exv99w1

Exhibit 99.1

Investor Presentation

November 2006

501% Total Shareholder Return Since 2003

Low or No

Capital Driven Capital Growth through Strategic Acquisitions Organic Improvement Growth $80 Initiative

Debt Crude Reduction Flexibility $60

Washington $40 Acquired

Hawaii Acquired GE Salt Lake City & Acquired $20 Mandan Acquired

$0 19981999 2000 2001 2002 2003 2004 2005 2006

Analyst Presentation -November 2006 Slide 1

Tesoro Investment Considerations

• Organizational effectiveness drive continues

· New capital-driven organic growth opportunities in the system

· Assets have real potential to capture new value

Access to Canadian Crudes

· Existing pipeline to three refineries

· Future waterborne access to an additional three

Reliability –constant trend of higher production capabilities

Marketing – upgrading channel mix and expanding product offtake to drive higher utilization

High quality octane components for CARBOB production are in tight supply since the removal of MTBE

· Tesoro maximizes premium component potential by moving product between markets

· Balanced position on premium gasoline components

Analyst Presentation-November 2006 Slide 2

Drive to Achieve Operational Excellence

mbpd $/bbl 550 $0.00 Tesoro Cost of Crude vs. WTI

500

TSO Throughput

450 ($4.00) 2003 2004 2005 2006*

* 2006 is Trailing Twelve Months

Analyst Presentation -November 2006 Slide 3

Business Review

• Tesoro has moved from single focus on debt reduction to generating superior shareholders returns

2002: $2.1 billion of debt after purchase of Golden Eagle, 68% debt:cap

Currently 30% debt:cap and will continue to focus on balanced use of cash to grow shareholders returns

• Capital-Driven Organic Growth

· Stock buyback, and

· Dividends

• New, centralized management team is entering its second year of natural working teams

Lowering feedstock costs Optimizing channels of trade Analyst Presentation -November 2006 Slide 4

Tesoro’s Refining System

Kenai, Alaska

· 72 mbpd

· 4.9 complexity

· Key product : Jet

Anacortes, Washington

· 115 mbpd

· 8.2 complexity

· Key product : Gasoline

Mandan, North Dakota

· 58 mbpd

· 7.8 c

omplexity

· Key product : Gasoline & Diesel

Salt Lake City, Utah

· 58 mbpd

· 6.3 complexity

· Key product

: Gasoline & Diesel

Martinez, California

· 166 mbpd

· 13.5 complexity

· Key product : CARB Gasoline

Kapolei, Hawaii

· 94 mbpd

· 4.5 complexity

· Key product :

Jet

Analyst Presentation -November 2006 Slide 5

Who We Are • 2^ndlargest refiner in the Western US

· Operate in a region with highest historical market spreads

· Connected assets allows optimization of products into highest value markets

Product transfer among Anacortes, California, Hawaii, Alaska and Salt Lake City

• Global trading offices: Singapore, Calgary, Long Beach, Denver and San Antonio

· Unique product areas: production matched to demand

Refinery production is matched to area consumption

•Alaska/Hawaii: Jet •California: Gasoline Analyst Presentation -November 2006 Slide 6

Near Term Fundamentals

Analyst Presentation -November 2006 Slide 7

New Ethanol Capacity Will Not Replace The Energy Lost From MTBE Until 2009/10

mbpd -ethanol Net Ethanol Additions

equivalents

700 600 500 400 300

200 100

0 MTBE2006 2007 2008 2009 2010 2011 2012 Loss

Source: EIA, FBR Analyst Presentation -November 2006 Slide 8

Early Sulfur Credits Will Not Be Available Beginning 2007

• Early Sulfur Credits

Generated for levels below 90% of 1997/98 baseline

Generated in years 2000 – 2003 Used for compliance in 2005/06

• Venezuela believed heavily dependent on credits

93 % gasoline exports to the U.S.(75-85 MBPD)

Export refineries run high sulfur crudes

Little investment in hydrotreating/none planned

Analyst Presentation -November 2006 Slide 9

Inventories Have Been Dropping Rapidly In October Due To Heavy Turnarounds

Gasoline On Road Diesel

mmbl mmbl 220 100

215

210

80 205 70 200

60 195

190 50 Wk1 Wk2 Wk3 Wk4 2005 Wk1 Wk2 Wk3 Wk4 2005

Source: EIA Analyst Presentation -November 2006 Slide 10

Product Demand Is Growing

Gasoline Demand Growth Diesel Demand Growth

Annual % Growth Annual % Growth 3 3.0

2.5 2.5 Ex Hurricanes

2 2.0

Ex Hurricanes 1.5 1.5

1 1.0 0.5 0.5

00.0 Historical 2005 1Q 2Q 3Q (0.5) Historical 2005 1Q 2Q 3Q Source: EIA Analyst Presentation -November 2006 Slide 11

West Coast Slides Analyst Presentation -November 2006 Slide 12

Heavy West Coast Turnaround Schedule In The January -April 2007 Timeframe

Distillation Turnarounds Conversion Turnarounds

% Capacity % Capacity 9 Down 7 Down

8 6 7 5 6

5 4

4 3 3 2 2 1 1

0 0 J F M A J F M A 2007 Forecast 2006 2007 Forecast 2006

Source: PIRA

Analyst Presentation -November 2006 Slide 13

The West Coast Is Highly Leveraged To On Road Diesel And Imports Are Growing

On Road % Diesel Demand PADD 5 On Road Imports

% Total Demand MBPD

90 30 5.6% Total Demand

25 85

20 80 15 75 10

70 5

65 0

PADD’s 1-3 PADD 4 PADD 5 2001 2002 2003 2004 2005 YTD

2006

Source: EIA Analyst Presentation -November 2006 Slide 14

Guidance Analyst Presentation -November 2006 Slide 15

2006 Capital Update

• Total projected Capexspend is $550 -$575 million

Present challenging environment around project execution makes estimates fluid

Managing total Capex program around our cash flow projections and economic guidelines

• Projects impacting 2007 EBITDA are completed or near completion

· Anacortes coker project cancelled No longer met return requirements Reduced 2006 capital spend by $71 million

Moving forward with sulfur handling portion of project that allows incremental sour crude processing

Analyst Presentation -November 2006 Slide 16

Golden Eagle Coker Modification Update

• Modification of existing fluid coker to a delayed provides both environmental and economic benefits

Environmental

• Fulfills consent decree with air quality regulators

•Reduces emissions Economic Drivers

• Cycle-average EBITDA enhanced by approximately $100 million

Allows incrementally heavier crude slate and lower maintenance costs/higher reliability

• Required turnaround maintenance extended to every 5 years versus current requirement of every 2.5

· Turnarounds reduced from 55 days to 35 days

Projected cost is $475 -$525 million Expected on-line in early 2008 Analyst Presentation -November 2006 Slide 17

2006 Capital Update -Strategic Organic Growth Projects

2007 Incremental Project Benefits EBITDA*

•Improved unit reliability

Golden Eagle Control • Improved communication between operating areas $10 -$20 Million Room Modernization

• Advanced process control & optimization

· Potential for 100% waterborne crude Golden Eagle Amorco

· Reduced demurrage $30 -$50 Million

Wharf Expansion

• Improved measurement accuracy Hawaii Ultra Low • Sole producer of ULSD on the islands

$10 -$ 20 Million

Diesel Optimization • Increased sulfur recovery capability Anacortes Fluid Cat • Improved fuel efficiency

•Improved product recovery from $3 -$6 Million Cracker Optimization refinery fuel system Alaska Ultra Low • 10 mbpd Diesel De-Sulfurization Unit

$25 -$30 Million

Sulfur Diesel Project • Sole producer of ULSD in Alaska

* Reflects trailing twelve month basis at June 2005

Analyst Presentation -November 2006 Slide 18

2007 Capital Outlook

• Total projected Capex spend is $550 — $650 million (includes turnaround spending of $90-$100 million)

· Golden Eagle coker modification project expenditures of $200 — $220 million, remaining will be spent in 2008

· Only significant turnaround is Golden Eagle FCC during 1Q07

· Anacortes sulfur handling project expected completion in mid-2007

Total spending approximately $34 million

Combination of new Amine Plant and additional sulfur capacity allows higher-sulfur crude slate

Analyst Presentation -November 2006 Slide 19

2007 Modeling Guidance Turnarounds/Projects On-Stream/Throughput 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Full Year Control Room & Amorco California Refinery FCC TAR

Wharf Complete

WA FCC AK DDU WA Sour Pacific Northwest Refineries (AK & HI) Upgrades Complete Crude Project Ultra-Low Mid-Pacific Refinery (HI) Sulfur Optimization¹Mid-Continent Refineries (UT & ND)

Expected Total Throughput (mbpd) 485 — 505 540 — 560 540 — 560 515 — 535 520 — 540

¹ Completed in late 2006

Other 2007 Guidance (millions)

Depreciation and Amortization $ 280 Interest (less Capitalized Interest) 75 Corporate & Unallocated 150 Tax Rate 38% Cash Taxes % of Book 80% Dividends ($0.40/share) 28

Analyst Presentation -November 2006 Slide 20

2007 First Call Cash Flow Outlook

(millions) 2006 2007

First Call EPS $10.17 $7.57 Assumed Shares Outstanding¹ 70.1 69.9 Free Cash Flow Model EBITDA $1,475 $1,200

Incremental EBITDA from Projects

Cash Taxes (375) (250) Cash Interest (75) (75) Capital Expenditures (575) — (550) (650) — (550) Free Cash Flow $ 450 — $475 $ 225 — $325

¹ Reflects 2006 YTD through September Diluted Weighted Average Comm on Shares, 2007 reflects 3rd Quarter average. Does not reflect impact of additional share repurchases.

Analyst Presentation -November 2006 Slide 21

Appendix Analyst Presentation -November 2006 Slide 22

Forward Looking Statements

• This Presentation includes forward-looking statements with in the meaning of the Private Securities Litigation Reform Act of 1995. These statements relate to, among other things, projections of refining margins, debt reduction, cash fl ows and capital expenditures. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “project”, “should”, “will” and similar terms and phrases to identify forward-looking statements in this Presentation.

· Although we believe the assumptions upon which these forward-look ing 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 cont rol, 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 fa ctors which 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 Presentation.

Analyst Presentation -November 2006 Slide 23

Golden Eagle Coker Modification, Crude Dynamics

mbpd

Delayed

Coker Run

45 Rate

40 35 30 25

Fluid Coker

Run Rate

15 10 5 0

Year 12 3 4 5 6 7 8 9 10 Analyst Presentation -November 2006 Slide 24

EBITDA Per Barrel of Throughput

$3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $-

3Q05 4Q05 1Q06 2Q06 3Q06 TSO VLO SUN

12-month rolling average. EBITDA and throughput for peers are taken from reports on Form 10-K and 10-Q, and is calculated in a s imilar manner as Tesoro’s calculation.

Analyst Presentation -November 2006 Slide 25