Edgar Filing: TESORO CORP /NEW/

e10vq

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 March 31, 2006


o		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 1-3473

TESORO CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		95-0862768
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 68,567,483 shares of the registrant’s Common Stock outstanding at May 1, 2006.

TESORO CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION	Page

Item 1. Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets — March 31, 2006 and December 31, 2005		3

Condensed Statements of Consolidated Operations — Three Months Ended March 31, 2006 and 2005		4

Condensed Statements of Consolidated Cash Flows — Three Months Ended March 31, 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		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		29

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		30

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 6. Exhibits		30

SIGNATURES		31

EXHIBIT INDEX		32
Certificate of Amendment to Restated Certificate of Incorporation of the Company
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TESORO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(Dollars in millions except per share amounts)


	March 31,			December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	306		$	440
Receivables, less allowance for doubtful accounts		713			718
Inventories		1,037			953
Prepayments and other		123			104

Total Current Assets		2,179			2,215

PROPERTY, PLANT AND EQUIPMENT
Refining		2,901			2,850
Retail		211			223
Corporate and other		109			107

		3,221			3,180
Less accumulated depreciation and amortization		(751	)		(713	)

Net Property, Plant and Equipment		2,470			2,467


OTHER NONCURRENT ASSETS
Goodwill		89			89
Acquired intangibles, net		118			119
Other, net		224			207

Total Other Noncurrent Assets		431			415

Total Assets	$	5,080		$	5,097

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,239		$	1,171
Accrued liabilities		248			328
Current maturities of debt		12			3

Total Current Liabilities		1,499			1,502


DEFERRED INCOME TAXES		396			389
OTHER LIABILITIES		279			275
DEBT		1,037			1,044
COMMITMENTS AND CONTINGENCIES (Note I)
STOCKHOLDERS’ EQUITY
Common stock, par value $0.16²/₃; authorized 100,000,000 shares; 71,166,330 shares issued (70,850,681 in 2005)		12			12
Additional paid-in capital		809			794
Retained earnings		1,138			1,102
Treasury stock, 2,652,082 common shares (1,548,568 in 2005), at cost		(88	)		(19	)
Accumulated other comprehensive loss		(2	)		(2	)

Total Stockholders’ Equity		1,869			1,887

Total Liabilities and Stockholders’ Equity	$	5,080		$	5,097

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

TESORO CORPORATION

CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Unaudited)

(In millions except per share amounts)


	Three Months Ended
	March 31,
	2006			2005
REVENUES	$	3,877		$	3,171
COSTS AND EXPENSES:
Costs of sales and operating expenses		3,689			2,997
Selling, general and administrative expenses		40			54
Depreciation and amortization		60			41
Loss on asset disposals and impairments		7			1

OPERATING INCOME		81			78
Interest and financing costs		(20	)		(32	)
Interest income and other		10			1

EARNINGS BEFORE INCOME TAXES		71			47
Income tax provision		28			19

NET EARNINGS	$	43		$	28

NET EARNINGS PER SHARE:
Basic	$	0.63		$	0.41
Diluted	$	0.61		$	0.40
WEIGHTED AVERAGE COMMON SHARES:
Basic		68.5			66.8
Diluted		70.6			70.1
DIVIDENDS PER SHARE	$	0.10		$	¾

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

TESORO CORPORATION

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(In millions)


	Three Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings	$	43		$	28
Adjustments to reconcile net earnings to net cash from (used in) operating activities:
Depreciation and amortization		60			41
Amortization of debt issuance costs and discounts		3			4
Loss on asset disposals and impairments		7			1
Stock-based compensation		6			9
Deferred income taxes		7			6
Excess tax benefits from stock-based compensation arrangements		(6	)		(10	)
Other changes in non-current assets and liabilities		(32	)		(23	)
Changes in current assets and current liabilities:
Receivables		10			(115	)
Inventories		(84	)		(224	)
Prepayments and other		(14	)		(12	)
Accounts payable and accrued liabilities		16			238

Net cash from (used in) operating activities		16			(57	)


CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures		(81	)		(64	)
Proceeds from asset sales		1			¾

Net cash used in investing activities		(80	)		(64	)


CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repurchase of common stock		(72	)		¾
Dividend payments		(7	)		¾
Repayments of debt		(1	)		(1	)
Proceeds from stock options exercised		4			16
Excess tax benefits from stock-based compensation arrangements		6			10

Net cash from (used in) financing activities		(70	)		25


DECREASE IN CASH AND CASH EQUIVALENTS		(134	)		(96	)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		440			185


CASH AND CASH EQUIVALENTS, END OF PERIOD	$	306		$	89


SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of capitalized interest	$	(2	)	$	1
Income taxes paid	$	2		$	71

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

TESORO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
	March 31,
	2006		2005
Basic:
Net earnings	$	43	$	28

Weighted average common shares outstanding		68.5		66.8

Basic Earnings Per Share	$	0.63	$	0.41


Diluted:
Net earnings	$	43	$	28

Weighted average common shares outstanding		68.5		66.8
Dilutive effect of stock options and unvested restricted stock		2.1		3.3

Total diluted shares		70.6		70.1

Diluted Earnings Per Share	$	0.61	$	0.40

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 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
	March 31,
	2006			2005
Revenues
Refining:
Refined products	$	3,727		$	2,953
Crude oil resales and other (a)		103			175
Retail:
Fuel		213			197
Merchandise and other		32			31
Intersegment Sales from Refining to Retail		(198	)		(185	)

Total Revenues	$	3,877		$	3,171


Segment Operating Income (Loss)
Refining	$	125		$	132
Retail (b)		(12	)		(11	)

Total Segment Operating Income		113			121
Corporate and Unallocated Costs		(32	)		(43	)

Operating Income		81			78
Interest and Financing Costs		(20	)		(32	)
Interest Income and Other		10			1

Earnings Before Income Taxes	$	71		$	47


Depreciation and Amortization
Refining	$	54		$	35
Retail		4			4
Corporate		2			2

Total Depreciation and Amortization	$	60		$	41


Capital Expenditures (c)
Refining	$	55		$	37
Retail		1			¾
Corporate		2			27

Total Capital Expenditures	$	58		$	64

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	March 31,		December 31,
	2006		2005
Identifiable Assets
Refining	$	4,319	$	4,204
Retail		217		222
Corporate		544		671

Total Assets	$	5,080	$	5,097


(a)		To balance or optimize our refinery supply requirements, we sell certain crude oil that we purchase under our supply contracts.

(b)		Retail operating loss for the three months ended March 31, 2006, includes an impairment charge of $4 million related to a pending sale of 13 retail sites.

(c)		Capital expenditures do not include refinery turnaround and other maintenance costs of $31 million and $34 million for the three months ended March 31, 2006 and 2005, respectively.

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%. At March 31, 2006, the notes were included in current maturities of debt in the condensed consolidated balance sheet.

Credit Agreement

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 ($1.7 billion as of March 31, 2006), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of March 31, 2006, we had no borrowings and $179 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $571 million, or 76% of the eligible borrowing base. Borrowings under the revolving credit facility bear interest at either a base rate (7.75% at March 31, 2006) or a eurodollar rate (4.83% at March 31, 2006), plus an applicable margin. The applicable margin at March 31, 2006 was 1.50% in the case of the eurodollar rate, but varies based on credit facility availability. 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 March 31, 2006).

The credit agreement allows up to $250 million in letters of credit outside the credit agreement for crude oil purchases 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 crude oil. 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 March 31, 2006, we had $88 million in letters of credit outstanding under this agreement.

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 $1 million for the three months ended March 31, 2006 and 2005, respectively.

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 will repurchase our common stock from time to time in the open market. Purchases will depend on price, market conditions and other factors. During the quarter ended March 31, 2006, we repurchased 1.1 million shares of common stock for $71 million under the program, or an average cost per share of $62.71. As of March 31, 2006, approximately $115 million remained available for future repurchases under the program.

Cash Dividends

On May 2, 2006, our Board of Directors declared a quarterly cash dividend on common stock of $0.10 per share, payable on June 15, 2006 to shareholders of record on June 1, 2006. In March 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):


	March 31,		December 31,
	2006		2005
Crude oil and refined products, at LIFO cost	$	965	$	882
Oxygenates and by-products, at the lower of FIFO cost or market		15		14
Merchandise		8		9
Materials and supplies		49		48

Total Inventories	$	1,037	$	953

Inventories valued at LIFO cost were less than replacement cost by approximately $815 million and $687 million, at March 31, 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 pension plan under applicable laws and regulations in 2006, during the three months ended March 31, 2006 we voluntarily contributed $6 million to improve the funded status of the plan. The components of pension and other postretirement benefit expense included in the condensed statements of consolidated operations for the three months ended March 31, 2006 and 2005 were (in millions):


							Other Postretirement
	Pension Benefits						Benefits
	2006			2005			2006		2005
Service Cost	$	5		$	5		$	3	$	2
Interest Cost		4			3			3		2
Expected return on plan assets		(5	)		(3	)		¾		¾
Recognized net actuarial loss		1			1			¾		¾
Curtailments and settlements		¾			3			¾		¾

Net Periodic Benefit Expense	$	5		$	9		$	6	$	4

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.” Total compensation expense for all stock-based awards for the three months ended March 31, 2006 and 2005 totaled $6 million and $9 million, respectively, including $1 million for each of the three months ended March 31, 2006 and 2005 for our outstanding phantom stock options. The first quarter of 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 $6 million and $10 million for the three months ended March 31, 2006 and 2005, respectively.

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 three months ended March 31, 2006, we granted 526,260 options with a weighted-average exercise price of $67.35. These options become exercisable after one year in 33% annual increments and expire ten years from the date of grant. Total compensation cost recognized for all outstanding stock options for the three months ended March 31, 2006 and 2005 totaled $3 million and $7 million, respectively. Total unrecognized compensation cost related to non-vested stock options totaled $28 million as of March 31, 2006, which is expected to be recognized over a weighted-average period of 2.3 years. A summary of our outstanding and exercisable options as of March 31, 2006 is presented below:


					Weighted-Average
			Weighted-Average		Remaining	Intrinsic Value
	Shares		Exercise Price		Contractual Term	(In Millions)
Options Outstanding		4,310,921	$	24.07	6.7 years	$	191
Options Exercisable		2,695,421	$	14.00	5.5 years	$	146

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 three months ended March 31, 2006, we issued 63,050 shares of restricted stock with a weighted-average grant-date fair

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

value of $66.61. These restricted shares vest in annual increments ratably over three years, assuming continued employment at the vesting dates. Total compensation cost recognized for our outstanding restricted stock for both the three months ended March 31, 2006 and 2005 totaled $1 million. Total unrecognized compensation cost related to our non-vested restricted stock totaled $12 million as of March 31, 2006, which is expected to be recognized over a weighted-average period of 1.9 years. As of March 31, 2006 we had 605,155 shares of restricted stock outstanding at a weighted-average grant-date fair value of $25.44.

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. In February 2006, we granted 314,110 SARs at 100% of the fair value of Tesoro’s common stock on the grant date of $66.61 per share. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model. Total compensation expense for our outstanding SARs totaled approximately $1 million for the three months ended March 31, 2006.

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 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 March 31, 2006, our accruals for environmental expenses totaled $29 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.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

emission limits. In January 2006, we executed a Settlement Agreement and Release with CARB and paid a civil penalty of $325,000 to resolve this matter.

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

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

out of the Pre-Acquisition Operations. In December 2003, we initiated arbitration proceedings against Tosco seeking damages, indemnity and a declaration that Tosco is responsible for the defined environmental liabilities arising from Pre-Acquisition Operations at our California refinery.

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. 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 2005, the parties agreed in principle to settle their claims, including the defined environmental liabilities arising from Pre-Acquisition Operations and certain additional environmental conditions, both discussed above, pending negotiation and execution of a final written settlement agreement. In the event we are unable to finalize the settlement, we intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail.

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 will become 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, approximately $9 million of which was spent during the 2006 first quarter. Included in the estimate are capital projects to manufacture ultra-low sulfur diesel at our Alaska refinery, for which we expect to spend approximately $53 million through 2007. We spent approximately $2 million during the 2006 first quarter. 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 sellers’ 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 $5 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.

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 we will make 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 (i) lower emissions and (ii) increase overall efficiency by lowering 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. We spent $10 million in the 2006 first quarter and $3 million in 2005. However, 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 this project to increase by approximately 50%. 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 $109 million from 2006 through 2010, $4 million of which was spent during the 2006 first quarter. 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.

Claims Against Third-Parties

Beginning in the early 1980s, Tesoro Hawaii Corporation, Tesoro Alaska Company and other fuel suppliers entered into a series of long-term, fixed-price fuel supply contracts with the U.S. Defense Energy Support Center (“DESC”). Each of the contracts contained a provision for price adjustments by the DESC. The federal acquisition regulations control how prices may be adjusted, and we and many other suppliers have filed in separate suits in the Court of Federal Claims contesting the DESC’s price adjustments prior to 1999. We and the other suppliers seek recovery of approximately $3 billion in underpayment for fuel. Our share of that underpayment totals approximately $165 million, plus interest. We alleged that the DESC’s price adjustments violated federal regulations by not adjusting the sales price of fuel based on changes to each supplier’s established prices or costs, as the Court of Federal Claims had held in prior rulings on similar contracts. The Court of Federal Claims granted partial summary judgment in our favor on that issue, but the Court of Appeals for the Federal Circuit has reversed and ruled that DESC’s prices did not need to be tied to changes in a specific supplier’s prices or costs. We have also asserted other grounds to challenge the DESC contract pricing formulas, and we are evaluating our position with respect to further litigation on those additional grounds. We cannot predict the outcome of these further actions.

In 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the transportation of its crude oil through the Trans Alaska Pipeline System (“TAPS”). Our protest asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory Commission of Alaska (“RCA”) considered our protest of the intrastate rates for the years 1997 through 2000. The RCA set just and reasonable final rates for the years 1997 through 2000, and held that we are entitled to receive approximately $52 million in refunds, including interest through the expected conclusion of appeals in December 2007. The RCA’s ruling is currently on appeal in the Alaska courts, and we cannot give any assurances of when or whether we will prevail in the appeal.

In 2002, the RCA rejected the TAPS Carriers’ proposed intrastate rate increases for 2001-2003 and maintained the permanent rate of $1.96 to the Valdez Marine Terminal. That ruling is currently on appeal to the Alaska Superior Court, and the TAPS Carriers did not move to prevent the rate decrease. The rate decrease has been in effect since June

TESORO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2003. If the RCA’s decision is upheld on appeal, we could be entitled to refunds resulting from our shipments from January 2001 through mid-June 2003. If the RCA’s decision is not upheld on appeal, we could have to pay additional shipping charges resulting from our shipments from mid-June 2003 through March 2006. We cannot give any assurances of when or whether we will prevail in the appeal. We also believe that, should we not prevail on appeal, the amount of additional shipping charges cannot reasonably be estimated since it is not possible to estimate the permanent rate which the RCA could set, and the appellate courts approve, for each year. In addition, depending upon the level of such rates, there is a reasonable possibility that any refunds for the period January 2001 through mid-June 2003 could offset some or all of any repayments due for the period mid-June 2003 through March 2006.

In July 2005, the TAPS Carriers filed a proceeding at the Federal Energy Regulatory Commission (“FERC”), seeking to have the FERC assume jurisdiction over future rates for intrastate transportation on TAPS. We have filed a protest in that proceeding, which has now been consolidated with another FERC proceeding seeking to set just and reasonable rates for future interstate transportation on TAPS. If the TAPS carriers should prevail, then the rates charged for all shipments of Alaska North Slope crude oil on TAPS could be revised by the FERC, but any FERC changes to rates for intrastate transportation of crude oil supplies for our Alaska refinery should be prospective only and should not affect prior intrastate rates, refunds or repayments.

NOTE J— NEW ACCOUNTING STANDARDS

EITF Issue No. 04-13

In September 2005, the Emerging Issues Task Force (“EITF”) reached a consensus on EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue No. 04-13 requires that two or more exchange transactions involving inventory with the same counterparty entered into in contemplation of one another should be reported net in the statement of operations. The inventory could be raw materials, work-in-process or finished goods. The provisions of this EITF issue also require the exchange of finished goods for raw materials or work-in-process inventories within the same line of business to be accounted for at fair value if the fair value is determinable within reasonable limits and the transaction has commercial substance as described in SFAS No. 153. Tesoro has historically not exchanged finished goods for raw materials. We adopted the provisions of EITF Issue No. 04-13 on January 1, 2006 for new arrangements entered into, and modifications or renewals of existing arrangements, which did not have a material impact on our financial position or results of operations. Prior to our adoption of EITF Issue No. 04-13, we had entered into a limited number of refined product purchases and sales transactions with the same counterparty which were reported on a gross basis in revenues and costs of sales and operating expenses in the condensed statements of consolidated operations. Refined product sales and purchases associated with these arrangements reported on a gross basis totaled $146 million and $159 million, respectively, for the three months ended March 31, 2005.

SFAS No. 154

In May 2005, the Financial Accounting Standards Board issued SFAS No. 154, “Accounting Changes and Error Corrections” which replaces Accounting Principles Board (“APB”) Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS No. 154 requires retrospective application of a voluntary change in accounting principle, unless it is impracticable to do so. This statement carries forward without change the guidance in APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. SFAS No. 154 became effective for changes in accounting principle made in fiscal years beginning after December 15, 2005. We adopted the provisions of SFAS No. 154 as of January 1, 2006, which had no impact on our financial position or results of operations.

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

Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” on page 27 for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

BUSINESS STRATEGY AND OVERVIEW

Our strategy is to create a value-added refining and marketing business that has (i) economies of scale, (ii) a low-cost structure, (iii) effective management information systems and (iv) outstanding employees focused on business excellence in a global market, that can provide stockholders with competitive returns in any economic environment.

Our goals are focused on: (i) operating our facilities in a safe, reliable, and environmentally responsible way; (ii) improving profitability by achieving greater operational and administrative efficiencies; and (iii) using excess cash flows from operations in a balanced way to create further shareholder value.

Our 2006 capital budget is approximately $670 million (including refinery turnaround and other maintenance costs of approximately $105 million). Our Board of Directors has approved the following three significant strategic capital projects which we expect to be substantially complete in 2007:

	•		The modification of our existing fluid coker unit to a delayed coker unit at our California refinery which is designed to lower emissions and increase overall efficiency by lowering operating costs. We previously expected to spend approximately $275 million through the fourth quarter of 2007 for this project, of which we have spent $13 million through the first quarter of 2006. However, 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 this project to increase by approximately 50%.

	•		A 25,000 barrels per day (“bpd”) delayed coker unit at our Washington refinery that will allow us to process a larger proportion of lower-cost heavy crude oils or manufacture a larger percentage of higher-value products. We previously expected to spend approximately $250 million through the fourth quarter of 2007 for this project, of which we have spent $6 million through the 2006 first quarter. However, 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 this project to increase by approximately 50%.

	•		A 10,000 bpd diesel desulfurizer unit at our Alaska refinery which will allow us to manufacture ultra-low sulfur diesel. We expect to spend approximately $55 million through the 2007 second quarter for this project of which we spent $5 million through the 2006 first quarter.

All cost estimates are subject to further review and analysis. Despite the estimated increases in overall capital expenditures for our two delayed coker projects, we expect our capital expenditures during the remainder of 2006 to approximate $507 million (excluding refinery turnaround and other maintenance costs of approximately $74 million).

In November 2005, our Board of Directors authorized a $200 million share repurchase program. During the 2006 first quarter, we repurchased 1.1 million shares of common stock for $71 million. Since the inception of the program, we have repurchased 1.4 million shares of common stock for $85 million through March 31, 2006. During April 2006, we repurchased an additional 198,900 shares of common stock under the program at a cost of $14 million.

The fundamentals of the refining industry remain strong on both a worldwide and a domestic level. Continued high demand growth in developing areas such as India and China, coupled with reduced surplus production capacity within OPEC, have lead to high prices for crude and petroleum products. In the U.S., refining margins remain above historical levels, in spite of an unusually warm winter, in part due to the following:

•

higher than normal industry maintenance during the first part of the year reflecting turnarounds which were postponed in 2005 due to hurricanes Katrina and Rita;

	•		the continued downtime at three refineries damaged by the hurricanes and other incidents; and

	•		the introduction at the beginning of the year of new, lower sulfur requirements for gasoline.

The outlook for the second quarter also remains strong due to continued demand growth and the introduction of MTBE free gasoline and ultra-low sulfur diesel.

RESULTS OF OPERATIONS — THREE MONTHS ENDED MARCH 31, 2006 COMPARED WITH THREE MONTHS ENDED MARCH 31, 2005

Summary

Our net earnings were $43 million ($0.63 per basic share and $0.61 per diluted share) for the three months ended March 31, 2006 (“2006 Quarter”), compared with net earnings of $28 million ($0.41 per basic share and $0.40 per diluted share) for the three months ended March 31, 2005 (“2005 Quarter”). The increase in net earnings during the 2006 Quarter was primarily due to higher throughput levels, lower interest expense as a result of debt reduction and refinancing in 2005 and decreased corporate general and administrative expenses. Net earnings for the 2005 Quarter included charges for executive termination and retirement costs of $6 million aftertax or $0.09 per share. A discussion and analysis of the factors contributing to our results of operations is presented below. The accompanying condensed consolidated financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.

Refining Segment


	Three Months Ended
	March 31,
(Dollars in millions except per barrel amounts)	2006			2005
Revenues
Refined products (a)	$	3,727		$	2,953
Crude oil resales and other		103			175

Total Revenues	$	3,830		$	3,128


Refining Throughput (thousand barrels per day) (b)
California		152			149
Pacific Northwest
Washington		108			82
Alaska		46			58
Mid-Pacific
Hawaii		86			84
Mid-Continent
North Dakota		54			56
Utah		51			48

Total Refining Throughput		497			477


% Heavy Crude Oil of Total Refining Throughput (c)		49	%		55	%


Yield (thousand barrels per day)
Gasoline and gasoline blendstocks		234			223
Jet fuel		69			65
Diesel fuel		100			91
Heavy oils, residual products, internally produced fuel and other		114			116

Total Yield		517			495


	Three Months Ended
	March 31,
(Dollars in millions except per barrel amounts)	2006		2005
Refining Margin ($/throughput barrel) (d)
California
Gross refining margin	$	13.26	$	16.58
Manufacturing cost before depreciation and amortization	$	6.06	$	5.54
Pacific Northwest
Gross refining margin	$	7.20	$	4.57
Manufacturing cost before depreciation and amortization	$	3.18	$	3.20
Mid-Pacific
Gross refining margin	$	3.23	$	4.04
Manufacturing cost before depreciation and amortization	$	1.56	$	1.67
Mid-Continent
Gross refining margin	$	8.17	$	5.08
Manufacturing cost before depreciation and amortization	$	3.18	$	2.69
Total
Gross refining margin	$	8.52	$	8.37
Manufacturing cost before depreciation and amortization	$	3.77	$	3.55

Segment Operating Income
Gross refining margin (after inventory changes) (e)	$	395	$	367
Expenses
Manufacturing costs		169		153
Other operating expenses		39		39
Selling, general and administrative		5		7
Depreciation and amortization (f)		54		35
Loss on asset disposals and impairments		3		1

Segment Operating Income	$	125	$	132


Product Sales (thousand barrels per day) (a) (g)
Gasoline and gasoline blendstocks		271		267
Jet fuel		91		96
Diesel fuel		125		123
Heavy oils, residual products and other		82		69

Total Product Sales		569		555


Product Sales Margin ($/barrel) (g)
Average sales price	$	73.36	$	59.09
Average costs of sales		65.78		51.36

Product Sales Margin	$	7.58	$	7.73


(a)		Includes intersegment sales to our retail segment, at prices which approximate market of $198 million and $185 million for the three months ended March 31, 2006 and 2005, respectively.

(b)		We experienced reduced throughput during scheduled maintenance turnarounds at the California refinery during the 2006 and 2005 first quarters and the Washington refinery during the 2005 first quarter.

(c)		We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 degrees 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 $1.11 and $0.73 for the three months ended March 31, 2006 and 2005, respectively.

(g)		Sources of total product sales include 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.

Three Months Ended March 31, 2006 Compared with Three Months Ended March 31, 2005. Operating income from our refining segment was $125 million in the 2006 Quarter compared to $132 million for the 2005 Quarter. The $7 million decrease in our operating income was primarily due to lower industry refining margins on the U.S. west coast and increased operating expenses, partly offset by slightly higher total gross refining margins and throughput. Total gross refining margins increased to $8.52 per barrel in the 2006 Quarter, compared to $8.37 per barrel in the 2005 Quarter. Our total gross refining margins increased despite lower industry refining margins in the 2006 Quarter as compared to the 2005 Quarter in all of our regions except for the Mid-Continent region. Industry margins on the U.S. west coast were negatively impacted during the 2006 Quarter as a result of heavy rains impacting demand and record high industry throughput and gasoline production resulting in higher average inventory levels for finished products. Industry margins on a national basis increased during the 2006 Quarter compared to the 2005 Quarter primarily due to the continued increased demand for finished products due to improved economic fundamentals worldwide, higher than normal industry maintenance during the 2006 Quarter which was postponed in 2005 due to hurricanes Katrina and Rita and the impact of more stringent sulfur requirements for gasoline at the beginning of the year.

Gross refining margins at our California refinery decreased to $13.26 per barrel in the 2006 Quarter from $16.58 per barrel in the 2005 Quarter. In addition to the factors discussed above, gross refining margins at our California refinery were impacted by a scheduled maintenance turnaround during the 2006 Quarter. As a result of the turnaround, we manufactured a higher percentage of lower-valued heavy products. Despite lower gross refining margins in our California and Mid-Pacific regions, our total gross refining margin increased year-over-year due to significant improvements in our Pacific Northwest and Mid-Continent regions. Gross refining margins in our Pacific Northwest region increased to $7.20 per barrel in the 2006 Quarter from $4.57 per barrel in the 2005 Quarter and in our Mid-Continent region gross refining margins increased to $8.17 per barrel in the 2006 Quarter from $5.08 per barrel in the 2005 Quarter. The year-over-year improvement in gross refining margins in our Pacific Northwest region was primarily due to the negative impacts during the 2005 Quarter of a scheduled maintenance turnaround of the crude and naphtha reforming units and unscheduled downtime due to outages of certain processing equipment at our Washington refinery. The 2005 turnaround resulted in the Washington refinery processing higher cost blendstocks instead of crude oil. In our Mid-Continent region, refining margins were negatively impacted during the 2005 Quarter as our Utah refinery experienced higher crude oil costs due to Canadian production constraints and depressed market fundamentals in the Salt Lake City area.

Total refining throughput averaged 497 thousand barrels per day (“Mbpd”) in the 2006 Quarter compared to 477 Mbpd during the 2005 Quarter. The increase in refining throughput is primarily a result of experiencing less scheduled and unscheduled downtime during the 2006 Quarter. During the 2006 Quarter, we experienced a scheduled maintenance turnaround at our California refinery. We also experienced reduced throughput at our Alaska refinery during the 2006 Quarter as a result of the grounding of our time-chartered vessel which impacted our supply of feedstocks to the refinery. As described above, in the 2005 Quarter we experienced scheduled major maintenance turnarounds and other unscheduled downtime at both our California and Washington refineries.

Revenues from sales of refined products increased 23% to $3.7 billion in the 2006 Quarter, from $3.0 billion in the 2005 Quarter, primarily due to significantly higher average product sales prices combined with slightly higher product sales volumes. Our average product prices increased 24% to $73.36 per barrel, reflecting the continued strength in market fundamentals. Total product sales averaged 569 Mbpd in the 2006 Quarter, an increase of 14 Mbpd from the 2005 Quarter. Our average costs of sales increased 28% to $65.78 per barrel during the 2006 Quarter reflecting

significantly higher average feedstock prices. Expenses, excluding depreciation and amortization, increased to $216 million in the 2006 Quarter, compared with $200 million in the 2005 Quarter, primarily due to higher utilities of $15 million. Depreciation and amortization increased to $54 million in the 2006 Quarter, compared to $35 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 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.

Retail Segment


	Three Months Ended
	March 31,
(Dollars in millions except per gallon amounts)	2006			2005
Revenues
Fuel	$	213		$	197
Merchandise and other		32			31

Total Revenues	$	245		$	228

Fuel Sales (millions of gallons)		99			111
Fuel Margin ($/gallon) (a)	$	0.15		$	0.12
Merchandise Margin (in millions)	$	8		$	8
Merchandise Margin (percent of sales)		25	%		25	%
Average Number of Stations (during the period)
Company-operated		210			215
Branded jobber/dealer		263			291

Total Average Retail Stations		473			506

Segment Operating Loss
Gross Margins
Fuel (b)	$	15		$	13
Merchandise and other non-fuel margin		9			8

Total gross margins		24			21
Expenses
Operating expenses		22			22
Selling, general and administrative		6			6
Depreciation and amortization		4			4
Loss on asset disposals and impairments		4			¾

Segment Operating Loss	$	(12	)	$	(11	)


(a)		Management uses fuel margin per gallon to compare profitability to other companies in the industry. Fuel margin per gallon is calculated by dividing fuel gross margin by fuel sales volumes and may not be calculated similarly by other companies. Investors and analysts use fuel margin per gallon to help analyze and compare companies in the industry on the basis of operating performance. This financial measure should not be considered as an alternative to segment operating income and revenues or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America.

(b)		Includes the effect of intersegment purchases from our refining segment at prices which approximate market.

Three Months Ended March 31, 2006 Compared with Three Months Ended March 31, 2005. Operating loss for our retail segment was $12 million in the 2006 Quarter, compared to an operating loss of $11 million in the 2005 Quarter. The 2006 Quarter included an impairment of $4 million for the pending sale of 13 retail sites located in the Pacific Northwest. The sale is expected to be completed during the 2006 second quarter. Total gross margins increased to $24 million during the 2006 Quarter from $21 million in the 2005 Quarter reflecting higher fuel margins per gallon partially offset by lower sales volumes. Fuel margin increased to $0.15 per gallon in the 2006 Quarter compared to $0.12 per

gallon. Total gallons sold decreased to 99 million from 111 million, reflecting the decrease in average station count to 473 in the 2006 Quarter from 506 in the 2005 Quarter. The decrease in average station count reflects our continued rationalization of retail assets.

Revenues on fuel sales increased to $213 million in the 2006 Quarter, from $197 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.

Selling, General and Administrative Expenses

Selling, general and administrative expenses totaled $40 million in the 2006 Quarter, compared to $54 million in the 2005 Quarter. The decrease was due to charges totaling $11 million for the termination and retirement of certain executive officers during the 2005 Quarter and lower contract labor expenses of $7 million, partially offset by higher employee expenses of $4 million.

Interest and Financing Costs

Interest and financing costs amounted to $20 million in the 2006 Quarter, compared to $32 million in the 2005 Quarter. The decrease during the 2006 Quarter was 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.

Interest Income and Other

Interest income and other amounted to $10 million in the 2006 Quarter, compared to $1 million in the 2005 Quarter. The increase during the 2006 Quarter is due to a significant increase in invested cash balances and a gain of $5 million associated with the sale of our leased corporate headquarters by a limited partnership in which we were a 50% limited partner.

Income Tax Provision

The income tax provision totaled $28 million in the 2006 Quarter, compared to $19 million in the 2005 Quarter, reflecting higher earnings before income taxes. The combined federal and state effective income tax rate was 39% and 40% for the 2006 and 2005 Quarters, 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, worldwide geo-political conditions and overall market and economic conditions. See “Forward-Looking Statements” on page 27 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 first quarter of 2006 with $306 million of cash and cash equivalents, no borrowings, and $571 million in available borrowing capacity under our $750 million revolving credit agreement after $179 million in outstanding letters of credit. We also have a separate letters of credit agreement of which we had $77 million available after $88 million in outstanding letters of credit as of March 31, 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 March 31, 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
8% Senior Secured Notes Due 2008		9
9⁵/₈% Senior Subordinated Notes Due 2012		14
Junior subordinated notes due 2012		95
Capital lease obligations		31

Total debt		1,049
Stockholders’ equity		1,869

Total Capitalization	$	2,918

At both March 31, 2006 and December 31, 2005, our debt to capitalization ratio was 36%.

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

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 will 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 Quarter, we repurchased 1.1 million shares of common stock under the program for $71 million, or an average cost per share of $62.71. As of March 31, 2006, $115 million remained available for future repurchases under the program. During April 2006, we repurchased an additional 198,900 shares of common stock under the program at a cost of $14 million.

Cash Flow Summary

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


	Three Months Ended
	March 31,
	2006			2005
Cash Flows From (Used In):
Operating Activities	$	16		$	(57	)
Investing Activities		(80	)		(64	)
Financing Activities		(70	)		25

Decrease in Cash and Cash Equivalents	$	(134	)	$	(96	)

Net cash from operating activities during the 2006 Quarter totaled $16 million, compared to $57 million used in operating activities in the 2005 Quarter. The increase was primarily due to increased earnings, higher depreciation and amortization, and lower working capital requirements. Net cash used in investing activities of $80 million in the 2006 Quarter was primarily for capital expenditures. Net cash used in financing activities primarily reflects repurchases of our common stock totaling $72 million (including $71 million associated with the common stock repurchase program). During the 2006 Quarter, we did not borrow or make repayments under the revolving credit facility. Working capital decreased to $680 million at March 31, 2006 compared to $713 million at year-end 2005, primarily as a result of the decrease in cash and cash equivalents, partially offset by an increase in inventory values.

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 (used in) operating activities was (in millions):


	Three Months Ended
	March 31,
	2006			2005
Net Cash From (Used in) Operating Activities	$	16		$	(57	)
Changes in Assets and Liabilities		104			136
Excess Tax Benefits from Stock-Based Compensation Arrangements		6			10
Deferred Income Taxes		(7	)		(6	)
Stock-Based Compensation		(6	)		(9	)
Loss on Asset Disposals and Impairments		(7	)		(1	)
Amortization and Write-off of Debt Issuance Costs and Discounts		(3	)		(4	)
Depreciation and Amortization		(60	)		(41	)

Net Earnings	$	43		$	28
Add Income Tax Provision		28			19
Less Interest Income and Other		(10	)		(1	)
Add Interest and Financing Costs		20			32

Operating Income		81			78
Add Depreciation and Amortization		60			41
Add Gain on Partnership Sale		5			¾

EBITDA	$	146		$	119

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

During the 2006 Quarter, our capital expenditures, including accruals, totaled $58 million (excluding refinery turnaround and other maintenance costs of $31 million), and included $21 million for clean air, clean fuels and other environmental projects, $10 million for the delayed coker modification at our California refinery, $11 million for other refinery improvements at our California refinery and $4 million for the delayed coker unit at our Washington refinery. Refinery turnaround and other maintenance costs consisted primarily of the scheduled turnaround at our California refinery which was completed during the 2006 Quarter.

Despite the estimated increases in overall capital expenditures for our two delayed coker projects, we expect our capital expenditures during the remainder of 2006 to approximate $507 million (excluding refinery turnaround and other major maintenance costs of approximately $74 million).

Environmental and Other

Environmental Liabilities

During the first quarter of 2006, we continued settlement discussions with the California Air Resources Board (“CARB”) concerning a notice of violation (“NOV”) we received in October 2004. The NOV, issued by CARB, alleged that Tesoro offered eleven batches of gasoline for sale in California that did not meet CARB’s gasoline exhaust emission limits. In January 2006, we executed a Settlement Agreement and Release with CARB and paid a civil penalty of $325,000 to resolve this matter.

Other Environmental Matters

Environmental Capital Expenditures

In connection with the 2002 acquisition of our California refinery, subject to certain conditions, we assumed the seller’s 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 we will make 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.

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 our 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 are our primary sources of market risk. We have a risk management committee responsible for reviewing 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 497,000 bpd, would change annualized pretax operating income by approximately $181 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 30 million barrels and 28 million barrels at March 31, 2006 and December 31, 2005, respectively. The average cost of our refinery feedstocks and refined products at March 31, 2006 was approximately $39 per barrel on a LIFO basis, compared to market prices of approximately $74 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 crude oil 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 quarter. Accordingly, no change in the value of the related underlying physical asset is recorded. During the first quarter of 2006, we settled futures and swaps positions of approximately 24 million barrels of crude oil and refined products, which resulted in gains of $1 million. At March 31, 2006, we had open net futures contracts and swap positions of 3 million barrels and 2 million barrels, respectively, which will expire at various times during 2006. We recorded the fair value of our open positions, which resulted in an unrealized mark-to-market loss of $6 million at March 31, 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 5 million barrels as of March 31, 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 $5 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 March 31, 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 $10 million less than its carrying value at March 31, 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 period covered by this report, 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

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 March 31, 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*

January 2006

30,000

61.19

30,000

$184 million

February 2006

421,069

62.71

391,800

$159 million

March 2006

705,000

62.88

705,000

$115 million

Total

1,156,069

62.78

1,126,800

$115 million


*		All of the shares repurchased during the three-months period ended March 31, 2006 were acquired pursuant to the stock repurchase program (see below), except for 29,269 shares acquired in February 2006, which were surrendered to Tesoro to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to certain executive officers.

**		Tesoro’s existing stock repurchase program was publicly announced on November 3, 2005. The program authorizes Tesoro to purchase up to $200 million aggregate purchase price of shares of Tesoro’s common stock.

ITEM 6. EXHIBITS

(a)

Exhibits

	3.1		Certificate of Amendment to Restated Certificate of Incorporation of the Company.

	31.1		Certification by Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2		Certification by Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1		Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2		Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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


		TESORO CORPORATION

Date: May 4, 2006		/s/ BRUCE A. SMITH
		Bruce A. Smith
		Chairman of the Board of Directors,
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: May 4, 2006		/s/ GREGORY A. WRIGHT
		Gregory A. Wright
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

EXHIBIT INDEX


Exhibit
Number
3.1		Certificate of Amendment to Restated Certificate of Incorporation of the Company.

31.1		Certification by Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification by Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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