UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

TESORO CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		95-0862768
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

300 Concord Plaza Drive, San Antonio, Texas 78216-6999
(Address of principal executive offices) (Zip Code)

210-828-8484
(Registrant’s telephone number, including area code)

     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 o

     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 o            Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 68,248,696 shares of the registrant’s Common Stock outstanding at August 1, 2006.

 

 

		Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets – June 30, 2006 and December 31, 2005			3
Condensed Statements of Consolidated Operations – Three Months and Six Months Ended June 30, 2006 and 2005			4
Condensed Statements of Consolidated Cash Flows – Six Months Ended June 30, 2006 and 2005			5
Notes to Condensed Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			17
Item 3. Quantitative and Qualitative Disclosures About Market Risk			31
Item 4. Controls and Procedures			32
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			33
Item 4. Submission of Matters to a Vote of Security Holders			34
Item 5. Other Information			34
Item 6. Exhibits			35
SIGNATURES			36
EXHIBIT INDEX			37
First Amendment to the 2006 Long-Term Incentive Plan
Amendment No. 3 to the Third Amended and Restated Credit Agreement
Certification by CEO Pursuant to Section 302
Certification by CFO Pursuant to Section 302
Certification by CEO Pursuant to Section 906
Certification by CFO Pursuant to Section 906

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

		June 30,				December 31,
		2006				2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	620			$	440
Receivables, less allowance for doubtful accounts			931				718
Inventories			988				953
Prepayments and other			112				104
Total Current Assets			2,651				2,215
PROPERTY, PLANT AND EQUIPMENT
Refining			2,985				2,850
Retail			207				223
Corporate and other			112				107
			3,304				3,180
Less accumulated depreciation and amortization			(790	)			(713	)
Net Property, Plant and Equipment			2,514				2,467
OTHER NONCURRENT ASSETS
Goodwill			89				89
Acquired intangibles, net			116				119
Other, net			230				207
Total Other Noncurrent Assets			435				415
Total Assets		$	5,600			$	5,097
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,293			$	1,171
Accrued liabilities			346				328
Current maturities of debt			3				3
Total Current Liabilities			1,642				1,502
DEFERRED INCOME TAXES			432				389
OTHER LIABILITIES			290				275
DEBT			1,039				1,044
COMMITMENTS AND CONTINGENCIES (Note I)
STOCKHOLDERS’ EQUITY
Common stock, par value $0.162/3; authorized 200,000,000 shares; 71,589,637 shares issued (70,850,681 in 2005)			12				12
Additional paid-in capital			829				794
Retained earnings			1,457				1,102
Treasury stock, 2,811,235 common shares (1,548,568 in 2005), at cost			(99	)			(19	)
Accumulated other comprehensive loss			(2	)			(2	)
Total Stockholders’ Equity			2,197				1,887
Total Liabilities and Stockholders’ Equity		$	5,600			$	5,097

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

TESORO CORPORATION

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
REVENUES		$	4,929			$	4,033			$	8,806			$	7,204
COSTS AND EXPENSES:
Costs of sales and operating expenses			4,276				3,601				7,965				6,598
Selling, general and administrative expenses			45				48				85				102
Depreciation and amortization			60				43				120				84
Loss on asset disposals and impairments			5				4				12				5
OPERATING INCOME			543				337				624				415
Interest and financing costs			(21	)			(32	)			(41	)			(64	)
Interest income and other			7				—				17				1
EARNINGS BEFORE INCOME TAXES			529				305				600				352
Income tax provision			203				121				231				140
NET EARNINGS		$	326			$	184			$	369			$	212
NET EARNINGS PER SHARE:
Basic		$	4.79			$	2.69			$	5.40			$	3.13
Diluted		$	4.66			$	2.62			$	5.25			$	3.02
WEIGHTED AVERAGE COMMON SHARES:
Basic			68.0				68.3				68.3				67.5
Diluted			69.9				70.1				70.3				70.1
DIVIDENDS PER SHARE		$	0.10			$	0.05			$	0.20			$	0.05

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

TESORO CORPORATION

		Six Months Ended
		June 30,
		2006				2005
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings		$	369			$	212
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation and amortization			120				84
Amortization of debt issuance costs and discounts			7				9
Write-off of unamortized debt issuance costs			—				2
Loss on asset disposals and impairments			12				5
Stock-based compensation			14				15
Deferred income taxes			43				50
Excess tax benefits from stock-based compensation arrangements			(15	)			(20	)
Other changes in non-current assets and liabilities			(39	)			(31	)
Changes in current assets and current liabilities:
Receivables			(208	)			(166	)
Inventories			(36	)			(239	)
Prepayments and other			(3	)			(21	)
Accounts payable and accrued liabilities			145				185
Net cash from operating activities			409				85
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures			(145	)			(116	)
Other			2				—
Net cash used in investing activities			(143	)			(116	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repurchase of common stock			(86	)			—
Dividend payments			(14	)			(3	)
Repayments of debt			(10	)			(98	)
Proceeds from stock options exercised			10				26
Excess tax benefits from stock-based compensation arrangements			15				20
Financing costs and other			(1	)			(3	)
Net cash used in financing activities			(86	)			(58	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			180				(89	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			440				185
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	620			$	96
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of capitalized interest		$	26			$	48
Income taxes paid		$	85			$	135

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

TESORO CORPORATION

NOTE A – BASIS OF PRESENTATION

The interim condensed consolidated financial statements and notes thereto of Tesoro Corporation (“Tesoro”) and its subsidiaries have been prepared by management without audit according to the rules and regulations of the SEC. The accompanying financial statements reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of results for the periods presented. Such adjustments are of a normal recurring nature. The consolidated balance sheet at December 31, 2005 has been condensed from the audited consolidated financial statements at that date. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to the SEC’s rules and regulations. However, management believes that the disclosures presented herein are adequate to make the information not misleading. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2005.

We prepare our condensed consolidated financial statements in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods. We review our estimates on an ongoing basis, based on currently available information. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates. The results of operations for any interim period are not necessarily indicative of results for the full year.

NOTE B – EARNINGS PER SHARE

We compute basic earnings per share by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effects of potentially dilutive shares, principally common stock options and unvested restricted stock outstanding during the period. Earnings per share calculations are presented below (in millions except per share amounts):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Basic:
Net earnings		$	326			$	184			$	369			$	212
Weighted average common shares outstanding			68.0				68.3				68.3				67.5
Basic Earnings Per Share		$	4.79			$	2.69			$	5.40			$	3.13
Diluted:
Net earnings		$	326			$	184			$	369			$	212
Weighted average common shares outstanding			68.0				68.3				68.3				67.5
Dilutive effect of stock options and unvested restricted stock			1.9				1.8				2.0				2.6
Total diluted shares			69.9				70.1				70.3				70.1
Diluted Earnings Per Share		$	4.66			$	2.62			$	5.25			$	3.02

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE C – OPERATING SEGMENTS

We are an independent refiner and marketer of petroleum products and derive revenues from two operating segments, refining and retail. We evaluate the performance of our segments and allocate resources based primarily on segment operating income. Segment operating income includes those revenues and expenses that are directly attributable to management of the respective segment. Intersegment sales from refining to retail are made at prevailing market rates. Income taxes, interest and financing costs, interest income and other, and corporate general and administrative expenses are excluded from segment operating income. Identifiable assets are those assets utilized by the segment. Corporate and unallocated costs are principally general and administrative expenses. Corporate assets are principally cash and other assets that are not associated with a specific operating segment. Segment information is as follows (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Revenues
Refining:
Refined products		$	4,803			$	3,824			$	8,530			$	6,777
Crude oil resales and other (a)			76				156				179				331
Retail:
Fuel			295				238				508				435
Merchandise and other			39				36				71				67
Intersegment Sales from Refining to Retail			(284	)			(221	)			(482	)			(406	)
Total Revenues		$	4,929			$	4,033			$	8,806			$	7,204
Segment Operating Income (Loss)
Refining		$	593			$	381			$	718			$	513
Retail (b)			(12	)			(9	)			(24	)			(20	)
Total Segment Operating Income			581				372				694				493
Corporate and Unallocated Costs			(38	)			(35	)			(70	)			(78	)
Operating Income			543				337				624				415
Interest and Financing Costs			(21	)			(32	)			(41	)			(64	)
Interest Income and Other			7				—				17				1
Earnings Before Income Taxes		$	529			$	305			$	600			$	352
Depreciation and Amortization
Refining		$	54			$	37			$	108			$	72
Retail			4				4				8				8
Corporate			2				2				4				4
Total Depreciation and Amortization		$	60			$	43			$	120			$	84
Capital Expenditures (c)
Refining		$	88			$	48			$	143			$	85
Retail			—				1				1				1
Corporate			6				3				8				30
Total Capital Expenditures		$	94			$	52			$	152			$	116

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

		June 30,				December 31,
		2006				2005
Identifiable Assets
Refining		$	4,523			$	4,204
Retail			224				222
Corporate			853				671
Total Assets		$	5,600			$	5,097

NOTE D – DEBT

8% Senior Secured Notes Due 2008

On April 17, 2006, we voluntarily prepaid the remaining $9 million outstanding principal balance of our 8% senior secured notes at a prepayment premium of 4%.

Credit Agreement

In July 2006, we amended our credit agreement to extend the term by one year to June 2009 and reduce letters of credit fees and revolver borrowing interest by 0.25%. Our credit agreement currently provides for borrowings (including letters of credit) up to the lesser of the agreement’s total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base ($2.0 billion as of June 30, 2006), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of June 30, 2006, we had no borrowings and $218 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $532 million or 71% of the eligible borrowing base. Borrowings under the revolving credit facility bear interest at either a base rate (8.25% at June 30, 2006) or a eurodollar rate (5.35% at June 30, 2006), plus an applicable margin. The applicable margin at June 30, 2006 was 1.50% in the case of the eurodollar rate, but varies based upon our credit facility availability and credit ratings. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate tied to the eurodollar rate applicable margin (1.50% at June 30, 2006). We also incur commitment fees for the unused portion of the revolving credit facility at an annual rate of 0.50% as of June 30, 2006.

The credit agreement allows up to $250 million in letters of credit outside the credit agreement for petroleum inventories from non-U.S. vendors. In September 2005, we entered into a separate letters of credit agreement that provides up to $165 million in letters of credit for the purchase of foreign petroleum inventories. The agreement is secured by our petroleum inventories supported by letters of credit issued under the agreement and will remain in effect until terminated by either party. Letters of credit outstanding under this agreement incur fees at an annual rate of 1.25% to 1.38%. As of June 30, 2006, we had $140 million in letters of credit outstanding under this agreement. In July 2006, we increased the capacity under the separate letters of credit agreement to $250 million.

Capitalized Interest

We capitalize interest as part of the cost of major projects during extended construction periods. Capitalized interest, which is a reduction to interest and financing costs in the condensed statements of consolidated operations, totaled $2 million and $3 million for the three months ended June 30, 2006 and 2005, respectively, and $4 million for each of the six months ended June 30, 2006 and 2005.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE E – STOCKHOLDERS’ EQUITY

Common Stock Repurchase Program

In November 2005, our Board of Directors authorized a $200 million share repurchase program. Under the program, we repurchase our common stock from time to time in the open market. Purchases will depend on price, market conditions and other factors. During the six months ended June 30, 2006, we repurchased 1.3 million shares of common stock for $84 million under the program, or an average cost per share of $63.57. As of June 30, 2006, approximately $102 million remained available for future repurchases under the program.

Cash Dividends

On August 1, 2006, our Board of Directors declared a quarterly cash dividend on common stock of $0.10 per share, payable on September 15, 2006 to shareholders of record on September 1, 2006. In both March and June 2006, we paid a quarterly cash dividend on common stock of $0.10 per share.

Authorized Shares of Common Stock

On May 3, 2006 at our 2006 Annual Meeting, our shareholders approved an increase in the number of authorized shares of common stock from 100 million to 200 million. The additional 100 million authorized shares of common stock have the same rights and privileges as the shares previously authorized.

NOTE F – INVENTORIES

Components of inventories were as follows (in millions):

		June 30,				December 31,
		2006				2005
Crude oil and refined products, at LIFO cost		$	914			$	882
Oxygenates and by-products, at the lower of FIFO cost or market			16				14
Merchandise			9				9
Materials and supplies			49				48
Total Inventories		$	988			$	953

Inventories valued at LIFO cost were less than replacement cost by approximately $1.2 billion and $687 million, at June 30, 2006 and December 31, 2005, respectively.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE G – PENSION AND OTHER POSTRETIREMENT BENEFITS

Tesoro sponsors defined benefit pension plans, including a funded employee retirement plan, an unfunded executive security plan and an unfunded non-employee director retirement plan. Although Tesoro has no minimum required contribution obligation to its funded employee retirement plan under applicable laws and regulations in 2006, during the three and six months ended June 30, 2006, we voluntarily contributed $6 million and $13 million, respectively, to improve the funded status of the plan. The components of pension benefit expense included in the condensed statements of consolidated operations were (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Service Cost		$	5			$	4			$	10			$	9
Interest Cost			3				3				7				6
Expected return on plan assets			(4	)			(2	)			(9	)			(5	)
Amortization of prior service cost			1				1				1				1
Recognized net actuarial loss			1				—				2				1
Curtailments and settlements			—				—				—				3
Net Periodic Benefit Expense		$	6			$	6			$	11			$	15

The components of other postretirement benefit expense, primarily for health insurance, included in the condensed statements of consolidated operations were (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Service Cost		$	2			$	2			$	5			$	4
Interest Cost			2				2				5				4
Recognized net actuarial loss			1				—				1				—
Net Periodic Benefit Expense		$	5			$	4			$	11			$	8

NOTE H – STOCK-BASED COMPENSATION

Tesoro follows the fair value method of accounting for stock-based compensation prescribed by Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised 2004), “Share-Based Payment.” Stock-based compensation expense for our stock-based compensation plans was as follows (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Stock options		$	4			$	2			$	7			$	9
Restricted stock			1				1				2				2
Stock appreciation rights			1				—				2				—
Phantom stock			2				3				3				4
Total Stock-Based Compensation		$	8			$	6			$	14			$	15

The six months ended June 30, 2005 included stock-based compensation totaling $5 million associated with the termination and retirement of certain executive officers. The excess income tax benefits realized from tax deductions associated with option exercises totaled $15 million and $20 million for the six months ended June 30, 2006 and 2005, respectively.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Stock Options

We amortize the estimated fair value of our stock options granted over the vesting period using the straight-line method. The fair value of each option was estimated on the date of grant using the Black-Scholes option-pricing model. During the six months ended June 30, 2006, we granted 552,260 options with a weighted-average exercise price of $67.34. These options generally become exercisable after one year in 33% annual increments and expire ten years from the date of grant. Total unrecognized compensation cost related to non-vested stock options totaled $25 million as of June 30, 2006, which is expected to be recognized over a weighted-average period of 2.1 years. A summary of our outstanding and exercisable options as of June 30, 2006 is presented below:

										Weighted-Average
						Weighted-Average				Remaining				Intrinsic Value
		Shares				Exercise Price				Contractual Term				(In Millions)
Options Outstanding			3,879,477			$	25.35			6.6 years				$	190
Options Exercisable			2,534,215			$	14.23			5.4 years				$	152

Restricted Stock

We amortize the estimated fair value of our restricted stock granted over the vesting period using the straight-line method. The fair value of each restricted share on the date of grant is equal to its fair market price. During the six months ended June 30, 2006, we issued 63,050 shares of restricted stock with a weighted-average grant-date fair value of $66.61. These restricted shares vest in annual increments ratably over three years, assuming continued employment at the vesting dates. Total unrecognized compensation cost related to non-vested restricted stock totaled $11 million as of June 30, 2006, which is expected to be recognized over a weighted-average period of 1.8 years. As of June 30, 2006 we had 597,688 shares of restricted stock outstanding at a weighted-average grant-date fair value of $25.37.

2006 Long-Term Stock Appreciation Rights Plan

In February 2006, our Board of Directors approved the 2006 Long-Term Stock Appreciation Rights Plan (the “SAR Plan”). The SAR Plan permits the grant of stock appreciation rights (“SARs”) to key managers and other employees of Tesoro. A SAR granted under the SAR Plan entitles an employee to receive cash in an amount equal to the excess of the fair market value of one share of common stock on the date of exercise over the grant price of the SAR. Unless otherwise specified, all SARs under the SAR Plan vest ratably during a three-year period following the date of grant. The term of a SAR granted under the SAR Plan shall be determined by the Compensation Committee provided that no SAR shall be exercisable on or after the tenth anniversary date of its grant. During the six months ended June 30, 2006, we granted 327,610 SARs at 100% of the fair value of Tesoro’s common stock with a weighted-average grant-date fair value of $66.59. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model.

NOTE I – COMMITMENTS AND CONTINGENCIES

We are a party to various litigation and contingent loss situations, including environmental and income tax matters, arising in the ordinary course of business. Where required, we have made accruals in accordance with SFAS No. 5, “Accounting for Contingencies,” in order to provide for these matters. We cannot predict the ultimate effects of these matters with certainty, and we have made related accruals based on our best estimates, subject to future developments. We believe that the outcome of these matters will not result in a material adverse effect on our liquidity and consolidated financial position, although the resolution of certain of these matters could have a material adverse impact on interim or annual results of operations.

Tesoro is subject to audits by federal, state and local taxing authorities in the normal course of business. It is possible that tax audits could result in claims against Tesoro in excess of recorded liabilities. We believe, however, that when these matters are resolved, they will not materially affect Tesoro’s consolidated financial position or results of operations.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Tesoro is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites, install additional controls, or make other modifications or changes in use for certain emission sources.

Environmental Liabilities

We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our previously owned properties. At June 30, 2006, our accruals for environmental expenses totaled $28 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline and terminal operations and retail service stations. We believe these accruals are adequate, based on currently available information, including the participation of other parties or former owners in remediation action.

We have completed an investigation of environmental conditions at certain active wastewater treatment units at our California refinery. This investigation was driven by an order from the San Francisco Bay Regional Water Quality Control Board that names us as well as two previous owners of the California refinery. We are not certain if the San Francisco Bay Regional Water Quality Control Board will require further investigation. A reserve for this matter is included in the environmental accruals referenced above.

On October 24, 2005, we received an NOV from the EPA. The EPA alleges certain modifications made to the fluid catalytic cracking unit at our Washington refinery prior to our acquisition of the refinery were made without a permit in violation of the Clean Air Act. We have investigated the allegations and believe the ultimate resolution of the NOV will not have a material adverse effect on our financial position or results of operations. A reserve for our response to the NOV is included in the environmental accruals referenced above.

On February 28, 2006, we received an offer of settlement from the Bay Area Air Quality Management District. The District has offered to settle 28 NOVs issued to Tesoro from January 2004 to September 2004 for $275,000. The NOVs allege violations of various air quality requirements at the California refinery. A reserve for the settlement of the NOVs is included in the environmental accruals referenced above.

Other Environmental Matters

In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters for which the likelihood of loss may be reasonably possible but the amount of loss is not currently estimable, and some matters may require years for us to resolve. As a result, we have not established reserves for these matters. On the basis of existing information, we believe that the resolution of these matters, individually or in the aggregate, will not have a material adverse effect on our financial position or results of operations. However, we cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our financial position or results of operations in future periods.

We are a defendant, along with other manufacturing, supply and marketing defendants, in ten pending cases alleging MTBE contamination in groundwater. The defendants are being sued for having manufactured MTBE and having manufactured, supplied and distributed gasoline containing MTBE. The plaintiffs, all in California, are generally water providers, governmental authorities and private well owners alleging, in part, the defendants are liable for manufacturing or distributing a defective product. The suits generally seek individual, unquantified compensatory and punitive damages and attorney’s fees, but we cannot estimate the amount or the likelihood of the ultimate resolution of these matters at this time, and accordingly have not established a reserve for these cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and contractually indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000, which are identified prior to August 31, 2010 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the known environmental liabilities arising from Pre-Acquisition Operations including soil and groundwater conditions at the refinery will exceed the $50 million indemnity. We expect to be reimbursed for excess liabilities under certain environmental insurance policies that provide $140 million of coverage in excess of the $50 million indemnity. Because of Tosco’s indemnification and the environmental insurance policies, we have not established a reserve for these defined environmental liabilities arising out of the Pre-Acquisition Operations.

In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery related to the soil and groundwater conditions referenced above. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established, and which may not be covered by the $50 million indemnity for the defined environmental liabilities arising from Pre-Acquisition Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa County Superior Court action alleging that we are contractually responsible for additional environmental liabilities at our California refinery, including the defined environmental liabilities arising from Pre-Acquisition Operations. In February 2005, the parties agreed to stay the arbitration proceedings to pursue settlement discussions. In June 2006, the parties terminated settlement discussions and agreed to proceed with the arbitration. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, and although we cannot provide assurance that we will prevail, we believe that the resolution of the arbitration will not have a material adverse effect on our financial position or results of operations.

Environmental Capital Expenditures

EPA regulations related to the Clean Air Act require reductions in the sulfur content in gasoline. Our California, Washington, Hawaii, Alaska and North Dakota refineries will not require additional capital spending to meet the low sulfur gasoline standards. We currently estimate we will make capital improvements of approximately $8 million at our Utah refinery from 2008 through 2009, that will permit the Utah refinery to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations related to the Clean Air Act also require reductions in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards became effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become effective in phases between 2007 and 2010. Based on our latest engineering estimates, to meet the revised diesel fuel standards, we expect to spend approximately $71 million in capital improvements through 2007, $22 million of which was spent during the first six months of 2006. Included in the estimate are capital projects to manufacture additional ultra-low sulfur diesel at our Alaska refinery, for which we expect to spend approximately $53 million through 2007. We spent $9 million during the first six months of 2006. These cost estimates are subject to further review and analysis. Our California, Washington and North Dakota refineries will not require additional capital spending to meet the new diesel fuel standards.

In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro assumed the seller’s obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, Tesoro is required to address issues that

13

14

15

16

17

18

19

(a)		Includes intersegment sales to our retail segment at prices which approximate market of $284 million and $221 million for the three months ended June 30, 2006 and 2005, respectively, and $482 million and $406 million for the six months ended June 30, 2006 and 2005, respectively.
(b)		We experienced reduced throughput due to scheduled maintenance turnarounds at the Alaska refinery during the 2006 Quarter and the California refinery during the 2006 first quarter, and unscheduled downtime at the North Dakota refinery during the 2006 Quarter. During the 2005 Quarter, we experienced reduced throughput at the Hawaii refinery due to a scheduled maintenance turnaround. In the 2005 first quarter we experienced reduced throughput at the California and Washington refineries, primarily as a result of scheduled major maintenance turnarounds and unscheduled downtime.
(c)		We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less.
(d)		Management uses gross refining margin per barrel to evaluate performance, allocate resources and compare profitability to other companies in the industry. Gross refining margin per barrel is calculated by dividing gross refining margin before inventory changes by total refining throughput and may not be calculated similarly by other companies. Management uses manufacturing costs per barrel to evaluate the efficiency of refinery operations and allocate resources. Manufacturing costs per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these financial measures to help analyze and compare companies in the industry on the basis of operating performance. These financial measures should not be considered as alternatives to segment operating income, revenues, costs of sales and operating expenses or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America.
(e)		Gross refining margin is calculated as revenues less costs of feedstocks, purchased products, transportation and distribution. Gross refining margin approximates total refining segment throughput times gross refining margin per barrel, adjusted for changes in refined product inventory due to selling a volume and mix of product that is different than actual volumes manufactured. Gross refining margin also includes the effect of intersegment sales to the retail segment at prices which approximate market.
(f)		Includes manufacturing depreciation and amortization per throughput barrel of approximately $1.01 and $0.66 for the three months ended June 30, 2006 and 2005, respectively, and $1.06 and $0.70 for the six months ended June 30, 2006 and 2005, respectively.
(g)		Sources of total product sales included products manufactured at the refineries and products purchased from third parties. Total product sales margin includes margins on sales of manufactured and purchased products and the effects of inventory changes. Total product sales were reduced by approximately 23 thousand barrels per day (“Mbpd”) and 21 Mbpd in the 2006 Quarter and 2006 Period, respectively, as a result of recording certain purchases and sales transactions with the same counterparty on a net basis beginning in the 2006 first quarter upon adoption of EITF Issue No. 04-13 (see Note J of the condensed consolidated financial statements in Item 1 for further information.)

20

2006 Quarter further tightening supplies. Finally, more stringent sulfur standards for gasoline and diesel and the removal of MTBE as a blendstock nationwide further reduced finished product supplies and helped bolster industry refining margins.

On an aggregate basis total gross refining margins increased to $858 million during the 2006 Quarter from $640 million in the 2005 Quarter, reflecting higher per barrel gross refining margins as described above and slightly increased throughput. Total refining throughput averaged 544 Mbpd in the 2006 Quarter compared to 541 Mbpd during the 2005 Quarter despite a scheduled maintenance turnaround at our Alaska refinery and unscheduled downtime at our North Dakota refinery. Throughput at our Hawaii refinery was up significantly from the 2005 Quarter reflecting a scheduled turnaround in the 2005 Quarter. The increased throughput from Hawaii more than offset the Alaska and North Dakota reductions.

Revenues from sales of refined products increased 26% to $4.8 billion in the 2006 Quarter, from $3.8 billion in the 2005 Quarter, primarily due to significantly higher average product sales prices partially offset by lower product sales volumes. Our average product prices increased 35% to $90.45 per barrel, reflecting the continued strength in market fundamentals. Total product sales averaged 584 Mbpd in the 2006 Quarter, a decrease of 43 Mbpd from the 2005 Quarter, primarily reflecting lower volumes of products purchased for resale and recording certain purchases and sales transactions on a net basis as described in note (g) in the table above. Our average costs of sales increased 32% to $74.24 per barrel during the 2006 Quarter reflecting significantly higher average feedstock prices. Expenses, excluding depreciation and amortization, decreased to $211 million in the 2006 Quarter, compared with $222 million in the 2005 Quarter, primarily as a result of reclassifying certain pipeline and terminal costs of $12 million from other operating costs to costs of sales. Depreciation and amortization increased to $54 million in the 2006 Quarter, compared to $37 million in the 2005 Quarter. During the fourth quarter of 2005, we shortened the estimated lives of the fluid coker unit and certain tanks at our California refinery and recorded asset retirement obligations. The fluid coker unit is being modified to a delayed coker unit. The shortened asset lives and recorded asset retirement obligations resulted in additional depreciation of $11 million during the 2006 Quarter and will increase depreciation in 2006 by approximately $45 million. The increase in depreciation and amortization also reflects increasing capital expenditures.

Six Months Ended June 30, 2006 Compared with Six Months Ended June 30, 2005. Operating income from our refining segment was $718 million in the 2006 Period compared to $513 million for the 2005 Period. The $205 million increase in our operating income was primarily due to increased gross refining margins and higher throughput levels, partly offset by higher depreciation expense. Total gross refining margins increased to $13.44 per barrel in the 2006 Period compared to $11.00 per barrel in the 2005 Period due to higher industry margins in all of our regions reflecting the same industry trends noted above. Further, industry margins on the U.S. west coast improved significantly during the 2006 second quarter as compared to the 2006 first quarter during which heavy rains impacted demand, and record high industry throughput and gasoline production resulted in higher average inventory levels for finished products and lower finished product prices.

During the 2006 Period, we achieved higher gross refining margins on a per-barrel-basis in all of our regions because of strong industry fundamentals and margins. By comparison, several factors negatively impacted our gross refining margins in 2005. Our gross refining margins in our Pacific Northwest region were negatively impacted during the 2005 first quarter as our Washington refinery completed a scheduled maintenance turnaround of the crude and naphtha reforming units and incurred unscheduled downtime due to outages of certain processing equipment. In addition, our gross refining margins in our Pacific Northwest region during the 2005 Period were negatively impacted as the increased differential between light and heavy crude oil depressed the margins for heavy fuel oils. Scheduled maintenance and unscheduled downtime at our California refinery during the 2005 first quarter and a scheduled maintenance turnaround at our Hawaii refinery during the 2005 second quarter negatively impacted gross refining margins. In our Mid-Continent region, our Utah refinery was negatively impacted by certain factors primarily during the 2005 first quarter, including higher crude oil costs due to Canadian production constraints and depressed market fundamentals in the Salt Lake City area due to record high first quarter production in PADD IV.

On an aggregate basis, total gross refining margins increased to $1.3 billion during the 2006 Period from $1.0 billion in the 2005 Period, reflecting increased throughput and higher per barrel gross refining margins as described above. Total refining throughput averaged 520 Mbpd in the 2006 Period, an increase of 11 Mbpd from the 2005 Period, primarily as a result of experiencing less scheduled and unscheduled downtime during the 2006 Period. During the 2006 Period, we

experienced scheduled refinery turnarounds at our California and Alaska refineries and unscheduled downtime at our North Dakota refinery. We also experienced reduced throughput at our Alaska refinery during the 2006 first quarter as a result of the grounding of our time-chartered vessel which impacted our supply of feedstocks to the refinery. As described above, during the 2005 Period, we experienced scheduled refinery turnarounds at our California, Washington and Hawaii refineries and other unscheduled downtime.

Revenues from sales of refined products increased 25% to $8.5 billion in the 2006 Period, from $6.8 billion in the 2005 Period, primarily due to significantly higher average product sales prices partially offset by slightly lower product sales volumes. Our average product prices increased 30% to $82.06 per barrel reflecting the continued strength in market fundamentals. Total product sales averaged 576 Mbpd in the 2006 Period, a decrease of 15 Mbpd from the 2005 Period, primarily reflecting recording certain purchases and sales transactions on a net basis as described in note (g) in the table above. Our average costs of sales increased 30% to $70.09 per barrel during the 2006 Period, reflecting significantly higher average feedstock prices. Expenses, excluding depreciation and amortization, increased to $427 million in the 2006 Period, compared with $422 million in the 2005 Period, primarily due to higher utilities of $15 million, increased employee costs of $3 million and higher insurance costs of $2 million, partly offset by reclassifying certain pipeline and terminal costs of $16 million from other operating costs to costs of sales. Depreciation and amortization increased to $108 million in the 2006 Period, compared to $72 million in the 2005 Period primarily due to shortening the estimated lives and recording asset retirement obligations of certain assets at our California refinery, as described above, resulting in additional depreciation of $22 million during the 2006 Period. The increase in depreciation and amortization also reflects increasing capital expenditures.

Retail Segment

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(Dollars in millions except per gallon amounts)		2006				2005				2006				2005
Revenues
Fuel		$	295			$	238			$	508			$	435
Merchandise and other			39				36				71				67
Total Revenues		$	334			$	274			$	579			$	502
Fuel Sales (millions of gallons)			111				117				210				228
Fuel Margin ($/gallon) (a)		$	0.10			$	0.15			$	0.12			$	0.13
Merchandise Margin (in millions)		$	10			$	9			$	18			$	17
Merchandise Margin (percent of sales)			26	%			26	%			26	%			26	%
Average Number of Stations (during the period)
Company-operated			210				214				210				214
Branded jobber/dealer			256				286				259				289
Total Average Retail Stations			466				500				469				503
Segment Operating Loss
Gross Margins
Fuel (b)		$	11			$	17			$	26			$	30
Merchandise and other non-fuel margin			11				10				20				18
Total gross margins			22				27				46				48
Expenses
Operating expenses			23				22				45				44
Selling, general and administrative			6				8				12				14
Depreciation and amortization			4				4				8				8
Loss on asset disposals and impairments			1				2				5				2
Segment Operating Loss		$	(12	)		$	(9	)		$	(24	)		$	(20	)

Three Months Ended June 30, 2006 Compared with Three Months Ended June 30, 2005. Operating loss for our retail segment was $12 million in the 2006 Quarter, compared to an operating loss of $9 million in the 2005 Quarter. Total gross margins decreased to $22 million during the 2006 Quarter from $27 million in the 2005 Quarter reflecting lower fuel margins per gallon and lower sales volumes. Fuel margin decreased to $0.10 per gallon in the 2006 Quarter compared to $0.15 per gallon in the 2005 Quarter as retail gasoline prices lagged higher wholesale prices. Total gallons sold decreased to 111 million from 117 million, reflecting the decrease in average station count to 466 in the 2006 Quarter from 500 in the 2005 Quarter. The decrease in average station count reflects our continued rationalization of retail assets.

Revenues on fuel sales increased to $295 million in the 2006 Quarter, from $238 million in the 2005 Quarter, reflecting increased sales prices, partly offset by lower sales volumes. Costs of sales increased in the 2006 Quarter due to higher average prices of purchased fuel, partly offset by lower sales volumes.

Six Months Ended June 30, 2006 Compared with Six Months Ended June 30, 2005. Operating loss for our retail segment was $24 million in the 2006 Period, compared to an operating loss of $20 million in the 2005 Period. The 2006 first quarter included an impairment of $4 million related to the sale of 13 retail sites located in the Pacific Northwest in August 2006. Total gross margins decreased to $46 million during the 2006 Period from $48 million in the 2005 Period primarily reflecting lower sales volumes. Total gallons sold decreased to 210 million from 228 million, reflecting the decrease in average station count to 469 in the 2006 Period from 503 in the 2005 Period. The decrease in average station count reflects our continued rationalization of retail assets. Fuel margin remained flat at $0.12 per gallon in the 2006 Period compared to $0.13 per gallon in the 2005 Period.

Revenues on fuel sales increased to $508 million in the 2006 Period, from $435 million in the 2005 Period, reflecting higher sales prices, partly offset by lower sales volumes. Costs of sales increased in the 2006 Period due to higher average prices of purchased fuel, partly offset by lower sales volumes.

Selling, General and Administrative Expenses

Selling, general and administrative expenses totaled $45 million and $85 million for the 2006 Quarter and 2006 Period, respectively, compared to $48 million and $102 million in the 2005 Quarter and 2005 Period, respectively. The decrease during the 2006 Period was primarily due to charges totaling $11 million for the termination and retirement of certain executive officers during the 2005 Period and lower contract labor expenses of $10 million, partially offset by higher employee expenses of $6 million.

Interest and Financing Costs

Interest and financing costs decreased by $11 million and $23 million in the 2006 Quarter and 2006 Period, respectively. The decreases were primarily due to lower interest expense associated with debt reduction during 2005 totaling $191 million and the refinancing of our 8% senior secured notes and 9⁵/₈% senior subordinated notes. The 2005 Quarter included prepayment charges of $3 million in connection with the voluntary prepayment of our senior secured term loans.

Interest Income and Other

Interest income and other increased by $7 million and $16 million for the 2006 Quarter and 2006 Period, respectively. The increases reflect a significant increase in invested cash balances. In addition, during the 2006 Period we recorded a gain of $5 million associated with the sale of our leased corporate headquarters by a limited partnership in which we were a 50% partner.

Income Tax Provision

The income tax provision totaled $203 million and $231 million for the 2006 Quarter and 2006 Period, respectively, compared to $121 million and $140 million for the 2005 Quarter and 2005 Period, respectively, reflecting higher earnings before income taxes. The combined federal and state effective income tax rate was 39% and 40% for the 2006 and 2005 Periods, respectively.

CAPITAL RESOURCES AND LIQUIDITY

Overview

We operate in an environment where our capital resources and liquidity are impacted by changes in the price of crude oil and refined petroleum products, availability of trade credit, market uncertainty and a variety of additional factors beyond our control. These risks include, among others, the level of consumer product demand, weather conditions, fluctuations in seasonal demand, governmental regulations, geopolitical conditions and overall market and economic conditions. See “Forward-Looking Statements” on page 30 for further information related to risks and other factors. Future capital expenditures, as well as borrowings under our credit agreement and other sources of capital, may be affected by these conditions.

Our primary sources of liquidity have been cash flows from operations and borrowing availability under revolving lines of credit. We ended the second quarter of 2006 with $620 million of cash and cash equivalents, no revolver borrowings, and $532 million in available borrowing capacity under our $750 million credit agreement after $218 million in outstanding letters of credit. We also have a separate letters of credit agreement of which we had $25 million available after $140 million in outstanding letters of credit as of June 30, 2006. We believe available capital resources will be adequate to meet our capital expenditures, working capital and debt service requirements.

Capitalization

Our capital structure at June 30, 2006 was comprised of the following (in millions):

Debt, including current maturities:
Credit Agreement – Revolving Credit Facility		$	¾
61/4% Senior Notes Due 2012			450
65/8% Senior Notes Due 2015			450
95/8% Senior Subordinated Notes Due 2012			14
Junior subordinated notes due 2012			98
Capital lease obligations and other			30
Total debt			1,042
Stockholders’ equity			2,197
Total Capitalization		$	3,239

At June 30, 2006, our debt to capitalization ratio was 32% compared with 36% at year-end 2005, reflecting an increase in retained earnings primarily due to net earnings of $369 million during the 2006 Period.

Our credit agreement and senior notes impose various restrictions and covenants on us that could potentially limit our ability to respond to market conditions, raise additional debt or equity capital, or take advantage of business opportunities.

Credit Agreement

In July 2006, we amended our credit agreement to extend the term by one year to June 2009 and reduce letters of credit fees and revolver borrowing interest by 0.25%. Our credit agreement currently provides for borrowings (including letters of credit) up to the lesser of the agreement’s total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base ($2.0 billion as of June 30, 2006), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of June 30, 2006, we had no borrowings and $218 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $532 million or 71% of the eligible borrowing base. Borrowings under the revolving credit facility bear interest at either a base rate (8.25% at June 30, 2006) or a eurodollar rate (5.35% at June 30, 2006), plus an applicable margin. The applicable margin at June 30, 2006 was 1.50% in the case of the eurodollar rate, but varies based upon our credit facility availability and credit ratings. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate tied to the eurodollar rate applicable margin (1.50% at June 30, 2006). We also incur commitment fees for the unused portion of the revolving credit facility at an annual rate of 0.50% as of June 30, 2006.

The credit agreement allows up to $250 million in letters of credit outside the credit agreement for petroleum inventories from non-U.S. vendors. In September 2005, we entered into a separate letters of credit agreement that provides up to $165 million in letters of credit for the purchase of foreign petroleum inventories. The agreement is secured by our petroleum inventories supported by letters of credit issued under the agreement and will remain in effect until terminated by either party. Letters of credit outstanding under this agreement incur fees at an annual rate of 1.25% to 1.38%. As of June 30, 2006, we had $140 million in letters of credit outstanding under this agreement. In July 2006, we increased the capacity under the separate letters of credit agreement to $250 million.

8% Senior Secured Notes Due 2008

On April 17, 2006, we voluntarily prepaid the remaining $9 million outstanding principal balance of our 8% senior secured notes at a prepayment premium of 4%.

Common Stock Repurchase Program

In November 2005, our Board of Directors authorized a $200 million share repurchase program. Under the program, we repurchase our common stock from time to time in the open market. Purchases will depend on price, market conditions and other factors. During the 2006 Period, we repurchased 1.3 million shares of common stock under the program for $84 million, or an average cost per share of $63.57. As of June 30, 2006, $102 million remained available for future repurchases under the program, which we expect to complete by the end of the year.

Cash Flow Summary

Components of our cash flows are set forth below (in millions):

		Six Months Ended
		June 30,
		2006				2005
Cash Flows From (Used In):
Operating Activities		$	409			$	85
Investing Activities			(143	)			(116	)
Financing Activities			(86	)			(58	)
Increase (Decrease) in Cash and Cash Equivalents		$	180			$	(89	)

Net cash from operating activities during the 2006 Period totaled $409 million, compared to $85 million in the 2005 Period. The increase was primarily due to increased cash earnings and lower working capital requirements. Net cash used in investing activities of $143 million in the 2006 Period was primarily for capital expenditures, excluding turnarounds. Net cash used in financing activities primarily reflects repurchases under our common stock repurchase program totaling $84 million.

During the 2006 Quarter, we did not borrow or make repayments under the revolving credit facility. Working capital was $1.0 billion at June 30, 2006 compared to $713 million at year-end 2005, as a result of the increase in cash and cash equivalents, higher receivables and inventory values, partially offset by increases in accounts payable, attributable to higher crude and product prices.

Historical EBITDA

EBITDA represents earnings before interest and financing costs, interest income, income taxes, and depreciation and amortization. We present EBITDA because we believe some investors and analysts use EBITDA to help analyze our cash flow including our ability to satisfy interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used by some investors and analysts to analyze and compare companies on the basis of operating performance. EBITDA is also used by management for internal analysis and as a component of the fixed charge coverage financial covenant in our credit agreement. EBITDA should not be considered as an alternative to net earnings, earnings before income taxes, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America. EBITDA may not be comparable to similarly titled measures used by other entities. Our historical EBITDA reconciled to net cash from operating activities was (in millions):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Net Cash From Operating Activities		$	393			$	142			$	409			$	85
Changes in Assets and Liabilities			37				136				141				272
Excess Tax Benefits from Stock-Based Compensation Arrangements			9				10				15				20
Deferred Income Taxes			(36	)			(44	)			(43	)			(50	)
Stock-Based Compensation			(8	)			(6	)			(14	)			(15	)
Loss on Asset Disposals and Impairments			(5	)			(4	)			(12	)			(5	)
Amortization and Write-off of Debt Issuance Costs and Discounts			(4	)			(7	)			(7	)			(11	)
Depreciation and Amortization			(60	)			(43	)			(120	)			(84	)
Net Earnings			326				184				369				212
Add Income Tax Provision			203				121				231				140
Less Interest Income and Other			(7	)			¾				(17	)			(1	)
Add Interest and Financing Costs			21				32				41				64
Operating Income			543				337				624				415
Add Depreciation and Amortization			60				43				120				84
Add Gain on Partnership Sale			¾				¾				5				¾
EBITDA		$	603			$	380			$	749			$	499

Historical EBITDA as presented above differs from EBITDA as defined under our credit agreement. The primary differences are non-cash postretirement benefit costs and loss on asset disposals and impairments, which are added to net earnings under the credit agreement EBITDA calculations.

Capital Expenditures and Refinery Turnaround Spending

In July 2006, we revised our projected 2006 capital spending by $40 million to approximately $530 million (excluding refinery turnaround and other maintenance costs of approximately $100 million). The expected capital spending reduction primarily reflects our decision to cancel the delayed coker project at the Washington refinery which had experienced significant cost escalations in engineering, materials and labor (see “Business Strategy and Overview”). The revisions to our 2006 capital spending projections are comprised of reductions for the cancellation of the delayed coker project of $61 million and other delayed or cancelled projects of $36 million, partly offset by additional capital spending for new projects of $57 million.

We plan to continue with certain units included in the overall delayed coker project scope at the Washington refinery which are designed to increase sulfur handling capabilities, improve utilization and maintain environmental compliance. The sulfur handling units will cost an estimated $55 million and are expected to be completed in the fourth quarter of 2007. In addition, we will continue with the modification of our existing fluid coker unit to a delayed coker unit at our California refinery. During the design phase for this project, we decided to utilize a different delayed coker technology and given current trends in engineering, labor and material costs on similar projects within the industry, we now expect costs for the project to total approximately $415 million. We originally expected to spend approximately $275 million for this project through the fourth quarter of 2007. The project is currently scheduled to be substantially completed during the fourth quarter of 2007, with spending through the first quarter of 2008. These cost estimates are subject to further review and analysis.

During the 2006 Period, our capital expenditures, including accruals, totaled $152 million (excluding refinery turnaround and other maintenance costs of $51 million), and included $34 million for the delayed coker modification at our California refinery, $9 million for the diesel desulfurizer unit at our Alaska refinery, $18 million for other refinery improvements at our California refinery, $33 million for other clean air, clean fuels and environmental projects, and $19 million for the cancelled delayed coker unit at our Washington refinery. Refinery turnaround and other maintenance costs consisted primarily of the scheduled turnaround at our California refinery during the 2006 first quarter and our Alaska refinery during the 2006 second quarter.

We expect our capital expenditures for the remainder of 2006 to approximate $378 million (excluding $49 million of refinery turnaround and other maintenance costs). Our estimated capital expenditures for the remainder of 2006 includes $97 million for the delayed coker modification project at our California refinery, $24 million for the diesel desulfurizer unit at our Alaska refinery, $54 million for other clean air, clean fuels and environmental projects and $52 million for other refinery improvements at our California refinery. The refinery turnaround and other maintenance costs primarily include the planned scheduled maintenance turnaround at the Washington refinery during the fourth quarter of 2006.

Environmental and Other

Tesoro is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites, install additional controls, or make other modifications or changes in use for certain emission sources.

Environmental Liabilities

We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our previously owned properties. At June 30, 2006, our accruals for environmental expenses totaled $28 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline and terminal operations and retail service stations. We believe these accruals are adequate, based on currently available information, including the participation of other parties or former owners in remediation action.

We have completed an investigation of environmental conditions at certain active wastewater treatment units at our California refinery. This investigation was driven by an order from the San Francisco Bay Regional Water Quality Control Board that names us as well as two previous owners of the California refinery. We are not certain if the San Francisco Bay Regional Water Quality Control Board will require further investigation. A reserve for this matter is included in the environmental accruals referenced above.

On October 24, 2005, we received an NOV from the EPA. The EPA alleges certain modifications made to the fluid catalytic cracking unit at our Washington refinery prior to our acquisition of the refinery were made without a permit in violation of the Clean Air Act. We have investigated the allegations and believe the ultimate resolution of the NOV will not have a material adverse effect on our financial position or results of operations. A reserve for our response to the NOV is included in the environmental accruals referenced above.

On February 28, 2006, we received an offer of settlement from the Bay Area Air Quality Management District. The District has offered to settle 28 NOVs issued to Tesoro from January 2004 to September 2004 for $275,000. The NOVs allege violations of various air quality requirements at the California refinery. A reserve for the settlement of the NOVs is included in the environmental accruals referenced above.

Other Environmental Matters

In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters for which the likelihood of loss may be reasonably possible but the amount of loss is not currently estimable, and some matters may require years for us to resolve. As a result, we have not established reserves for these matters. On the basis of existing information, we believe that the resolution of these matters, individually or in the aggregate, will not have a material adverse effect on our financial position or results of operations. However, we cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our financial position or results of operations in future periods.

We are a defendant, along with other manufacturing, supply and marketing defendants, in ten pending cases alleging MTBE contamination in groundwater. The defendants are being sued for having manufactured MTBE and having manufactured, supplied and distributed gasoline containing MTBE. The plaintiffs, all in California, are generally water providers, governmental authorities and private well owners alleging, in part, the defendants are liable for manufacturing or distributing a defective product. The suits generally seek individual, unquantified compensatory and punitive damages and attorney’s fees, but we cannot estimate the amount or the likelihood of the ultimate resolution of these matters at this time, and accordingly have not established a reserve for these cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.

Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and contractually indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000, which are identified prior to August 31, 2010 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the known environmental liabilities arising from Pre-Acquisition Operations including soil and groundwater conditions at the refinery will exceed the $50 million indemnity. We expect to be reimbursed for excess liabilities under certain environmental insurance policies that provide $140 million of coverage in excess of the $50 million indemnity. Because of Tosco’s indemnification and the environmental insurance policies, we have not established a reserve for these defined environmental liabilities arising out of the Pre-Acquisition Operations.

In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery related to the soil and groundwater conditions referenced above. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established, and which may not be covered by the $50 million indemnity for the defined environmental liabilities arising from Pre-Acquisition Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa County Superior Court action alleging that we are contractually responsible for additional environmental liabilities at our California refinery, including the defined environmental liabilities arising from Pre-Acquisition Operations. In February 2005, the parties agreed to stay the arbitration proceedings to pursue settlement discussions. In June 2006, the parties terminated settlement discussion and agreed to proceed with the arbitration. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, and although we cannot provide assurance that we will prevail, we believe that the resolution of the arbitration will not have a material adverse effect on our financial position or results of operations.

Environmental Capital Expenditures

EPA regulations related to the Clean Air Act require reductions in the sulfur content in gasoline. Our California, Washington, Hawaii, Alaska and North Dakota refineries will not require additional capital spending to meet the low sulfur gasoline standards. We currently estimate we will make capital improvements of approximately $8 million at our Utah refinery from 2008 through 2009, that will permit the Utah refinery to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations related to the Clean Air Act also require reductions in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards became effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become effective in phases between 2007 and 2010. Based on our latest engineering estimates, to meet the revised diesel fuel standards, we expect to spend approximately $71 million in capital improvements through 2007, $22 million of which was spent during the first six months of 2006. Included in the estimate are capital projects to manufacture additional ultra-low sulfur diesel at our Alaska refinery, for which we expect to spend approximately $53 million through 2007. We spent $9 million during the first six months of 2006. These cost estimates are subject to further review and analysis. Our California, Washington and North Dakota refineries will not require additional capital spending to meet the new diesel fuel standards.

In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro assumed the seller’s obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, Tesoro is required to address issues that include leak detection and repair, flaring protection, and sulfur recovery unit optimization. We currently estimate we will spend $10 million over the next three years to comply with this consent decree. We also agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.

In connection with the 2002 acquisition of our California refinery, subject to certain conditions, we assumed the sellers obligations pursuant to settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. In November 2005, the Consent Decree was entered by the District Court for the Western District of Texas in which we agreed to undertake projects at our California refinery to reduce air emissions. We currently estimate that we will make additional capital improvements of approximately $30 million through 2010 to satisfy the requirements of the Consent Decree. This cost estimate is subject to further review and analysis.

During the fourth quarter of 2005, we received approval by the Hearing Board for the Bay Area Air Quality Management District to modify our existing fluid coker unit to a delayed coker at our California refinery which is designed to lower emissions while also enhancing the refinery’s capabilities in terms of reliability, lengthening turnaround cycles and reducing operating costs. We negotiated the terms and conditions of the Second Conditional Abatement Order with the District in response to the January 2005 mechanical failure of one of our boilers at the California refinery. We previously estimated that we would spend approximately $275 million through the fourth quarter of 2007 for this project. However, given current trends in engineering, labor and material costs on similar projects within the industry, we now anticipate to spend approximately $415 million for this project. The project is currently scheduled to be substantially completed during the fourth quarter of 2007, with spending through the first quarter of 2008. We spent $34 million in the first six months of 2006 and $3 million in 2005. This cost estimate is subject to further review and analysis.

We will spend additional capital at the California refinery for reconfiguring and replacing above-ground storage tank systems and upgrading piping within the refinery. We currently estimate that we will spend approximately $110 million through 2010, $8 million of which was spent during the first six months of 2006. This cost estimate is subject to further review and analysis.

Conditions may develop that cause increases or decreases in future expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are included throughout this Form 10-Q and relate to, among other things, expectations regarding refining margins, revenues, cash flows, capital expenditures, turnaround expenses and other financial items. These statements also relate to our business strategy, goals and expectations concerning our market position, future operations, margins and profitability. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “project”, “will” and similar terms and phrases to identify forward-looking statements in this Quarterly Report on Form 10-Q.

Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations involve risks and uncertainties, many of which are outside our control, and any one of which, or a combination of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be correct.

Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking statements depending on a variety of factors including, but not limited to:

	•		changes in general economic conditions;
	•		the timing and extent of changes in commodity prices and underlying demand for our products;
	•		the availability and costs of crude oil, other refinery feedstocks and refined products;
	•		changes in our cash flow from operations;
	•		changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products;
	•		disruptions due to equipment interruption or failure at our facilities or third-party facilities;
	•		actions of customers and competitors;
	•		changes in capital requirements or in execution of planned capital projects;
	•		direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;
	•		political developments in foreign countries;
	•		changes in our inventory levels and carrying costs;
	•		seasonal variations in demand for refined products;
	•		changes in fuel and utility costs for our facilities;
	•		state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond our control;
	•		adverse rulings, judgments, or settlements in litigation or other legal or tax matters, including unexpected environmental remediation costs in excess of any reserves;
	•		weather conditions affecting operations or the areas in which our products are marketed; and
	•		earthquakes or other natural disasters affecting operations.

Many of these factors are described in greater detail in our filings with the SEC. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this Quarterly Report on Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in commodity prices and interest rates are our primary sources of market risk. We have a risk management committee responsible for managing risks arising from transactions and commitments related to the sale and purchase of energy commodities and making recommendations to executive management.

Commodity Price Risks

Our earnings and cash flows from operations depend on the margin above fixed and variable expenses (including the costs of crude oil and other feedstocks) at which we are able to sell refined products. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the demand for crude oil, gasoline and other refined products, which in turn depend on, among other factors, changes in the economy, the level of foreign and domestic production of crude oil and refined products, worldwide geo-political conditions, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels and the impact of government regulations. The prices we receive for refined products are also affected by local factors such as local market conditions and the level of operations of other refineries in our markets.

The prices at which we sell our refined products are influenced by the commodity 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. In addition, the majority of our crude oil supply contracts are short-term in nature with market-responsive pricing provisions. Our financial results can be affected significantly by price level changes during the period between purchasing refinery feedstocks and selling the manufactured refined products from such feedstocks. We also purchase refined products manufactured by others for resale to our customers. Our financial results can be affected significantly by price level changes during the periods between purchasing and selling such products. Assuming all other factors remained constant, a $1.00 per barrel change in average gross refining margins, based on our 2006 year-to-date average throughput of 520,000 bpd, would change annualized pretax operating income by approximately $190 million.

We maintain inventories of crude oil, intermediate products and refined products, the values of which are subject to fluctuations in market prices. Our inventories of refinery feedstocks and refined products totaled 28 million barrels at both June 30, 2006 and December 31, 2005. The average cost of our refinery feedstocks and refined products at June 30, 2006 was approximately $37 per barrel on a LIFO basis, compared to market prices of approximately $86 per barrel. If market prices decline to a level below the average cost of these inventories, we would be required to write down the carrying value of our inventory.

Tesoro periodically enters into non-trading derivative arrangements primarily to manage exposure to commodity price risks associated with the purchase of feedstocks and blendstocks and the purchase and sale of manufactured and purchased refined products. To manage these risks, we typically enter into exchange-traded futures and over-the-counter swaps, generally with durations of one year or less. We mark to market our non-hedging derivative instruments and recognize the changes in their fair values in earnings. We include the carrying amounts of our derivatives in other current assets or accrued liabilities in the consolidated balance sheets. We did not designate or account for any derivative instruments as hedges during the 2006 first or second quarters. Accordingly, no change in the value of the related underlying physical asset is recorded. During the second quarter of 2006, we settled futures and swap positions of approximately 26 million barrels of crude oil and refined products, which resulted in losses of $9 million. At June 30, 2006, we had open net futures contracts and swap positions of 1 million barrels and 6 million barrels, respectively, which will expire at various times during 2006 and 2007. We recorded the fair value of our open positions, which resulted in an unrealized mark-to-market loss of $10 million at June 30, 2006.

We prepared a sensitivity analysis to estimate our exposure to market risk associated with our derivative instruments. This analysis may differ from actual results. The fair value of each derivative instrument was based on quoted market prices. Based on our open net short positions of 7 million barrels as of June 30, 2006, a $1.00 per-barrel change in quoted market prices of our derivative instruments, assuming all other factors remain constant, would change the fair

value of our derivative instruments and pretax operating income by $7 million. As of December 31, 2005 a $1.00 per-barrel change in quoted market prices for our derivative instruments, assuming all other factors remain constant, would have changed the fair value of our derivative instruments and pretax operating income by $7 million.

Interest Rate Risk

At June 30, 2006 all of our outstanding debt was at fixed rates and we had no borrowings under our revolving credit facility, which bears interest at variable rates. The fair market value of our senior notes, which is based on transactions and bid quotes, was approximately $49 million less than its carrying value at June 30, 2006. The fair market values of our junior subordinated notes and capital lease obligations approximate their carrying values.

ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation required by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act as of the end of the period. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company and required to be included in our periodic filings under the Exchange Act. During the quarter ended June 30, 2006, 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

Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and contractually indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000, which are identified prior to August 31, 2010 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the known environmental liabilities arising from Pre-Acquisition Operations including soil and groundwater conditions at the refinery will exceed the $50 million indemnity. We expect to be reimbursed for excess liabilities under certain environmental insurance policies that provide $140 million of coverage in excess of the $50 million indemnity. Because of Tosco’s indemnification and the environmental insurance policies, we have not established a reserve for these defined environmental liabilities arising out of the Pre-Acquisition Operations.

In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery related to the soil and groundwater conditions referenced above. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established, and which may not be covered by the $50 million indemnity for the defined environmental liabilities arising from pre-acquisition operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa County Superior Court action alleging that we are contractually responsible for additional environmental liabilities at our California refinery, including the defined environmental liabilities arising from Pre-Acquisition Operations. In February 2005, the parties agreed to stay the arbitration proceedings to pursue settlement discussions. In June 2006, the parties terminated settlement discussions and agreed to proceed with the arbitration. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, and although we cannot provide assurance that we will prevail, we believe that the resolution of the arbitration will not have a material adverse effect on our financial position or results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below provides a summary of all repurchases by Tesoro of its common stock during the three-month period ended June 30, 2006.

Approximate Dollar

Total Number of

Value of Shares That

Shares Purchased as

May Yet Be

Total Number

Average Price

Part of Publicly

Purchased Under the

of Shares

Paid Per

Announced Plans or

Plans or

Period

Purchased

Share

Programs*

Programs*

April 2006

198,900

$

68.41

198,900

$102 million

May 2006

—

$

—

—

$102 million

June 2006

—

$

—

—

$102 million

Total

198,900

$

68.41

198,900