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| 8-K - FORM 8-K - VALERO ENERGY CORP/TX | d845386d8k.htm |
 Investor
Presentation January 2015
Exhibit 99.1 |
 Statements
contained in this presentation that state the company’s or management’s
expectations or predictions of the future are forward– looking statements intended
to be covered by the safe harbor provisions of the Securities Act of 1933 and the
Securities Exchange Act of 1934. The words “believe,”
“expect,”
“should,”
“estimates,”
“intend,”
and other similar expressions identify forward–looking
statements. It is important to note that actual results could differ
materially from those projected in such forward–looking statements.
For more information concerning factors that could cause actual
results to differ from those expressed or forecasted, see Valero’s
annual reports on Form 10-K and quarterly reports on Form 10-Q, filed
with the Securities and Exchange Commission, and available on
Valero’s website at www.valero.com.
2
Safe Harbor Statement |
 3
Who We Are
World’s Largest Independent Refiner
Large Logistics Infrastructure with Focus on Growth
•
•
Wholesale Fuels Marketer
•
•
One of North America’s Largest Renewable Fuels Producers
•
•
•
15 refineries, 2.9 million barrels per day (BPD) of high-complexity throughput
capacity •
Greater
than
70%
of
refining
capacity
located
in
U.S.
Gulf
Coast
and
Mid-Continent
•
Approximately 10,000 employees
General partner and majority owner of Valero Energy Partners LP (NYSE: VLP), a
growth-oriented, fee-based master limited partnership (MLP)
Significant inventory of logistics assets within Valero
Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock, and Beacon
11 corn ethanol plants, 1.3 billion gallons per year (85,000 BPD) production capacity
Operator
and
50%
owner
of
Diamond
Green
Diesel
joint
venture
–
10,500
BPD
renewable diesel production capacity
Approximately 7,400 marketing sites in U.S., Canada, United Kingdom, and Ireland
|
 4
Assets Concentrated in
Advantaged Locations
Refinery
Capacities (MBPD)
Nelson
Index
Throughput
Crude Oil
Corpus Christi
325
205
19.9
Houston
165
90
15.1
Meraux
135
135
10.3
Port Arthur
350
330
12.6
St. Charles
280
190
17.5
Texas City
250
225
11.1
Three Rivers
100
95
12.4
Gulf Coast
1,605
1,270
14.1
Ardmore
90
86
12.1
McKee
170
168
9.5
Memphis
195
180
7.9
Mid-Con
455
434
9.3
Pembroke
270
220
9.7
Quebec City
235
230
7.7
North Atlantic
505
450
8.7
Benicia
170
145
16.1
Wilmington
135
85
15.8
West Coast
305
230
16.0
Total or Avg.
2,870
2,384
12.4 |
 Strategy to
Enhance Stockholder Returns Operations
Excellence
Capital Returns to
Stockholders
Disciplined Capital
Investments
Unlocking Asset
Value
•
Demonstrate commitment to safe and reliable operations
•
Continuously improve our top-tier operating performance
•
Optimize margins with refining system’s feedstock and product
markets flexibility
•
Disciplined capital allocation
•
Seek to increase cash returns through dividend growth
•
Use stock buybacks to reduce shares outstanding and concentrate
future value per share
•
Rigor in capital projects and M&A selection and execution
•
Invest to grow logistics assets and reduce feedstock costs
•
Evaluate investments to upgrade natural gas and natural gas liquids
•
Opportunistically invest in ethanol to maintain high returns
•
Grow Valero Energy Partners LP and realize value for Valero
•
Evaluate acceleration of dropdowns and other potential MLP-able
earnings streams
•
Previously unlocked value in retail business via 2013 spinoff to
stockholders
5 |
 6
Key Market Trends
U.S. and Canadian crude oil, natural gas, and natural gas liquids
(NGLs) production growth is providing cost advantages to
North American refiners
Global refined products demand growth is expected to continue
Location-advantaged refiners in U.S. Gulf Coast, Mid-Continent,
and Canada benefit from resource advantages and/or export
opportunities
-
Lower crude prices may temporarily constrain production growth rate
-
Expect lower prices to consumers will drive product demand growth
|
 Production
Growth Provides Resource Advantage to North American Refiners
Source: DOE (for 2014, data through September)
Source: DOE (for 2014, data through September)
7
40
45
50
55
60
65
70
U.S. Natural Gas Production
(Bcf/day)
4,500
5,000
5,500
6,000
6,500
7,000
7,500
8,000
8,500
9,000
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
10,500
MBPD
MBPD
U.S. Crude Oil Production and
Imports
Imports
Production |
 8
Persistent Focus Drives Results in Safety,
Environmental, and Regulatory Compliance
(1)Source: U.S. Bureau of Labor Statistics.
All 2014 values are estimates.
Statistics are for Refining only.
Operations
Excellence
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
Personnel Safety
Employees
Contractors
Industry
(1)
0.00
0.05
0.10
0.15
0.20
Tier 1 Process Safety
0
5
10
15
20
0
10
20
30
40
Environmental Events
Total Air Emissions (U.S. Refineries) |
 9
Top-Tier Operating Performance through
Continuous Improvements
2012
2010
2008
•
Reliability drives safe and
profitable operations
Seven of our refineries are first
quartile in mechanical availability
•
Initiated new reliability programs
beginning mid-2000s
•
Significant gains made in
operations benchmarks since
2008
•
Personnel committed to
excellence
1
st
Quartile
2
nd
Quartile
3
rd
Quartile
4
th
Quartile
Source: Solomon Associates and Valero Energy, includes Pembroke and Meraux |
 Sustained high
availability and favorable margin environment enable higher capacity utilization
rates 10
Reliability Programs and Commercial
Optimization Drive Higher Utilization Rates
System-wide
mechanical
availability near
1
st
Quartile since
2011
88%
87%
92%
95%
96%
2010
2011
2012
2013
2014 1Q-3Q
Valero Refinery Utilization Rates |
 Optimizing
Margins with Feedstock Flexibility in Our Complex Refinery System
Range of Flexibility in Valero’s Gulf Coast
Region Quarterly Feedstock Mix 2010-2014
•
Capability to adjust
feedstocks and optimize
margins as crude price
environment shifts among
grades: light, medium,
heavy, sweet, sour
•
Focus on optimization
activities
•
Expect additional light crude
flexibility with completion
of topper units in progress
35%
34%
28%
23%
9%
26%
20%
12%
12%
4%
Avg
30%
Avg
26%
Avg
20%
Avg
18%
Avg
6% |
 •
120 MBPD of combined new capacity
successfully started end of 2012 and
mid-2013
•
Designed to produce high-quality
distillates from low-quality feedstocks
and natural gas
Port Arthur and St. Charles Hydrocrackers
Performing Better Than Expected
12
(1) See Appendix for details and assumptions
•
Approximately half of benefit seen by >4%
points increase in margin capture rate
•
Approximately half of benefit due to 100
MBPD increase in throughput volumes from
feedstocks and new gas plant
•
Realized annual EBITDA estimated at
$800 million for trailing 4-quarters 3Q14
•
Compares to $780 million implied by
disclosed guidance model
(1)
•
Benefits visible in U.S. Gulf Coast region
reported results improvement from
4Q12 to 3Q14
(1) |
 Disciplined
Capital Allocation Framework Emphasizes Stockholders
Dividend Growth
•
•
Sustaining Capex
•
•
Debt and Cash
•
•
Stock Buybacks
•
•
Growth Capex
•
Acquisitions
•
•
“Non-Discretionary”
“Discretionary”
13
Capital
Returns to
Stockholders
(1) Debt-to-cap ratio based on total debt reduced by $2 billion cash balance,
excluding VLP debt and equity Estimate $1.5 billion or
lower annual “stay-in-
business”
spend
•
Key to safe and
reliable operations
Focus on sustainability
Increase competition
for cash flow versus
reinvestments (growth
capex and acquisitions)
Maintain investment
grade credit rating
Target 20% to 30%
debt-to-cap ratio
(1)
Flexibility to return
cash, reduce share
count, and manage
capital employed
Increase competition
versus reinvestments
Prioritize higher-value,
higher-growth, faster-
payback opportunities
that enhance future
returns
Evaluate accretion
versus stock buybacks
Enhance future
returns |
 14
Increasing Focus on Dividends and Stock
Buybacks
•
Regular dividend increases over
last three years
•
Significantly increased stock
buybacks in 2013 and 2014
•
Accelerated stock buybacks
throughout 2014 with 10 million
shares bought in 4Q14
•
Approximately $2 billion of stock
repurchase authorization at end
of 3Q14
Given cash return priority, we plan
to increase our total payout ratio of
earnings over 2014’s level
$0.10
$0.15
$0.20
$0.25
$0.30
Dividend Per Share of Valero
1Q
2Q
3Q
4Q
$0
$500
$1,000
$1,500
2011
2012
2013
2014
millions
Stock Buybacks |
 15
Advancing Growth Investments While
Managing Capital Spending Lower
(1) Excludes estimated placeholder for methanol project of $150 million in 2015 and $300
million in 2016 as evaluation remains in progress Disciplined
Capital
Investment
•
Focus on logistics growth after 2015 spending to complete crude toppers
•
Expect nearly all logistics growth investments to be eligible for dropdown into VLP
millions
$2,900
$2,650
$2,400
$695
$695
$900
$400
$615
$765
$730
$690
$790
$300
$715
$655
2014E
2015E
2016E
Logistics Growth
Refining, Renewables, &
Other Growth
Turnarounds & Catalyst
Sustaining
(1) |
 •
Completed tie-in to pipeline in Childress, TX and secured incremental
40 to 50 MBPD Midland-priced crude as substitute for Cushing-priced
crude primarily at the McKee refinery
•
Expect Diamond Pipeline to supply Memphis refinery via Cushing and
start up in 1H17 or earlier
•
Tanks and vessels to supply crude to Quebec City refinery post-Enbridge
Line 9B reversal expected in 1H15
•
New Corpus Christi dock commissioned in 3Q14; completion of tanks for
crude exports expected in 1H15
16
Logistics Investments Enhance Valero’s
Feedstock Flexibility and Export Capability
•
Purchased 5,320 CPC-1232 railcars; received 3,547 through Nov 2014
•
Completed crude unloading facilities at Quebec City, St. Charles, and
Port Arthur in 2014
•
Benicia crude unloading facility undergoing permitting process
Pipelines
Tanks, Docks, and Vessels
Rail |
 Crude Topper
Investments Very Attractive 17
Estimate $500 million annual EBITDA for combined projects in 2014 price environment
•
160 MBPD new topping capacity
designed to process up to 50 API
domestic sweet crude
Lowers feedstock cost by
generating 55 MBPD low sulfur
resid
Increases net throughput
capacity by 105 MBPD
•
Expect startup in 1H16
•
Expect 50% IRR on 2014 prices,
>25% IRR with Brent and LLS even
•
Corpus Christi: Estimated $350 MM
capex for 70 MBPD capacity
•
Houston: Estimated $400 MM
capex for 90 MBPD capacity
Incremental Volume
(MBPD)
Feeds
Eagle Ford crude
160
Low sulfur atmos resid
(55)
Products
LPG
3.3
Propylene
1.3
BTX
0.4
Naphtha (at export prices)
40
Gasoline
12
Jet
39
Diesel
13
Resid
(3)
Combined Projects Estimates
Total investment
(1)
$750 MM
Annual EBITDA contribution
(2)
$500 MM
Unlevered IRR on total spend
(2)
50%
See Appendix for assumptions.
(1)
Excluding interest and overhead allocation (2)
Estimates based on 2014 prices through Dec 9; EBITDA = operating
income before deduction for depreciation and amortization expense
|
 Key Natural Gas
and NGLs Upgrading Investments
18
Hydrocracker
Expansions
Evaluating
Methanol Plant at
St. Charles
Evaluating Houston
Alkylation Unit
•
1.6
–
1.7
million
tonnes
per
year
production
(36
–
38
MBPD)
•
Leverages existing assets to lower capital requirement
compared to grassroots facility
•
In evaluation; estimated capital cost and project economics
remain in development
•
Expect investment decision in 2Q15; startup in 2018 if approved
•
12.5 MBPD capacity
•
Upgrades low-cost NGLs to premium-priced alkylate
•
In evaluation; estimated capital cost and project economics
remain in development
•
Expect investment decision in 2015; startup in 2017 if approved
•
Increase distillate yield partially from hydrogen via natural gas
•
Completed Meraux’s 20 MBPD capacity expansion in 4Q14;
expect approximately $90 million annual EBITDA contribution
at 2014
(1)
prices on total investment of approx. $260 million
•
30 MBPD total capacity addition at St. Charles and Port Arthur
in progress; expect startup in 2H15
(1) 2014 based on Jan 1 through Dec 9 prices; see project details in Appendix
|
 19
Ethanol Investments Performing Well
Note: See Appendix for reconciliation of EBITDA to GAAP results. 2014 EBITDA through
3Q. Outstanding
Cash
Generation
Excellent
Acquisitions
Competitive
Advantages
•
11 plants acquired between
2Q09 and 1Q14 for
$794MM, less than 35% of
replacement value
•
1.3 billion gallons total
annual production
•
Scale and location in corn
belt
•
Operational best practices
transferred from refining
•
Low capital investment
•
$2.1 billion cumulative
EBITDA generated since
acquisitions
•
$162 million cumulative
capex excluding acquisition
costs
$2,058
$162
millions
Cumulative Capex and EBITDA
EBITDA
Capex |
 20
Our Sponsored MLP
Valero Energy Partners (NYSE: VLP)
Growth-oriented
logistics MLP with
100% fee-based
revenues
•
Valero owns entire 2% general partner interest, all incentive
distribution rights, and 68.6% LP interest
•
High-quality assets integrated with Valero’s refining system
•
Primary vehicle to grow Valero’s midstream investments
•
Provides access to lower cost capital
•
Completed first dropdown from Valero on July 1, 2014
Unlocking
Asset Value |
 21
Significant Growth Opportunity with Estimated Inventory
of Eligible MLP Assets EBITDA over $900 Million
(1) Includes assets that have other joint venture or minority interests.
Pipelines
(1)
Racks, Terminals, and Storage
(1)
Rail
Marine
(1)
•
51 docks and two Panamax class vessels
Fuels Marketing and Distribution
We are also developing an accelerated drop-down strategy
•
Over 1,200 miles of active pipelines
•
Expect start-up of 440-mile Diamond Pipeline from Cushing to Memphis refinery
in 1H17
•
Over 72 million barrels of active shell capacity for crude and products
•
139 truck rack bays
•
Three crude unloading facilities with estimated total capacity of 150 MBPD
•
Our 5,320 new CPC-1232 railcars can be used for long-term rail movements, such
as ethanol and asphalt
•
Currently under evaluation as drop-down candidate |
 22
We Believe Valero Is an Excellent Investment
•
Majority of capacity located in U.S. Gulf Coast and Mid-
Continent with access to cost-advantaged crude, natural
gas, NGLs, and corn
•
Proven operations excellence
•
Excellent investment and operations in ethanol
•
Emphasis on capital allocation to stockholders
•
Disciplined capital investment that prioritizes higher-value,
higher-growth, faster-payback opportunities to capture
benefits of advantaged resources
•
Unlocking value through growth in MLP-able assets and
dropdowns to VLP
•
Focus on valuation multiple expansion |
 23
Appendix
Topic
Pages
Valero 2014 Highlights and 2015 Goals
24-25
Valero Energy Partners LP and CST Brands Spinoff
26-28
Capital Spending and Key Investment Details
29-38
Other Valero Operations Highlights
39-44
Macro Outlook and Key Margin Drivers
45-51
Global Demand and Refining Capacity
52-56
U.S. Fundamentals and DOE Data
58-68
International Fundamentals
69-70
Non-GAAP Reconciliations
71
IR Contact Information
72 |
 24
Key 2014 Highlights
Operations Excellence
•
Achieved record system refinery capacity utilization of approximately 96% in 2014 through
3Q •
Increased consumption of price-advantaged North American light sweet crudes by 297 MBPD on
average through 3Q14 compared to 2013
•
Reduced Quebec refinery’s crude costs by $3/bbl versus Brent from premium of
approximately $2.50/bbl in 2013 to discount of approximately $0.50/bbl in 2014 through
3Q •
Secured attractively priced term-supply of WTI Midland for Mid-Continent
refineries •
Increased
gasoline
and
distillate
exports
by
57
MBPD,
or
18%,
in
2014
through
3Q
versus
2013
•
Launched Top Tier gasoline in wholesale marketing system
•
Achieved record $664 million Ethanol segment EBITDA through 3Q14
Capital Returns to Stockholders
•
Increased cash returned to stockholders through dividends and buybacks by approximately $460
million, or 33%, versus 2013
Disciplined Capital Investments
•
Completed and started up Meraux hydrocracker conversion project in 4Q14
•
Secured capital efficient Diamond Pipeline option and supply to Memphis refinery with crude
from Cushing •
Started
up
90
MBPD
of
total
crude
rail
unloading
capacity
at
St.
Charles
and
Port
Arthur
•
Acquired
idled
ethanol
plant
in
Mt.
Vernon,
Indiana
at
less
than
15%
of
replacement
cost
and
restarted
facility
within
five months
Unlocking Asset Value
•
Grew VLP via first drop-down acquisition of $154 million purchase price on July 1,
2014 Other
•
Diamond Green Diesel JV to benefit by estimated $130 million on retroactive reinstatement of
biodiesel blending credit |
 25
Key 2015 Goals
Operations Excellence
•
Start up Montreal crude terminal with startup of Enbridge Line 9B reversal and lower Quebec
refinery’s crude costs versus Brent compared to 2014
•
Grow product export market share and increase branded wholesale fuels volume
Capital Returns to Stockholders
•
Increase total payout ratio of earnings over 2014’s level
Disciplined Capital Investments
•
Complete Houston and Corpus Christi toppers on time and on budget
•
Make
final
investment
decisions
on
methanol
plant
at
St.
Charles
refinery
and
alkylation
unit
at
Houston refinery; if approved, share strategic rationale with investors
•
Complete 25 MBPD McKee CDU capacity expansion
•
Complete 30 MBPD total hydrocracker capacity expansions at Port Arthur and St. Charles
•
Gain permit approval and construct Benicia crude rail unloading facility
Unlocking Asset Value
•
Grow inventory of MLP-able EBITDA |
 Growth in
Inventory of Estimated Eligible MLP EBITDA
Fuels distribution would provide incremental EBITDA if selected
$800
($15)
$24
$46
$54
$909
Dec. 2013
Guidance (with
base + 2014-
2015
projects)
Drop
-Downs
2014
-
2015
Logistics
Additional
Projects
Diamond Pipeline
Current Guidance
2016
-
2019
Logistics Projects
millions
26 |
 27
VLP Nearing the “High Splits”
•
3Q14 distribution at $0.24 per unit
•
Expect VLP to reach 25% split in 2015 and 50% split in 2016 based on existing growth
guidance, but timing may change depending on evaluation of accelerated drop-down
strategy Minimum quarterly
First target
Second target
Third target
Thereafter
Target Quarterly Distribution per Unit
Marginal Percentage Interest in Distributions
Unitholders
GP
$0.2125
above $0.2125 up to $0.244375
above $0.244375 up to $0.265625
above $0.265625 up to $0.31875
$0.31875
98%
98%
85%
75%
50%
2%
2%
15%
50%
25% |
 CST Brands,
Inc. (NYSE: CST) has traded at approximately double the earnings valuation of VLO
VLO received nearly $1 billion in cash net of tax liability
and working capital benefit to CST
•
Liquidated our 20% retained interest in CST common stock, or 15
million shares, in November 2013
CST Brands is now Valero’s largest wholesale customer
28
Unlocked Value via Retail Spinoff in 2013 |
 Allocating
Significant Growth Capital to Logistics
29
•
Railcars spending declines as receipt of railcars order concludes
•
Future spending focuses on pipelines
$510
$175
$45
$220
$180
$665
$170
$45
$5
$900
$400
$715
2014E
2015E
2016E
millions
Marine, Docks, and Other
Logistics
Pipelines and Tanks
Railcars and Unloading |
 30
Refining & Renewables Capital Focused on
Capturing Benefits of Key Long-Term Trends
$345
$490
$180
$110
$30
$120
$150
$105
$45
$40
$115
$690
$790
$300
2014E
2015E
2016E
millions
Nat Gas & Petchems
Other Projects
Hydrocracking
Advantaged Crude
Processing
$50
•
Advantaged crude processing optimizes feedstock flexibility, mainly for light crudes
•
Hydrocracking increases production of high-margin distillates
•
Petchems, methanol, and hydrocracking upgrade natural gas or NGLs to higher-value
liquids |
 McKee Diesel
Recovery Improvement and CDU Expansion Startup Expected in 2H15
31
Incremental Volume
(MBPD)
Feeds
WTI
25
Products
LPG
0.4
Benzene concentrate
0.3
Gasoline
12
Jet
-
Diesel
12
Resid
0.6
Investment Highlights
Status
•
Adding 25 MBPD crude unit capacity
and parallel light ends processing
train
•
Expect to improve yields and volume
gain by recovering diesel from FCC
and HCU feeds
•
Expect to increase diesel and
gasoline production on price-
advantaged crude
•
Expect to reduce energy
consumption via heat integration
•
Diesel recovery and benefits started
in mid-2014; Expect crude
expansion start-up in 2H15
Project Estimates
Total investment
$140 MM
Annual EBITDA contribution
(1)
$100 MM
Unlevered IRR on total spend
(1)
45%
(1)
Estimates based on 2014 prices through Dec 9; EBITDA = operating income before
deduction for depreciation and amortization expense |
 Meraux
Hydrocracker Conversion Completed December 2014
32
Incremental Volume
(MBPD)
Feeds
Purchased hydrogen
(MMSCFD)
13
Products (MBPD)
Gasoline
5
Jet
-
Diesel
19
HSVGO
2
Unconverted gasoil
(23)
Fuel oil
-
Project Estimates
Total investment
$260 MM
Annual EBITDA contribution
(1)
$90 MM
Unlevered IRR on total spend
(1)
25%
Investment Highlights
Status
•
Converted hydrotreater into high-
pressure hydrocracker and
repurposed old FCC gas plant for
additional LPG recovery
•
Expect to upgrade 23 MBPD gasoil
and low-cost hydrogen (via natural
gas) mainly into high quality diesel
•
Expect to increase refinery distillate
yield versus gasoline (Gas/Diesel ratio
drops from 0.72 to 0.59)
•
Expect to increase refinery liquid
volume yield by 1.8%
•
Avoided compliance capex on FCC
•
Project started up Dec-14
and operating well
(1)
Estimates based on 2014 prices through Dec 9; EBITDA = operating income before
deduction for depreciation and amortization expense
|
 Houston and
Corpus Christi Crude Topping Units Expected Online in 1
st
Half of 2016
33
Estimates
Incremental Volume (MBPD)
Feeds
Eagle Ford crude
70
Low sulfur atmos resid
(24)
Products
LPG
2.5
Propylene
0.9
BTX
0.4
Naphtha
16
Gasoline
7
Jet
16
Diesel
9
Resid
(3)
Project Estimates
Total investment
$350 MM
Annual EBITDA contribution
(1)
$260 MM
Unlevered IRR on total spend
(1)
55%
Estimates
Incremental Volume (MBPD)
Feeds
Eagle Ford crude
90
Low sulfur atmos resid
(29)
Distillate
(2)
Butane
(2)
Hydrogen (MMSCFD)
3
Products
LPG
0.8
Propylene
0.4
Naphtha
24
Gasoline
5
Jet
23
Diesel
4
Slurry
0.2
Project Estimates
Total investment
$400 MM
Annual EBITDA contribution
(1)
$240 MM
Unlevered IRR on total spend
(1)
45%
Corpus Christi
Houston
(1)
Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for
depreciation and amortization expense |
 Diamond
Pipeline 34
Project Estimates
Total investment
(1)
$484 MM
Cumulative spend through 2014
Zero
Annual EBITDA contribution
(2)
$46 MM
Unlevered IRR on total spend
at least 12%
(1)
Includes additional Valero cost for pipeline connection at Memphis refinery
(2)
EBITDA = Operating income before deduction for depreciation and amortization expense
Investment Highlights
•
Increases Memphis refinery’s crude
supply flexibility via connection to
Cushing and economic crudes
•
Provides direct control over crude
blend quality
•
Grows Valero’s inventory of assets
eligible for VLP dropdown in capital-
efficient manner
•
Valero holds option until January
2016 to acquire 50% interest in
pipeline
•
Expect completion in 1H17 or earlier |
 Estimated Key
Price Sensitivities on Project Economics
35
Change
in
Estimated
EBITDA
(1)
Relative
to
2014
(2)
Prices ($millions/year)
McKee Diesel
Recovery & CDU
Expansion
Meraux HCU
Expansion
Corpus
Christi
Topper
Houston
Topper
ICE Brent, +$1/bbl
none
$0.8
$0.4
none
ICE Brent –
WTI, +$1/bbl
$5.5
none
None
none
ICE Brent –
LLS, +$1/bbl
N/A
none
$25.6
$32.9
Group 3 CBOB –
ICE Brent, +$1/bbl
$2.0
N/A
N/A
N/A
Group 3 ULSD –
ICE Brent, +$1/bbl
$5.5
N/A
N/A
N/A
USGC CBOB –
ICE Brent, +$1/bbl
N/A
$1.7
$2.4
$2.4
USGC ULSD –
ICE Brent, +$1/bbl
N/A
$6.8
$9.0
$9.9
Natural gas (Houston Ship Channel), +$1/mmBtu
-$0.7
-$1.9
-$4.3
-$3.2
Naphtha –
ICE Brent, +$1/bbl
N/A
none
$5.8
$8.8
LSVGO –
ICE Brent, + $1/bbl
N/A
-$7.3
$3.1
$5.2
Total investment IRR, +10% cost
-6%
N/A
-5%
-4%
(1)
Operating income before deduction for depreciation and amortization expense
(2)
2014 YTD through Dec 9
Note: Margin drivers shown are not inclusive of all feedstocks and products in economic
models. Estimated economic sensitivities can not be accurately interpolated or extrapolated solely
from the estimated key price sensitivities shown above. 1 |
 Project Price
Set Assumptions 36
Driver ($/bbl)
2014
(1)
ICE Brent
99.51
ICE Brent –
WTI
6.43
ICE Brent –
LLS
2.64
USGC
CBOB
–
ICE
Brent
3.70
G3 CBOB –
WTI
12.45
USGC ULSD –
ICE Brent
14.45
G3 ULSD –
WTI
24.00
Natural gas (Houston Ship Channel, $/mmBtu)
4.36
Naphtha –
ICE Brent
-2.12
LSVGO –
ICE Brent
8.92
(1) 2014 = YTD through Dec 9
|
 37
Port Arthur and St. Charles Hydrocrackers
Performance Details
Benefits Realized in Reported Results
Trailing 4 Quarters
$mm, except /bbl amounts
4Q12
3Q14
Increase
Gulf Coast Capture Rate
58.8%
63.2%
4.4%
x Gulf Coast Indicator/bbl, trailing 4Q 3Q14
$19
= Extra margin captured/bbl
$0.83
x Gulf Coast volume, trailing 4Q 3Q14 MPBD
1,586
x Annualized Days
365
= Benefit from higher Capture Rate
$483
Gulf Coast Throughput Volume MBPD
1,488
1,586
98
x Gulf Coast Indicator/bbl, trailing 4Q 3Q14
$19
x Gulf Coast Capture Rate, trailing 4Q 3Q14
63%
x Annualized Days
365
= Benefit from higher Volume
$429
Total Benefit from Hydrocracker Projects
$912
Less: estimated operating costs before depreciation and amort. exp.
-110
= EBITDA (estimated)
$802
Key Assumptions
•
Market prices for trailing 4 quarters as of 3Q14 applied to guidance model disclosed by Valero
in February 2012 to estimate $780 million in EBITDA •
Gulf Coast capture rate increase based on average of trailing 4 quarters reported margin per
barrel (excluding cost of RINs allocated in results at $0.30/bbl for 4Q12 and $0.40/bbl
for 4Q13 averages) divided by Gulf Coast indicator margin •
Gulf Coast LPGs pricing based on propane
•
Many factors can influence our reported margins including, but not limited to, charges,
yields, pricing, timing and ratability, secondary costs, other allocations, hedging, and
GAAP inventory costing methods •
EBITDA = operating income before deduction for depreciation and amortization expense
|
 Gated
Investment Management Process •
Development costs increase as project progresses through the phases
•
NPV and IRR of future cash flows per price forecasts and operating plans evaluated
•
“Target”
IRR hurdle rate ranges, which can change depending on the project and
market conditions:
Refining growth projects, target >=50% in Phase 1 to >=30% in Phase 3
Cost savings projects, target >=12% in Phase 3
Logistics projects, target pre-tax >=12% in Phase 3 + refinery benefits
38
PHASE 2
Lead Case
Development
•
Select lead case
and define
project
objectives
•
Improve cost
estimate to
+/-
30%
PHASE 3
Refinement
•
Define project
scope and
execution plans
•
Prepare decision
support package
for final decision
•
Narrow cost
estimate to
+/-10%
PHASE 1
Opportunity
Evaluation
•
Identify
opportunities
and alternatives
•
Develop
business case
•
Generate cost
estimate range
of +100% to -
50%
PHASE 4
Execution
•
Detail
engineering,
procurement,
and initial
construction
•
Develop start-
up schedule
APPROVED
Startup and
Evaluate
•
Post-audit back-
casting
•
Capture lessons
learned |
 39
Valero’s Light Crude Processing Capacity in
North America
MBPD
(1) Not incentivized in 3Q14 to maximize North American light crude consumption versus
alternative grades.
•
25 MBPD additional capacity
expected in 2H15
•
Distillate recovery improvements
•
90 MBPD capacity expected 1H16
•
Displaces 30 MBPD intermediate
feedstock purchases
•
70 MBPD capacity expected 1H16
•
Displaces 25 MBPD intermediate
feedstock purchases
(1)
1,010
1,210
1,395
3Q14 Actual
Utilization
Current Capacity
Estimate
Future Capacity
(with Projects)
McKee Crude Unit Expansion
Corpus Christi Crude Topper
Houston Crude Topper |
 40
Processing of Cost-Advantaged U.S. and
Canadian Crude by Valero Continues to Grow
Note: Non-U.S. and Canadian crude runs exclude Valero’s Pembroke
Refinery. Cost-advantaged crudes exclude imports and historically discounted medium sour crudes, such as Mars/ASCI domestic;
heavy sour crudes, such as Maya; and high-acid crudes, such as Pazflor.
0
200
400
600
800
1,000
1,200
1,400
1,600
0
200
400
600
800
1,000
1,200
2010
2011
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
MBPD
MBPD
Gulf Coast
Mid-Con
West Coast
Quebec
Non-U.S. & Canadian |
 41
Valero Leads Peers in Total Location-
Advantaged Crude Capacity
Source: Company 10-k reports. Crude distillation capacity based on geographic
location. Access to lower cost North American crude benefits refiners in
Mid-Continent, Gulf Coast, and Canada; product export opportunities for Gulf Coast
and Canada 1,934
1,714
1,211
443
129
VLO
MPC
PSX
HFC
TSO
MBPD
Canada
U.S. Gulf Coast
U.S. Midcontinent |
 42
Expect Quebec City Refinery to Have Cost-Advantaged
Access to 100% North American Crude Slate in 2015
Shifted to cost-advantaged crudes via rail and foreign flagged ships from USGC, with
additional savings expected from deliveries on Enbridge Line 9B beginning in 1H15
0%
20%
40%
60%
80%
100%
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
Quebec City Refinery Crude Slate
Foreign
Imports
North
American |
 43
U.S. Natural Gas Provides Opex and
Feedstock Cost Advantages
Note: Estimated per barrel cost of 860,000 mmBtu/day of natural gas consumption at 94%
refinery throughput capacity utilization, or 2.7 MMBPD. $1.3 billion
higher pre-tax
annual costs
$2.5 billion
higher pre-tax
annual costs
Valero’s refining operations consume approximately 860,000 mmBtu/day of
natural
gas, split almost equally between operating expense and cost of goods sold
Significant annual pre-tax cost savings compared to refiners in Europe or Asia
$4/mmBtu
$1.27/bbl
$8/mmBtu
Europe
$2.55/bbl
$16/mmBtu
$5.10/bbl
$0
$1
$2
$3
$4
$5
$6
/bbl
Natural Gas Cost Sensitivity for Valero’s Refineries
Asian LNG |
 44
Valero’s Capacity for Additional
Product Exports
(1)
YTD through September 30
Opportunities to expand U.S. Gulf
Coast export capability for gasoline
to 308 MBPD and diesel to 472
MBPD
Export markets pull volume from
U.S., enabling high refinery
utilization and improved margins
Supported by global refined
products demand growth
Logistics investments also support
segregation
(1)
255
412
0
100
200
300
400
500
600
700
2011
Actual
2012
Actual
2013
Actual
Current
Capacity
Valero’s U.S. Product Exports
(MBPD)
Gasoline
Diesel
2014
YTD |
 Long-Term
Macro Market Expectations Global Outlook
U.S. Economy and
Petroleum Demand
North American
Resource
Advantage
International Export
Markets
•
Economic activity and total petroleum demand increases
•
Transportation fuels demand grows
•
Refining capacity growth slows after 2015; utilization stabilizes then
expected to increase
•
Refinery rationalization pressure continues in Europe, Japan, and Australia
•
Economic growth strengthens over next five years, which stimulates refined
product demand
•
Diesel and jet fuel demand continues to strengthen
•
Gasoline demand continues to recover moderately
•
Natural gas production growth still attractive and development continues
•
Crude production is economic; growth continues, but may be tempered
with lower prices
•
North American refiners maintain competitive advantage
•
Broad lifting of crude export ban not expected for several years, if ever
•
U.S. continues to be an advantaged net exporter of products
•
Atlantic Basin market continues to grow, with increasing demand from
Latin America and Africa
•
U.S. Gulf Coast is strategically positioned with globally competitive assets
45 |
 46
U.S. and Canadian Production Growth Provides
Crude Cost Advantage to North American Refiners
Source: EIA, Consultants, company announcements and Valero estimates; 2014 U.S. Crude imports
as of Sep 2014 Production growth
reduces imports
Largest growth from U.S.
shale crude and heavy
Canadian crude
0
2
4
6
8
10
12
14
16
18
2010
2011
2012
2013
2014E
2015E
2020E
MMBPD
U.S. and Canadian Crude Production vs. U.S. Crude Imports
U.S. Shale Crude
Heavy Canadian
Light Canadian/
Syncrude
Other U.S.
Non-Canadian U.S.
Crude Imports |
 Estimated Crude
Oil Transportation Costs to USEC
Rail $12 to
$15/bbl
to St. James
Rail $12/bbl
to Cushing
Rail $9/bbl
Cushing
to Houston
Pipe $2 to
$4/bbl
Midland
to Houston
Pipe $4/bbl
CC to Houston
$1 to $2/bbl
Houston to
St. James
$1 to $2 /bbl
to West Coast
Rail $13 to $15/bbl
USGC to USEC
U.S. Ship $5 to $7/bbl
USGC to Canada
Foreign Ship $2/bbl
Alberta to Bakken
$1 to $2/bbl
Rail $9/bbl
U.S. Ship
$4 to
$5/bbl
Alberta
to Eastern Canada
Rail $11 to $12/bbl
Bakken
47 |
 48
Crude Oil Differentials Versus ICE Brent
Source: Argus; 4Q14 through Dec 12. LLS prices are roll adjusted
-30%
-25%
-15%
-10%
-5%
0%
5%
10%
15%
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
1Q14
2Q14
3Q14
4Q14
Maya
Mars
ANS
WTI
LLS
-20% |
 49
Valero’s Regional Refinery Indicator Margins
Source: Argus; 4Q14 through Dec 12
$5
$10
$15
$20
$25
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
1Q14
2Q14
3Q14
4Q14
$/bbl
Midcontinent WTI Cracking
West Coast ANS Medium Sour Coking
North Atlantic Brent Cracking
Gulf Coast Heavy Sour Coking |
 •
Gulf Coast Indicator: (GC Colonial 85 CBOB A grade-
LLS) x 60% + (GC ULSD 10ppm
Colonial Pipeline prompt -
LLS) x 40% + (LLS -
Maya Formula Pricing) x 40% + (LLS -
Mars Month 1) x 40%
•
Midcontinent Indicator: [(Group 3 CBOB prompt -
WTI Month 1) x 60% + (Group 3
ULSD 10ppm prompt -
WTI Month 1) x 40%] x 60% + [(GC Colonial 85 CBOB A grade
prompt -
LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline -
LLS) x 40%] x 40%
•
West Coast Indicator: (San Fran CARBOB Gasoline Month 1 -
ANS USWC Month 1) x
60% + (San Fran EPA 10 ppm Diesel pipeline -
ANS USWC Month 1) x 40% + 10%
(ANS –
West Coast High Sulfur Vacuum Gasoil cargo prompt)
•
North Atlantic Indicator: (NYH Conv 87 Gasoline Prompt –
ICE Brent) x 50% + (NYH
ULSD 15 ppm cargo prompt –
ICE Brent) x 50%
•
LLS prices are Month 1, adjusted for complex roll
•
Prior to 2010, GC Colonial 85 CBOB is substituted for GC 87 Conventional
•
Prior to 4Q13, Group 3 Conventional 87 gasoline substituted for Group 3 CBOB
50
Valero’s
Regional
Indicator
Margins
Defined |
 51
Source: Argus & Bloomberg; 2014 YTD Japan LNG through Oct 31, U.S. & Europe
through Dec 15; natural gas price converted to barrels using factor of 6.05x 0
20
40
60
80
100
120
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Brent and Natural Gas Prices
Brent
U.S.
Europe
Japan LNG
•
U.S. natural gas is significantly discounted to Brent on an energy equivalent basis
•
Prices expected to remain low and disconnected from global oil and gas markets
for foreseeable future
Low Cost U.S. Natural Gas Provides
Competitive Advantage
$/bbl
$101
$97
$16/mmBtu
$51
$8/mmBtu
$26
$4/mmBtu |
 52
Global Petroleum Demand Projected to Grow
Source: Consultant (EIA and IEA) and Valero estimates. Consultant annual estimates
generally updated 6 to 12 months after year end. Emerging markets in Latin
America, Middle East, Africa, and Asia lead demand growth
-3.5
-2.5
-1.5
-0.5
0.5
1.5
2.5
3.5
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014E
2015E
MMBPD
World Petroleum Demand Growth
Non-OECD
OECD (excl. U.S.)
U.S. |
 53
U.S. Refining Capacity Is Globally Competitive and
Continues to Take Market Share
Source: EIA and IEA (U.S. data through September 2014, Europe data through October
2014) Less-competitive capacity
Source: EIA (2014 data through September)
Net imports
Net
exports
•
U.S. flipped from importer to exporter on lower local product demand and higher refinery
utilization, particularly in PADDS 2, 3, and 4, driven by structural cost advantages
for crude oil and natural gas
•
Gulf Coast refineries have gained export market share in the Atlantic Basin
-3.0
-2.5
-2.0
-1.5
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
1999
2001
2003
2005
2007
2009
2011
2013
MMBPD
U.S. Net Product Imports
Midcon
93%
Gulf
Coast
91%
Rockies
91%
West
Coast
86%
East
Coast
82%
Western
Europe
77%
PADD 2
PADD 3
PADD 4
PADD 5
PADD 1
OECD
Europe
Refinery Utilization by PADD
Trailing 12-months |
 54
World Refinery Capacity Growth
-0.2
0.2
0.6
1.0
1.4
1.8
2014
2015
2016
2017
2018
MMBPD
Estimated Net Global Refinery Crude Distillation Additions
China
Middle East
Other (incl. U.S. and Latin America)
•
New capacity additions expected in Asia and Middle East
•
Announced
new
capacity
in
Brazil,
Mexico,
and
Colombia
likely
to
be
smaller
and
start
later
than planned
•
Expansions in Ecuador, Peru, Algeria, and Egypt unlikely due to cost and geopolitical
pressures •
Capacity rationalization expected to continue in Europe, Australia, and Japan
Source: Consultant and Valero estimates; Net Global Refinery Additions = New Capacity +
Restarts – Announced Closures |
 55
Capacity Rationalization in Atlantic Basin
Sources: Industry and Consultant reports and Valero estimates
•
Marginal refiners in U.S. East Coast, Caribbean and Western Europe are shutting capacity
•
Demand growth, poor reliability, and low utilization in Latin American refineries provide
opportunities for competitive refineries to export products and meet supply needs
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
MPBD
Rest of World
Atlantic Basin
Annual Global CDU Capacity
Closures
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
MBPD
Cumulative Global CDU Capacity
Closures
Rest of World
Atlantic Basin |
 *Partial
closure of refinery captured in capacity. Note: This data represents refineries currently closed, ownership may choose to restart or sell listed refinery.
Sources: Industry and Consultant reports and Valero estimates
Location
Owner
CDU Capacity
Closed (MBPD)
Year
Closed
Location
Owner
CDU Capacity
Closed (MBPD)
Year
Closed
Perth Amboy, NJ
Chevron
80
2008
St. Croix, U.S.V.I
Hovensa
350
2012
Bakersfield,CA
Big West
65
2008
Aruba
Valero
235
2012
Westville, NJ
Sunoco
145
2009
Rome, Italy
TotalErg
82
2012
Bloomfield, NM
Western
17
2009
Fawley, U.K.*
ExxonMobil
80
2012
Teesside, UK
Petroplus
117
2009
Trecate, Italy*
ExxonMobil
70
2012
Gonfreville, France*
Total
100
2009
Paramo, Czech Republic
Unipetrol
20
2012
Dunkirk, France
Total
140
2009
Lisichansk, Ukraine
TNK-BP
175
2012
Japan*
JX Holdings
110
2009
Paramount, CA
Alon
90
2012
Toyama, Japan
Nihonkai Oil
57
2009
Harburg, Germany
Shell
107
2013
Ingolstadt, Germany*
Bayernoil
102
2010
Port Reading, NJ
Hess
N/A
2013
Japan*
JX Holdings
90
2010
Venice, Italy
ENI
80
2013
Arpechim, Romania
OMV
70
2010
Sakaide, Japan
Cosmo Oil
140
2013
Odessa, Ukraine
Lukoil
57
2010
Dartmouth, Canada
Imperial Oil
88
2013
Montreal, Canada
Shell
130
2010
Thessaloniki, Greece
Hellenic Petroleum
83
2013
Yorktown, Virginia
Western
65
2010
Tenerife, Canary Islands
Cepsa
85
2013
Reichstett, France
Petroplus
85
2010
Yokkaichi, Japan*
Cosmo Oil
43
2014
Wilhemshaven, Germany
Phillips 66
260
2010
Tokuyama, Japan
Indemitsu Kosan
114
2014
Sodegaura, Japan
Fuji Oil
50
2010
Japan
Nippon
200
2014
Cremona, Italy
Tamoil
94
2011
Kurnell, Australia
Caltex
135
2014
St. Croix, U.S.V.I,*
Hovensa
150
2011
Kawasaki, Japan
Tonen-
General
105
2014
Funshun, China
PetroChina
70
2011
Mantova, Italy
Mol
69
2014
Keihin Ohgimachi, Japan
Toa Oil Company
120
2011
North Pole, AK
Flint Hills
220
2014
Clyde, Australia
Shell
75
2011
Muroran, Japan
JX Holdings
180
2014
Marcus Hook, PA
Sunoco
175
2011
Ellesmere Port, UK*
Essar
55
2014
Berre, France
LyondellBasell
105
2012
Milford Haven, UK
Murphy
130
2014
Coryton, U.K.
Petroplus
220
2012
Kaohsiung, Taiwan
Chinese Petroleum Corp
200
2015
Petit Couronne, France
Petroplus
160
2012
Bulwer Island, Australia
BP
102
2015
56
Global Refining Capacity Rationalization |
 Location
Owner
CDU Capacity (MBPD)
Lytton, Australia
Caltex
109
Nishihara, Japan
Petrobras/Sumitomo
95
Inchon, Korea
SK Energy
270
Whitegate, Ireland
Phillips 66
71
Barbers Point, HI
Chevron
54
Come-By-Chance, Canada
North Atlantic Refining
115
Pasadena, TX
Petrobras
100
Bahia Blanca, Argentina
Petrobras
31
Gothenburg, Sweden
Shell
80
Livorno
ENI
106
Taranto
ENI
120
Mazeikiai, Lithuania
PKN
190
Okinawa, Japan
Petrobras/Nansei Sekiyu
100
Falconara, Italy
API
80
Hamburg, Germany
Tamoil
78
Collombey, Switzerland
Tamoil
72
Chiba, Japan
Cosmo Oil
240
Chiba, Japan
TonenGeneral
152
57
Global Refining Capacity For Sale or Under
Strategic Review
Sources: Direct and public disclosure by each owner |
 58
U.S. Crude Fundamentals
Source: DOE weekly data through December 5, 2014
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
55,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Cushing Crude Inventory (MB)
5 Yr High
5 Yr Low
2012
140,000
150,000
160,000
170,000
180,000
190,000
200,000
210,000
220,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
PADD 3 Crude Inventory (MB)
320,000
330,000
340,000
350,000
360,000
370,000
380,000
390,000
400,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
U.S. Crude Inventory (MB)
5 Yr High
5 Yr Low
2012
2013
2014
5 Yr Avg
5 Yr High
5 Yr Low
2012 |
 59
U.S. Gasoline Fundamentals
USGC Brent Gasoline Crack (per bbl)
U.S. Gasoline Demand (mmbpd)
U.S. Net Imports of Gasoline and Blendstocks (mbpd)
U.S. Gasoline Days of Supply
22
23
24
25
26
27
28
29
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2013
5 year avg
-400
-200
0
200
400
600
800
1000
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 year avg
5 yr high
5 yr low
2014
2013
-$15
-$10
-$5
$0
$5
$10
$15
$20
$25
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2013
2014
5 year avg
8.2
8.4
8.6
8.8
9.0
9.2
9.4
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2013
5 year avg
Source: Argus; 2014 weekly data through Dec 12 Source: 2014 DOE
monthly data through Sep; weekly data through Dec 5
Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 Source: 2014 DOE
monthly data through Sep; weekly data through Dec 5 |
 60
U.S. Distillate Fundamentals
USGC Brent ULSD Crack (per bbl)
U.S. Distillate Demand (mmbpd)
Source: Argus; 2014 data through Dec 12
Source: 2014 DOE monthly data through Sep; weekly data through Dec 5
Source: 2014 DOE monthly data through Sep; weekly data through Dec 5
Source: 2014 DOE monthly data through Sep; weekly data through Dec 5
U.S. Distillate Days of Supply
U.S. Distillate Net Imports (mbpd)
$0
$5
$10
$15
$20
$25
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2013
2014
5 year avg
3.2
3.4
3.6
3.8
4
4.2
4.4
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2013
5 year avg
25
30
35
40
45
50
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr high
5 yr low
2014
2013
5 year avg
-1300
-1100
-900
-700
-500
-300
-100
100
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
5 yr low
5 yr high
2014
2013
5 year avg |
 61
U.S. Transport Indicators |
 62
U.S. Transport Indicators: Trucking |
 63
Increase in U.S. Gasoline Exports
0
100
200
300
400
500
600
700
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Mexico
Canada
Latest 4 Wk avg estimate
(Finished only)
12 Month Moving Average, MBPD
Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol,
MTBE, and other oxygenates)
Source: DOE Petroleum Supply Monthly data as of September 2014. 4 Week
Average estimate from Weekly Petroleum Statistics Report and Valero estimates. |
 64
Decrease in U.S. Gasoline Imports
0
200
400
600
800
1000
1200
1400
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Canada
Latest 4 Wk avg estimate
(Fin+Blendstock)
12 Month Moving Average, MBPD
Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol,
MTBE, and other oxygenates)
Source: DOE Petroleum Supply Monthly data as of September 2014. 4 Week Average
estimate from Weekly Petroleum Statistics Report and Valero estimates. |
 Source: DOE
Petroleum Supply Monthly with data as of September 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report
65
Increase in U.S. Diesel Exports
12 Month Moving Average, MBPD
0
200
400
600
800
1000
1200
1400
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Other Latin America
Mexico
Canada
Latest 4 Wk avg estimate |
 66
U.S. Is Net Refined Products Exporter
U.S. Demand for Refined Products and Net Trade
MMBPD
U.S. Petroleum Demand Excluding Ethanol and Non-Refinery NGL’s
(Refined Product Demand)
Net Imports
Net
Exports
Implied Total Production of
U.S. Refined Products
Implied Production of U.S. Refined
Products for Domestic Use
Valero’s share of U.S. exports has averaged 20% to 25% over the past few years
14
15
16
17
18
19
20
21
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
Note: Implied production = Petroleum demand excluding ethanol and non-refinery NGLs minus
product net imports. Source: EIA, Consultant and Valero estimates; data through Sep 2014
|
 67
U.S. Shifted to Net Exporter
•
Net refined products exports increased from 335 MBPD in 2010 to 2,426 MBPD in 2014
•
Diesel net exports averaged 917 MBPD in 2014 (Jan-Sep)
•
Gasoline
net
imports
averaged
-31
MBPD
in
2014
(Jan
–
Sep)
•
Gasoline and blendstocks have shifted to net exports
-3,000
-2,500
-2,000
-1,500
-1,000
-500
0
500
1,000
1,500
2,000
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
Other
Diesel
Gasoline
Total
Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol,
MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly data as of Sep 2014 MBPD
|
 68
U.S. Growing Market Share by Exports
•
Refined products demand is growing in developing countries and Atlantic Basin
(capacity closures)
•
U.S. Gulf Coast (PADD III) is the largest source of exported products
U. S. Product Exports By Destination
U. S. Product Exports By Source
12 Month Moving Average
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2014
MMBPD
PADD V
PADD I
PADD II
PADD III
(Gulf Coast)
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Other
Europe
Latin America
Canada
MMBPD
Source: DOE Petroleum Supply Monthly data as of Sep 2014; Latin America includes South
and Central America plus Mexico. |
 Mexico
Statistics Diesel Gross Imports (MBPD)
Gasoline Gross Imports (MBPD)
Crude Unit Throughput (MBPD)
Crude Unit Utilization
69
200
250
300
350
400
450
500
550
2007
2008
2009
2010
2011
2012
2013
2014
60%
65%
70%
75%
80%
85%
90%
2007
2008
2009
2010
2011
2012
2013
2014
950
1,000
1,050
1,100
1,150
1,200
1,250
1,300
1,350
2007
2008
2009
2010
2011
2012
2013
2014
0
20
40
60
80
100
120
140
160
180
200
2007
2008
2009
2010
2011
2012
2013
2014
Source: PEMEX, latest data Oct 2014 |
 70
Decrease in Venezuelan Exports to the U.S.
Source: EIA, September 2014
0
50
100
150
200
250
300
350
MBPD
Total Products
Gasoline and Gasoline Blending
Components
Diesel |
 71
Reconciliation of Operating Income to EBITDA
Ethanol (millions)
2Q09 –
4Q09
2010
2011
2012
2013
2014*
Cumulative
Operating income
$165
$209
$396
$(47)
$491
$628
$1,842
+ Depreciation and
amortization expense
$18
$36
$39
$42
$45
$36
$216
= EBITDA
$183
$245
$435
$(5)
$536
$664
$2,058
*2014 Ethanol earnings through September 30 |
 Investor
Relations Contacts 72
For more information, please contact:
John Locke
Executive Director, Investor Relations
210-345-3077
john.locke@valero.com
Karen Ngo
Manager, Investor Relations
210-345-4574
karen.ngo@valero.com |