Valero Energy (VLO) 8-K Statements contained in this presentation that state the company’s or

Investor Presentation

January 2015

Exhibit 99.1

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

World’s Largest Independent Refiner

Large Logistics Infrastructure with Focus on Growth

•

•

Wholesale Fuels Marketer

•

•

One of North America’s Largest Renewable Fuels Producers

•

•

•

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

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

Approximately 7,400 marketing sites in U.S., Canada, United Kingdom, and Ireland

4

Assets Concentrated in

Advantaged Locations

Refinery

Capacities (MBPD)

Nelson

Index

Throughput

Crude Oil

Corpus Christi

325

205

19.9

Houston

165

90

15.1

Meraux

135

135

10.3

Port Arthur

350

330

12.6

St. Charles

280

190

17.5

Texas City

250

225

11.1

Three Rivers

100

95

12.4

Gulf Coast

1,605

1,270

14.1

Ardmore

90

86

12.1

McKee

170

168

9.5

Memphis

195

180

7.9

Mid-Con

455

434

9.3

Pembroke

270

220

9.7

Quebec City

235

230

7.7

North Atlantic

505

450

8.7

Benicia

170

145

16.1

Wilmington

135

85

15.8

West Coast

305

230

16.0

Total or Avg. 

2,870

2,384

12.4

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

•

Evaluate acceleration of dropdowns and other potential MLP-able

earnings streams

•

Previously unlocked value in retail business via 2013 spinoff to

stockholders

5

6

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

Global refined products demand growth is expected to continue

Location-advantaged refiners in U.S. Gulf Coast, Mid-Continent,

and Canada benefit from resource advantages and/or export

opportunities

-

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 September)

Source:  DOE (for 2014, data through September)

7

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

8

Persistent Focus Drives Results in Safety,

Environmental, and Regulatory Compliance

(1)Source: U.S. Bureau of Labor Statistics.

All 2014 values are estimates.

Statistics are for Refining only. 

Operations

Excellence

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Personnel Safety

Employees

Contractors

Industry

(1)

0.00

0.05

0.10

0.15

0.20

Tier 1 Process Safety

0

5

10

15

20

0

10

20

30

40

Environmental Events

Total Air Emissions (U.S. Refineries)

9

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

beginning mid-2000s

•

Significant gains made in

operations benchmarks since

2008

•

Personnel committed to

excellence

1

st

Quartile

2

nd

Quartile

3

rd

Quartile

4

th

Quartile

Source:  Solomon Associates and Valero Energy, includes Pembroke and Meraux

Sustained high availability and favorable margin environment enable higher

capacity utilization rates

10

Reliability Programs and Commercial

Optimization Drive Higher Utilization Rates

System-wide

mechanical

availability near

1

st

Quartile since

2011

88%

87%

92%

95%

96%

2010

2011

2012

2013

2014 1Q-3Q

Valero Refinery Utilization Rates

Optimizing Margins with Feedstock Flexibility

in Our Complex Refinery System

Range of Flexibility in Valero’s Gulf Coast

Region Quarterly Feedstock Mix 2010-2014

��

Capability to adjust

feedstocks and optimize

margins as crude price

environment shifts among

grades: light, medium,

heavy, sweet, sour

•

Focus on optimization

activities

•

Expect additional light crude

flexibility with completion

of topper units in progress

35%

34%

28%

23%

9%

26%

20%

12%

12%

4%

Avg

30%

Avg

26%

Avg

20%

Avg

18%

Avg

6%

•

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

12

(1) See Appendix for details and assumptions

•

Approximately half of benefit seen by >4%

points increase in margin capture rate

•

Approximately half of benefit due to 100

MBPD increase in throughput volumes from

feedstocks and new gas plant

•

Realized annual EBITDA estimated at

$800 million for trailing 4-quarters 3Q14

•

Compares to $780 million implied by

disclosed guidance model

(1)

•

Benefits visible in U.S. Gulf Coast region

reported results improvement from

4Q12 to 3Q14

(1)

Disciplined Capital Allocation

Framework Emphasizes Stockholders

Dividend Growth

•

•

Sustaining Capex

•

•

Debt and Cash

•

•

Stock Buybacks

•

•

Growth Capex

•

Acquisitions

•

•

“Non-Discretionary”

“Discretionary”

13

Capital

Returns to

Stockholders

(1) Debt-to-cap ratio based on total debt reduced by $2 billion cash balance, excluding VLP debt and equity

Estimate $1.5 billion or

lower annual “stay-in-

business”

spend

•

Key to safe and

reliable operations

Focus on sustainability

Increase competition

for cash flow versus

reinvestments (growth

capex and acquisitions)

Maintain investment

grade credit rating

Target 20% to 30%

debt-to-cap ratio

(1)

Flexibility to return

cash, reduce share

count, and manage

capital employed

Increase competition

versus reinvestments

Prioritize higher-value,

higher-growth, faster-

payback opportunities

that enhance future

returns

Evaluate accretion

versus stock buybacks

Enhance future

returns

14

Increasing Focus on Dividends and Stock

Buybacks

•

Regular dividend increases over

last three years

•

Significantly increased stock

buybacks in 2013 and 2014

•

Accelerated stock buybacks

throughout 2014 with 10 million

shares bought in 4Q14

•

Approximately $2 billion of stock

repurchase authorization at end

of 3Q14

Given cash return priority, we plan

to increase our total payout ratio of

earnings over 2014’s level

$0.10

$0.15

$0.20

$0.25

$0.30

Dividend Per Share of Valero

1Q

2Q

3Q

4Q

$0

$500

$1,000

$1,500

2011

2012

2013

2014

millions

Stock Buybacks

15

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

•

Focus on logistics growth after 2015 spending to complete crude toppers

•

Expect nearly all logistics growth investments to be eligible for dropdown into VLP

millions

$2,900

$2,650

$2,400

$695

$695

$900

$400

$615

$765

$730

$690

$790

$300

$715

$655

2014E

2015E

2016E

Logistics Growth

Refining, Renewables, &

Other Growth

Turnarounds & Catalyst

Sustaining

(1)

•

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

•

Expect Diamond Pipeline to supply Memphis refinery via Cushing and

start up in 1H17 or earlier

•

Tanks and vessels to supply crude to Quebec City refinery post-Enbridge

Line 9B reversal expected in 1H15

•

New Corpus Christi dock commissioned in 3Q14; completion of tanks for

crude exports expected in 1H15

16

Logistics Investments Enhance Valero’s

Feedstock Flexibility and Export Capability

•

Purchased 5,320 CPC-1232 railcars; received 3,547 through Nov 2014

•

Completed crude unloading facilities at Quebec City, St. Charles, and

Port Arthur in 2014

•

Benicia crude unloading facility undergoing permitting process

Pipelines

Tanks, Docks, and Vessels

Rail

Crude Topper Investments Very Attractive

17

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

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

Total investment

(1)

$750 MM

Annual EBITDA contribution

(2)

$500 MM

Unlevered IRR on total spend

(2)

50%

See Appendix for assumptions.

(1)

Excluding interest and overhead allocation

(2)

Estimates based on 2014 prices through Dec 9; EBITDA = operating

income before deduction for depreciation and amortization expense 

Key Natural Gas and NGLs Upgrading

Investments

18

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 lower capital requirement

compared to grassroots facility

•

In evaluation; estimated capital cost and project economics

remain in development

•

Expect investment decision in 2Q15; startup in 2018 if approved

•

12.5 MBPD capacity

•

Upgrades low-cost NGLs to premium-priced alkylate

•

In evaluation; estimated capital cost and project economics

remain in development

•

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 based on  Jan 1 through Dec 9 prices; see project details in Appendix

19

Ethanol Investments Performing Well

Note:  See Appendix for reconciliation of EBITDA to GAAP results. 2014 EBITDA through 3Q.

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

•

$2.1 billion cumulative

EBITDA generated since

acquisitions

•

$162 million cumulative

capex  excluding acquisition

costs

$2,058

$162

millions

Cumulative Capex and EBITDA

EBITDA

Capex

20

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 68.6% 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

•

Completed first dropdown from Valero on July 1, 2014

Unlocking

Asset Value

21

Significant Growth Opportunity with Estimated Inventory

of Eligible MLP Assets EBITDA over $900 Million

(1) Includes assets that have other joint venture or minority interests.

Pipelines

(1)

Racks, Terminals, and Storage

(1)

Rail

Marine

(1)

•

51 docks and two Panamax class vessels

Fuels Marketing and Distribution

We are also developing an accelerated drop-down strategy

•

Over 1,200 miles of active pipelines

•

Expect start-up of 440-mile Diamond Pipeline from Cushing to Memphis refinery

in 1H17

•

Over 72 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

•

Our 5,320 new CPC-1232 railcars can be used for long-term rail movements, such as

ethanol and asphalt

•

Currently under evaluation as drop-down candidate

22

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,

higher-growth, faster-payback opportunities to capture

benefits of advantaged resources

•

Unlocking value through growth in MLP-able assets and

dropdowns to VLP

•

Focus on valuation multiple expansion

23

Appendix

Topic

Pages

Valero 2014 Highlights and 2015 Goals

24-25

Valero Energy Partners LP and CST Brands Spinoff

26-28

Capital Spending and Key Investment Details

29-38

Other Valero Operations Highlights

39-44

Macro Outlook and Key Margin Drivers

45-51

Global Demand and Refining Capacity

52-56

U.S. Fundamentals and DOE Data

58-68

International Fundamentals

69-70

Non-GAAP Reconciliations

71

IR Contact Information

72

24

Key 2014 Highlights

Operations Excellence

•

Achieved record system refinery capacity utilization of approximately 96% in 2014 through 3Q

•

Increased consumption of price-advantaged North American light sweet crudes by 297 MBPD on average through 3Q14

compared to 2013

•

Reduced Quebec refinery’s crude costs by $3/bbl versus Brent from premium of approximately $2.50/bbl in 2013 to

discount of approximately $0.50/bbl in 2014 through 3Q

•

Secured attractively priced term-supply of WTI Midland for Mid-Continent refineries

•

Increased

gasoline

and

distillate

exports

by

57

MBPD,

or

18%,

in

2014

through

3Q

versus

2013

•

Launched Top Tier gasoline in wholesale marketing system

•

Achieved record $664 million Ethanol segment EBITDA through 3Q14

Capital Returns to Stockholders

•

Increased cash returned to stockholders through dividends and buybacks by approximately $460 million, 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 to benefit by estimated $130 million on retroactive reinstatement of biodiesel blending credit

25

Key 2015 Goals

Operations Excellence

•

Start up Montreal crude terminal with startup of 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 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 and construct Benicia crude rail unloading facility

Unlocking Asset Value

•

Grow inventory of MLP-able EBITDA

Growth in Inventory of Estimated Eligible

MLP EBITDA

Fuels distribution would provide incremental EBITDA if selected

$800

($15)

$24

$46

$54

$909

Dec. 2013

Guidance (with

base + 2014-

2015

projects)

Drop

-Downs

2014

-

2015

Logistics

Additional

Projects

Diamond Pipeline

Current Guidance

2016

-

2019

Logistics Projects

millions

26

27

VLP Nearing the “High Splits”

•

3Q14 distribution at $0.24 per unit

•

Expect VLP to reach 25% split in 2015 and 50% split in 2016 based on existing growth

guidance, but timing may change depending on evaluation of accelerated drop-down strategy

Minimum quarterly

First target

Second target

Third target

Thereafter

Target Quarterly Distribution per Unit

Marginal Percentage Interest in Distributions

Unitholders

GP

$0.2125

above $0.2125 up to $0.244375

above $0.244375 up to $0.265625

above $0.265625 up to $0.31875

$0.31875

98%

98%

85%

75%

50%

2%

2%

15%

50%

25%

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

28

Unlocked Value via Retail Spinoff in 2013

Allocating Significant Growth Capital to

Logistics

29

•

Railcars spending declines as receipt of railcars order concludes

•

Future spending focuses on pipelines

$510

$175

$45

$220

$180

$665

$170

$45

$5

$900

$400

$715

2014E

2015E

2016E

millions

Marine, Docks, and Other

Logistics

Pipelines and Tanks

Railcars and Unloading

30

Refining & Renewables Capital Focused on

Capturing Benefits of Key Long-Term Trends

$345

$490

$180

$110

$30

$120

$150

$105

$45

$40

$115

$690

$790

$300

2014E

2015E

2016E

millions

Nat Gas & Petchems

Other Projects

Hydrocracking

Advantaged Crude

Processing

$50

•

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

McKee Diesel Recovery Improvement and

CDU Expansion Startup Expected in 2H15

31

Incremental Volume

(MBPD)

Feeds

WTI

25

Products

LPG

0.4

Benzene concentrate

0.3

Gasoline

12

Jet

-

Diesel

12

Resid

0.6

Investment Highlights

Status

•

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

•

Diesel recovery and benefits started

in mid-2014; Expect crude

expansion start-up in 2H15

Project Estimates

Total investment

$140 MM

Annual EBITDA contribution

(1)

$100 MM

Unlevered IRR on total spend

(1)

45%

(1)

Estimates based on 2014 prices through Dec 9; EBITDA = operating income before 

deduction for depreciation and amortization expense

Meraux Hydrocracker Conversion Completed

December 2014

32

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%

Investment Highlights

Status

•

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

•

Project started up Dec-14

and operating well

(1)

Estimates based on 2014 prices through Dec 9; EBITDA = operating income before

deduction for depreciation and amortization expense 

Houston and Corpus Christi Crude Topping

Units Expected Online in 1

st

Half of 2016

33

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

$350 MM

Annual EBITDA contribution

(1)

$260 MM

Unlevered IRR on total spend

(1)

55%

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

Project Estimates

Total investment

$400 MM

Annual EBITDA contribution

(1)

$240 MM

Unlevered IRR on total spend

(1)

45%

Corpus Christi

Houston

(1)

Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for depreciation and amortization expense

Diamond Pipeline

34

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%

(1)

Includes additional Valero cost for pipeline connection at Memphis refinery

(2)

EBITDA = Operating income before deduction for depreciation and amortization expense

Investment Highlights

•

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 dropdown in capital-

efficient manner

•

Valero holds option until January

2016 to acquire 50% interest in

pipeline

•

Expect completion in 1H17 or earlier

Estimated Key Price Sensitivities on Project

Economics

35

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

-$0.7

-$1.9

-$4.3

-$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 YTD through Dec 9

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. 1

Project Price Set Assumptions

36

Driver ($/bbl)

2014

(1)

ICE Brent

99.51

ICE Brent –

WTI

6.43

ICE Brent –

LLS

2.64

USGC

CBOB

–

ICE

Brent

3.70

G3 CBOB –

WTI

12.45

USGC ULSD –

ICE Brent

14.45

G3 ULSD –

WTI

24.00

Natural gas (Houston Ship Channel, $/mmBtu)

4.36

Naphtha –

ICE Brent

-2.12

LSVGO –

ICE Brent

8.92

(1) 2014 = YTD through Dec 9

37

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%

4.4%

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

98

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)

$802

Key Assumptions

•

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

38

PHASE 2

Lead Case

Development

•

Select lead case

and define

project

objectives

•

Improve cost

estimate to    

+/-

30%

PHASE 3

Refinement

•

Define project

scope and

execution plans

•

Prepare decision

support package

for final decision

•

Narrow cost

estimate to    

+/-10%

PHASE 1

Opportunity

Evaluation

•

Identify

opportunities

and alternatives

•

Develop

business case

•

Generate cost

estimate range

of +100% to -

50%

PHASE 4

Execution

•

Detail

engineering,

procurement,

and initial

construction

•

Develop start-

up schedule

APPROVED

Startup and

Evaluate

•

Post-audit back-

casting

•

Capture lessons

learned

39

Valero’s Light Crude Processing Capacity in

North America

MBPD

(1) Not incentivized in 3Q14 to maximize North American light crude consumption versus

alternative grades.

•

25 MBPD additional capacity

expected in 2H15

•

Distillate recovery improvements

•

90 MBPD capacity expected 1H16

•

Displaces 30 MBPD intermediate

feedstock purchases

•

70 MBPD capacity expected 1H16

•

Displaces 25 MBPD intermediate

feedstock purchases

(1)

1,010

1,210

1,395

3Q14 Actual

Utilization

Current Capacity

Estimate

Future Capacity

(with Projects)

McKee Crude Unit Expansion

Corpus Christi Crude Topper

Houston Crude Topper

40

Processing of Cost-Advantaged U.S. and

Canadian Crude by Valero Continues to Grow

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

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

MBPD

MBPD

Gulf Coast

Mid-Con

West Coast

Quebec

Non-U.S. & Canadian

41

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

1,934

1,714

1,211

443

129

VLO

MPC

PSX

HFC

TSO

MBPD

Canada

U.S. Gulf Coast

U.S. Midcontinent

42

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 1H15

0%

20%

40%

60%

80%

100%

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

Quebec City Refinery Crude Slate

Foreign

Imports

North

American

43

U.S. Natural Gas Provides Opex and

Feedstock Cost Advantages

Note:  Estimated per barrel cost of 860,000 mmBtu/day of natural gas consumption at 94% refinery throughput capacity utilization, or 2.7 MMBPD.

$1.3 billion

higher pre-tax

annual costs

$2.5 billion

higher pre-tax

annual costs

Valero’s refining operations consume approximately 860,000 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

$4/mmBtu

$1.27/bbl

$8/mmBtu

Europe

$2.55/bbl

$16/mmBtu

$5.10/bbl

$0

$1

$2

$3

$4

$5

$6

/bbl

Natural Gas Cost Sensitivity for Valero’s Refineries

Asian LNG

44

Valero’s Capacity for Additional

Product Exports

(1)

YTD through September 30

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

(1)

255

412

0

100

200

300

400

500

600

700

2011

Actual

2012

Actual

2013

Actual

Current

Capacity

Valero’s U.S. Product Exports

(MBPD)

Gasoline

Diesel

2014

YTD

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 may be 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

45

46

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 Sep 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

47

48

Crude Oil Differentials Versus ICE Brent

Source:  Argus; 4Q14 through Dec 12. LLS prices are roll adjusted

-30%

-25%

-15%

-10%

-5%

0%

5%

10%

15%

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

1Q14

2Q14

3Q14

4Q14

Maya

Mars

ANS

WTI

LLS

-20%

49

Valero’s Regional Refinery Indicator Margins

Source:  Argus; 4Q14 through Dec 12

$5

$10

$15

$20

$25

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

1Q14

2Q14

3Q14

4Q14

$/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

50

Valero’s

Regional

Indicator

Margins

Defined

51

Source:  Argus & Bloomberg; 2014 YTD Japan LNG through Oct 31, U.S. & Europe through Dec 15; natural gas price converted to barrels using factor of 6.05x

0

20

40

60

80

100

120

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Brent and Natural Gas Prices

Brent

U.S.

Europe

Japan LNG

•

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

Low Cost U.S. Natural Gas Provides

Competitive Advantage

$/bbl

$101

$97

$16/mmBtu

$51

$8/mmBtu

$26

$4/mmBtu

52

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

MMBPD

World Petroleum Demand Growth

Non-OECD

OECD (excl. U.S.)

U.S.

53

U.S. Refining Capacity Is Globally Competitive and

Continues to Take Market Share

Source:  EIA and IEA (U.S. data through September 2014, Europe data through October 2014)

Less-competitive capacity

Source:  EIA (2014 data through September)

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

54

World Refinery Capacity Growth

-0.2

0.2

0.6

1.0

1.4

1.8

2014

2015

2016

2017

2018

MMBPD

Estimated Net Global Refinery Crude Distillation Additions

China

Middle East

Other (incl. U.S. and Latin America)

•

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

Source: Consultant and Valero estimates;  Net Global Refinery Additions = New Capacity + Restarts – Announced Closures

55

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

Rest of World

Atlantic Basin

Annual Global CDU Capacity

Closures

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

*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 and Valero estimates

Location

Owner

CDU Capacity

Closed (MBPD)

Year

Closed

Location

Owner

CDU Capacity

Closed (MBPD)

Year

Closed

Perth Amboy, NJ

Chevron

80

2008

St. Croix, U.S.V.I

Hovensa

350

2012

Bakersfield,CA 

Big West

65

2008

Aruba

Valero

235

2012

Westville, NJ

Sunoco

145

2009

Rome, Italy

TotalErg

82

2012

Bloomfield, NM

Western

17

2009

Fawley, U.K.*

ExxonMobil

80

2012

Teesside, UK

Petroplus

117

2009

Trecate, Italy*

ExxonMobil

70

2012

Gonfreville, France*

Total

100

2009

Paramo, Czech Republic

Unipetrol

20

2012

Dunkirk, France

Total

140

2009

Lisichansk, Ukraine

TNK-BP

175

2012

Japan*

JX Holdings

110

2009

Paramount, CA

Alon

90

2012

Toyama, Japan

Nihonkai Oil

57

2009

Harburg, Germany

Shell

107

2013

Ingolstadt, Germany*

Bayernoil

102

2010

Port Reading, NJ

Hess

N/A

2013

Japan*

JX Holdings

90

2010

Venice, Italy

ENI

80

2013

Arpechim, Romania

OMV

70

2010

Sakaide, Japan

Cosmo Oil

140

2013

Odessa, Ukraine

Lukoil

57

2010

Dartmouth, Canada

Imperial Oil

88

2013

Montreal, Canada 

Shell

130

2010

Thessaloniki, Greece

Hellenic Petroleum

83

2013

Yorktown, Virginia

Western

65

2010

Tenerife, Canary Islands

Cepsa

85

2013

Reichstett, France

Petroplus

85

2010

Yokkaichi, Japan*

Cosmo Oil

43

2014

Wilhemshaven, Germany

Phillips 66

260

2010

Tokuyama, Japan

Indemitsu Kosan

114

2014

Sodegaura, Japan

Fuji Oil

50

2010

Japan

Nippon

200

2014

Cremona, Italy

Tamoil

94

2011

Kurnell, Australia

Caltex

135

2014

St. Croix, U.S.V.I,*

Hovensa

150

2011

Kawasaki, Japan

Tonen-

General

105

2014

Funshun, China

PetroChina

70

2011

Mantova, Italy

Mol

69

2014

Keihin Ohgimachi, Japan

Toa Oil Company

120

2011

North Pole, AK

Flint Hills

220

2014

Clyde, Australia

Shell

75

2011

Muroran, Japan

JX Holdings

180

2014

Marcus Hook, PA

Sunoco

175

2011

Ellesmere Port, UK*

Essar

55

2014

Berre, France

LyondellBasell

105

2012

Milford Haven, UK

Murphy

130

2014

Coryton, U.K.

Petroplus

220

2012

Kaohsiung, Taiwan

Chinese Petroleum Corp

200

2015

Petit Couronne, France

Petroplus

160

2012

Bulwer Island, Australia

BP

102

2015

56

Global Refining Capacity Rationalization

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

Come-By-Chance, Canada

North Atlantic Refining

115

Pasadena, TX

Petrobras

100

Bahia Blanca, Argentina

Petrobras

31

Gothenburg, Sweden

Shell

80

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

57

Global Refining Capacity For Sale or Under

Strategic Review

Sources: Direct and public disclosure by each owner

58

U.S. Crude Fundamentals

Source:  DOE weekly data through December 5, 2014

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 High

5 Yr Low

2012

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)

320,000

330,000

340,000

350,000

360,000

370,000

380,000

390,000

400,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

U.S. Crude Inventory (MB)

5 Yr High

5 Yr Low

2012

2013

2014

5 Yr Avg

5 Yr High

5 Yr Low

2012

59

U.S. Gasoline Fundamentals

USGC Brent Gasoline Crack (per bbl)

U.S. Gasoline Demand (mmbpd)

U.S. Net Imports of Gasoline and Blendstocks (mbpd)

U.S. Gasoline Days of Supply

22

23

24

25

26

27

28

29

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 yr high

5 yr low

2014

2013

5 year avg

-400

-200

0

200

400

600

800

1000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 year avg

5 yr high

5 yr low

2014

2013

-$15

-$10

-$5

$0

$5

$10

$15

$20

$25

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 yr high

5 yr low

2013

2014

5 year avg

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

2014

2013

5 year avg

Source:  Argus; 2014 weekly data through Dec 12

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

60

U.S. Distillate Fundamentals

USGC Brent ULSD Crack (per bbl)

U.S. Distillate Demand (mmbpd)

Source:  Argus; 2014 data through Dec 12

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

Source:  2014 DOE monthly data through Sep; weekly data through Dec 5

U.S. Distillate Days of Supply

U.S. Distillate Net Imports (mbpd)

$0

$5

$10

$15

$20

$25

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 yr high

5 yr low

2013

2014

5 year avg

3.2

3.4

3.6

3.8

4

4.2

4.4

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 yr high

5 yr low

2014

2013

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

2014

2013

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

2014

2013

5 year avg

61

U.S. Transport Indicators

62

U.S. Transport Indicators:  Trucking

63

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

Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)

Source:  DOE Petroleum Supply Monthly data as of September 2014.   4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.

64

Decrease in U.S. Gasoline Imports

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

Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)

Source:  DOE Petroleum Supply Monthly data as of September 2014.  4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.

Source: DOE Petroleum Supply Monthly with data as of September 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report

65

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

66

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 Sep 2014 

67

U.S. Shifted to Net Exporter

•

Net refined products exports increased from 335 MBPD in 2010 to 2,426 MBPD in 2014

•

Diesel net exports averaged 917 MBPD in 2014 (Jan-Sep)

•

Gasoline

net

imports

averaged

-31

MBPD

in

2014

(Jan

–

Sep)

•

Gasoline and blendstocks have shifted to net exports

-3,000

-2,500

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

2,000

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

Other

Diesel

Gasoline

Total

Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)

Source:  DOE Petroleum Supply Monthly data as of Sep 2014

MBPD

68

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

U. S. Product Exports By Destination

U. S. Product Exports By Source

12 Month Moving Average

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)

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

MMBPD

Source:  DOE Petroleum Supply Monthly data as of Sep 2014; Latin America includes South and Central America plus Mexico.

Mexico Statistics

Diesel Gross Imports (MBPD)

Gasoline Gross Imports (MBPD)

Crude Unit Throughput (MBPD)

Crude Unit Utilization

69

200

250

300

350

400

450

500

550

2007

2008

2009

2010

2011

2012

2013

2014

60%

65%

70%

75%

80%

85%

90%

2007

2008

2009

2010

2011

2012

2013

2014

950

1,000

1,050

1,100

1,150

1,200

1,250

1,300

1,350

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

Source:  PEMEX, latest data Oct 2014

70

Decrease in Venezuelan Exports to the U.S.

Source:  EIA, September 2014

0

50

100

150

200

250

300

350

MBPD

Total Products

Gasoline and Gasoline Blending

Components

Diesel

71

Reconciliation of Operating Income to EBITDA

Ethanol (millions)

2Q09 –

4Q09

2010

2011

2012

2013

2014*

Cumulative

Operating income

$165

$209

$396

$(47)

$491

$628

$1,842

+ Depreciation and

amortization expense

$18

$36

$39

$42

$45

$36

$216

= EBITDA

$183

$245

$435

$(5)

$536

$664

$2,058

*2014 Ethanol earnings through September 30

Investor Relations Contacts

72

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