended June 30, 2006
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	200,962		$	208,252		$	27		$	(208,279	)	$	200,962
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(328,355	)		-			-			328,355			-
Depreciation, accretion and amortization		43			19,111			-			(246	)		18,908
Stock-based compensation expense		7,599			-			-			-			7,599
Income tax benefits of stock compensation		4,992			-			-			-			4,992
Excess income tax benefits of share-based payment arrangements		(4,876	)		-			-			-			(4,876	)
Deferred income taxes		4,639			-			-			-			4,639
Income taxes eliminated in consolidation		-			117,461			-			(117,461	)		-
Deferred financing cost amortization		241			157			-			-			398
Amortization of long-term prepaid insurance		606			-			-			-			606
Long-term commutation account		1,780			-			-			-			1,780
Other		(4	)		(2,847	)		-			-			(2,851	)
Changes in working capital from operations		54,046			(123,237	)		-			(909	)		(70,100	)
Net cash provided by (used in) operating activities		(58,327	)		218,897			27			1,460			162,057
Cash flows from investing activities:
Additions to property, plant and equipment		(31	)		(65,810	)		-			(1,460	)		(67,301	)
El Dorado Refinery contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Net cash used in investing activities		(31	)		(73,310	)		-			(1,460	)		(74,801	)
Cash flows from financing activities:
Proceeds from issuance of common stock		2,206			-			-			-			2,206
Purchase of treasury stock		(39,542	)		-			-			-			(39,542	)
Dividends paid		(60,841	)		-			-			-			(60,841	)
Excess income tax benefits of share-based payment arrangements		4,876			-			-			-			4,876
Other		-			(6	)		-			-			(6	)
Intercompany transactions		124,453			(124,426	)		(27	)		-			-
Net cash provided by (used in) financing activities		31,152			(124,432	)		(27	)		-			(93,307	)
(Decrease) increase in cash and cash equivalents		(27,206	)		21,155			-			-			(6,051	)
Cash and cash equivalents, beginning of period		244,357			111,708			-			-			356,065
Cash and cash equivalents, end of period	$	217,151		$	132,863		$	-		$	-		$	350,014

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Six Months Ended June 30, 2005
(Unaudited, in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	100,397		$	109,056		$	38		$	(109,094	)	$	100,397
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(174,668	)		-			-			174,668			-
Depreciation and amortization		32			17,111			-			(278	)		16,865
Stock-based compensation expense		696			-			-			-			696
Income tax benefits of stock compensation		7,138			-			-			-			7,138
Deferred income taxes		17,758			-			-			-			17,758
Income taxes eliminated in consolidation		-			64,992			-			(64,992	)		-
Deferred financing cost amortization		241			237			-			-			478
Amortization of long-term prepaid insurance		606			-			-			-			606
Long-term commutation account		2,293			-			-			-			2,293
Other		492			(65	)		-			-			427
Changes in working capital from operations		21,580			(69,074	)		-			-			(47,494	)
Net cash provided by (used in) operating activities		(23,435	)		122,257			38			304			99,164
Cash flows from investing activities:
Additions to property, plant and equipment		(51	)		(52,662	)		-			(304	)		(53,017	)
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		(51	)		(58,020	)		-			(304	)		(58,375	)
Cash flows from financing activities:
Proceeds from issuance of common stock		12,201			-			-			-			12,201
Purchase of treasury stock		(5,986	)		-			-			-			(5,986	)
Dividends paid		(3,289	)		-			-			-			(3,289	)
Debt issue costs and other		(100	)		(7	)		-			-			(107	)
Intercompany transactions		55,962			(55,924	)		(38	)		-			-
Net cash provided by (used in) financing activities		58,788			(55,931	)		(38	)		-			2,819
Decrease in cash and cash equivalents		35,302			8,306			-			-			43,608
Cash and cash equivalents, beginning of period		105,409			18,980			-			-			124,389
Cash and cash equivalents, end of period	$	140,711		$	27,286		$	-		$	-		$	167,997

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 the 2006 year at $61.04 per barrel, ended the first quarter of 2006 at $66.63 per barrel and ended the second quarter of 2006 at $73.93 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 six months and three months ended June 30, 2006, when compared to the same periods in 2005. During the first six 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 if indicated) have been revised to reflect the effect of the stock split.

Six months ended June 30, 2006 compared with the same period in 2005

Overview of Results

We had net income for the six months ended June 30, 2006 of nearly $201.0 million, or $1.78 per diluted share, doubling our net income of $100.4 million, or $0.89 per diluted share, earned in the same period in 2005. Our operating income of $314.3 million for the six months ended June 30, 2006 was an increase of nearly $149.0 million from the $165.4 million for the comparable period in 2005. The average diesel and gasoline crack spreads were higher during the first six months of 2006 ($15.07 and $19.50 per barrel, respectively) than in the first six months of 2005 ($9.95 and $12.71 per barrel, respectively), and both the light/heavy and WTI/WTS crude oil differentials increased for the six months ended June 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 $658.4 million, or 40%, from $1.7 billion to $2.3 billion for the six months ended June 30, 2006 compared to the same period in 2005. This increase was due to increased sales prices ($18.84 higher average per sales barrel), largely the result of higher crude oil prices and continued tight product availability, as well as higher sales volumes in 2006 (7,879 more bpd).

Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields increased 11,997 bpd at the El Dorado Refinery while decreasing 3,975 bpd at the Cheyenne Refinery for the six months ended June 30, 2006 as 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 than the comparable period in 2006.

Other revenues. Other revenues increased $4.3 million to $4.8 million for the six months ended June 30, 2006, compared to $592,000 for the same period in 2005, the sources of which were $3.3 million in net gains from derivative contracts in the six months ended June 30, 2006 compared to net derivative gains of $540,000 for the same period in 2005 and $1.6 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 $478.0 million, from $1.4 billion in the six months ended June 30, 2005, to $1.8 billion in the same period for 2006. The increase in raw material, freight and other costs was due to greater crude oil charges and higher average crude oil prices, offset by a larger FIFO inventory gain in the six months ended June 30, 2006, compared to the same period in 2005. We also benefited from improved crude oil differentials during the six months ended June 30, 2006 when compared to the same period in 2005. For the six months ended June 30, 2006, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $24.4 million after tax ($38.3 million pretax, comprised of an $18.0 million gain at the Cheyenne Refinery and a $20.3 million gain at the El Dorado Refinery). For the six months ended June 30, 2005, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $18.6 million after tax ($29.8 million pretax, comprised of $8.8 million at the Cheyenne Refinery and $21.0 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 $55.16 per sales barrel for the six months ended June 30, 2006 increased from $43.01 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 $17.09 per barrel in the six months ended June 30, 2006 compared to $14.13 per barrel in the same period in 2005.

The El Dorado Refinery raw material, freight and other costs of $61.66 per sales barrel for the six months ended June 30, 2006 increased from $47.88 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 $4.68 per barrel in the six-month period ended June 30, 2005, to $5.74 per barrel in the same period in 2006. For the six months ended June 30, 2006 the light/heavy crude oil differential averaged $25.22 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 $143.5 million in the six months ended June 30, 2006 compared to $115.2 million in the comparable period of 2005.

The Cheyenne Refinery operating expenses, excluding depreciation, were $56.8 million in the six months ended June 30, 2006 compared to $34.2 million in the comparable period of 2005. The primary areas of increased costs were in higher maintenance costs ($6.4 million, with $5.1 million of the costs related to a plant-wide steam outage in February 2006 and a butamer unit outage), environmental expenditures ($5.4 million, with an estimated $5.0 million related to a waste water pond clean up), turnaround accruals and excess costs ($5.4 million, primarily due to the alkylation plant spring turnaround in April 2006), increased usage and price of natural gas ($2.0 million), higher salaries ($1.0 million) and chemical and additive costs ($721,000).

The El Dorado Refinery operating expenses, excluding depreciation, were $86.7 million in the six months ended June 30, 2006, increasing from $81.0 million in the same six-month period of 2005. The primary areas of increased costs were in electricity ($2.4 million), chemicals and additives ($2.6 million), maintenance ($1.6 million, due to a fire on a distillate hydrotreater unit), lease and rental equipment ($692,000), insurance ($330,000), salaries and benefits ($296,000), non-maintenance contractors ($290,000), property taxes ($273,000) and environmental ($265,000). Reduced costs resulted from lower turnaround costs in excess of accruals ($2.9 million), consulting and legal ($483,000) and a net $511,000 reduction in natural gas costs, as reduced consumption more than offset an increase in price. Electricity costs were higher during the six months ended June 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. These increased electricity costs were partially offset by lower natural gas costs, as we did not purchase natural gas for the cogeneration facility.

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $5.2 million, or 32%, from $16.5 million for the six months ended June 30, 2005 to $21.7 million for the six months ended June 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 $6.6 million for the six months ended June 30, 2006 compared to $627,000 for the comparable period in 2005.

Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $2.0 million, or 12%, for the six months ended June 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 $5.3 million for the six months ended June 30, 2006 decreased $694,000, or 12%, from $6.0 million in the comparable period in 2005. The reduction was due to $2.5 million of interest cost being capitalized in the six months ended June 30, 2006, compared to only $634,000 of interest cost being capitalized in the six months ended June 30, 2005, offset by $623,000 in accrued interest expense for income tax contingencies in 2006 (none in 2005) and $673,000 in facility costs and financing expenses related to the Utexam Master Crude Oil Purchase and Sale Contract (“Utexam Arrangement”) (see Note 10 in the “Notes to Interim Consolidated Financial Statements”). Average debt outstanding decreased to $153.1 million during the six months ended June 30, 2006 from $170.0 million for the same period in 2005 (excluding amounts payable to Utexam under the Utexam Arrangement during the 2006 period in which it is being utilized).

Interest and investment income. Interest and investment income increased $4.7 million from $1.7 million in the six months ended June 30, 2005, to $6.5 million in the six months ended June 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 six months ended June 30, 2006 was $114.5 million on pretax income of $315.5 million (or 36.3%) reflecting a benefit of the “American Jobs Creation Act of 2004” (the “Act”) production activities deduction for manufacturers. The income tax provision for the six months ended June 30, 2006 also includes the benefit of a $4.0 million credit for production of ultra low sulfur diesel fuel. Our current estimated effective tax rate excluding both of these benefits is 37.92%. Our provision for income taxes for the six months ended June 30, 2005, was $60.7 million on pretax income of $161.1 million (or 37.7%) reflecting a benefit of the production activities deduction for manufacturers.

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

Overview of Results

We had net income for the three months ended June 30, 2006 of $143.3 million, or $1.26 per diluted share, more than double our net income of nearly $66.0 million, or $0.58 per diluted share, in the same period in 2005. Our operating income of $222.3 million for the three months ended June 30, 2006 was an increase of $114.6 million from the $107.7 million of operating income for the comparable period in 2005. The average diesel and gasoline crack spreads were higher during the second quarter of 2006 ($20.92 and $23.49 per barrel, respectively) than in the second quarter of 2005 ($12.50 and $15.51 per barrel, respectively), and both the light/heavy and WTI/WTS crude oil differentials increased for the quarter ended June 30, 2006 compared to the same period in 2005.

Specific Variances

Refined product revenues. Refined product revenues increased $344.1 million, or 35%, from $971.1 million to $1.3 billion for the three months ended June 30, 2006 compared to the same period in 2005. This increase was due to increased sales prices ($22.77 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 (2,872 less bpd).

Manufactured product yields. Yields increased 9,488 bpd at the El Dorado Refinery and decreased 8,736 bpd at the Cheyenne Refinery for the three months ended June30, 2006 compared to same period in 2005. A Cheyenne Refinery turnaround in April 2006 caused yields to be lower than in the comparable period in 2005 and, an El Dorado Refinery turnaround in 2005 caused yields to be lower than the comparable period in 2006.

Other revenues. Other revenues decreased nearly $1.1 million to $120,000 for the three months ended June 30, 2006, compared to $1.2 million for the same period in 2005, the source of which was $1.4 million in net losses from derivative contracts in the three months ended June 30, 2006 compared to net derivative gains of $1.1 million for the same period in 2005, offset by $1.6 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 increased by $202.9 million, from $792.7 million in the three months ended June 30, 2005, to $995.6 million in the same period for 2006. The increase in raw material, freight and other costs was due to higher average crude prices offset by a significant FIFO inventory gain in the three months ended June 30, 2006, compared to a small net FIFO inventory loss in the three months ended June 30, 2005. We also benefited from improved crude oil differentials during the three months ended June 30, 2006 compared to the same period in 2005. For the three months ended June 30, 2006, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $23.6 million after tax ($38.3 million pretax, comprised of $18.1 million at the Cheyenne Refinery and $20.2 million at the El Dorado Refinery). For the three months ended June 30, 2005, we realized an increase in raw material, freight and other costs as a result of net inventory losses of approximately $988,000 after tax ($1.6 million pretax, comprised of a $2.3 million gain at the Cheyenne Refinery offset by a $3.9 million loss at the El Dorado Refinery).

The Cheyenne Refinery raw material, freight and other costs of $60.15 per sales barrel for the three months ended June 30, 2006 increased from $44.63 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 $15.19 per barrel in the three months ended June 30, 2006 compared to $14.15 per barrel in the same period in 2005.

The El Dorado Refinery raw material, freight and other costs of $64.18 per sales barrel for the three months ended June 30, 2006 increased from $51.52 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 $4.67 per barrel in the three-month period ended June 30, 2005, to $5.04 per barrel in the same period in 2006. For the three months ended June 30, 2006, the light/heavy crude oil differential averaged $25.41 per barrel.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, were $74.6 million in the three months ended June 30, 2006 compared to $53.8 million in the comparable period of 2005.

The Cheyenne Refinery operating expenses, excluding depreciation, were nearly $33.0 million in the three months ended June 30, 2006 compared to $16.9 million in the comparable period of 2005. The primary areas of increase were higher maintenance costs ($3.9 million, including $2.9 for continued work related to the plant-wide steam outage which occurred in February 2006), turnaround costs in excess of accruals and turnaround accruals ($5.1 million, primarily related to the alkylation plant spring turnaround), and environmental expenditures and accruals ($5.2 million, with an estimated $5.0 million related to a waste water pond clean up).

The El Dorado Refinery operating expenses, excluding depreciation, were $41.6 million in the three months ended June 30, 2006, increasing from $36.9 million in the same three-month period of 2005. The primary areas of increased costs were maintenance ($2.0 million, primarily from a fire on a distillate hydrotreater unit), chemicals and additives ($1.1 million), salaries and benefits ($778,000), electricity ($572,000), property taxes ($236,000) and lease and rental equipment ($214,000). Reduced costs resulted from lower turnaround accrual and turnaround costs in excess of accruals ($769,000).

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $3.4 million, or 36%, from $9.4 million for the three months ended June 30, 2005 to $12.8 million for the three months ended June 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 $4.4 million for the three months ended June 30, 2006 compared to $392,000 for the comparable period in 2005.

Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $1.4 million, or 17%, for the three months ended June 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 $2.8 million for the three months ended June 30, 2006 decreased $92,000, or 3%, from $2.9 million in the comparable period in 2005. The reduction was due to $936,000 of interest cost being capitalized in the three months ended June 30, 2006, compared to only $434,000 of interest cost being capitalized in the three months ended June 30, 2005, offset by $273,000 in facility and financing costs related to the Utexam Arrangement (see Note 10 in the “Notes to Interim Consolidated Financial Statements”) and $379,000 in accrued interest on income tax contingencies during the three months ended June 30, 2006. Average debt outstanding decreased to $150.0 million during the three months ended June 30, 2006 from $172.3 million for the same period in 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 $2.9 million from $990,000 in the three months ended June 30, 2005, to $3.9 million in the three months ended June 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 June 30, 2006 was $80.0 million on pretax income of $223.4 million (or 35.8%) reflecting the benefit of the Act’s production activities deduction for manufacturers. The income tax provision for the three months ended June 30, 2006 also includes the benefit of a $4.0 million credit for the production of ultra low sulfur diesel fuel. The provision for income taxes for the three months ended June 30, 2005, was $39.8 million on pretax income of $105.7 million (or 37.6%) reflecting the benefit of the production activities deduction for manufacturers.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities. Net cash provided by operating activities was $162.1 million for the six months ended June 30, 2006 compared to net cash provided by operating activities of $99.2 million during the six months ended June 30, 2005. Improved results of operations increased cash flow significantly but were offset by higher uses of cash for working capital.

Working capital changes used a total of $70.1 million of cash in the six months ended June 30, 2006 while using $47.5 million of cash in the comparable period in 2005. The most significant uses of cash for working capital changes during the six-month period of 2006 were an increase in inventories of $124.2 million and an increase in receivables of $37.0 million compared to an increase in inventories of $43.4 million and an increase in receivables of $64.6 million in the 2005 comparable period. The increase in inventories during the six months ended June 30, 2006, was due to a significant increase in crude oil in-transit inventories, primarily the Canadian crude in-transit for the El Dorado Refinery, as well as other increased inventory levels and higher prices. The significant sources of cash for working capital changes during the six months ended June 30, 2006 included an increase in accrued liabilities of $50.8 million and increases in crude and other payables of $35.9 million, compared to an increase in accrued liabilities of $5.5 million and increases in crude and other payables of $54.2 million in the comparable period in 2005. The increase in accrued liabilities during the six months ended 2006 was primarily due to an increase in accrued income taxes. The increase in crude and other payables in both years was due to increased crude payables.

At June 30, 2006, we had $350.0 million of cash and cash equivalents, working capital of $387.5 million and $162.0 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 six months of 2006 were $67.3 million, which included approximately $41.6 million for the El Dorado Refinery and $25.6 million for the Cheyenne Refinery. The $41.6 million of capital expenditures for our El Dorado Refinery included $23.8 million for the ultra low sulfur diesel project and $9.7 million for the crude unit and vacuum tower expansion as well as operational, payout, safety, administrative, environmental and optimization projects. The $25.6 million of capital expenditures for our Cheyenne Refinery included approximately $7.3 million for the ultra low sulfur diesel project and $7.4 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. 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 six months ended June 30, 2006, it is probable that a payment will be required in early 2007, and $7.5 million was accrued as of June 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. Payments totaling $60.8 million in dividends during the six months ended June 30, 2006 were our largest use of cash for financing activities. We also increased our treasury stock by 44,068 shares ($1.2 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 six months of 2006. During the six months ended June 30, 2006, we also used $39.5 million to repurchase stock, of which $1.9 million was for the settlement of stock purchased in December 2005 and $36.4 million was for the purchase of 1,452,788 shares in the first six months of 2006 (both of which were made under the authorization of the stock repurchase program discussed below).

We have authorization from our Board of Directors to repurchase up to 32 million shares of our common stock. Through June 30, 2006, we had purchased 20,363,852 shares of common stock under this stock repurchase program and had authorization remaining under this program to purchase an additional 11,636,148 shares. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases under this program. We may repurchase our common stock under this program from time to time in the open market depending on price, market conditions and other factors. Through of June 30, 2006, $44.0 million (1,844,388 shares) of the $100 million had been utilized for repurchases.

During the six months ended June 30, 2006, we issued 495,600 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $2.2 million in cash.

As of June 30, 2006, we had $150.0 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $63.0 million of letters of credit outstanding under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of June 30, 2006. We had shareholders’ equity of $616.7 million as of June 30, 2006. 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.”

Our Board of Directors (“Board”) 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, and a quarterly cash dividend of $0.03 per share was declared in June 2006 and paid in July 2006. The total cash required for the dividend declared in June 2006 was approximately $3.4 million and was included in “Accrued dividends” on the June 30, 2006 Consolidated Balance Sheet.

We announced on April 27, 2006 that our Board 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 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.

Future capital expenditures. Capital expenditures aggregating approximately $203 million are currently planned for 2006 (including the $67.3 million paid during the first six months), and include $98 million at our El Dorado Refinery, $104 million at our Cheyenne Refinery, and $700,000 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 $28.6 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 $104 million of planned capital expenditures for our Cheyenne Refinery includes approximately $10.6 million for the ultra low sulfur diesel project, $51 million for the coker expansion, $7.5 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 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 project in order to run higher levels of high acid crude oils at our El Dorado Refinery and, at our Cheyenne Refinery, a $78.5 million coker expansion and revamp, a $7.5 million new amine unit and an $8.2 million crude fractionation project. The above amounts include estimated capitalized interest. At June 30, 2006, outstanding purchase commitments for the crude unit and vacuum tower expansion project at our El Dorado Refinery were $20.8 million. At our Cheyenne Refinery, the coker expansion project’s outstanding commitments at June 30, 2006 were $6.4 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 light products such as gasoline and diesel. The new amine unit at the Cheyenne Refinery is intended to result in improved alkylation unit reliability and provide a 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 replace light crude purchases with less expensive heavier crude oil while maintaining gasoline and diesel yields. We expect to fund these projects with existing cash and internally generated cash flow.

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 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.

Operating Data

The following tables set forth the refining operating statistical information on a consolidatedbasis and for each Refinery for the six months and three months ended June 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:
	Six Months Ended				Three Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		41,181		36,909		42,049		40,206
Intermediate crude		65,461		71,985		62,654		75,668
Heavy crude		45,107		37,346		49,269		40,478
Other feed and blend stocks		17,079		14,765		17,454		14,964
Total		168,828		161,005		171,426		171,316
Manufactured product yields (bpd)
Gasoline		81,680		77,715		79,817		88,306
Diesel and jet fuel		53,748		53,610		54,857		58,060
Asphalt		5,329		6,029		5,385		7,918
Other		23,647		19,031		26,455		11,480
Total		164,404		156,385		166,514		165,764
Total product sales (bpd)
Gasoline		90,902		84,297		91,721		95,057
Diesel and jet fuel		53,517		52,802		56,167		56,087
Asphalt		5,954		5,811		5,417		7,101
Other		18,803		18,387		20,337		18,269
Total		169,176		161,297		173,642		176,514
Refinery operating margin information (per sales barrel)
Refined products revenue	$	75.85	$	57.01	$	83.23	$	60.46
Raw material, freight and other costs (FIFO inventory accounting)		59.73		46.28		63.01		49.35
Refinery operating expenses, excluding depreciation		4.69		3.95		4.72		3.35
Depreciation, accretion and amortization		0.61		0.57		0.63		0.53
Average WTI crude oil priced at Cushing, OK	$	65.71	$	50.71	$	69.08	$	51.89
Average gasoline crack spread (per barrel)	$	15.07	$	9.95	$	20.92	$	12.50
Average diesel crack spread (per barrel)	$	19.50	$	12.71	$	23.49	$	15.51
Average sales price (per sales barrel)
Gasoline	$	82.37	$	61.98	$	91.57	$	65.47
Diesel and jet fuel		85.33		63.77		92.17		67.57
Asphalt		32.97		23.95		38.76		25.75
Other		30.96		25.25		32.80		25.99

Cheyenne Refinery:
	Six Months Ended				Three Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		11,727		7,317		11,047		7,565
Heavy crude		31,822		37,347		31,446		40,478
Other feed and blend stocks		1,553		4,326		581		3,691
Total		45,102		48,990		43,074		51,734
Manufactured product yields (bpd)
Gasoline		17,874		20,341		16,165		20,967
Diesel		13,250		14,356		12,169		15,330
Asphalt		5,329		6,029		5,385		7,918
Other		6,624		6,326		7,144		5,384
Total		43,077		47,052		40,863		49,599
Total product sales (bpd)
Gasoline		26,227		26,246		26,622		26,388
Diesel		13,062		14,412		13,341		15,384
Asphalt		5,954		5,811		5,417		7,101
Other		4,977		6,600		5,163		6,720
Total		50,220		53,069		50,543		55,593
Refinery operating margin information (per sales barrel)
Refined products revenue	$	73.49	$	54.49	$	82.40	$	57.82
Raw material, freight and other costs (FIFO inventory accounting)		55.16		43.01		60.15		44.63
Refinery operating expenses, excluding depreciation		6.25		3.56		7.17		3.34
Depreciation, accretion and amortization		1.01		0.92		1.02		0.88
Average light/heavy crude oil differential (per barrel)	$	17.09	$	14.13	$	15.19	$	14.15
Average gasoline crack spread (per barrel)	$	15.63	$	10.62	$	21.93	$	14.36
Average diesel crack spread (per barrel)	$	22.72	$	14.22	$	27.17	$	17.14
Average sales price (per sales barrel)
Gasoline	$	84.27	$	63.39	$	94.43	$	68.05
Diesel		88.93		65.50		96.72		69.57
Asphalt		32.97		23.95		38.76		25.75
Other		24.68		21.94		29.18		24.68

El Dorado Refinery:
	Six Months Ended				Three Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Charges (bpd)
Light crude		29,454		29,592		31,001		32,640
Intermediate crude		65,461		71,985		62,654		75,668
Heavy crude		13,284		-		17,824		-
Other feed and blend stocks		15,526		10,439		16,874		11,273
Total		123,725		112,016		128,353		119,581
Manufactured product yields (bpd)
Gasoline		63,806		57,373		63,652		67,339
Diesel and jet fuel		40,499		39,254		42,688		42,729
Other		17,024		12,705		19,312		6,096
Total		121,329		109,332		125,652		116,164
Total product sales (bpd)
Gasoline		64,675		58,052		65,099		68,669
Diesel and jet fuel		40,455		38,389		42,825		40,703
Other		13,826		11,787		15,174		11,548
Total		118,956		108,228		123,098		120,920
Refinery operating margin information (per sales barrel)
Refined products revenue	$	76.85	$	58.24	$	83.58	$	61.67
Raw material, freight and other costs (FIFO inventory accounting)		61.66		47.88		64.18		51.52
Refinery operating expenses, excluding depreciation		4.03		4.13		3.71		3.36
Depreciation, accretion and amortization		0.45		0.41		0.47		0.37
WTI/WTS crude oil differential (per barrel)	$	5.74	$	4.68	$	5.04	$	4.67
Average light/heavy crude oil differential (per barrel)	$	25.22		-	$	25.41		-
Average gasoline crack spread (per barrel)	$	14.84	$	9.65	$	20.50	$	11.79
Average diesel crack spread (per barrel)	$	18.46	$	12.15	$	22.34	$	14.89
Average sales price (per sales barrel)
Gasoline	$	81.60	$	61.34	$	90.40	$	64.48
Diesel and jet fuel		84.17		63.12		90.76		66.81
Other		33.23		27.11		34.04		26.75

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Impact of Changing Prices. Our earnings and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depend on, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The 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 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 Consolidated Statements of Income at each period end. See Note 6 “Price Risk Management Activities” in the “Notes to Interim 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 June 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 June 30, 2006 was $143.3 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 Interim 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)
April 1, 2006 to
April 30, 2006	-	-	-	12,781,948
May 1, 2006 to
May 31, 2006	100,000	$27.727	100,000	12,681,948
June 1, 2006 to
June 30, 2006	1,045,800	26.019	1,045,800	11,636,148
Total second quarter	1,145,800	$26.168	1,145,800	11,636,148

(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 June 30, 2006, $44.0 million (1,844,388 shares) of the $100 million had been utilized for repurchases. We may repurchase our common stock under this program from time to time in the open market depending on price, market conditions and other factors. 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 - The annual meeting of the Company was held on April 26, 2006, with 52,085,172 of the Company’s shares present or represented by proxy at the meeting. This represented nearly 93% of the Company’s shares outstanding as of the record date for the meeting. The stockholders of the Company took the following actions:
	1.	Election of Directors: Elected the following seven directors for terms of office expiring at the annual meeting of stockholders in 2007:

Name	For	Withheld
James R. Gibbs	50,715,914	1,369,258
Douglas Y. Bech	50,617,359	1,467,613
G. Clyde Buck	51,690,971	394,201
T. Michael Dossey	51,686,674	398,498
James H. Lee	51,220,866	864,603
Paul B. Loyd, Jr.	30,069,448	22,015,724
Michael E. Rose	51,217,365	867,806

2.	Ratified the Frontier Oil Corporation Omnibus Incentive Compensation Plan. The vote was 34,235,579 for, 8,840,115 against, 224,920 abstentions and no broker non-votes.
3.	Ratified the appointment of Deloitte & Touche LLP as the Company’s auditors for the year ending December 31, 2006. The vote was 51,707,138 for, 314,676 against, 63,368 abstentions and no broker non-votes.
At a special meeting of the Company held on June 9, 2006, the shareholders authorized an amendment to the Company’s Restated Articles of Incorporation, as amended, to increase the number of authorized shares of common stock from 90,000,000 to 180,000,000. The number of votes cast for, against and withheld were 45,320,631, 225,267 and 59,171, respectively. There were no broker non-votes.

ITEM 6

Exhibits - 10.1 - Form of First Amendment to the Restricted Stock Unit Agreement (*) 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.

* Management contract or compensatory plan or arrangement

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: August 7, 2006