2. We Need an Economic Recovery
U.S.
U S Non-Farm Payroll Employment Change U.S.
U S Freight Shipment Index
(Month-Over-Month) 1.4
Thousands
400
1.3
200
Market Fundamentals
1.2
0
1.1
-200
1.0
Jan 1990 = 1.0
-400
0.9
0.8
-600
Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09
Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09
Source: U.S. Bureau of Labor Statistics Source: Cass Freight Systems
1
3. Demand Has Weakened
Substantially
MMBPD Global Refining Supply and Demand
3.5
Petroleum Demand Growth
3.0
30
Jan 2008 Crude Unit Expansions
2.5 Demand
Conversion Capacity Growth
Forecast
2.0
1.5
1.0
Market Fundamentals
0.5
0.0
-0.5
-1.0
2003 2004 2005 2006 2007 2008E 2009E 2010E 2011E 2012E 2013E
Source: Industry reports and Valero forecast; 2008 through 2013 estimates are based on consultant averages and are subject to change; includes capacity creep
• Near-term demand weakness creating g • Eventually, economic recovery drives
y, y
spare capacity demand growth
• Projects getting canceled and deferred • The world will need more refining
capacity again
• Threat to less competitive refiners
Building greenfield projects
Leading to bankruptcies d t ti l
L di t b k t i and potential
closures Return on investments at
replacement costs
2
4. Expect OPEC Cut on Relatively Low
Crude Oil Prices
MMBPD
WTI Cushing (per bbl) OPEC-11 Production and Quota
31
$150
30
$130
29
$110
28
$90
27
$70
Market Fundamentals
Quota
26
Actual Crude Production
$50 25
$30 24
Nov-05 May-06 Nov-06 May-07 Nov-07 May-08 Nov-08 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09
Source: Argus weekly averages; 2009 through January 30 Source: Average of Industry Reports and Consultants
• Longer-term – oil prices may climb as
• Crude oil market looking for support
demand increases
• 2009 economic activity very weak
Lower prices causing some project
Huge worldwide stimulus being applied
delays
• Expect OPEC to cut again Non-OPEC crude production at low
• Lo crude oil prices good for the
Low cr de growth or decline
th d li
economy and ultimately demand U.S. restrictions on drilling
3
5. Gasoline Supply Capacity in Surplus
Relative to Demand
250 $40
U.S. Gasoline Inventory (millions of barrels) Gulf Coast Gas Crack (vs. WTI, per bbl)
$35
240
$30
230
$25
2008
220 5-Yr Avg
$20
2008
210 $15
2009 2009
$10
200
5-Yr Avg
$5
Market Fundamentals
190
$0
2009 Forward Curve
180 -$5
-$10
170
Jan Apr Jul Oct
Jan Apr Jul Oct
Source: Argus weekly averages; 2009 through January 30
Source: DOE unadjusted weekly data; 2009 through January 23
• U.S. gasoline inventories in good • Gulf coast gas crack much
shape – near 5-year average improved
impro ed since 4Q08
• Refiners reducing utilization of
• Expect actual 2009 gasoline
gasoline making units
margins will be better than
FCCs and reformers
forward curve
Valero taking extra units down during
Refiners must restrict output
planned maintenance
• Lower pump prices helping demand Demand improvements
recovery 4
6. Distillate Margins Continue
To Be Favorable
U.S. and Europe Commercial Distillate/ Gulf Coast On-Road Diesel Crack
500 $40
Gasoil Inventories (millions of barrels) (vs. WTI, per bbl)
$35
475
4 2008
2006
$30
2007
2005
450 2009
$25
5-Yr Avg
$20
425 2008
Market Fundamentals
$15
400
2009 Forward Curve
$10
375 $5
Jan Apr Jul Oct Jan Apr Jul Oct
Source: IEA and Euroilstock as of December 2008; Includes heating oil, diesel, gasoil Source: Argus weekly averages; 2009 through January 27; LSD prior to May 2006;
ULSD after April 2006; 2009 Forward Curve as of January 30
• Expect long-term demand growth • Distillate margins strong all of 2008 and in
January 2009
Growing faster than gasoline
• Despite U.S. volumes down, getting near-term
worldwide
support from:
Economic growth drives diesel
Colder-than-normal weather in northern
demand hemisphere
p
• Supply options limited Tight European inventories due to disruption of
Fewer substitutes such as ethanol for Russian gas supply
gasoline • World is still tight on diesel
5
7. Expect Feedstock Discounts to
Improve
$20 35%
Maya Crude Differentials (per bbl) Maya Percentage Crude Differentials
30%
vs. WTI
$15
vs. WTI
vs. LLS
25%
vs. LLS
$10
20%
Market Fundamentals
$5
15%
10%
$0
2002 2003 2004 2005 2006 2007 2008 2009
2002 2003 2004 2005 2006 2007 2008 2009
YTD YTD
Source: Argus quarterly averages; 2009 through January 30 Source: Argus monthly averages; 2009 through January 30
• Crude discounts vs. WTI recently • Longer-term, cancellations and
narrowed deferrals of cokers and upgraders
reduce demand for heavy oil
WTI’s recent weakness and steep
Examples: MRO Detroit, VLO Port Arthur,
contango – Cushing issue
Petro-Canada Fort Hills, Suncor Voyageur,
OPEC cutting medium sour barrels
g
and BA E
d Energy H tl d
Heartland
• Compared to LLS, discounts still good
• Also, Valero working to encourage
delivery of Canadian heavy crude oil
6
to Gulf Coast
8. Why Own Valero?
• Larger More Complex, Lower cost
Larger, Complex Lower-cost
Refineries
• Strong Financial Position
• Continuing to Invest in Growth Projects
with Disciplined Capital Program
• Shareholder Focused Company
Shareholder-Focused
• Improving Competitiveness
7
9. Valero’s Refineries Are Larger and
More Complex
U.S. Refinery Crude Distillation Unit Capacity vs. Nelson Complexity
25
121 MBPD Avg
Avg.
CDU Capacity Valero Refineries
20 Avg. VLO CDU Capacity = 160 MBPD
Nelson Complexity Index
Avg. VLO Complexity = 11.9
Other U.S. refineries
y
15
Why Own Valero?
10
V
10.6 Avg.
10 6 Avg
n
Complexity
5
0
0 100 200 300 400 500 600
CDU Capacity, MBPD
Source: Oil and Gas Journal, PIRA, and Valero estimates
• Smallest, least complex refineries in lower-left quadrant: total of 75 refineries and
3.3 million barrels per day of CDU capacity
• Valero’s average CDU capacity is 160,000 barrels per day and complexity is 11.9 8
10. Valero Has Lowest Cost per Barrel
Cash Operating Expense per Barrel for
Independent Refiners1
$7.00
$
$6.50
$6.00
Why Own Valero?
$
$5.50
V
$5.00
$4.50
$4.00
TSO FTO HOC SUN WNR ALJ VLO
120081Q through 3Q refining operating expense excluding depreciation and amortization divided by refinery throughput volumes; data per
company filings and Valero estimates
11. Strong Financial Position
Debt Maturities and Puts (millions)
• Investment-grade credit rating
$600
Upgraded a notch by Moody’s in 4Q08
Moody s
S&P and Moody’s re-affirmed rating in
$400
January
• Over $5 billion in liquidity at year-end
$200
$940 million i cash
illi in h
$4.7 billion of credit available, net of letters
Why Own Valero?
$-
of credit issued
2009 2010 2011
No borrowings on credit facilities
V
• Manageable debt schedule Net Debt-to-Capitalization Ratio (period-end)
In 2008, paid off $357 million of debt 60%
2009 debt maturities of $310 million 50%
2010 debt maturities only $30 million 40%
• Year-end net debt-to-cap ratio at 26.2% 30%
Includes goodwill write-off in 4Q08 20%
Maximum net debt-to-cap ratio per bank 10%
agreement is 60% 0%
No coverage-type ratios in covenants 2001 2002 2003 2004 2005 2006 2007 2008
• No goodwill on year-end balance sheet
10
12. Continuing to Invest in Growth Projects
with Disciplined Capital Program
• 2009 budget estimated at $2.7 billion, down from previous $3.5 billion
Will continue to evaluate budget for additional reductions
• Non-strategic workload declining as legacy issues addressed
• Strategic capital focused on flagship refineries
• Estimate minimum capital of $1.8 billion over next couple of years, including
p $ p y , g
regulatory
Why Own Valero?
$3,750 Millions
V
$3,200
Strategic
$920
$2,695 $2,700
$1,110
Tier II
$680
$990
$ ,0 0
$1,020
$50
$325
Sustaining/
$-
Reliability $705 $1,200 $555
$895
$490
$550
Turnarounds
$
$410
$505
$635
$585 $430
$290
Regulatory
2006 2007 2008 2009 Estimate
11
13. Shareholder-
Shareholder-Focused Company
Diluted Shares Outstanding (Wtd. Avg.)
Millions Annual Dividends per Share
$
$0.60
700
$0.50
660
Cut share count
by 134 million $0.40
620
(21%) since
year-end 2005
d $0.30
580
Why Own Valero?
$0.20
540
$0.10
V
500
$0.00
2000 2001 2002 2003 2004 2005 2006 2007 2008
Stock Buybacks Reduced Sharecount Dividend Growth
• I 2008, purchased 23 million shares,
In 2008 h d illi h • At stock price of $23/ h 2 5% yield
tki f $23/sh., 2.5% i ld
reducing share count by 4% using last 4 quarters of dividends
payments
• Since early 2006, have reduced share
count by 21% • In 2008, raised quarterly dividend per
share by 25% from $0.12 to $0.15
• In 2009, plan is to conserve cash
• In 2009, planning to maintain dividend
12
14. Improving Competitiveness
millions
$1,000
Other
$200 Operating
$800 Expenses
$250
Energy
$600
Efficiency
Why Own Valero?
$400
$550
Mechanical
V
$200 Availability
(Reliability)
$0
2008 2009 2010 2011
• In early 2007, identified gaps of approximately $1 billion of annual operating
income
Assessed refining system based on 2006 Solomon Survey results and prices
• Developed initiatives to close gaps
• Reliability a main focus via “Commitment to Excellence Management System”
13
15. Improving Competitiveness
• Improving reliability
Implementing standards for consistent, world class operations
world-class
No cracks in Port Arthur coke drums since repair in spring 2008
• Increasing energy efficiency
Implemented strategies at six refineries in 2008 and already
achieving savings
• Reducing maintenance costs
Why Own Valero?
Better work scheduling and improvements in reliability
• Improving margins with molecule management
V
initiative
Identified and achieving savings through non-capital improvements
to optimize profitability of each refinery unit
• Reducing costs via measurement assurance
Identified and achieving savings by mass/volume analysis
throughout system
• Adjusting feedstock slate
Added
Add d 11 new di
discounted crudes i 2007 and 13 i 2008
td d in d in
• Systematically reviewing each department’s costs and how we do
business
14
16. Stock Price Same as Early 2005, But
Much Stronger Company Now
per
Valero Split-Adjusted Stock Price
share
$80
$70
$60
$50
$40
Why Own Valero?
$30
$20
V
$10
$0
Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09
Then Now
Cash (millions) $846 $940
Additional Available Liquidity (billions) $1.5 $4.7
Debt-to-Cap Ratio, net of cash 30.7% 26.2%
Average Refinery Throughput Capacity (MBPD) 164 188
Total Refining Throughput Capacity (MMBPD) 2.5 3.0 15
17. Committed to Creating
Long-
Long-Term Shareholder Value
• Refining Industry
Expect margins to be volatile and seasonal
E t i tb l til d l
Refiners showing production discipline
Asset values very cheap
y p
Economic recovery will improve demand
Refined products still most economic
• Valero
Geographically diverse portfolio of refineries
Refineries are larger more complex and have lower
larger, complex,
cost per barrel
Exporting diesel/gasoline to a global market
Profitable in 4Q08 and profitable now
Best value in refining!
16
19. Refining Portfolio
Quebec, Canada
• 235,000 bpd capacity
Benicia, California
• 7.7 Nelson complexity
• 170,000 bpd capacity
• 15.0 Nelson complexity
Paulsboro,
Paulsboro New Jersey
• 195,000 bpd capacity
• 9.4 Nelson complexity
Wilmington, California Delaware City, Delaware
• 135,000 bpd capacity • 210,000 bpd capacity
• 15.9 Nelson complexity • 13.2 Nelson complexity
Lima, Ohio
• 165,000 bpd capacity
• SOLD in 2007 for $1.9
McKee, Texas billion
• 170,000 bpd capacity
• 9.4 Nelson complexity
Memphis, Tennessee
• 195 000 bpd capacity
195,000 b d it
• 7.5 Nelson complexity
• Under Strategic Evaluation
Three Rivers, Texas
• 100,000 bpd capacity
Ardmore, Oklahoma
• 12.4 Nelson complexity
• 90,000 bpd capacity
Corpus Christi, Texas
• 12.0 Nelson complexity
• 315,000 bpd capacity
• Under Strategic Evaluation
• 19.1 Nelson complexity
Legend Krotz Springs, Louisiana
• 85,000 bpd capacity St. Charles, Louisiana
Texas City, Texas • 6.5 Nelson complexity • 250,000 bpd capacity
Valero Marketing Presence • 245,000 bpd capacity • Sold July 2008 for more • 15.3 Nelson complexity
• 11.1 Nelson complexity than $500 million
Core Refinery
Houston, Texas Port Arthur, Texas San Nicholas, Aruba
,
• 145,000 bpd capacity • 310,000 bpd capacity • 235,000 bpd capacity
• 15.1 Nelson complexity • 12.5 Nelson complexity
Non-Core Refinery Under Strategic Evaluation • 8.0 Nelson complexity
• Under Strategic Evaluation
Non-Core Refinery – Sold
Note: Capacity shown in terms of crude and feedstock throughput
18
Sources: Nelson complexities, Oil & Gas Journal and Valero estimates
20. Prudently Investing in Strategic
Growth Projects
Estimated
Total
Start-
Cost1
Refinery Project Up Description
$mm
Strategy to Enhance Shareholde Value
Hydro- New hydrocracker – 50 mbpd estimated
Port Arthur cracker/ $1,700 3Q11 Crude expansion – unlock up to 75
er
mbpd existing capacity
b d i ti it
Crude
Crude unit expansion – 45 mbpd
Crude/
St. Charles $250 1Q10 estimated
Coker Coker expansion – 10 mbpd estimated
S
Convert to conventional design
St. Charles FCC $225 2Q10 Improve reliability and get 5%+ volume
expansion
New hydrocracker – 50 mbpd
Hydro-
Hydro
o
St. Charles $1,250 4Q12 Upgrades low-value feedstocks mainly
cracker into ULSD with 25% volume expansion
1 Total project cost includes non-strategic capital costs and interest and overhead
To maintain financial strength focusing on key projects and adjusting schedule
strength,
• Delayed St. Charles hydrocracker and Port Arthur hydrocracker, gasifier, and new coker
• Reduced scope of St. Charles paraxylene project
• Cut other, discretionary projects at many refineries
19
21. Safe Harbor Statement
Statements contained in this presentation that state the Company's or
management's expectations or predictions of the future are forward–
looking statements intended to be covered by the safe harbor
provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. The words quot;believe,quot; quot;expect,quot; quot;should,quot; quot;estimates,quot;
and other similar expressions identify forward–looking statements. It
is important to note that actual results could differ materially from
those projected in such forward–looking statements. For more
information concerning factors that could cause actual results to
differ from those expressed or forecasted, see Valero’s annual reports
on Form 10-K and quarterly reports on Form 10-Q, filed with the
Securities and Exchange Commission, and available on Valero’s
website at www.valero.com.
20
