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): September 8, 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 September 8, 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: September 8, 2015     by:   /s/ Jay D. Browning
      Jay D. Browning
      Executive Vice President and General Counsel

 

3



Investor Presentation
September 2015
Exhibit 99.01


2
Safe Harbor Statement
Statements
contained
in
this
presentation
that
state
the
company’s
or
management’s
expectations
or
predictions
of
the
future
are
forward–looking
statements
intended
to
be
covered
by
the
safe
harbor
provisions
of
the
Securities
Act
of
1933
and
the
Securities
Exchange
Act
of
1934.
The
words
“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.


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
Operator of
Liquids-Focused
Logistics Assets
General partner and
majority owner of
Valero Energy
Partners LP (NYSE:
VLP), a 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
Strong Gulf Coast
and Mid-Continent Presence
Refineries and ethanol plants
are in advantaged locations


5
Current Macro Environment
Abundant
supply of crude
oil and natural
gas
1
Expected petroleum
demand increase,
with
highest growth
in China, India and
Middle East
countries
5
Forecasted
world GDP growth
3
Structural product
shortage in Latin
America, Europe,
Africa and Eastern
Canada
6
Demand response
to lower product
prices
4
COST
STRUCTURE
SUPPLY
DEMAND
North American
logistics
infrastructure
additions
2
See appendix for footnotes


6
Production Growth Provides Resource
Advantage to North American Refiners
58
74
U.S. Natural Gas
Production
(Bcf/day)
Source:
DOE, 2015 data through May
9,212
7,257
5,475
9,527
U.S. Crude Oil Production
and Imports
(MBPD)
Imports
Production


7
Safety and Reliability are
Imperative for Profitability
Mechanical Availability
Personnel Index
Maintenance Index
Non-Energy Cash
Opex
Energy Intensity Index
VLO’s Performance Versus Industry Benchmarks
2008
2010
2012
2014
4
th
Quartile
1
st
Quartile
3
rd
Quartile
2
nd
Quartile
See appendix for footnotes
Operate Safely and Reliably


8
Leader in Refinery Complexity
and Clean Product Yields
12.4
12.3
11.5
11.1
10.9
VLO
HFC
TSO
MPC
PSX
Nelson Complexity Index
91%
86%
84%
83%
78%
HFC
VLO
PSX
TSO
MPC
1H15 Clean Product Yields
(As Percentage of Total Products)
See appendix for footnotes
Expand Commercial and Operational Flexibility


9
Leader in Location-Advantaged CDU Capacity and
Our Gulf Coast Assets Have Flexible Feed Slates
26%
17%
12%
12%
4%
37%
34%
30%
23%
10%
Feedstock Ranges in Gulf Coast
(2010 –
2015)
See appendix for footnotes
1,948
1,731
1,230
443
129
VLO
MPC
PSX
HFC
TSO
Location-Advantaged CDU Capacity
(MBPD)
Eastern Canada
U.S. Gulf Coast
U.S. Mid-Continent
Expand Commercial and Operational Flexibility


10
Our System Enables Optimization
of Product Exports and Netbacks
69
86
255
308
164
221
412
472
2011
2012
2013
2014
1H15
Current
Capacity
Potential
Future
Capacity
VLO’s U.S. Product Exports
(MBPD)
Diesel
Gasoline
Expand Commercial and Operational Flexibility
Actual
export
volumes
for
2011
1H15.
See
appendix
for
additional
footnotes.


11
Location Advantage, Feedstock Flexibility and
Low Opex Deliver Strong Operating Income
$5.50
$6.20
$7.20
$7.90
$8.90
VLO
MPC
HFC
PSX
TSO
1H15 Refining Operating Expenses
Per Barrel Throughput
(Includes Cash Costs and D&A)
$10.40
$7.50
$7.20
$6.60
$5.00
HFC
VLO
MPC
TSO
PSX
1H15 Refining Operating Income Per
Barrel of Product Yield
Rounded figures presented.  See appendix for additional footnotes.
Expand Commercial and Operational Flexibility


12
Current Capital Allocation Framework
Sustaining Capex
Estimate $1.5 billion or
lower annual spend
Key to safe and reliable
operations
Dividend Growth
Should be sustainable
Compete for cash flow
versus reinvestments
Debt and Cash
Maintain investment
grade credit rating and
strong balance sheet
Target 20% to 30% debt-
to-cap ratio
(1)
(1)
Debt-to-cap ratio based on total debt reduced by $2 billion of cash.
Growth Capex
Prioritize higher-value,
higher-growth, quicker
payback opportunities
Stock Buybacks
Flexibility to return cash
and manage capital
employed
Acquisitions
Evaluate versus
alternative uses of cash
Disciplined Capital Management to Unlock Value


13
Investing in Logistics and
Higher Margin Businesses
$765
$730
$695
$655
$790
$300
$400
$715
$2,650
$2,400
2015E
2016E
Capital Expenditures
(millions)
Logistics
Light Crude Processing, Natural
Gas and NGLs Upgrading
Turnarounds & Catalyst
Sustaining
(1)
Excludes
estimated
placeholder
for
potential
methanol
project
of
$150
million
in
2015
and
$300
million
in
2016,
as
evaluation
remains
in
progress
(1)
Disciplined Capital Management to Unlock Value


14
Investing in Feedstock Flexibility
Light Crude
160 MBPD total new topping
capacity at Corpus Christi
and Houston refineries to
process up to 50 API sweet
crude
Replaces approximately 55
MBPD of purchased low
sulfur resid for FCCs with
indigenous production
Net throughput capacity
increase of approximately
105 MBPD expected
Expect startup in 1H16 and
annual EBITDA contribution
of approximately $500 MM
See appendix for project details
Disciplined Capital Management to Unlock Value


15
Investing to Increase
High Value Product Yields
Distillate
Meraux’s hydrocracker
expansion
(1)
in 4Q14
increased distillate yields by
approximately 19 MBPD
30 MBPD total hydrocracker
capacity addition at Port
Arthur (4Q15) and
St. Charles (1Q16) expected
to increase distillate yields by
approximately 23 MBPD
Alkylate
New 13 MBPD alkylation unit
at Houston refinery
Upgrades low-cost NGLs to
premium-priced alkylate
In phase 3 of development
with investment decision
expected in 1Q16 and startup
in 2018 if approved
Methanol
1.6 –
1.7 million TPY
(36 –
38 MBPD) production
capacity at St. Charles
refinery
Leverages existing assets to
reduce capital requirement
compared to grassroots
facility
In phase 3 of development
with investment decision
expected in 4Q15 and startup
in 2018 if approved
(1)
See appendix for project details
Disciplined Capital Management to Unlock Value


16
Delivering High Cash Returns to
Stockholders is One of Our Priorities
75% total payout target for 2015
2015 YTD through September 2.  Payout ratio as percent of 2015 net income.
169
360
462
554
409
409
349
281
928
1,296
992
1,807
25%
31%
51%
51%
61% YTD
75% Target
2011
2012
2013
2014
1H15
2015 YTD
Buybacks ($MM)
Dividends ($MM)
Payout Ratio
Disciplined Capital Management to Unlock Value


17
Our Sponsored MLP
Valero Energy Partners (NYSE:VLP)
Disciplined Capital Management to Unlock Value
Logistics MLP
VLO owns entire 2% general partner interest, all incentive distribution rights and 69.6% LP
interest
High-quality assets integrated with Valero’s refining system
Fee-based, liquids-focused revenue generation with no direct commodity price exposure


18
$95
$200
4Q14
Annualized
4Q15E
Annualized
Adjusted EBITDA Attributable to VLP
(millions)
Expect $1 Billion of Drop-Down Transactions
to VLP in 2015
See appendix for reconciliation of estimated 2015 EBITDA to net income
Sold Houston and St. Charles Terminals to VLP for $671 MM in March 2015
Disciplined Capital Management to Unlock Value


19
More Than $1 Billion of Estimated MLP Eligible
EBITDA Inventory
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
5,320 purchased
railcars, expected
to serve long-term
needs in ethanol
and asphalt
Pipelines
(1)
Over 1,200 miles
of active pipelines
440 mile Diamond
Pipeline
(2)
from
Cushing to
Memphis refinery
expected to be
commissioned in
1H17
Marine
(1)
51 docks
Two Panamax
class vessels
(1)
Includes assets that have other joint venture or minority interests.
(2)
VLO holds option until January 2016 to acquire 50 percent interest in Diamond Pipeline.
Disciplined Capital Management to Unlock Value
Fuels
Distribution
Approximately 
800 MBPD fuels
distribution
volume


20
Renewables Business Has Performed Well
Ethanol
11 plants with 1.3 billion gallons total annual
production
Low capital investment with scale and location in
corn belt
Operational best practices transferred from refining
Disciplined Capital Management to Unlock Value
Diamond Green Diesel
50-50 joint venture with Darling Ingredients
Approximately 11 MBPD production capacity
Renewable diesel prices at a premium versus
biodiesel due to higher quality


21
VLO
14.2%
Median
10.4%
2016E Return on Average Market
Capital Employed
VLO
5.9x
Median
8.1x
2016E Price to Earnings Ratio
We Believe Valero
is an Excellent Investment
Majority of capacity located in U.S. Gulf
Coast and Mid-Continent with access to
cost-advantaged crude, natural gas, NGLs
and corn
Proven operations excellence
Excellent investment and operations in
renewable fuels
Focus on expansion of valuation multiple
Disciplined capital investment to drive
earnings growth
Unlocking value through growth in MLP-able
assets and drop-downs to VLP
Capital allocation to stockholders
We believe VLO is undervalued. We have a disciplined management team, a
strong financial position and a favorable macro environment.
See appendix for footnotes
Peer range
Peer range


22
Appendix Contents
Topic
Pages
Footnotes
23
2015 Goals
24
Refining Operating Statistics
25 –
28
Capital Investment Details
29 –
34
Valero Energy Partners LP
35
Natural Gas Cost Sensitivity
36
Crude Oil Transportation
37 –
38
Global Fundamentals
39 –
43
Non-GAAP
Reconciliations
44
IR Contacts
45


23
Footnotes
Slide 5
Macro environment themes represent industry consult views, of which points 1, 2, 5, and 6 are supported by additional slides in the presentation. 
Slide 7
Contractor recordable incident rate from U.S. Bureau of Labor Statistics.  Tier 1 process safety event defined within API Recommended Practice 754.  Industry
benchmarking and VLO performance statistics from Solomon Associates and Valero.
Slide 8
Nelson Complexity Index for HFC, TSO, and MPC from company presentations.  PSX’s Nelson Complexity calculated per Oil and Gas Journal NCI formula based on crude
capacities in company 10-K report and process unit capacities in Oil and Gas Journal as of January 1, 2015.  Total company NCI is weighted average for refineries.
Product yields from company 10-Q reports and presentations for six months ended June 30, 2015.  Clean products defined as gasoline, jet fuel/kerosene, and distillates.
Slide 9
Crude distillation capacities from company 10-K reports and presentations, grouped by geographic location. 
Valero’s Gulf Coast feedstock ranges are based upon quarterly processing rates between 1Q10 and 2Q15.
Slide 10
Valero’s potential future gasoline and distillate export capacities are based upon potential expansion opportunities at the St. Charles and Port Arthur refineries.
Slide 11
Refining operating expenses include cash costs and depreciation and amortization from company 10-Q reports for six months ended June 30, 2015.  PSX’s refining
operating expense per barrel of throughput from analyst reports. 
Refining
operating
income
and
total
product
yields
from
company
10-Q
reports
for
six
months
ended
June
30,
2015.
PSX’s
refining
operating
income
approximated
as
segment net income from company 10-Q with a 50% allocation of interest and debt expense and an assumed income tax of 35%.
Slide 21
Source for price to earnings ratios and returns on average market capital employed (ROMC) is Barclays.  2016 estimated ROMC defined as (tax effected operating and
other income) / (average of 2016 and 2015 market capital employed), where market capital employed is calculated as (year-end share price * shares outstanding) + total
debt.  Prices as of August 28, 2015 market close.


24
Key Goals Expected in 2015
Operations Excellence
Start up Montreal crude terminal
with the Enbridge Line 9B reversal
and lower Quebec City 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 construction of Houston and Corpus Christi
crude topping units
Make final investment decisions on methanol plant at
St. Charles refinery and alkylation unit at Houston
refinery
Complete 25 MBPD McKee refinery CDU capacity
expansion
Complete 30 MBPD total hydrocracker capacity
expansions at Port Arthur and St. Charles refineries
Gain permit approval to construct Benicia crude rail
unloading facility
Unlocking Asset Value
Increase the identified MLP-able EBITDA available
for drop-downs to VLP
Execute $1 billion of drop-down transactions to VLP


25
Our Refining Capacity and Nelson Complexity
Refinery
Capacities (MBPD)
Nelson Complexity
Index
Throughput
Crude
Corpus Christi
(1)
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 Average
2,935
2,388
12.4
(1)
Represents the combined capacities of two refineries—Corpus Christi East and Corpus Christi West.


26
Reliability Initiatives Have Improved Refinery
Availability and Enabled Higher Utilization


27
Valero Is Currently Utilizing 84 Percent of Its
Available Light Crude Capacity in North America
McKee Refinery Crude Unit Expansion
25 MBPD additional capacity
expected in 2H15
Distillate recovery improvements
Houston Refinery Crude Topping Unit
90 MBPD capacity expected 1H16
Displaces 30 MBPD intermediate
feedstock purchases
Corpus Christi Refinery Crude
Topping Unit
70 MBPD capacity expected 1H16
Displaces 25 MBPD intermediate
feedstock purchases
Actual light crude consumption less than capacity due to turnaround
maintenance and economics. Includes imported foreign sweet crudes.
1,030
1,220
1,410
2Q15 Actual
Utilization
Current
Capacity
Estimate
Future
Capacity (with
Projects)
MBPD


28
0%
50%
100%
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
Quebec City Refinery Crude Slate
Foreign Imports
North American
Expect Quebec City Refinery to Have Access
to 100% North American Crude in 2015
Processing advantaged crudes delivered by rail and foreign flagged ships from U.S. Gulf Coast,
with additional transportation cost savings expected after reversal of Enbridge Line 9B in 4Q15


29
Meraux Hydrocracker Conversion
Completed December 2014
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
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


30
McKee Refinery Diesel Recovery Improvement
and CDU Expansion Startup Expected in 2H15
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)
Feeds
WTI
25
Products (MBPD)
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%
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income
before deduction for depreciation and amortization expense


31
Light Crude Processing Investments
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 Refinery:
Estimated
$350 MM capex for 70 MBPD
capacity
Houston Refinery:
Estimated $400
MM capex for 90 MBPD capacity
Estimate $500 million annual EBITDA for
combined projects in 2014 price environment
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 Project Estimates
Total investment
(1)
$750
MM
Annual EBITDA contribution
(2)
$500 MM
Unlevered IRR on total spend
(2)
50%
(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


32
Houston and Corpus Christi Crude
Topping Project Economics
Corpus Christi Refinery
Houston Refinery
(1)
Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense
Project Estimates
Total investment
$400 MM
Annual EBITDA contribution
(1)
$240 MM
Unlevered IRR on total spend
(1)
45%
Project Estimates
Total investment
$350 MM
Annual EBITDA contribution
(1)
$260 MM
Unlevered IRR on total spend
(1)
55%
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
LPG
0.8
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)


33
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


34
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
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.


35
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
above $0.31875
50%
50%
2Q15 distribution at $0.2925 per unit
Valero’s GP interest in VLP expected to reach 50% split in 4Q15, payable
in 2016, based on accelerated drop-down strategy


36
$3/mmBtu
U.S.
$0.90/bbl
$7/mmBtu
Europe
$2.20/bbl
$11/mmBtu
Asian LNG
$3.65/bbl
Natural Gas Cost Sensitivity for Valero’s Refineries
U.S. Natural Gas Provides Opex
and Feedstock Cost Advantages
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
$1.5 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


37
Estimated Crude Oil Transportation Costs
to Houston
Pipe
$2
to
$4/bbl
USGC to USEC
U.S. Ship $3 to
$5/bbl
USGC to Canada
Foreign Ship
$2/bbl
U.S. Ship $4
to $5/bbl
Brent to
USEC
$2/bbl
to USEC
Rail $11 to $13/bbl
to St. James
Rail $11/bbl
Cushing
Midland
to Houston
Pipe $3/bbl
CC to Houston
$1 to $2/bbl
Houston to St. James
$1 to $2 /bbl
to West Coast
Rail $13 to $15/bbl
Alberta to Bakken
$1 to $2/bbl
Rail $9/bbl
Alberta
to Eastern Canada
Rail $11 to $12/bbl
Bakken
to Cushing
Rail $9/bbl
to Cushing
Pipe $5 to $6/bbl


38
KEY
New Crude Oil Pipeline Capacities
Niobrara
Eagle
Ford
Cushing
Bakken
Recently Completed
2015 Startup
> 2015 Est. Startup
Capacities in MBPD.
Permian
Alberta


39
Net
0.8
Net
1.5
Net
1.4
-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
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


40
0.85
0.70
0.98
0.91
0.96
-0.4
0.0
0.4
0.8
1.2
2015
2016
2017
2018
2019
MMBPD
Estimated Net Global Refinery Crude Distillation Changes
Europe
China
Middle East
Other (incl. U.S. and Latin America)
Total
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


41
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)
Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Source:
DOE Petroleum Supply Monthly data through May 2015.   4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.
U.S. Gasoline Exports


42
Source: DOE Petroleum Supply Monthly with data through May 2015. 4 Week Average estimate from Weekly Petroleum Statistics Report
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)


43
-3,000
-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
MBPD
Net Exports of Products from the U.S.
Source:  DOE Petroleum Supply Monthly data through May 2015.
Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates)
Net refined products exports increased from 335 MBPD in 2010 to 3 MMBPD in 2015
Diesel net exports averaged 919 MBPD in 2014; 817 MBPD in 2015 (Jan-May)
Gasoline
net
exports
averaged
66
MBPD
in
2014;
67
MBPD
in
2015
(Jan
May)


44
Non-GAAP Reconciliations
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 VLP Forecasted
Net Income to EBITDA
Three Months Ended
December 31, 2014
Three Months Ended
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.


45
Investor Relations Contacts
For more information, please contact:
John Locke
Vice President, Investor Relations
210.345.3077
john.locke@valero.com
Karen Ngo
Manager, Investor Relations
210.345.4574
karen.ngo@valero.com
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