UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 13, 2015

 

 

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1-13175   74-1828067

(State or other jurisdiction

of incorporation)

   (Commission File Number)  

(IRS Employer

Identification No.)

One Valero Way

San Antonio, Texas

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

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

 

 

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

 

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

 

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

 

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

 

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

 

 

 

Item 7.01 Regulation FD Disclosure.

Senior management of Valero Energy Corporation (the “Company”) will make certain investor presentations beginning as early as May 13, 2015. The slides attached to this report were prepared for management’s presentations. The slides are included in Exhibit 99.01 to this report and are incorporated herein by reference. The slides will be available on the Company’s website at www.valero.com.

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

Safe Harbor Statement

Statements contained in the exhibit to this report that state the Company’s or its management’s expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. It is important to note that the Company’s actual results could differ materially from those projected in such forward-looking statements. Factors that could affect those results include those mentioned in the documents that the Company has filed with the Securities and Exchange Commission.

 

Item 9.01 Financial Statements and Exhibits.

 

  (d) Exhibits.

 

        99.01 Slides from management presentation.

 

2

SIGNATURE

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

 

VALERO ENERGY CORPORATION
Date: May 13, 2015 by: /s/ Jay D. Browning
Jay D. Browning
Executive Vice President and General Counsel

 

3



Investor Presentation
May 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
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
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 February)
Source:  DOE (for 2015, data through February)

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

Source:  DOE Petroleum Supply Monthly data as of February 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

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 excellent 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
•
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
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. 

11
Excellent Operating Performance through
Continuous Improvements
Source:
Solomon
Associates
and
Valero
Energy,
includes
Pembroke
and
Meraux
•
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

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
quartile since 2011
st

13
Refinery Feedstock Flexibility Enables
Margin Optimization
•
Refining and logistics growth
investments enhance our
capability to adjust feedstocks
and optimize margins
•
Able to shift feed slate as price
environment changes
•
Expect additional light crude
flexibility with completion of
Houston and Corpus Christi
topper units currently under
construction
Valero’s Gulf Coast Region Quarterly
Feedstock Mix 2010 –
2015
(1)
(1) 2015 through March 31.

14
Capital Allocation Framework Emphasizes
Discipline and Stockholder Returns
Dividend Growth
•
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 May 11

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
•
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

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
17
Logistics Investments Enhance Valero’s
Feedstock Flexibility and Export Capability
Rail
•
Purchased 5,320 CPC-1232 railcars; received 4,964 through April 2015
•
Expect new railcars 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
Should lower feedstock cost by
generating 55 MBPD low sulfur
resid
Expect increase in net throughput
capacity of 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 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
•
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 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
Unlocking Asset Value

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    acquisition –
Texas Crude
Systems Business in July 2014
for $154 million
•
2     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
st
nd

22
Significant Inventory of Estimated MLP
Eligible EBITDA at Valero
Fuels distribution would provide incremental EBITDA if selected
(1) Assumes total cost of $900 MM and 10x EBITDA multiple on VLO’s share.

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
Pages
Valero 2014 Highlights and 2015 Goals
26-27
Ethanol Segment
28
Capital Spending and Key Investment Details
29-39
Valero Energy Partners LP
40-41
Refining Operations Highlights
42-46
Macro Outlook and Key Margin Drivers
47-53
Global Demand and Refining Capacity
54-58
U.S. Fundamentals and DOE Data
59-68
International Fundamentals
69-70
Non-GAAP Reconciliations
71
IR Contacts
72

26
Key 2014 Highlights
Operations Excellence
•
Achieved record annual system refinery capacity utilization of approximately 96% in 2014
•
Increased average consumption of price-advantaged North American light sweet crudes in 2014 by approximately 200
MBPD compared to 2013
•
Reduced Quebec refinery’s crude costs by $3/bbl versus Brent from premium of approximately $2/bbl in 2013 to
discount of approximately $1/bbl in 2014
•
Secured attractively priced term-supply of WTI Midland for Mid-Continent refineries
•
Increased gasoline and diesel exports by 49 MBPD, or approximately 18%, in 2014 versus 2013
•
Launched Top Tier gasoline in wholesale marketing system
•
Achieved record $835 million annual Ethanol segment EBITDA
Capital Returns to Stockholders
•
Increased cash returned to stockholders through dividends and buybacks by $460 million in 2014, or 33%, versus 2013
Disciplined Capital Investments
•
Completed and started up Meraux hydrocracker conversion project in 4Q14
•
Secured capital efficient Diamond Pipeline option and supply to Memphis refinery with crude from Cushing
•
Started
up
90
MBPD
of
total
crude
rail
unloading
capacity
at
St.
Charles
and
Port
Arthur
•
Acquired
idled
ethanol
plant
in
Mt.
Vernon,
Indiana
at
less
than
15%
of
replacement
cost
and
restarted
facility
within
five months
Unlocking Asset Value
•
Grew VLP via first drop-down acquisition of $154 million purchase price on July 1, 2014
Other
•
Diamond
Green
Diesel
JV
benefitted
by
approximately
$126
million
on
retroactive
reinstatement
of
Blenders
Tax
Credit

27
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

28
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

29
Refining & Renewables Capital Focused on
Capturing Benefits of Key Long-Term Trends
•
Advantaged crude processing optimizes feedstock flexibility, mainly for light crudes
•
Hydrocracking increases production of high-margin distillates
•
Petchems, methanol, and hydrocracking upgrade natural gas or NGLs to higher value liquids

30
Allocating Significant Growth Capital to Logistics
•
Railcars spending declines as receipt of railcars order concludes
•
Future spending focuses on pipelines

Gated Investment Management Process
31
•
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

32
McKee Diesel Recovery Improvement and
CDU Expansion Startup Expected in 2H15
Incremental Volume
(MBPD)
Feeds
WTI
25
Products
LPG
0.4
Benzene concentrate
0.3
Gasoline
12
Jet
-
Diesel
12
Resid
0.6
Project Estimates
Total investment
$140 MM
Annual EBITDA contribution
(1)
$100 MM
Unlevered IRR on total spend
(1)
45%
Investment Highlights
•
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
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before
deduction for depreciation and amortization expense

33
Meraux Hydrocracker Conversion
Completed December 2014
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%
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before
deduction for depreciation and amortization expense
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

34
Houston and Corpus Christi Crude Topping
Units Expected Online in 1st Half of 2016
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 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense
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)

35
Diamond Pipeline
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%
(1)
Includes additional Valero cost for pipeline connection at Memphis refinery
(2)
EBITDA = Operating income before deduction for depreciation and amortization expense
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 or earlier

36
Estimated Key Price Sensitivities on Project
Economics
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 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.

37
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
38
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
(1)
(1) See page 39 for details and assumptions.

39
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

40
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
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

41
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

42
Valero’s Light Crude Processing 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

43
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
Eastern Canada; product export opportunities for Gulf Coast and Canada

44
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

45
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
Valero’s refining operations consume approximately 864,000 mmBtu/day of
natural
gas, split almost equally between operating expense and cost of goods sold
Significant annual pre-tax cost savings compared to refiners in Europe or Asia

46
Capacity to Export Additional Product
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
47

48
U.S. and Canadian Production Growth Provides
Crude Cost Advantage to North American Refiners
Source: EIA, Consultants, company announcements and Valero estimates; 2015 U.S. Crude imports as of February 2015

Estimated Crude Oil Transportation Costs

50
Crude Oil Differentials Versus ICE Brent
Source:  Argus; 2Q15 through May 1. LLS prices are roll adjusted.

51
Valero’s Regional Refining Indicator Margins
Source:  Argus; 2Q15 through May 1.

•
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
52
Regional Indicator Margins Defined

53
Low Cost U.S. Natural Gas Provides
Competitive Advantage
Sources:  Argus and Bloomberg. Japan LNG through Feb 28, 2015; U.S. and Europe through May 5, 2015. Natural gas price converted to barrels using factor of 6.05x
•
U.S. natural gas is significantly discounted to Brent on an energy equivalent basis
•
Prices expected to remain low and disconnected from global oil and gas markets
for foreseeable future

54
U.S. Refining Capacity Is Globally Competitive and
Continues to Take Market Share
Source:  EIA and IEA (U.S. data through February 2015, Europe data through March 2015)
Source:  EIA (2015 data through February)
•
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

55
World Refinery Capacity Growth
Source:
Consultantand
Valero
estimates;
Net
Global
Refinery
Additions
=
New
Capacity
+
Restarts
–
Announced
Closures
•
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

56
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

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
57
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. 

58
Global Refining Capacity For Sale or Under
Strategic Review
Location
Owner
CDU Capacity (MBPD)
Lytton, Australia
Caltex
109
Nishihara, Japan
Petrobras/Sumitomo
95
Inchon, Korea
SK Energy
270
Whitegate, Ireland
Phillips 66
71
Barbers Point, HI
Chevron
54
Pasadena, TX
Petrobras
100
Bahia Blanca, Argentina
Petrobras
31
Gothenburg, Sweden
Shell
80
Port Dickson, Malaysia
Shell
156
Livorno
ENI
106
Taranto
ENI
120
Mazeikiai, Lithuania
PKN
190
Okinawa, Japan
Petrobras/Nansei Sekiyu
100
Falconara, Italy
API
80
Hamburg, Germany
Tamoil
78
Collombey, Switzerland
Tamoil
72
Chiba, Japan
Cosmo Oil
240
Chiba, Japan
TonenGeneral
152
Sources: Direct and public disclosure by each owner

59
U.S. Crude Fundamentals
Source:  DOE weekly data through May 1, 2015

60
U.S. Gasoline Fundamentals
USGC Brent Gasoline Crack (per bbl)
U.S. Gasoline Demand (mmbpd)
Source:  Argus; 2015 weekly data through May 1
Source:  DOE monthly data through Feb 2015; 2015 weekly data through May 1
Source:  DOE monthly data through Feb 2015; 2015 weekly data through May 1
U.S. Net Imports of Gasoline and Blendstocks (mbpd)
Source:  DOE monthly data through Feb 2015
U.S. Gasoline Days of Supply

61
U.S. Distillate Fundamentals
USGC Brent ULSD Crack (per bbl)
U.S. Distillate Demand (mmbpd)
Source:  Argus; 2015 weekly data through May 1
Source:  DOE monthly data through Feb 2015; 2015 weekly data through May 1
Source:  DOE monthly data through Feb 2015; 2015 weekly data through May 1
Source:  DOE monthly data through Feb 2015; 2015 weekly data through May 1
U.S. Distillate Days of Supply
U.S. Distillate Net Imports (mbpd)

62
U.S. Transport Indicators

63
U.S. Transport Indicators:  Trucking

Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:  DOE Petroleum Supply Monthly data through February 2015.   4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.
64
Increase in U.S. Gasoline Exports

Decrease in U.S. Gasoline Imports
Note:  Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:  DOE Petroleum Supply Monthly data through February 2015.  4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.
65

Source: DOE Petroleum Supply Monthly with data through February 2015. 4 Week Average estimate from Weekly Petroleum Statistics Report
66
Increase in U.S. Diesel Exports
12 Month Moving Average, MBPD

67
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
Note: Implied production = Petroleum demand excluding ethanol and non-refinery NGLs minus product net imports. Source: EIA, Consultant and Valero estimates; data through February 2015

68
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 February 2015
•
Net refined products exports increased from 335 MBPD in 2010 to 2,504 MBPD in 2015
•
Diesel net exports averaged 919 MBPD in 2014; 651 MBPD in 2015 (Jan-Feb)
•
Gasoline
net
exports
averaged
66
MBPD
in
2014;
199
MBPD
in
2015
(Jan
–
Feb)
•
Gasoline and blendstocks have shifted to net exports

69
Mexico Statistics
Diesel Gross Imports (MBPD)
Source:  PEMEX, latest data February 2015
Gasoline Gross Imports (MBPD)
Crude Unit Throughput (MBPD)
Crude Unit Utilization

70
Decrease in Venezuelan Exports to the U.S.
Source:  EIA, February 2015

71
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
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
Valero Energy (NYSE:VLO)
Historical Stock Chart
From Mar 2024 to Apr 2024 Click Here for more Valero Energy Charts.
Valero Energy (NYSE:VLO)
Historical Stock Chart
From Apr 2023 to Apr 2024 Click Here for more Valero Energy Charts.