Valero Energy (VLO) 8-K Regulation FD Disclosure

Investor Presentation

June 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

World’s Largest Independent Refiner

•

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

World’s Largest Independent Refiner

•

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

Large Logistics Infrastructure with Focus on Growth

•

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

Large Logistics Infrastructure with Focus on Growth

•

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

Wholesale Fuels Marketer

•

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

•

Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock, and Beacon

Wholesale Fuels Marketer

•

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

•

Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock, and Beacon

One of North America’s Largest Renewable Fuels Producers

•

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 –

10,800 BPD

renewable diesel production capacity

One of North America’s Largest Renewable Fuels Producers

•

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 –

10,800 BPD

renewable diesel production capacity

4

Assets Concentrated in Advantaged Locations

Refinery

Capacities (MBPD)

Nelson

Index

Throughput

Crude

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

-

Lower crude prices may temporarily constrain production growth rate

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

-

Expect lower prices to consumers will drive product demand growth

6

Production Growth Provides Resource

Advantage to North American Refiners

Source:

DOE (for 2015, data through March)

Source:

DOE (for 2015, data through March)

4,500

5,500

6,500

7,500

8,500

9,500

10,500

MBPD

U.S. Crude Oil Production and

Imports

Imports

Production

45

50

55

60

65

70

75

80

U.S. Natural Gas Production

(Bcf/day)

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

-2.5

-1.5

-0.5

0.5

1.5

2.5

3.5

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015E

2016E

MMBPD

World Petroleum Demand Growth

U.S.

OECD (excl. U.S.)

Non-OECD

Source:

DOE Petroleum Supply Monthly data as of March 2015; Latin America includes South and Central America plus Mexico.

U. S. Product Exports By Destination

12 Month Moving Average

U. S. Product Exports By Source

8

U.S. Is Growing Product Exports Market Share

Refiners in U.S. Gulf Coast are the largest source of products exported to Latin

America and countries in the Atlantic Basin

PADD I

PADD II

PADD III

(Gulf Coast)

PADD V

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

2015

MMBPD

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

2015

MMBPD

Other

Europe

Latin America

Canada

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 operating performance

•

Optimize margins with refining system’s feedstock and product

markets flexibility

•

Demonstrate commitment to safe and reliable operations

•

Continuously improve operating performance

•

Optimize margins with refining system’s feedstock and product

markets flexibility

•

Disciplined capital allocation

•

Seek to increase cash returns through dividend growth

•

Reduce shares outstanding and concentrate future value per share

via stock buybacks

•

Disciplined capital allocation

•

Seek to increase cash returns through dividend growth

•

Reduce shares outstanding and concentrate future value per share

via stock buybacks

•

Rigorous investment management and execution process

•

Invest to grow logistics assets and reduce feedstock costs

•

Evaluate investments to upgrade natural gas and natural gas liquids

•

Opportunistic renewable fuels investments

•

Rigorous investment management and execution process

•

Invest to grow logistics assets and reduce feedstock costs

•

Evaluate investments to upgrade natural gas and natural gas liquids

•

Opportunistic renewable fuels investments

•

Grow Valero Energy Partners LP and realize value for Valero

•

Execute accelerated drop-down strategy and evaluate other

potential MLP-able earnings streams

•

Grow Valero Energy Partners LP and realize value for Valero

•

Execute accelerated drop-down strategy and evaluate other

potential MLP-able earnings streams

9

Persistent Focus Drives Results in Safety,

Environmental, and Regulatory Compliance

Operations Excellence

10

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

All 2014 values are estimates.

Statistics are for refining only. 

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Personnel Safety

Employees

Contractors

Industry

(1)

0.0

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)

11

Excellent Operating Performance through

Continuous Improvements

Source:

Solomon Associates and Valero Energy, includes Pembroke and Meraux

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

st

Quartile

2

nd

Quartile

3

rd

Quartile

4

th

Quartile

Sustained high availability and favorable margin environment enable higher capacity

utilization rates

12

Investments, Operations Excellence, and

Commercial Optimization Drive High Utilization

System-wide mechanical

availability near 1

st

quartile since 2011

88%

87%

92%

95%

96%

92%

2010

2011

2012

2013

2014

1Q15

Valero Refinery Utilization Rates

13

Refining and Logistics Growth Investments

Enhance Feedstock Flexibility

Valero’s

Gulf

Coast

Region

Quarterly

Feedstock

Mix

2010

–

2015

(1)

(1) 2015 through March 31.

•

Feedstock mix and rates are adjusted to optimize margins as price environment changes

•

Expect additional light crude flexibility with completion of Houston and Corpus Christi

topper units currently under construction

26%

17%

12%

12%

4%

37%

34%

30%

23%

10%

Heavy sour

Medium/light sour

Sweet

Residuals

Other feedstocks

14

Capital Allocation Framework Emphasizes

Discipline and Stockholder Returns

Dividends

•

Focus on sustainability

•

Increase competition

for cash flow versus

reinvestments (growth

capex and acquisitions)

Sustaining Capex

•

Estimate $1.5 billion or

lower annual “stay-in-

business” spend

•

Key to safe and

reliable operations

Debt and Cash

•

Maintain investment

grade credit rating

•

Target 20% to 30%

debt-to-cap ratio

(1)

Stock Buybacks

•

Flexibility to return

cash, reduce share

count, and manage

capital employed

•

Increase competition

versus reinvestments

Growth Capex

•

Prioritize higher-value,

higher-growth

opportunities that

enhance future

returns

Acquisitions

•

Evaluate accretion

versus stock buybacks

•

Enhance future

returns

“Non-Discretionary”

“Discretionary”

Capital Returns to Stockholders

(1) Debt-to-cap ratio based on total debt reduced by $2 billion cash balance

15

Increasing Dividends and Stock Buybacks

•

Increased dividend by 45% in

1Q15 versus 4Q14

•

Regular dividend increases over

last three years

•

Accelerated stock buybacks

beginning in 2013

•

Approximately $1.2 billion of

stock repurchase authorization at

end of 1Q15

Targeting >50% total payout ratio of

earnings in 2015 via dividends and

stock buybacks

*2015 through June 12

*2015 through June 12

1Q

2Q

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

2011

2012

2013

2014

2015*

Annual Dividend Per Share

$792

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2011

2012

2013

2014

2015*

MM

Stock Buybacks

16

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

(1)

•

Logistics growth spending increases after completion of crude toppers in 2016

•

Expect nearly all logistics growth investments to be eligible for drop-down to VLP

Disciplined Capital Investment

$765

$730

$695

$655

$790

$300

$400

$715

$2,650

$2,400

2015E

2016E

millions

Logistics Growth

Refining, Renewables, & Other

Growth

Turnarounds & Catalyst

Sustaining

Pipelines

•

Connection to Centurion pipeline in Childress, TX and 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, with

start up in 1H17

Pipelines

•

Connection to Centurion pipeline in Childress, TX and 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, with

start up in 1H17

Tanks, Docks, and Vessels

•

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

Line 9B reversal expected in 2Q15

•

Commissioned new Corpus Christi dock in 3Q14 and tanks for crude oil

loading in April 2015

Tanks, Docks, and Vessels

•

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

Line 9B reversal expected in 2Q15

•

Commissioned new Corpus Christi dock in 3Q14 and tanks for crude oil

loading in April 2015

17

Logistics Investments Enhance Valero’s

Feedstock Flexibility and Export Capability

Rail

•

Received 96 percent of 5,320 purchased railcars through May 2015, with

balance of order expected to arrive in June

•

New railcars expected to serve long-term needs in ethanol and asphalt

•

Crude unloading facilities at Quebec City, St. Charles, and Port Arthur

Rail

•

Received 96 percent of 5,320 purchased railcars through May 2015, with

balance of order expected to arrive in June

•

New railcars expected to serve long-term needs in ethanol and asphalt

•

Crude unloading facilities at Quebec City, St. Charles, and Port Arthur

18

Crude Topper Investments Very Attractive

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

Estimated 55 MBPD low sulfur

resid

yield should lower feedstock

costs

Net throughput capacity increase

of approximately 105 MBPD, with

startup expected 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 full year average prices; EBITDA = operating income before

deduction for depreciation and amortization expense

19

Investments in Natural Gas and NGLs Upgrading

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 2018 if approved

•

Converts natural gas to incremental distillate via hydrogen

•

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 Port Arthur and St. Charles

in progress; expect startup in 2H15

(1) 2014 full year average prices; see project details in Appendix

20

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

21

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 approximately 25%

CAGR for LP distributions

through 2017

$95

$200

4Q14

4Q15E

Adjusted EBITDA Attributable to VLP

(millions)

Annualized

Annualized

22

Significant Inventory of Estimated MLP

Eligible EBITDA at Valero

Fuels distribution would provide incremental EBITDA if selected

(1)

(1) Assumes total cost of $900 MM and 10x EBITDA multiple on VLO’s share.

$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

23

Estimated Inventory of Eligible MLP Assets

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

Pipelines

(1)

•

Over 1,200 miles of active pipelines

•

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

1H17

Racks, Terminals, and Storage

(1)

•

Over 100 million barrels of active shell capacity for crude and products

•

139 truck rack bays

Rail

•

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

Marine

(1)

•

51 docks

•

Two Panamax class vessels

Fuels Distribution

•

Evaluating qualifying volumes and commercial structure as potential drop-down

candidate

24

We Believe VLO Is an Excellent Investment

•

Majority of capacity has access to cost-advantaged crude, natural

gas, NGLs, and corn

•

Proven operations excellence

•

Emphasis on capital allocation to stockholders

•

Discipline and rigor in capital projects and M&A selection and

execution

•

Unlocking value through growth in MLP-able assets and drop-

downs to VLP

•

Excellent ethanol investments and operations

•

Focus on valuation multiple expansion

25

Appendix

Topic

Page

Valero 2015 Goals

26

Ethanol Segment

27

Investment Management Process

28

Capital Spending and Investment Details

29 –

38

Valero Energy Partners LP

39 –

40

Refining Operations Highlights

41 –

45

Macro

Outlook

46

Estimated Crude Oil Transportation

Costs

47

Regional Indicator Margins

48

Global

Refining Capacity

49 –

51

U.S. Fundamentals and Transport Indicators

52 –

57

Mexico Fundamentals

58

Non-GAAP

Reconciliations

59

IR Contacts

60

26

Key Goals Expected in 2015

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

27

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

•

$2.3 billion cumulative

EBITDA generated since

acquisitions

•

$167 million cumulative

capex  excluding acquisition

costs

$2,254

$167

millions

Cumulative Capex and EBITDA

EBITDA

Capex

Gated Investment Management Process

28

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

•

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 4

Execution

•

Detail

engineering,

procurement,

and initial

construction

•

Develop start-up

schedule

APPROVED

Startup and

Evaluate

•

Post-audit back-

casting

•

Capture lessons

learned

•

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

29

Refining

&

Renewables

Capital

Focused

on

Capturing

Benefits

of

Key

Long-Term

Trends

$490

$50

$110

$30

$150

$105

$40

$115

$790

$300

2015E

2016E

millions

Nat Gas & Petchems

Other Projects

Hydrocracking

Advantaged Crude Processing

•

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

30

Allocating Significant Growth Capital to Logistics

$175

$45

$180

$665

$45

$5

$400

$715

2015E

2016E

millions

Marine, Docks and Other

Logistics

Pipelines and Tanks

Railcars and Unloading

•

Railcars spending declines as receipt of railcars order concludes

•

Future spending focuses on pipelines

31

McKee Diesel Recovery Improvement and

CDU Expansion Startup Expected in 2H15

(1)

Estimates based on 2014 full year average prices; EBITDA = operating income before

deduction for depreciation and amortization expense

Project Estimates

Annual EBITDA contribution

(1)

$100 MM

Total investment

$140 MM

Unlevered IRR on total spend

(1)

45%

Investment Highlights

•

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

Status

•

Diesel recovery and benefits started

in mid-2014; expect crude

expansion start-up in 2H15

Incremental Volume

(MBPD)

WTI

25

Products

Benzene concentrate

0.3

Jet

-

Resid

0.6

Feeds

LPG

0.4

Gasoline

12

Diesel

12

32

Meraux Hydrocracker Conversion

Completed December 2014

(1)

Estimates based on 2014 full year average prices; EBITDA = operating income before

deduction for depreciation and amortization expense

Project Estimates

Annual EBITDA contribution

(1)

$90 MM

Total investment

$260 MM

Unlevered IRR on total spend

(1)

25%

Incremental Volume

(MBPD)

Feeds

Purchased hydrogen

(MMSCFD)

13

Products (MBPD)

Gasoline

5

Jet

-

Diesel

19

HSVGO

2

Unconverted gasoil

(23)

Fuel oil

-

Investment Highlights

•

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

Status

•

Project started up in Dec 2014 and is

operating well

33

Houston and Corpus Christi Crude Topping

Units Expected Online in 1st Half of 2016

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

Project Estimates

Annual EBITDA contribution

(1)

$240 MM

Total investment

$400

MM

Unlevered IRR on total spend

(1)

45%

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%

34

Diamond Pipeline

(1)

Includes additional Valero cost for pipeline connection at Memphis refinery

(2)

EBITDA = Operating income before deduction for depreciation and amortization expense

Project Estimates

Total investment

(1)

$484

MM

Cumulative spend through 2014

Zero

Annual EBITDA contribution

(2)

$46 MM

Unlevered pre-tax IRR on total spend

at

least 12%

Investment Highlights

•

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

35

Estimated Key Price Sensitivities on Project

Economics

(1)

Operating income before deduction for depreciation and amortization expense

(2)

2014 full year average

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.

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

ICE Brent –

WTI, +$1/bbl

ICE Brent –

LLS, +$1/bbl

Group 3 CBOB –

ICE

Brent, +$1/bbl

Group 3 ULSD –

ICE Brent, +$1/bbl

USGC CBOB

–

ICE Brent, +$1/bbl

USGC ULSD –

ICE

Brent, +$1/bbl

Natural

gas (Houston Ship Channel), +$1/mmBtu

Naphtha –

ICE Brent, +$1/bbl

LSVGO

–

ICE Brent, + $1/bbl

Total investment IRR, +10% cost

none

$0.8

$0.4

none

$5.5

none

None

none

N/A

none

$25.6

$32.9

$2.0

N/A

N/A

N/A

$5.5

N/A

N/A

N/A

N/A

$1.7

$2.4

$2.4

N/A

$6.8

$9.0

$9.9

-$0.7

-$1.9

-$4.3

-$3.2

N/A

none

$5.8

$8.8

N/A

-$7.3

$3.1

$5.2

-6%

N/A

-5%

-4%

36

Project Price Set Assumptions

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

•

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

37

Port Arthur and St. Charles Hydrocrackers

Performing Better Than Expected

•

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

•

Realized annual EBITDA estimated at

$800 million for trailing 4-quarters

3Q14

•

Compares to $780 million implied by

disclosed guidance model

38

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

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

39

Drop Down of Houston and St. Charles

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

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

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 on track to achieve $1 billion in drop-down transactions in 2015

40

Valero’s GP Interest in VLP Nearing the

“High Splits”

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%

•

1Q15 distribution at $0.2775 per unit

•

Valero’s GP interest in VLP expected to reach 50% split in 2015, payable in 2016, based on

accelerated drop-down strategy

41

Valero Is Currently Utilizing 82 Percent of It’s

Available Light Crude Capacity in North America

(1) Actual light crude consumption less than capacity due to turnaround maintenance and

economics. Includes imported foreign sweet crudes.

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)

1,000

1,220

1,410

1Q15 Actual

Utilization

Current Capacity

Estimate

Future Capacity

(with Projects)

MBPD

42

Valero Leads Peers in Total

Location-Advantaged Crude Capacity

Source:  Company 10-Ks and IR slides.  Crude distillation capacity based on geographic location.

Access to lower cost North American crude benefits refiners in Mid-Continent, Gulf Coast, and

Eastern Canada; product export opportunities for Gulf Coast and Canada

1,948

1,731

1,230

443

129

VLO

MPC

PSX

HFC

TSO

MBPD

Eastern Canada

U.S. Gulf Coast

U.S. Midcontinent

0%

20%

40%

60%

80%

100%

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

Quebec City Refinery Crude Slate

Foreign

Imports

North

American

43

Expect Quebec City Refinery to Have Cost-Advantaged

Access to 100% North American Crude 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 3Q15

44

U.S. Natural Gas Provides Opex and

Feedstock Cost Advantages

Note:  Estimated per barrel cost of 864,000 mmBtu/day of natural gas consumption at 92% refinery throughput capacity utilization, or 2.7 MMBPD.

$1.3 billion

higher pre-tax

annual costs

$2.8 billion

higher pre-tax

annual costs

•

Our 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

•

Prices expected to remain low and disconnected from global oil and gas markets

$3/mmBtu

$1/bbl

$7/mmBtu

Europe

$2.20/bbl

$14/mmBtu

Asian LNG

$4.50/bbl

$0

$1

$1

$2

$2

$3

$3

$4

$4

$5

$5

/bbl

Natural Gas Cost Sensitivity for Valero’s Refineries

45

Capacity to Export Additional Product

255

412

0

100

200

300

400

500

600

700

2011

2012

2013

2014

1Q15

Current

Capacity

Valero’s U.S. Product Exports

(MBPD)

Gasoline

Diesel

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

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, expected to strengthen

near-term with lower prices

•

Natural gas production growth still attractive and development continues

•

Crude production 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

46

47

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

Midland

to Houston

Pipe

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

Rail $9/bbl

U.S. Ship

$4 to

$5/bbl

Alberta

to Eastern Canada

Rail $11 to $12/bbl

Bakken

Brent to

USEC

$2/bbl

Alberta to Bakken

$1 to $2/bbl

$4/bbl

$4/bbl

Pipe $2 to

•

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

48

Regional Indicator Margins Defined

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)

49

World Refinery Capacity Growth

•

New capacity additions expected in Asia and the Middle East

•

Announced new capacity in Latin America likely to be smaller and start later than planned

•

Capacity rationalization expected to continue in Europe

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

50

Capacity Rationalization in Atlantic Basin

Sources:  Industry and Consultant reports and Valero estimates

•

Marginal refiners continue to rationalize capacity

•

Closures in the last few years have been focused in Japan, Australia, and Europe

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

Rome, Italy

Total/Erg

88

2012

Bakersfield, CA

Big West

65

2008

Fawley, U.K.*

ExxonMobil

80

2012

Ingolstadt, Germany*

Bayernoil

102

2008

Paramo, Czech Republic

Unipetrol

20

2012

Yabucoa, Puerto Rico

Shell

Yabucoa, Inc.

76

2008

St. Croix, USVI

Hovensa

350

2012

Westville, NJ

Sunoco

145

2009

San Nicholas, Aruba

Valero

235

2012

Bloomfield, NM

Western

17

2009

Lisichansk, Ukraine

TNK-BP

175

2012

North Pole, AK*

Flint Hills Resources

85

2009

Clyde, Australia

Shell

75

2012

Teesside, UK

Petroplus

117

2009

Port Reading, NJ

Hess

2013

Gonfreville

L'Orcher, France*

Total

90

2009

Dartmouth, Canada

Imperial Oil

88

2013

Dunkirk, France

Total

140

2009

Harburg, Germany

Shell

107

2013

Toyama, Japan

Nihonkai

Oil

57

2009

Porto Marghera, Italy

ENI

80

2013

Yorktown, VA

Western

65

2010

Sakaide, Japan

Cosmo Oil

140

2013

Montreal, Canada

Shell

130

2010

North Pole, AK

Flint Hills Resources

80

2014

Reichstett, France

Petroplus

85

2010

Mantova, Italy

MOL

69

2014

Wilhelmshaven, Germany

ConocoPhillips

260

2010

Stanlow, U.K.*

Essar

101

2014

Sodegaura, Japan*

Fuji Oil

50

2010

Milford Haven, U.K.

Murphy

130

2014

Oita, Japan*

JX Holdings

24

2010

Yokkaichi, Japan*

Cosmo Oil

43

2014

Mizushima, Japan*

JX Holdings

110

2010

Tokuyama, Japan

Idemitsu Kosan

114

2014

Negishi, Japan*

JX Holdings

70

2010

Kurnell, Australia

Caltex

135

2014

Kashima, Japan*

JX Holdings

18

2010

Kawasaki, Japan*

Tonen-General

67

2014

Marcus Hook, PA

Sunoco

175

2011

Wakayama, Japan*

Tonen-General

38

2014

St. Croix, USVI*

Hovensa

150

2011

Muroran, Japan

JX Holdings

180

2014

Arpechim, Romania

OMV Petrom

70

2011

Chiba, Japan*

Kyokuto Petroleum Ltd.

23

2014

Cremona, Italy

Tamoil

94

2011

Kaohsiung, Taiwan

Chinese Petroleum Corp.

200

2015

Ogimachi, Japan

Toa/Showa Shell

120

2011

Bulwer Island, Australia

BP

102

2015

Fushun, China

Fushun Petrochem.

70

2011

Chiba, Japan*

Idemitsu Kosan

20

2015

Paramount, CA

Alon

90

2012

Kawasaki, Japan*

Tonen-General

10

2015

North Pole, AK*

Flint Hills Resources

48

2012

Nishirara, Okinawa

Petrobras/Nansei Sekiyu

100

2015

Berre L'Etang, France

LyondellBasell

105

2012

Collombey, Switzerland

Tamoil

55

2015

Coryton, U.K.

Petroplus

175

2012

Lindsey, U.K.*

Total

110

2016

Petit Couronne, France

Petroplus

160

2012

La Mede, France

Total

159

2016

51

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. 

52

U.S. Refining Capacity Is Globally Competitive and

Continues to Take Market Share

Source:  EIA and IEA (U.S. data through March 2015, Europe data through March 2015)

Less-competitive capacity

Source:  EIA (2015 data through March)

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

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

-3.0

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2005

2007

2009

2011

2013

2015

MMBPD

U.S. Net Product Imports

Net

imports

0

100

200

300

400

500

600

700

800

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

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 through March 2015.   4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.

53

Increase in U.S. Gasoline Exports

Source: DOE Petroleum Supply Monthly with data through March 2015. 4 Week Average estimate from Weekly Petroleum Statistics Report

54

Increase in U.S. Diesel Exports

0

200

400

600

800

1000

1200

1400

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Other

Europe

Other Latin America

Mexico

Canada

Latest 4 Wk avg estimate

12 Month Moving Average, MBPD

MBPD

55

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 March 2015

•

Net refined products exports increased from 335 MBPD in 2010 to 2,399 MBPD in 2015

•

Diesel net exports averaged 919 MBPD in 2014; 666 MBPD in 2015 (Jan-Mar)

•

Gasoline

net

exports

averaged

66

MBPD

in

2014;

145

MBPD

in

2015

(Jan

–

Mar)

•

Gasoline and blendstocks

have shifted to net exports

-2,500

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

2,000

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Other

Diesel

Gasoline

Total

56

U.S. Transport Indicators

Source:  U.S. DOE PSM

/  U.S. DOT FHA

Most recent data includes Mar 2015

-5.0%

-3.0%

-1.0%

1.0%

3.0%

5.0%

7.0%

U.S. VMT Growth vs. Gasoline Demand Growth

U.S. Gasoline Demand Growth

U.S. VMT Growth

U.S. Gasoline Demand Growth 12MMA

U.S. VMT Growth 12MMA

-30%

-20%

-10%

0%

10%

20%

30%

-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 Apr 2015

Demand Latest Data Mar 2015

70%

75%

80%

85%

90%

1.0

1.5

2.0

2.5

3.0

Airline Traffic Indicators

International

Domestic

Load Factor

Source:

Bureau of Transportation Statistics

Latest Data:  Feb 2015

-30%

-20%

-10%

0%

10%

20%

30%

2010

2011

2012

2013

2014

2015

North American Rail Traffic

4WMA

Latest Data as of: 5/28/2015

57

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 Apr -

15

Source:  ATA

85

95

105

115

125

135

145

ATA Non-Seasonally Adj Truck Tonnage Index

Current Year

12-Mth Moving Avg

Source:  ATA

Data Through Apr -

15

90

95

100

105

110

115

120

125

Transportation Services Index -

Freight

Current Year

12-Mth Moving Avg

Source:

BTS

95

100

105

110

115

120

125

130

135

2010

2011

2012

2013

2014

Freight: Annual Index Averages

SA ATA Truck Tonnage

TSI-Freight

ATA data through April-15, TSI data through March -

15

Data Through Mar -

15

58

Mexico Statistics

Diesel Gross Imports (MBPD)

Source:

PEMEX, latest data April 2015

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

1,350

2010

2011

2012

2013

2014

2015

1,400

55%

60%

65%

70%

75%

80%

85%

90%

2010

2011

2012

2013

2014

2015

200

250

300

350

400

450

500

2010

2011

2012

2013

2014

2015

550

0

20

40

60

80

100

120

140

160

180

2010

2011

2012

2013

2014

2015

200

59

Non-GAAP Reconciliations

Ethanol (millions)

2Q09 –

4Q09

2010

2011

2012

2013

2014

1Q15

Cumulative

Operating income

$165

$209

$396

$(47)

$491

$786

$12

$2,012

+ Depreciation and

amortization

expense

$18

$36

$39

$42

$45

$49

$13

$242

= EBITDA

$183

$245

$435

$(5)

$536

$835

$25

$2,254

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

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

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.

Investor Relations Contacts

60

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