UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): March 3, 2015

 

 

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1-13175   74-1828067

(State or other jurisdiction

of incorporation)

  

(Commission

File Number)

  

(IRS Employer

Identification No.)

 

One Valero Way

San Antonio, Texas

   78249
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (210) 345-2000

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 

Item 7.01 Regulation FD Disclosure.

Senior management of Valero Energy Corporation (the “Company”) will make certain investor presentations beginning as early as March 3, 2015. The slides attached to this report were prepared for management’s presentations. The slides are included in Exhibit 99.01 to this report and are incorporated herein by reference. The slides will be available on the Company’s website at www.valero.com.

The information in this report is being furnished, not filed, pursuant to Regulation FD. Accordingly, the information in Items 7.01 and 9.01 of this report will not be incorporated by reference into any registration statement filed by the Company under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. The furnishing of the information in this report is not intended to, and does not, constitute a determination or admission by the Company that the information in this report is material or complete, or that investors should consider this information before making an investment decision with respect to any security of the Company or any of its affiliates.

Safe Harbor Statement

Statements contained in the exhibit to this report that state the Company’s or its 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, as amended, and the Securities Exchange Act of 1934, as amended. It is important to note that the Company’s actual results could differ materially from those projected in such forward-looking statements. Factors that could affect those results include those mentioned in the documents that the Company has filed with the Securities and Exchange Commission.

 

Item 9.01 Financial Statements and Exhibits.

 

  (d) Exhibits.

99.01 Slides from management presentation.

 

2

SIGNATURE

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

 

VALERO ENERGY CORPORATION
Date: March 3, 2015 by:

/s/ Jay D. Browning

Jay D. Browning
Executive Vice President and General Counsel

 

3



Investor Presentation
March 2015
Exhibit 99.01

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 “believe,”
“expect,”
“should,”
“estimates,”
“intend,”
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.
2
Safe Harbor Statement

3
Who We Are
•
15 refineries, 2.9 million barrels per day (BPD) of high-complexity throughput capacity
•
Greater than 70% of refining capacity located in U.S. Gulf Coast
and Mid-Continent
•
Approximately 10,000 employees
•
General partner and majority owner of Valero Energy Partners LP (NYSE: VLP), a
growth-oriented, fee-based master limited partnership (MLP)
•
Significant inventory of logistics assets within Valero
•
Approximately 7,400 marketing sites in U.S., Canada, United Kingdom, and Ireland
•
Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock, and Beacon
•
11 corn ethanol plants, 1.3 billion gallons per year (85,000 BPD) production capacity
•
Operator
and
50%
owner
of
Diamond
Green
Diesel
joint
venture
–
10,500
BPD
renewable diesel production capacity
World’s Largest Independent Refiner
Large Logistics Infrastructure with Focus on Growth
Wholesale Fuels Marketer
One of North America’s Largest Renewable Fuels Producers

4
Assets Concentrated in Advantaged
Locations
Refinery
Capacities (MBPD)
Nelson
Index
Throughput
Crude Oil
Corpus Christi
325
205
19.9
Houston
175
90
15.4
Meraux
135
125
9.7
Port Arthur
375
335
12.4
St. Charles
290
215
16.0
Texas City
260
225
11.1
Three Rivers
100
89
13.2
Gulf Coast
1,660
1,284
14.0
Ardmore
90
86
12.1
McKee
180
168
9.5
Memphis
195
180
7.9
Mid-Con
465
434
9.3
Pembroke
270
210
10.1
Quebec City
235
230
7.7
North Atlantic
505
440
8.9
Benicia
170
145
16.1
Wilmington
135
85
15.9
West Coast
305
230
16.0
Total or Avg. 
2,935
2,388
12.4

5
Key Market Trends
U.S. and Canadian crude oil, natural gas, and natural gas liquids
(NGLs) production growth is providing cost advantages to
North American refiners
Location-advantaged refiners in U.S. Gulf Coast, Mid-Continent,
and Canada benefit from resource advantages and/or export
opportunities
Global refined products demand growth is expected to continue
-
Lower
crude
prices
may
temporarily
constrain
production
growth
rate
-
Expect lower prices to consumers will drive product demand growth

Production Growth Provides Resource Advantage to
North American Refiners
Source:  DOE (for 2014, data through November)
Source:  DOE (for 2014, data through November)
6
40
45
50
55
60
65
70
U.S. Natural Gas Production
(Bcf/day)
4,500
5,000
5,500
6,000
6,500
7,000
7,500
8,000
8,500
9,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
10,500
MBPD
MBPD
U.S. Crude Oil Production and
Imports
Imports
Production

7
Global Petroleum Demand Projected to Grow
Source:  Consultant (EIA and IEA) and Valero estimates. Consultant annual estimates generally updated 6 to 12 months after year end. 
Emerging markets in Latin America, Middle East, Africa, and Asia
lead demand growth
-3.5
-2.5
-1.5
-0.5
0.5
1.5
2.5
3.5
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014E
2015E
2016E
World Petroleum Demand Growth
Non-OECD
OECD (excl. U.S.)
U.S.
MMBPD

U. S. Product Exports By Destination
U. S. Product Exports By Source
MMBPD
12 Month Moving Average
8
U.S. Growing Market Share by Exports
•
Refined products demand is growing in developing countries and Atlantic Basin
(capacity closures)
•
U.S. Gulf Coast (PADD III) is the largest source of exported products
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Latin America
Canada
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2014
MMBPD
PADD V
PADD I
PADD II
PADD III
(Gulf Coast)
Source:  DOE Petroleum Supply Monthly data as of Nov 2014; Latin America includes South and Central America plus Mexico.

Strategy to Enhance Stockholder Returns
Operations
Excellence
Capital Returns to
Stockholders
Disciplined Capital
Investments
Unlocking Asset
Value
•
Demonstrate commitment to safe and reliable operations
•
Continuously improve our top-tier operating performance
•
Optimize margins with refining system’s feedstock and product
markets flexibility
•
Disciplined capital allocation
•
Seek to increase cash returns through dividend growth
•
Use stock buybacks to reduce shares outstanding and concentrate
future value per share
•
Rigor in capital projects and M&A selection and execution
•
Invest to grow logistics assets and reduce feedstock costs
•
Evaluate investments to upgrade natural gas and natural gas liquids
•
Opportunistically invest in ethanol to maintain high returns
•
Grow Valero Energy Partners LP and realize value for Valero
•
Execute accelerated drop-down strategy and evaluate other
potential MLP-able earnings streams
•
Previously unlocked value in retail business via 2013 spinoff to
stockholders
9

10
Persistent Focus Drives Results in Safety,
Environmental, and Regulatory Compliance
All 2014 values are estimates.
Statistics are for Refining only. 
Operations
Excellence
(1)
0.0
Employees
Contractors
Industry
10
20
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
Personnel Safety
0.00
0.05
0.10
0.15
0.20
Tier 1 Process Safety
0
5
10
15
20
0
30
40
Environmental Events
Total Air Emissions (U.S. Refineries)
(1)
Source: U.S. Bureau of Labor Statistics.

11
Top-Tier Operating Performance through
Continuous Improvements
2012
2010
2008
•
Reliability drives safe and
profitable operations
Seven of our refineries are first
quartile in mechanical availability
•
Initiated new reliability programs
and investments beginning mid-
2000s
•
Significant gains made in
operations benchmarks since
2008, particularly in mechanical
availability
•
Personnel committed to
excellence
1
Quartile
2
Quartile
3
Quartile
4
Quartile
th
st
nd
rd
Source:  Solomon Associates and Valero Energy, includes Pembroke and Meraux

Sustained high availability and favorable margin environment enable higher
capacity utilization rates
12
Investments, Reliability Programs, and
Commercial Optimization Drive Higher Utilization
System-wide
mechanical
availability near
1    Quartile since
2011
88%
87%
92%
95%
96%
2010
2011
2012
2013
2014
Valero Refinery Utilization Rates
st

13
Optimizing Margins with Feedstock Flexibility
in Our Complex Refinery System
•
Investments enhanced our
capability to adjust
feedstocks and optimize
margins
•
Focus on optimization
activities
•
Key advantages as crude
price environment shifts
among grades: light,
medium, heavy, sweet, sour
•
Expect additional light crude
flexibility with completion
of topper units investments
now in progress
Range of Flexibility in Valero’s Gulf Coast
Region Quarterly Feedstock Mix 2010-2014
26%
20%
12%
12%
4%
35%
34%
28%
23%
9%
Avg
30%
Avg
26%
Avg
20%
Avg
18%
Avg
6%

•
Approximately half of benefits visible in
margin capture rate increase of >4%
and balance of benefits in 100 MBPD
throughput volume increase from
feedstocks and new gas plant
•
Benefits visible in U.S. Gulf Coast
region reported results improvement
from 4Q12 to 3Q14
(1)
•
120 MBPD of combined new capacity
successfully started end of 2012 and
mid-2013
•
Designed to produce high-quality
distillates from low-quality feedstocks
and natural gas
Port Arthur and St. Charles Hydrocrackers
Performing Better Than Expected
14
(1) See Appendix for details and assumptions
•
Realized annual EBITDA estimated at
$800 million for trailing 4-quarters
3Q14
•
Compares to $780 million implied by
disclosed guidance model
(1)

Disciplined Capital Allocation
Framework Emphasizes Stockholders
“Non-Discretionary”
“Discretionary”
15
Capital
Returns to
Stockholders
(1) Debt-to-cap ratio based on total debt reduced by $2 billion cash balance, excluding VLP debt and equity
•
Flexibility to return
cash, reduce share
count, and manage
capital employed
•
Increase competition
versus reinvestments
•
Evaluate accretion
versus stock buybacks
•
Enhance future
returns
•
Focus on sustainability
•
Increase competition
for cash flow versus
reinvestments (growth
capex and acquisitions)
•
Estimate $1.5 billion or
lower annual “stay-in-
business”
spend
•
Key to safe and reliable
operations
•
Maintain investment
grade credit rating
•
Target 20% to 30%
debt-to-cap ratio
(1)
•
Prioritize higher-value,
higher-growth
opportunities that
enhance future returns
Sustaining Capex
Dividend Growth
Debt and Cash
Stock Buybacks
Growth Capex
Acquisitions

16
Increasing Focus on Dividends and Stock
Buybacks
•
Increased dividend by 45% in
1Q15 versus 4Q14
•
Regular dividend increases over
last three years
•
Accelerated stock buybacks in
2013 and 2014
•
Approximately $1.5 billion of
stock repurchase authorization at
end of 4Q14
Targeting >50% total payout ratio
of earnings in 2015 via dividends
and stock buybacks
*2015 through Mar 3
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
Dividend Per Share of Valero
$85
$0
$500
$1,000
$1,500
2011
2012
2013
2014
2015*
millions
Stock Buybacks

17
Advancing Growth Investments While
Managing Capital Spending Lower
(1) Excludes estimated placeholder for methanol project of $150 million in 2015 and $300 million in 2016 as evaluation remains in progress
Disciplined
Capital
Investment
(1)
•
Focus on logistics growth after 2015 spending to complete crude toppers
•
Expect nearly all logistics growth investments to be eligible for drop-down into
VLP
$555
$765
$730
$655
$695
$655
$690
$790
$300
$915
$400
$715
$2,815
$2,650
$2,400
2014
2015E
2016E
millions
Logistics Growth
Refining, Renewables, &
Other Growth
Turnarounds & Catalyst
Sustaining

•
•
Tanks, Docks, and Vessels
•
•
18
Logistics Investments Enhance Valero’s
Feedstock Flexibility and Export Capability
Rail
•
•
•
•
Expect Diamond Pipeline to supply Memphis refinery via Cushing and
start up in 1H17 or earlier
Pipelines
Completed
tie-in
to
pipeline
in
Childress,
TX
and
secured
incremental
40 to 50 MBPD Midland-priced crude as substitute for Cushing-priced
crude primarily at the McKee refinery
Tanks and vessels to supply crude to Quebec City refinery post-Enbridge
Line 9B reversal expected in 2Q15
Corpus Christi dock commissioned in 3Q14; completion of tanks for
crude exports expected in 1Q15
Benicia crude unloading facility undergoing permitting process
Crude unloading facilities at Quebec City, St. Charles, and Port
Arthur
Expect new railcars to serve long-term needs in ethanol and asphalt
Purchased 5,320 CPC-1232 railcars; received 4,078 through Jan 2015

Crude Topper Investments Very Attractive
19
Estimate $500 million annual EBITDA for combined projects in 2014 price environment
•
160 MBPD new topping capacity
designed to process up to 50 API
domestic sweet crude
Lowers feedstock cost by
generating 55 MBPD low sulfur
resid
Increases net throughput
capacity by 105 MBPD
•
Expect startup in 1H16
•
Expect 50% IRR on 2014 prices,
>25% IRR with Brent and LLS even
•
Corpus Christi:  Estimated $350 MM
capex for 70 MBPD capacity
•
Houston:  Estimated $400 MM
capex for 90 MBPD capacity
See Appendix for assumptions.
(1)
Excluding interest and overhead allocation
(2)
Estimates based on 2014 full year average prices; EBITDA = operating income before
deduction for depreciation and amortization expense
Incremental Volume
(MBPD)
Feeds
Eagle Ford crude
160
Low
sulfur atmos
resid
(55)
Products
LPG
3.3
Propylene
1.3
BTX
0.4
Naphtha (at
export prices)
40
Gasoline
12
Jet
39
Diesel
13
Resid
(3)
Combined Projects Estimates
(1)
$750
MM
Annual EBITDA contribution
(2)
$500 MM
Unlevered IRR on total spend
Total investment
(2)
50%

Key Natural Gas and NGLs Upgrading
Investments
20
Hydrocracker
Expansions
Evaluating
Methanol Plant at
St. Charles
Evaluating Houston
Alkylation Unit
•
1.6
–
1.7
million
tonnes
per
year
production
(36
–
38
MBPD)
•
Leverages existing assets to reduce capital requirement
compared to grassroots facility
•
Continuing to evaluate capital costs and project economics
•
Expect investment decision in 2Q15; startup in 2018 if approved
•
12.5 MBPD capacity
•
Upgrades low-cost NGLs to premium-priced alkylate
•
Continuing to evaluate capital costs and project economics
•
Expect investment decision in 2015; startup in 2017 if approved
•
Increase distillate yield partially from hydrogen via natural gas
•
Completed Meraux’s 20 MBPD capacity expansion in 4Q14;
expect approximately $90 million annual EBITDA contribution
at 2014
(1)
prices on total investment of approx. $260 million
•
30 MBPD total capacity addition at St. Charles and Port Arthur
in progress; expect startup in 2H15
(1) 2014 full year average prices; see project details in Appendix

21
Ethanol Investments Have Performed Well
Note:  See Appendix for reconciliation of EBITDA to GAAP results.
Outstanding
Cash
Generation
Excellent
Acquisitions
Competitive
Advantages
•
11 plants acquired between
2Q09 and 1Q14 for $794MM,
less than 35% of replacement
value
•
1.3 billion gallons total
annual production
•
Scale and location in corn
belt
•
Operational best practices
transferred from refining
•
Low capital investment
•
$2.2 billion cumulative
EBITDA generated since
acquisitions
•
$161 million cumulative
capex  excluding acquisition
costs
$2,229
$161
millions
Cumulative Capex and EBITDA
EBITDA
Capex

22
Our Sponsored MLP
Valero Energy Partners (NYSE:VLP)
Growth-oriented
logistics MLP with
100% fee-based
revenues
•
Valero owns entire 2% general partner interest, all incentive
distribution rights, and 69.6% LP interest
•
High-quality assets integrated with Valero’s refining system
•
Primary vehicle to grow Valero’s midstream investments
•
Provides access to lower cost capital
Unlocking
Asset Value

23
VLP Delivering Growth
VLP is on target to acquire $1 billion of assets from VLO in 2015
See Appendix for reconciliation of estimated 2015 EBITDA to net income.
•
1
st
acquisition –
Texas Crude
Systems Business in July 2014
for $154 million
•
2
nd
acquisition –
Houston and
St. Charles Terminal Services
Business in March 2015 for
$671 million
•
Plan to grow VLP’s 4Q15
annualized EBITDA to
approximately $200 million
•
Targeting nearly 25% CAGR for
LP distributions through 2017
$95
$200
4Q14
4Q15E
Adjusted EBITDA Attributable to VLP
(millions)
Annualized
Annualized

24
Drop Down of St. Charles and Houston
Terminal Services Business to VLP
Operations
•
Crude oil, intermediates, and refined
petroleum product terminaling services
in Houston, Texas and Norco, Louisiana
3.6 million barrels of storage capacity on the
Houston ship channel
10 million barrels of storage on the Mississippi
River
•
10-year terminaling agreements with
VLO subsidiaries
•
Over 85% of revenue is contractually
obligated by minimum volume
commitments
•
Expected to contribute $75 million of
EBITDA annually
Financing
•
$671 million transaction closed on
March 1, 2015
•
$411 million in cash to VLO
$211 million in cash from VLP’s balance sheet
$200 million under VLP’s revolving credit facility
•
$160 million 5-year subordinated loan
agreement with VLO
•
$100 million issuance of VLP units to
VLO
1,908,100 million common units
38,941 general partner units
Common and general partner units allocated in
proportion to allow general partner to maintain
its 2 percent interest
Transaction puts Valero ahead of accelerated schedule to achieve
$1 billion in drop-down transactions in 2015

25
Estimated EBITDA from Inventory of Eligible MLP
Assets Total Approximately $800 Million
(1) Includes assets that have other joint venture or minority interests.
Pipelines
(1)
•
•
Racks, Terminals, and Storage
(1)
•
•
Rail
•
•
Marine
(1)
•
•
Fuels Distribution
•
Over
1,200
miles
of
active
pipelines
Expect start-up of 440-mile Diamond Pipeline from Cushing to Memphis refinery in
1H17
Over 100 million barrels of active shell capacity for crude and products
139 truck rack bays
Three crude unloading facilities with estimated total capacity of 150 MBPD
Purchased CPC-1232 railcars expected to serve long-term needs in ethanol and
asphalt
51 docks
Two Panamax class vessels
Evaluating qualifying volumes and commercial structure as potential drop-down
candidate

26
We Believe Valero Is an Excellent Investment
•
Majority of capacity located in U.S. Gulf Coast and Mid-
Continent with access to cost-advantaged crude, natural gas,
NGLs, and corn
•
Proven operations excellence
•
Excellent investment and operations in ethanol
•
Emphasis on capital allocation to stockholders
•
Disciplined capital investment that prioritizes higher-value
and higher-growth opportunities to capture benefits of
advantaged resources
•
Unlocking value through growth in MLP-able assets and
drop-downs to VLP
•
Focus on valuation multiple expansion

27
Appendix
Topic
Pages
Valero 2014 Highlights and 2015 Goals
28-29
Valero Energy Partners LP and CST Brands Spinoff
30-32
Capital Spending and Key Investment Details
33-42
Other Valero Operations Highlights
43-48
Macro Outlook and Key Margin Drivers
49-55
Global Demand and Refining Capacity
56-60
U.S. Fundamentals and DOE Data
61-70
International Fundamentals
71-72
Non-GAAP Reconciliations
73
IR Contact Information
74

28
Key 2014 Highlights
Operations Excellence
•
Achieved record annual system refinery capacity utilization of approximately 96% in 2014
•
Increased average consumption of price-advantaged North American light sweet crudes in 2014 by approximately 200
MBPD compared to 2013
•
Reduced Quebec refinery’s crude costs by $3/bbl versus Brent from premium of approximately $2/bbl in 2013 to
discount of approximately $1/bbl in 2014
•
Secured attractively priced term-supply of WTI Midland for Mid-Continent refineries
•
Increased gasoline and diesel exports by 49 MBPD, or approximately 18%, in 2014 versus 2013
•
Launched Top Tier gasoline in wholesale marketing system
•
Achieved record $835 million annual Ethanol segment EBITDA
Capital Returns to Stockholders
•
Increased cash returned to stockholders through dividends and buybacks by $460 million in 2014, or 33%, versus 2013
Disciplined Capital Investments
•
Completed and started up Meraux hydrocracker conversion project in 4Q14
•
Secured capital efficient Diamond Pipeline option and supply to Memphis refinery with crude from Cushing
•
Started
up
90
MBPD
of
total
crude
rail
unloading
capacity
at
St.
Charles
and
Port
Arthur
•
Acquired
idled
ethanol
plant
in
Mt.
Vernon,
Indiana
at
less
than
15%
of
replacement
cost
and
restarted
facility
within
five months
Unlocking Asset Value
•
Grew VLP via first drop-down acquisition of $154 million purchase price on July 1, 2014
Other
•
Diamond
Green
Diesel
JV
benefitted
by
approximately
$126
million
on
retroactive
reinstatement
of
Blenders
Tax
Credit

29
Key 2015 Goals
Operations Excellence
•
Start up Montreal crude terminal with the Enbridge Line 9B reversal and lower Quebec
refinery’s crude costs versus Brent compared to 2014
•
Grow product export market share and increase branded wholesale fuels volume
Capital Returns to Stockholders
•
Increase total payout ratio of earnings over 2014’s 50% payout level
Disciplined Capital Investments
•
Complete Houston and Corpus Christi toppers on time and on budget
•
Make
final
investment
decisions
on
methanol
plant
at
St.
Charles
refinery
and
alkylation
unit
at
Houston
refinery;
if
approved,
share
strategic
rationale
with
investors
•
Complete 25 MBPD McKee CDU capacity expansion
•
Complete
30
MBPD
total
hydrocracker
capacity
expansions
at
Port
Arthur
and
St.
Charles
•
Gain permit approval to construct Benicia crude rail unloading facility
Unlocking Asset Value
•
Grow the size of identified MLP-able EBITDA available for drop-downs to VLP
•
Execute $1 billion of drop-down transactions to VLP

Significant Inventory of Estimated MLP
Eligible EBITDA at Valero
Fuels distribution would provide incremental EBITDA if selected
30
$800
($15)
($75)
$24
$34
$46
$814
Dec 2013
Guidance (with
base + 2014-2015
projects)
July 2014 Drop
Down
March 2015 Drop
Down
2014 -
2015
Additional
Logisitics Projects
2016 -
2017
Logistics Projects
Diamond Pipeline Current Guidance
Option
millions

31
Valero’s GP Interest in VLP
Nearing the “High Splits”
•
4Q14 distribution at $0.266 per unit
•
Valero’s GP interest in VLP expected to reach 50% split in 2015, payable in 2016, based on
accelerated drop-down strategy
Target Quarterly Distribution per Unit
Marginal Percentage Interest in Distributions
Unitholders
GP
Minimum quarterly
$0.2125
98%
2%
First target
above $0.2125 up to $0.244375
98%
2%
Second target
above $0.244375 up to $0.265625
85%
15%
Third target
above $0.265625 up to $0.31875
75%
25%
Thereafter
$0.31875
50%
50%

Unlocked Value via Retail Spinoff in 2013
32
CST Brands, Inc. (NYSE: CST) has traded
at approximately double the earnings
valuation of VLO
VLO received nearly $1 billion in cash net
of tax liability and working capital
benefit to CST
Liquidated our 20% retained interest in
CST common stock, or 15 million shares,
in November 2013
CST Brands is now Valero’s largest
wholesale customer

Allocating Significant Growth Capital to
Logistics
33
•
Railcars spending declines as receipt of railcars order concludes
•
Future spending focuses on pipelines
$510
$175
$45
$220
$180
$665
$185
$45
$5
$915
$400
$715
2014
2015E
2016E
millions
Marine, Docks, and Other
Logistics
Pipelines and Tanks
Railcars and Unloading

34
Refining & Renewables Capital Focused on
Capturing Benefits of Key Long-Term Trends
•
Advantaged crude processing optimizes feedstock flexibility, mainly for light crudes
•
Hydrocracking increases production of high-margin distillates
•
Petchems, methanol, and hydrocracking upgrade natural gas or NGLs to higher-value liquids
$326
$490
$50
$180
$110
$30
$141
$150
$105
$43
$40
$115
$690
$790
$300
2014
2015E
2016E
millions
Nat Gas & Petchems
Other Projects
Hydrocracking
Advantaged Crude
Processing

McKee Diesel Recovery Improvement and
CDU Expansion Startup Expected in 2H15
35
•
Adding 25 MBPD crude unit capacity
and parallel light ends processing
train
•
Expect to improve yields and volume
gain by recovering diesel from FCC
and HCU feeds
•
Expect to increase diesel and gasoline
production on price-advantaged
crude
•
Expect to reduce energy
consumption via heat integration
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before
deduction for depreciation and amortization expense
Incremental Volume
(MBPD)
Feeds
WTI
25
Products
LPG
0.4
Benzene concentrate
0.3
Gasoline
12
Jet
-
Diesel
12
Resid
0.6
Project Estimates
Total investment
$140 MM
Annual EBITDA contribution
(1)
$100 MM
Unlevered IRR on total spend
(1)
45%
Investment Highlights
Status
•
Diesel recovery and benefits
started in mid-2014; expect crude
expansion start-up in 2H15

Meraux Hydrocracker Conversion Completed
December 2014
36
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before
deduction for depreciation and amortization expense
•
Converted hydrotreater into high-
pressure hydrocracker and
repurposed old FCC gas plant for
additional LPG recovery
•
Expect
to
upgrade
23
MBPD
gasoil
and low-cost hydrogen (via natural
gas) mainly into high quality diesel
•
Expect
to
increase
refinery
distillate
yield versus gasoline (Gas/Diesel
ratio drops from 0.72 to 0.59)
•
Expect to increase refinery liquid
volume yield by 1.8%
•
Avoided
compliance
capex
on
FCC
Investment Highlights
Status
•
Project
started
up
in
Dec
2014
and
is
operating well
Incremental Volume
(MBPD)
Feeds
Purchased hydrogen
(MMSCFD)
13
Products (MBPD)
Gasoline
5
Jet
-
Diesel
19
HSVGO
2
Unconverted gasoil
(23)
Fuel oil
-
Project Estimates
Total investment
$260 MM
Annual EBITDA contribution
(1)
$90 MM
Unlevered IRR on total spend
(1)
25%

Houston and Corpus Christi Crude Topping
Units Expected Online in 1
st
Half of 2016
37
Corpus Christi
Houston
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense
Estimates
Incremental Volume (MBPD)
Feeds
Eagle Ford crude
90
Low
sulfur atmos resid
(29)
Distillate
(2)
Butane
(2)
Hydrogen (MMSCFD)
3
Products
LPG
0.8
Propylene
0.4
Naphtha
24
Gasoline
5
Jet
23
Diesel
4
Slurry
0.2
Estimates
Incremental Volume (MBPD)
Feeds
Eagle Ford crude
70
Low
sulfur atmos resid
(24)
Products
LPG
2.5
Propylene
0.9
BTX
0.4
Naphtha
16
Gasoline
7
Jet
16
Diesel
9
Resid
(3)
Project Estimates
Total investment
$400
MM
Annual EBITDA contribution
(1)
$240 MM
Unlevered IRR on total spend
(1)
45%
Project Estimates
Total investment
$350
MM
Annual EBITDA contribution
(1)
$260 MM
Unlevered IRR on total spend
(1)
55%

Diamond Pipeline
38
(1)
Includes additional Valero cost for pipeline connection at Memphis refinery
(2)
EBITDA = Operating income before deduction for depreciation and amortization expense
•
Valero holds option until January
2016 to acquire 50% interest in
pipeline
•
Increases Memphis refinery’s crude
supply flexibility via connection to
Cushing and economic crudes
•
Provides direct control over crude
blend quality
•
Grows Valero’s inventory of assets
eligible for VLP drop-down in
capital-efficient manner
•
Expect completion in 1H17 or earlier
Project Estimates
Total investment
(1)
$484
MM
Cumulative spend through 2014
Zero
Annual EBITDA contribution
(2)
$46 MM
Unlevered IRR on total spend
at
least 12%
Investment Highlights

Estimated Key Price Sensitivities on Project
Economics
39
Note:  Margin drivers shown are not inclusive of all feedstocks and products in economic models. Estimated economic sensitivities can not be accurately interpolated or extrapolated solely
from the estimated key price sensitivities shown above.
-$0.7
-$4.3
Change in Estimated
EBITDA
(1)
Relative to 2014
(2)
Prices
($millions/year)
McKee Diesel
Recovery & CDU
Expansion
Meraux HCU
Expansion
Corpus
Christi
Topper
Houston
Topper
ICE Brent, +$1/bbl
none
$0.8
$0.4
none
ICE Brent –
WTI, +$1/bbl
$5.5
none
None
none
ICE Brent –
LLS, +$1/bbl
N/A
none
$25.6
$32.9
Group 3 CBOB –
ICE
Brent, +$1/bbl
$2.0
N/A
N/A
N/A
Group 3 ULSD –
ICE Brent, +$1/bbl
$5.5
N/A
N/A
N/A
USGC CBOB
–
ICE Brent, +$1/bbl
N/A
$1.7
$2.4
$2.4
USGC ULSD –
ICE
Brent, +$1/bbl
N/A
$6.8
$9.0
$9.9
Natural
gas (Houston Ship Channel), +$1/mmBtu
-$1.9
-$3.2
Naphtha –
ICE Brent, +$1/bbl
N/A
none
$5.8
$8.8
LSVGO
–
ICE Brent, + $1/bbl
N/A
-$7.3
$3.1
$5.2
Total investment IRR, +10% cost
-6%
N/A
-5%
-4%
(1)
Operating income before deduction for depreciation and amortization expense
(2)
2014 full year average

Project Price Set Assumptions
40
Driver ($/bbl)
2014 Average
ICE Brent
99.49
ICE Brent –
WTI
6.35
ICE Brent –
LLS
2.75
USGC CBOB –
ICE Brent
3.52
G3 CBOB –
WTI
12.27
USGC ULSD –
ICE Brent
14.25
G3 ULSD –
WTI
23.88
Natural gas (Houston Ship Channel, $/mmBtu)
4.34
Naphtha –
ICE Brent
-0.67
LSVGO –
ICE Brent
8.86

41
Port Arthur and St. Charles Hydrocrackers
Performance Details
Benefits Realized in Reported Results
Trailing 4 Quarters
$mm, except /bbl amounts
4Q12
3Q14
Increase
Gulf Coast Capture Rate
58.8%
63.2%
x Gulf Coast Indicator/bbl, trailing 4Q 3Q14
$19
= Extra margin captured/bbl
$0.83
x Gulf Coast volume, trailing 4Q 3Q14 MPBD
1,586
x Annualized Days
365
= Benefit from higher Capture Rate
$483
Gulf Coast Throughput Volume MBPD
1,488
1,586
x Gulf Coast Indicator/bbl, trailing 4Q 3Q14
$19
x Gulf Coast Capture Rate, trailing 4Q 3Q14
63%
x Annualized Days
365
= Benefit from higher Volume
$429
Total Benefit from Hydrocracker Projects
$912
Less: estimated operating costs before depreciation and amort. exp.
-110
= EBITDA (estimated)
Key Assumptions
4.4%
98
$802
•
Market prices for trailing 4 quarters as of 3Q14 applied to guidance model disclosed by Valero in February 2012 to estimate $780 million in EBITDA
•
Gulf Coast capture rate increase based on average of trailing 4 quarters reported margin per barrel (excluding cost of RINs allocated in results at
$0.30/bbl for 4Q12 and $0.40/bbl for 4Q13 averages) divided by Gulf Coast indicator margin
•
Gulf Coast LPGs pricing based on propane
•
Many factors can influence our reported margins including, but not limited to, charges, yields, pricing, timing and ratability, secondary costs, other
allocations, hedging, and GAAP inventory costing methods
•
EBITDA = operating income before deduction for depreciation and amortization expense

Gated Investment Management Process
•
Development costs increase as project progresses through the phases
•
NPV and IRR of future cash flows per price forecasts and operating plans evaluated
•
“Target”
IRR hurdle rate ranges, which can change depending on the project and
market conditions:
Refining growth projects, target >=50% in Phase 1 to >=30% in Phase 3
Cost savings projects, target >=12% in Phase 3
Logistics projects, target pre-tax >=12% in Phase 3 + refinery benefits
42
PHASE 1
Opportunity
Evaluation
•
Identify
opportunities
and alternatives
•
Develop
business case
•
Generate cost
estimate range
of +100% to -
50%
PHASE 2
Lead Case
Development
•
Select lead case
and define
project
objectives
PHASE 3
Refinement
•
Define project
scope and
execution plans
•
Prepare decision
support package
for final decision
•
Narrow cost
estimate to    
+/-10%
PHASE 4
Execution
•
Detail
engineering,
procurement,
and initial
construction
•
Develop start-up
schedule
APPROVED
Startup and
Evaluate
•
Post-audit back-
casting
•
Capture lessons
learned
•
Improve cost
estimate to    
+/-30%

43
Valero’s Light Crude Processing Capacity in
North America
MBPD
(1) Not incentivized in 4Q14 to maximize North American light crude consumption versus
alternative grades.
McKee Crude Unit Expansion
•
25 MBPD additional capacity
expected in 2H15
•
Distillate recovery improvements
Houston Crude Topper
•
90 MBPD capacity expected 1H16
•
Displaces 30 MBPD intermediate
feedstock purchases
Corpus Christi Crude Topper
•
70 MBPD capacity expected 1H16
•
Displaces 25 MBPD intermediate
feedstock purchases
(1)
4Q14 Actual
Utilization
Current Capacity
Estimate
Future Capacity
(with Projects)
1,060
1,220
1,410

44
Valero Continues to Process Cost-Advantaged
U.S. and Canadian Crude
Note:  Non-U.S. and Canadian crude runs exclude Valero’s Pembroke Refinery.  Cost-advantaged crudes exclude imports and historically discounted medium sour crudes, such as Mars/ASCI domestic;
heavy sour crudes, such as Maya; and high-acid crudes, such as Pazflor.
0
200
400
600
800
1,000
1,200
1,400
1,600
0
200
400
600
800
1,000
1,200
2010
2011
2012
2013
1Q14
2Q14
3Q14
4Q14
MBPD
MBPD
Gulf Coast
Mid-Con
West Coast
Quebec
Non-U.S. & Canadian

45
Valero Leads Peers in Total Location-
Advantaged Crude Capacity
Source:  Company 10-K reports.  Crude distillation capacity based on geographic location.
Access to lower cost North American crude benefits refiners in Mid-Continent, Gulf Coast, and
Canada; product export opportunities for Gulf Coast and Canada
1,948
1,714
1,211
443
129
VLO
MPC
PSX
HFC
TSO
MBPD
Canada
U.S. Gulf Coast
U.S. Midcontinent

46
Expect Quebec City Refinery to Have Cost-Advantaged
Access to 100% North American Crude Slate in 2015
Shifted to cost-advantaged crudes via rail and foreign flagged ships from USGC, with
additional savings expected from deliveries on Enbridge Line 9B beginning in 2Q15
0%
20%
40%
60%
80%
100%
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
Quebec City Refinery Crude Slate
Foreign
Imports
North
American

47
U.S. Natural Gas Provides Opex and
Feedstock Cost Advantages
$1.3 billion
higher pre-tax
annual costs
$2.8 billion
higher pre-tax
annual costs
Valero’s
refining
operations
consume
approximately
864,000
mmBtu/day
of
natural
gas, split almost equally between operating expense and cost of goods sold
Significant annual pre-tax cost savings compared to refiners in Europe or Asia
$3/mmBtu
$1/bbl
$7/mmBtu
Europe
$2.20/bbl
$16/mmBtu
Asian
$5.10/bbl
$0
$1
$2
$3
$4
$5
$6
/bbl
Natural Gas Cost Sensitivity for Valero’s Refineries
LNG
Note:  Estimated per barrel cost of 864,000 mmBtu/day of natural gas consumption at 92% refinery throughput capacity utilization, or 2.7 MMBPD.

48
Valero’s Capacity for Additional
Product Exports
Opportunities to expand U.S. Gulf
Coast export capability for gasoline
to 308 MBPD and diesel to 472
MBPD
Export markets pull volume from
U.S., enabling high refinery
utilization and improved margins
Supported by global refined
products demand growth
Logistics investments also support
segregation
255
412
0
100
200
300
400
500
600
700
2011
Actual
2012
Actual
2013
Actual
2014
Actual
Current
Capacity
Valero’s U.S. Product Exports
(MBPD)
Gasoline
Diesel

Long-Term Macro Market Expectations
Global Outlook
U.S. Economy and
Petroleum Demand
North American
Resource
Advantage
International Export
Markets
•
Economic activity and total petroleum demand increases
•
Transportation fuels demand grows
•
Refining capacity growth slows after 2015; utilization stabilizes then
expected to increase
•
Refinery rationalization pressure continues in Europe, Japan, and Australia
•
Economic growth strengthens over next five years, which stimulates refined
product demand
•
Diesel and jet fuel demand continues to strengthen
•
Gasoline demand continues to recover moderately
•
Natural gas production growth still attractive and development continues
•
Crude production is economic; growth continues, but tempered with lower
prices
•
North American refiners maintain competitive advantage
•
Broad lifting of crude export ban not expected for several years, if ever
•
U.S. continues to be an advantaged net exporter of products
•
Atlantic Basin market continues to grow, with increasing demand from
Latin America and Africa
•
U.S. Gulf Coast is strategically positioned with globally competitive assets
49

50
U.S. and Canadian Production Growth Provides
Crude Cost Advantage to North American Refiners
Source: EIA, Consultants, company announcements and Valero estimates; 2014 U.S. Crude imports as of November 2014
Production growth
reduces imports
Largest growth from U.S.
shale crude and heavy
Canadian crude
0
2
4
6
8
10
12
14
16
18
2010
2011
2012
2013
2014E
2015E
2020E
MMBPD
U.S. and Canadian Crude Production vs. U.S. Crude Imports
U.S. Shale Crude
Heavy Canadian
Light Canadian/
Syncrude
Other U.S.
Non-Canadian U.S.
Crude Imports

Estimated Crude Oil Transportation Costs
to USEC
Rail $12 to
$15/bbl
to St. James
Rail $12/bbl
to Cushing
Rail $9/bbl
Cushing
to Houston
Pipe $2 to
$4/bbl
Midland
to Houston
Pipe $4/bbl
CC to Houston
$1 to $2/bbl
Houston to
St. James
$1 to $2 /bbl
to West Coast
Rail $13 to $15/bbl
USGC to USEC
U.S. Ship $5 to $7/bbl
USGC to Canada
Foreign Ship $2/bbl
Alberta to Bakken
$1 to $2/bbl
Rail $9/bbl
U.S. Ship
$4 to
$5/bbl
Alberta
to Eastern Canada
Rail $11 to $12/bbl
Bakken
51

52
Crude Oil Differentials Versus ICE Brent
Source:  Argus; 1Q15 through February 20. LLS prices are roll adjusted.
-30%
-25%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
1Q15
Maya
Mars
ANS
WTI
LLS

53
Valero’s Regional Refinery Indicator Margins
Source:  Argus; 1Q15 through February 20
$5
$10
$15
$20
$25
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
1Q15
$/bbl
Midcontinent WTI Cracking
West Coast ANS Medium Sour Coking
North Atlantic Brent Cracking
Gulf Coast Heavy Sour Coking

•
Gulf Coast Indicator: (GC Colonial 85 CBOB A grade-
LLS) x 60% + (GC ULSD 10ppm
Colonial Pipeline prompt -
LLS) x 40% + (LLS -
Maya Formula Pricing) x 40% + (LLS -
Mars Month 1) x 40%
•
Midcontinent Indicator: [(Group 3 CBOB prompt -
WTI Month 1) x 60% + (Group 3
ULSD 10ppm prompt -
WTI Month 1) x 40%] x 60% + [(GC Colonial 85 CBOB A grade
prompt -
LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline -
LLS) x 40%] x 40%
•
West Coast Indicator: (San Fran CARBOB Gasoline Month 1 -
ANS USWC Month 1) x
60% + (San Fran EPA  10 ppm Diesel pipeline -
ANS USWC Month 1) x 40% + 10%
(ANS –
West Coast High Sulfur Vacuum Gasoil cargo prompt)
•
North Atlantic Indicator: (NYH Conv 87 Gasoline Prompt –
ICE Brent) x 50% + (NYH
ULSD 15 ppm cargo prompt –
ICE Brent) x 50%
•
LLS prices are Month 1, adjusted for complex roll
•
Prior to 2010, GC Colonial 85 CBOB is substituted for GC 87 Conventional
•
Prior to 4Q13, Group 3 Conventional 87 gasoline substituted for Group 3 CBOB
54
Valero’s Regional Indicator Margins Defined

Low Cost U.S. Natural Gas Provides
Competitive Advantage
55
•
U.S. natural gas is significantly discounted to Brent on an energy equivalent basis
•
Prices expected to remain low and disconnected from global oil and gas markets
for foreseeable future
$54
$17
$3/mmBtu
$44
$7/mmBtu
$99
$16/mmBtu
0
20
40
60
80
100
120
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
$/bbl
Brent and Natural Gas Prices
Brent
U.S.
Europe
Japan LNG
Sources:  Argus and Bloomberg. Japan LNG through November 30, 2014; U.S. and Europe through February 26, 2015. Natural gas price converted to barrels using factor of 6.05x

56
U.S. Refining Capacity Is Globally Competitive
and Continues to Take Market Share
Source:  EIA and IEA (U.S. data through November 2014, Europe data through December 2014)
Less-competitive capacity
Source:  EIA (2014 data through November)
Net imports
Net
exports
•
U.S. flipped from importer to exporter on lower local product demand and higher refinery
utilization, particularly in PADDS 2, 3, and 4, driven by structural cost advantages for crude oil
and natural gas
•
Gulf Coast refineries have gained export market share in the Atlantic Basin
-3.0
-2.5
-2.0
-1.5
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
1999
2001
2003
2005
2007
2009
2011
2013
MMBPD
U.S. Net Product Imports
Midcon
93%
Gulf
Coast
91%
Rockies
91%
West
Coast
86%
East
Coast
82%
Western
Europe
77%
PADD 2
PADD 3
PADD 4
PADD 5
PADD 1
OECD
Europe
Refinery Utilization by PADD
Trailing 12-months

57
World Refinery Capacity Growth
0.0
0.4
0.8
1.2
2015
2016
2017
2018
2019
MMBPD
Estimated Net Global Refinery Crude Distillation Additions
China
Middle East
Other (incl. U.S. and Latin America)
Source: Consultant and Valero estimates;  Net Global Refinery Additions = New Capacity + Restarts – Announced Closures
•
New capacity additions expected in Asia and Middle East
•
Announced
new
capacity
in
Brazil,
Mexico,
and
Colombia
likely
to
be
smaller
and
start
later
than planned
•
Expansions in Ecuador, Peru, Algeria, and Egypt unlikely due to cost and geopolitical pressures
•
Capacity rationalization expected to continue in Europe, Australia, and Japan

58
Capacity Rationalization in Atlantic Basin
Sources:  Industry and Consultant reports and Valero estimates
•
Marginal refiners in U.S. East Coast, Caribbean and Western Europe are shutting capacity
•
Demand growth, poor reliability, and low utilization in Latin American refineries provide
opportunities for competitive refineries to export products and meet supply needs
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
MPBD
Annual Global CDU Capacity
Closures
Rest of World
Atlantic Basin
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
MBPD
Cumulative Global CDU Capacity
Closures
Rest of World
Atlantic Basin

Location
Owner
CDU Capacity
Closed (MBPD)
Year
Closed
Location
Owner
CDU Capacity
Closed (MBPD)
Year
Closed
Perth Amboy, NJ
Chevron
80
2008
Coryton, U.K.
Petroplus
175
2012
Bakersfield,CA 
Big West
65
2008
Petit Couronne, France
Petroplus
160
2012
Ingolstadt, Germany*
Bayernoil
102
2008
Rome, Italy
Total/Erg
88
2012
Yabucoa, Puerto Rico
Shell
76
2008
Fawley, U.K.*
ExxonMobil
80
2012
Westville, NJ
Sunoco
145
2009
Paramo, Czech Republic
Unipetrol
20
2012
Bloomfield, NM
Western
17
2009
St. Croix, U.S.V.I
Hovensa
350
2012
North Pole, AK*
Flint Hills
85
2009
Aruba
Valero
235
2012
Teesside, UK
Petroplus
117
2009
Lisichansk, Ukraine
TNK-BP
175
2012
Gonfreville, France*
Total
90
2009
Clyde, Australia
Shell
75
2012
Dunkirk, France
Total
140
2009
Port Reading, NJ
Hess
N/A
2013
Toyama, Japan
Nihonkai Oil
57
2009
Dartmouth, Canada
Imperial Oil
88
2013
Yorktown, VA
Western
65
2010
Harburg, Germany
Shell
107
2013
Montreal, Canada 
Shell
130
2010
Porto Marghera, Italy
ENI
80
2013
Reichstett, France
Petroplus
85
2010
Sakaide, Japan
Cosmo Oil
140
2013
Wilhemshaven, Germany
ConocoPhillips
260
2010
North Pole, AK
Flint Hills
80
2014
Sodegaura, Japan*
Fuji Oil
50
2010
Mantova, Italy
MOL
69
2014
Oita, Japan*
JX Holdings
24
2010
Stanlow, U.K.*
Essar
101
2014
Mizushima, Japan*
JX Holdings
110
2010
Milford Haven, UK
Murphy
130
2014
Negishi, Japan*
JX Holdings
70
2010
Yokkaichi, Japan*
Cosmo Oil
43
2014
Kashima, Japan*
JX Holdings
18
2010
Tokuyama, Japan
Idemitsu Kosan
114
2014
Marcus Hook, PA
Sunoco
175
2011
Kurnell, Australia
Caltex
135
2014
St. Croix, U.S.V.I,*
Hovensa
150
2011
Kawasaki, Japan *
Tonen-General
67
2014
Arpechim, Romania
OMV Petrom
70
2011
Wakayama, Japan*
Tonen-General
38
2014
Cremona, Italy
Tamoil
94
2011
Muroran, Japan
JX Holdings
180
2014
Ogimachi, Japan
Toa Oil Company
120
2011
Chiba, Japan*
Kyokuto Petroleum
23
2014
Funshun, China
Funshun Petrochem.
70
2011
Kaohsiung, Taiwan
Chinese Petroleum Corp.
200
2015
Paramount, CA
Alon
90
2012
Bulwer Island, Australia
BP
102
2015
North Pole, AK*
Flint Hills
48
2012
Lindsey, U.K.*
Total
110
2016
Berre L’Etang, France
LyondellBasell
105
2012
59
Global Refining Capacity Rationalization
*Partial closure of refinery captured in capacity.  Note:  This data represents refineries currently closed, ownership may choose to restart or sell listed refinery. 
Sources:  Industry and Consultant reports, Valero estimates, and direct and public disclosure by each owner. 

60
Global Refining Capacity For Sale or Under
Strategic Review
Sources: Direct and public disclosure by each owner
Location
Owner
CDU Capacity (MBPD)
Lytton, Australia
Caltex
109
Nishihara, Japan
Petrobras/Sumitomo
95
Inchon, Korea
SK Energy
270
Whitegate, Ireland
Phillips 66
71
Barbers Point, HI
Chevron
54
Pasadena, TX
Petrobras
100
Bahia Blanca, Argentina
Petrobras
31
Gothenburg, Sweden
Shell
80
Port Dickson, Malaysia
Shell
156
Livorno
ENI
106
Taranto
ENI
120
Mazeikiai, Lithuania
PKN
190
Okinawa, Japan
Petrobras/Nansei Sekiyu
100
Falconara, Italy
API
80
Hamburg, Germany
Tamoil
78
Collombey, Switzerland
Tamoil
72
Chiba, Japan
Cosmo Oil
240
Chiba,
Japan
TonenGeneral
152

61
U.S. Crude Fundamentals
Source:  DOE weekly data through February 6, 2015
320,000
330,000
340,000
350,000
360,000
370,000
380,000
390,000
400,000
410,000
420,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
U.S. Crude Inventory (MB)
5 Yr Range
5 Yr Low
2013
2014
2015
2010 -
2014 Avg.
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
55,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Cushing Crude Inventory (MB)
5 Yr Range
5 Yr Low
2013
2014
2015
2010 -
2014 Avg.
140,000
150,000
160,000
170,000
180,000
190,000
200,000
210,000
220,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
PADD 3 Crude Inventory (MB)
5 Yr Range
5 Yr Low
2013
2014
2015
2010 -
2014 Avg.

62
U.S. Gasoline Fundamentals
USGC Brent Gasoline Crack (per bbl)
U.S. Gasoline Demand (mmbpd)
Source:  Argus; 2015 weekly data through Feb 20
Source:  2014 DOE monthly data through Nov 2014; 2015 weekly data through Feb 6
Source:  2014 DOE monthly data through Nov 2014; 2015 weekly data through Feb 6
U.S. Net Imports of Gasoline and Blendstocks (mbpd)
Source:  2014 DOE monthly data through Nov 2014
U.S. Gasoline Days of Supply
-$12
-$8
-$4
$0
$4
$8
$12
$16
$20
$24
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
8.2
8.4
8.6
8.8
9.0
9.2
9.4
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2015
2014
5 year avg
5 yr high
5 yr low
2014
2015
5 year avg
-400
-200
0
200
400
600
800
1000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
22
23
24
25
26
27
28
29
30
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2013
5 year avg
5 yr high
5 yr low
2015
2014
5 year avg

63
U.S. Distillate Fundamentals
USGC Brent ULSD Crack (per bbl)
U.S. Distillate Demand (mmbpd)
Source:  Argus; 2015 weekly data through Feb 20
Source:  2014 DOE monthly data through Nov 2014; 2015 weekly data through Feb 6
Source:  2014 DOE monthly data through Nov 2014; 2015 weekly data through Feb 6
Source:  2014 DOE monthly data through Nov 2014; 2015 weekly data through Feb 6
U.S. Distillate Days of Supply
U.S. Distillate Net Imports (mbpd)
$5
$10
$15
$20
$25
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2015
5 year avg
3.2
3.4
3.6
3.8
4.0
4.2
4.4
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2015
2014
5 year avg
25
30
35
40
45
50
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2015
2014
5 year avg
-1300
-1100
-900
-700
-500
-300
-100
100
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr low
5 yr high
2015
214
5 year avg

64
U.S. Transport Indicators
Source:  U.S. DOE PSM  /  U.S. DOT FHA
Most recent data includes Nov 2014
-5.0%
-3.0%
-1.0%
1.0%
3.0%
5.0%
U.S. VMT Growth vs. Gasoline Demand Growth
U.S. Gasoline Demand Growth
U.S. VMT Growth
65%
70%
75%
80%
85%
1.0
1.5
2.0
2.5
3.0
3.5
Airline Traffic Indicators
International
Domestic
Load Factor
-30%
-20%
-10%
0%
10%
20%
30%
2008
2009
2010
2011
2012
2013
2014
2015
North American Rail Traffic
4WMA
Latest Data as of: 1/29/2015
-60%
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
40%
-600
-500
-400
-300
-200
-100
0
100
200
300
400
U.S. Distillate Demand and Long Beach + LA Cargo
Activity (Trailing 3-Month Moving Average)
Cargo Latest Data Nov 14
Demand Latest Data Nov 14
Source:  Bureau of Transportation Statistics
Latest Data:  Oct 2014

65
U.S. Transport Indicators:  Trucking
95
100
105
110
115
120
125
130
135
140
ATA Seasonally Adj Truck Tonnage Index
Current Year
12-Mth Moving Avg
Data Through Dec-14
Source:  ATA
85
95
105
115
125
135
145
ATA Non-Seasonally Adj Truck Tonnage Index
Current Year
12-Mth Moving Avg
Data Through Dec-14
92
94
96
98
100
102
104
106
108
110
112
114
116
118
120
122
Transportation
Services
Index
-
Freight
Current Year
12-Mth Moving Avg
Data Through Nov-14
95
100
105
110
115
120
125
130
135
Freight: Annual Index Averages
SA ATA Truck Tonnage
TSI-Freight
Source:  ATA
Source:  BTS
ATA data through December-14, TSI data through November-14

Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:  DOE Petroleum Supply Monthly data through November 2014.   4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.
66
Increase in U.S. Gasoline Exports
0
100
200
300
400
500
600
700
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Mexico
Canada
Latest 4 Wk avg estimate
(Finished only)
12 Month Moving
Average, MBPD

Decrease in U.S. Gasoline Imports
Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:  DOE Petroleum Supply Monthly data through November 2014.  4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.
67
0
200
400
600
800
1000
1200
1400
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Canada
Latest 4 Wk avg estimate
(Fin+Blendstock)
12 Month Moving Average, MBPD

Source: DOE Petroleum Supply Monthly with data through November 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report
68
Increase in U.S. Diesel Exports
12 Month Moving Average, MBPD
0
200
400
600
800
1000
1200
1400
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Mexico
Canada
Latest 4 Wk avg estimate

69
U.S. Is Net Refined Products Exporter
U.S. Demand for Refined Products and Net Trade
MMBPD
U.S. Petroleum Demand Excluding Ethanol and Non-Refinery NGL’s
(Refined Product Demand)
Net Imports
Net
Exports
Implied Total Production of
U.S. Refined Products
Implied Production of U.S. Refined
Products for Domestic Use
Valero’s share of U.S. exports has averaged 20% to 25% over the past few years
14
15
16
17
18
19
20
21
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
Note: Implied production = Petroleum demand excluding ethanol and non-refinery NGLs minus product net imports. Source: EIA, Consultant and Valero estimates; data through November 2014

MBPD
70
U.S. Shifted to Net Exporter
Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:  DOE Petroleum Supply Monthly data through November 2014
•
Net refined products exports increased from 335 MBPD in 2010 to 2,450 MBPD in 2014
•
Diesel net exports averaged 917 MBPD in 2014 (Jan-Nov)
•
Gasoline
net
exports
averaged
50
MBPD
in
2014
(Jan
–
Nov)
•
Gasoline and blendstocks have shifted to net exports
-3,000
-2,500
-2,000
-1,500
-1,000
-500
500
1,000
1,500
2,000
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
Other
Diesel
Gasoline
Total
0

71
Mexico Statistics
Diesel Gross Imports (MBPD)
Source:  PEMEX, latest data December 2014
Gasoline Gross Imports (MBPD)
Crude Unit Throughput (MBPD)
Crude Unit Utilization
950
1,000
1,050
1,100
1,150
1,200
1,250
1,300
2007
2008
2009
2010
2011
2012
2013
2014
1,350
60%
65%
70%
75%
80%
85%
90%
2007
2008
2009
2010
2011
2012
2013
2014
200
250
300
350
400
450
500
550
2007
2008
2009
2010
2011
2012
2013
2014
0
20
40
60
80
100
120
140
160
180
200
2007
2008
2009
2010
2011
2012
2013
2014

72
Decrease in Venezuelan Exports to the U.S.
Source:  EIA, November 2014
0
50
100
150
200
250
300
350
MBPD
Total Products
Gasoline and Gasoline Blending
Components
Diesel

73
Non-GAAP Reconciliations
Ethanol (millions)
2Q09 –
4Q09
2010
2011
2012
2013
2014
Cumulative
Operating income
$165
$209
$396
$(47)
$491
$786
$2,000
+ Depreciation and amortization
expense
$18
$36
$39
$42
$45
$49
$229
= EBITDA
$183
$245
$435
$(5)
$536
$835
$2,229
Forecasted
(thousands)
Full Year Beginning
March 1, 2015 Valero
Partners Houston and
Louisiana
Net income
$37,300
+ Interest expenses
18,100
+ Income tax expense
400
+ Depreciation expense
$20,000
= EBITDA
$75,800
Reconciliation of VLO Ethanol Operating Income to EBITDA
Reconciliation of VLP Forecasted Net Income to EBITDA
Reconciliation of VLP Net Income Under GAAP to EBITDA
(1)
Interest
expense
and
cash
interest
paid
both
include
commitment
fees
to
be
paid
on
VLP’s
revolving
credit
facility.
Interest
expense
also includes the amortization of estimated deferred issuance costs to be incurred in connection with establishing VLP’s revolving credit
facility.
Three Months Ended
Three Months Ended
December 31, 2014
December 31, 2015
(millions)
As Reported
Annualized (x4)
Forecasted
Annualized
(x4)
Net income
$19
$76
$32
$128
Plus:
Depreciation expense
5
18
11
44
Interest expense
(1)
-
1
7
28
Income tax expense
-
-
-
-
EBITDA
$24
$95
$50
$200

Investor Relations Contacts
74
For more information, please contact:
John Locke
Executive Director, Investor Relations
210-345-3077
john.locke@valero.com
Karen Ngo
Manager, Investor Relations
210-345-4574
karen.ngo@valero.com
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