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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _______________ to _______________
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Delaware
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74-1828067
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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One Valero Way
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78249
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San Antonio, Texas
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(Zip Code)
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(Address of principal executive offices)
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Registrant’s telephone number, including area code: (210) 345-2000
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Large accelerated filer
R
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
o
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Form 10-K Item No. and Caption
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Heading in 2012 Proxy Statement
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10.
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Directors, Executive Officers and Corporate
Governance
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Information Regarding the Board of Directors, Independent Directors, Audit Committee, Proposal No. 1 Election of Directors
,
Information Concerning Nominees and Other Directors,
Identification of Executive Officers,
Section 16(a) Beneficial Ownership Reporting Compliance,
and
Governance Documents and Codes of Ethics
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11.
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Executive Compensation
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Compensation Committee, Compensation Discussion and Analysis, Director Compensation, Executive Compensation,
and
Certain Relationships and Related Transactions
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12.
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Security Ownership of Certain Beneficial
Owners and Management and Related
Stockholder Matters
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Beneficial Ownership of Valero Securities
and
Equity Compensation Plan Information
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13.
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Certain Relationships and Related
Transactions, and Director Independence
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Certain Relationships and Related Transactions
and
Independent Directors
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14.
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Principal Accountant Fees and Services
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KPMG Fees for Fiscal Year 2011, KPMG Fees for Fiscal Year 2010,
and
Audit Committee Pre-Approval Policy
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PAGE
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Item 11.
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Executive Compensation
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
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Item 13.
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Certain Relationships and Related Transactions, and Director Independence
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Item 14.
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Principal Accountant Fees and Services
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•
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Our refining segment includes refining operations, wholesale marketing, product supply and distribution, and transportation operations. The refining segment is segregated geographically into the U.S. Gulf Coast, U.S. Mid-Continent, North Atlantic, and U.S. West Coast regions.
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•
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Our ethanol segment includes sales of internally produced ethanol and distillers grains. Our ethanol operations are geographically located in the central plains region of the U.S.
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•
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Our retail segment includes company-operated convenience stores, Canadian dealers/jobbers, truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is segregated into two geographic regions. Our retail operations in the U.S. are referred to as Retail-U.S. Our retail operations in Canada are referred to as Retail-Canada.
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Refinery
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Location
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Throughput
Capacity
(a)
(BPD)
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U.S. Gulf Coast
:
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Corpus Christi
(b)
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Texas
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325,000
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Port Arthur
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Texas
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310,000
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St. Charles
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Louisiana
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270,000
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Texas City
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Texas
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245,000
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Aruba
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Aruba
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235,000
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Houston
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Texas
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160,000
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Meraux
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Louisiana
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135,000
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Three Rivers
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Texas
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100,000
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1,780,000
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U.S. Mid-Continent
:
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Memphis
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Tennessee
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195,000
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McKee
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Texas
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170,000
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Ardmore
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Oklahoma
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90,000
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455,000
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North Atlantic
:
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Pembroke
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Wales, U.K.
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270,000
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Quebec City
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Quebec, Canada
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235,000
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505,000
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U.S. West Coast
:
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Benicia
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California
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170,000
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Wilmington
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California
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135,000
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305,000
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Total
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3,045,000
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(a)
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“Throughput capacity” represents estimated capacity for processing crude oil, intermediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.6 million BPD.
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(b)
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Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.
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Combined Total Refining System Charges and Yields
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Charges:
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sour crude oil
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37
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%
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acidic sweet crude oil
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5
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%
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sweet crude oil
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31
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%
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residual fuel oil
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11
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%
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other feedstocks
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5
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%
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blendstocks
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11
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%
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Yields:
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gasolines and blendstocks
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46
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%
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distillates
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34
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%
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petrochemicals
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3
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%
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other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)
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17
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%
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Combined U.S. Gulf Coast Region Charges and Yields
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Charges:
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sour crude oil
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50
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%
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acidic sweet crude oil
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2
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%
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sweet crude oil
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10
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%
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residual fuel oil
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19
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%
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other feedstocks
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6
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%
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blendstocks
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13
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%
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Yields:
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gasolines and blendstocks
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41
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%
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distillates
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33
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%
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petrochemicals
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4
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%
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other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)
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22
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%
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Combined U.S. Mid-Continent Region Charges and Yields
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Charges:
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sour crude oil
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9
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%
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sweet crude oil
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82
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%
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other feedstocks
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1
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%
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blendstocks
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8
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%
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Yields:
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gasolines and blendstocks
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54
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%
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distillates
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35
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%
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petrochemicals
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5
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%
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other products (includes gas oil, No. 6 fuel oil, and asphalt)
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6
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%
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North Atlantic Region Charges and Yields
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Charges:
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sour crude oil
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2
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%
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acidic sweet crude oil
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11
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%
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sweet crude oil
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78
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%
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residual fuel oil
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3
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%
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other feedstocks
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1
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%
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blendstocks
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5
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%
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Yields:
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gasolines and blendstocks
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43
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%
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distillates
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44
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%
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petrochemicals
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1
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%
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other products (includes gas oil, No. 6 fuel oil, and other products)
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12
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%
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Combined U.S. West Coast Region Charges and Yields
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Charges:
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sour crude oil
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48
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%
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acidic sweet crude oil
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17
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%
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sweet crude oil
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7
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%
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other feedstocks
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13
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%
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blendstocks
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15
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%
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Yields:
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gasolines and blendstocks
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62
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%
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distillates
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25
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%
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other products (includes gas oil, No. 6 fuel oil, petroleum coke, and asphalt)
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13
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%
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•
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We produce asphalt at five of our refineries. Our asphalt products are sold for use in road construction, road repair, and roofing applications through a network of refinery and terminal loading racks.
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•
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We produce napthenic oils at one of our refineries suitable for a wide variety of lubricant and process applications.
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•
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NGLs produced at our refineries include butane, isobutane, and propane. These products can be used for gasoline blending, home heating, and petrochemical plant feedstocks.
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•
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We are a significant producer of petroleum coke, supplying primarily power generation customers and cement manufacturers. Petroleum coke is used largely as a substitute for coal.
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•
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We produce and market a number of commodity petrochemicals including aromatic solvents (benzene, toluene, and xylene) and two grades of propylene. Aromatic solvents and propylenes are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives.
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•
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We are a large producer of sulfur with sales primarily to customers in the agricultural sector. Sulfur is used in manufacturing fertilizer.
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State
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City
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Ethanol Nameplate Production
(in gallons per year)
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Production of DDG
(in tons per year)
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Corn Processed
(in bushels per year)
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Indiana
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Linden
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110 million
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350,000
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40 million
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Iowa
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Albert City
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110 million
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350,000
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40 million
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Charles City
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110 million
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350,000
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40 million
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Fort Dodge
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110 million
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350,000
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40 million
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Hartley
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110 million
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350,000
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40 million
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Minnesota
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Welcome
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110 million
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350,000
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40 million
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Nebraska
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Albion
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110 million
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350,000
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40 million
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Ohio
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Bloomingburg
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110 million
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350,000
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40 million
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South Dakota
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Aurora
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120 million
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390,000
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43 million
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Wisconsin
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Jefferson
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110 million
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350,000
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40 million
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Total
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1,110 million
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3,540,000
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403 million
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1
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Ethanol is commercially produced using either the wet mill or dry mill process. Wet milling involves separating the grain kernel into its component parts (germ, fiber, protein, and starch) prior to fermentation. In the dry mill process, the entire grain kernel is ground into flour. The starch in the flour is converted to ethanol during the fermentation process, creating carbon dioxide and distillers grains.
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2
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During fermentation, nearly all of the starch in the grain is converted into ethanol and carbon dioxide, while the remaining nutrients (proteins, fats, minerals, and vitamins) are concentrated to yield modified distillers grains, or, after further drying, dried distillers grains. Distillers grains generally are an economical partial replacement for corn, soybean, and dicalcium phosphate in feeds for livestock, swine, and poultry.
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•
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sales of transportation fuels at retail stores and unattended self-service cardlocks,
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•
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sales of convenience store merchandise and services in retail stores, and
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•
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sales of home heating oil to residential customers.
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•
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sales of transportation fuels and convenience store merchandise through our company-operated retail sites and cardlocks,
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•
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sales of transportation fuels through sites owned by independent dealers and jobbers, and
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•
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sales of home heating oil to residential customers.
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•
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Item 1 under the caption “Risk Factors – Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance,”
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•
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Item 3 “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and
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•
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Item 8 “Financial Statements and Supplementary Data” in
Note 10
of Notes to Consolidated Financial Statements under the caption “
Environmental Liabilities
” and
Note 12
of Notes to Consolidated Financial Statements under the caption “
Environmental Matters.
”
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Sales Prices of the
Common Stock
|
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Dividends
Per
Common Share
|
||||||||
Quarter Ended
|
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High
|
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Low
|
|
|||||||
2011:
|
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|
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||||||
December 31
|
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$
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26.70
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|
$
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17.17
|
|
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$
|
0.15
|
|
September 30
|
|
26.89
|
|
|
17.78
|
|
|
0.05
|
|
|||
June 30
|
|
30.50
|
|
|
23.18
|
|
|
0.05
|
|
|||
March 31
|
|
30.73
|
|
|
23.19
|
|
|
0.05
|
|
|||
2010:
|
|
|
|
|
|
|
||||||
December 31
|
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$
|
23.35
|
|
|
$
|
17.25
|
|
|
$
|
0.05
|
|
September 30
|
|
18.31
|
|
|
15.65
|
|
|
0.05
|
|
|||
June 30
|
|
21.37
|
|
|
16.36
|
|
|
0.05
|
|
|||
March 31
|
|
20.69
|
|
|
17.45
|
|
|
0.05
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Period
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Total Number of Shares Purchased
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Average Price Paid per Share
|
Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)
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Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
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|||||
October 2011
|
195,078
|
|
$
|
25.08
|
|
195,078
|
|
—
|
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$ 3.46 billion
|
November 2011
|
1,986,045
|
|
$
|
23.43
|
|
1,986,045
|
|
—
|
|
$ 3.46 billion
|
December 2011
|
1,338,789
|
|
$
|
20.76
|
|
1,338,789
|
|
—
|
|
$ 3.46 billion
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Total
|
3,519,912
|
|
$
|
22.51
|
|
3,519,912
|
|
—
|
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$ 3.46 billion
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(a)
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The shares reported in this column represent purchases settled in the fourth quarter of
2011
relating to (a) our purchases of shares in open-market transactions to meet our obligations under incentive compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.
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(b)
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On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program, which is in addition to the $6 billion program. This $3 billion program has no expiration date.
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|
12/2006
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12/2007
|
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12/2008
|
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12/2009
|
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12/2010
|
|
12/2011
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||||||||||||
Valero Common Stock
|
$
|
100.00
|
|
|
$
|
137.91
|
|
|
$
|
43.38
|
|
|
$
|
34.60
|
|
|
$
|
48.28
|
|
|
$
|
44.49
|
|
S&P 500
|
100.00
|
|
|
105.49
|
|
|
66.46
|
|
|
84.05
|
|
|
96.71
|
|
|
98.75
|
|
||||||
Old Peer Group
|
100.00
|
|
|
127.94
|
|
|
98.91
|
|
|
94.54
|
|
|
112.51
|
|
|
130.65
|
|
||||||
New Peer Group
|
100.00
|
|
|
127.92
|
|
|
103.60
|
|
|
97.91
|
|
|
113.09
|
|
|
133.47
|
|
1
|
Assumes that an investment in Valero common stock and each index was $100 on
December 31, 2006
. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from
December 31, 2006
through
December 31, 2011
.
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|
Year Ended December 31,
|
||||||||||||||||||
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2011 (a)
|
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2010 (b)
|
|
2009 (b)
|
|
2008
|
|
2007
|
||||||||||
Operating revenues
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
64,599
|
|
|
$
|
106,676
|
|
|
$
|
85,079
|
|
Income (loss) from
continuing operations
|
2,096
|
|
|
923
|
|
|
(273
|
)
|
|
(1,154
|
)
|
|
4,230
|
|
|||||
Earnings per common
share from continuing
operations - assuming dilution
|
3.69
|
|
|
1.62
|
|
|
(0.50
|
)
|
|
(2.20
|
)
|
|
7.31
|
|
|||||
Dividends per common share
|
0.30
|
|
|
0.20
|
|
|
0.60
|
|
|
0.57
|
|
|
0.48
|
|
|||||
Total assets
|
42,783
|
|
|
37,621
|
|
|
35,572
|
|
|
34,417
|
|
|
42,722
|
|
|||||
Debt and capital lease
obligations, less current portion
|
6,732
|
|
|
7,515
|
|
|
7,163
|
|
|
6,264
|
|
|
6,470
|
|
(a)
|
We acquired the Meraux Refinery on October 1, 2011 and the Pembroke Refinery on August 1, 2011. The information presented for 2011 includes the results of operations from these acquisitions commencing on their respective acquisition dates.
|
(b)
|
We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented for 2010 and 2009 includes the results of operations of these plants commencing on their respective acquisition dates.
|
•
|
future refining margins, including gasoline and distillate margins;
|
•
|
future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise margins;
|
•
|
future ethanol margins;
|
•
|
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
|
•
|
anticipated levels of crude oil and refined product inventories;
|
•
|
our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of these capital investments on our results of operations;
|
•
|
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products globally and in the regions where we operate;
|
•
|
expectations regarding environmental, tax, and other regulatory initiatives; and
|
•
|
the effect of general economic and other conditions on refining, retail, and ethanol industry fundamentals.
|
•
|
acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;
|
•
|
political and economic conditions in nations that produce crude oil or consume refined products;
|
•
|
demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, petrochemicals, and ethanol;
|
•
|
demand for, and supplies of, crude oil and other feedstocks;
|
•
|
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on and to maintain crude oil price and production controls;
|
•
|
the level of consumer demand, including seasonal fluctuations;
|
•
|
refinery overcapacity or undercapacity;
|
•
|
our ability to successfully integrate any acquired businesses into our operations;
|
•
|
the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;
|
•
|
the levels of competitors’ imports into markets that we supply;
|
•
|
accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;
|
•
|
changes in the cost or availability of transportation for feedstocks and refined products;
|
•
|
the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
|
•
|
the levels of government subsidies for ethanol and other alternative fuels;
|
•
|
delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;
|
•
|
earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined products and ethanol;
|
•
|
rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
|
•
|
legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the EPA’s regulation of greenhouse gases, which may adversely affect our business or operations;
|
•
|
changes in the credit ratings assigned to our debt securities and trade credit;
|
•
|
changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, and the euro relative to the U.S. dollar;
|
•
|
overall economic conditions, including the stability and liquidity of financial markets; and
|
•
|
other factors generally described in the “Risk Factors” section included in Items 1, 1A, and 2, “Business, Risk Factors, and Properties” in this report.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
Change
|
||||||
Operating income (loss) by business segment:
|
|
|
|
|
|
|
||||||
Refining
|
|
$
|
3,516
|
|
|
$
|
1,903
|
|
|
$
|
1,613
|
|
Retail
|
|
381
|
|
|
346
|
|
|
35
|
|
|||
Ethanol
|
|
396
|
|
|
209
|
|
|
187
|
|
|||
Corporate
|
|
(613
|
)
|
|
(582
|
)
|
|
(31
|
)
|
|||
Total
|
|
$
|
3,680
|
|
|
$
|
1,876
|
|
|
$
|
1,804
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
Operating revenues
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
43,754
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
115,719
|
|
|
74,458
|
|
|
41,261
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining
|
3,406
|
|
|
2,944
|
|
|
462
|
|
|||
Retail
|
678
|
|
|
654
|
|
|
24
|
|
|||
Ethanol
|
399
|
|
|
363
|
|
|
36
|
|
|||
General and administrative expenses
|
571
|
|
|
531
|
|
|
40
|
|
|||
Depreciation and amortization expense:
|
|
|
|
|
|
||||||
Refining
|
1,338
|
|
|
1,210
|
|
|
128
|
|
|||
Retail
|
115
|
|
|
108
|
|
|
7
|
|
|||
Ethanol
|
39
|
|
|
36
|
|
|
3
|
|
|||
Corporate
|
42
|
|
|
51
|
|
|
(9
|
)
|
|||
Asset impairment loss
|
—
|
|
|
2
|
|
|
(2
|
)
|
|||
Total costs and expenses
|
122,307
|
|
|
80,357
|
|
|
41,950
|
|
|||
Operating income
|
3,680
|
|
|
1,876
|
|
|
1,804
|
|
|||
Other income, net
|
43
|
|
|
106
|
|
|
(63
|
)
|
|||
Interest and debt expense, net of capitalized interest
|
(401
|
)
|
|
(484
|
)
|
|
83
|
|
|||
Income from continuing operations before
income tax expense
|
3,322
|
|
|
1,498
|
|
|
1,824
|
|
|||
Income tax expense
|
1,226
|
|
|
575
|
|
|
651
|
|
|||
Income from continuing operations
|
2,096
|
|
|
923
|
|
|
1,173
|
|
|||
Loss from discontinued operations, net of income taxes
|
(7
|
)
|
|
(599
|
)
|
|
592
|
|
|||
Net income
|
2,089
|
|
|
324
|
|
|
1,765
|
|
|||
Less: Net loss attributable to noncontrolling interests
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Net income attributable to Valero stockholders
|
$
|
2,090
|
|
|
$
|
324
|
|
|
$
|
1,766
|
|
|
|
|
|
|
|
||||||
Net income attributable to Valero stockholders:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
2,097
|
|
|
$
|
923
|
|
|
$
|
1,174
|
|
Discontinued operations
|
(7
|
)
|
|
(599
|
)
|
|
592
|
|
|||
Total
|
$
|
2,090
|
|
|
$
|
324
|
|
|
$
|
1,766
|
|
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
3.69
|
|
|
$
|
1.62
|
|
|
$
|
2.07
|
|
Discontinued operations
|
(0.01
|
)
|
|
(1.05
|
)
|
|
1.04
|
|
|||
Total
|
$
|
3.68
|
|
|
$
|
0.57
|
|
|
$
|
3.11
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
Refining (a) (b) (c):
|
|
|
|
|
|
||||||
Operating income
|
$
|
3,516
|
|
|
$
|
1,903
|
|
|
$
|
1,613
|
|
Throughput margin per barrel (e)
|
$
|
9.30
|
|
|
$
|
7.80
|
|
|
$
|
1.50
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.83
|
|
|
3.79
|
|
|
0.04
|
|
|||
Depreciation and amortization expense
|
1.51
|
|
|
1.56
|
|
|
(0.05
|
)
|
|||
Total operating costs per barrel
|
5.34
|
|
|
5.35
|
|
|
(0.01
|
)
|
|||
Operating income per barrel
|
$
|
3.96
|
|
|
$
|
2.45
|
|
|
$
|
1.51
|
|
|
|
|
|
|
|
||||||
Throughput volumes (thousand BPD):
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude
|
454
|
|
|
458
|
|
|
(4
|
)
|
|||
Medium/light sour crude
|
442
|
|
|
386
|
|
|
56
|
|
|||
Acidic sweet crude
|
116
|
|
|
60
|
|
|
56
|
|
|||
Sweet crude
|
745
|
|
|
668
|
|
|
77
|
|
|||
Residuals
|
282
|
|
|
204
|
|
|
78
|
|
|||
Other feedstocks
|
122
|
|
|
110
|
|
|
12
|
|
|||
Total feedstocks
|
2,161
|
|
|
1,886
|
|
|
275
|
|
|||
Blendstocks and other
|
273
|
|
|
243
|
|
|
30
|
|
|||
Total throughput volumes
|
2,434
|
|
|
2,129
|
|
|
305
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD):
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,120
|
|
|
1,048
|
|
|
72
|
|
|||
Distillates
|
834
|
|
|
712
|
|
|
122
|
|
|||
Other products (f)
|
494
|
|
|
395
|
|
|
99
|
|
|||
Total yields
|
2,448
|
|
|
2,155
|
|
|
293
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
U.S. Gulf Coast: (a)
|
|
|
|
|
|
||||||
Operating income
|
$
|
1,833
|
|
|
$
|
1,349
|
|
|
$
|
484
|
|
Throughput volumes (thousand BPD)
|
1,450
|
|
|
1,280
|
|
|
170
|
|
|||
Throughput margin per barrel (e)
|
$
|
8.63
|
|
|
$
|
8.20
|
|
|
$
|
0.43
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.66
|
|
|
3.71
|
|
|
(0.05
|
)
|
|||
Depreciation and amortization expense
|
1.50
|
|
|
1.60
|
|
|
(0.10
|
)
|
|||
Total operating costs per barrel
|
5.16
|
|
|
5.31
|
|
|
(0.15
|
)
|
|||
Operating income per barrel
|
$
|
3.47
|
|
|
$
|
2.89
|
|
|
$
|
0.58
|
|
|
|
|
|
|
|
||||||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Operating income
|
$
|
1,413
|
|
|
$
|
339
|
|
|
$
|
1,074
|
|
Throughput volumes (thousand BPD)
|
411
|
|
|
398
|
|
|
13
|
|
|||
Throughput margin per barrel (e)
|
$
|
15.10
|
|
|
$
|
7.33
|
|
|
$
|
7.77
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
4.15
|
|
|
3.60
|
|
|
0.55
|
|
|||
Depreciation and amortization expense
|
1.52
|
|
|
1.40
|
|
|
0.12
|
|
|||
Total operating costs per barrel
|
5.67
|
|
|
5.00
|
|
|
0.67
|
|
|||
Operating income per barrel
|
$
|
9.43
|
|
|
$
|
2.33
|
|
|
$
|
7.10
|
|
|
|
|
|
|
|
||||||
North Atlantic (b):
|
|
|
|
|
|
||||||
Operating income
|
$
|
171
|
|
|
$
|
129
|
|
|
$
|
42
|
|
Throughput volumes (thousand BPD)
|
317
|
|
|
195
|
|
|
122
|
|
|||
Throughput margin per barrel (e)
|
$
|
5.43
|
|
|
$
|
6.18
|
|
|
$
|
(0.75
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.08
|
|
|
2.99
|
|
|
0.09
|
|
|||
Depreciation and amortization expense
|
0.87
|
|
|
1.39
|
|
|
(0.52
|
)
|
|||
Total operating costs per barrel
|
3.95
|
|
|
4.38
|
|
|
(0.43
|
)
|
|||
Operating income per barrel
|
$
|
1.48
|
|
|
$
|
1.80
|
|
|
$
|
(0.32
|
)
|
|
|
|
|
|
|
||||||
U.S. West Coast:
|
|
|
|
|
|
||||||
Operating income
|
$
|
99
|
|
|
$
|
88
|
|
|
$
|
11
|
|
Throughput volumes (thousand BPD)
|
256
|
|
|
256
|
|
|
—
|
|
|||
Throughput margin per barrel (e)
|
$
|
8.60
|
|
|
$
|
7.73
|
|
|
$
|
0.87
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
5.25
|
|
|
5.09
|
|
|
0.16
|
|
|||
Depreciation and amortization expense
|
2.29
|
|
|
1.69
|
|
|
0.60
|
|
|||
Total operating costs per barrel
|
7.54
|
|
|
6.78
|
|
|
0.76
|
|
|||
Operating income per barrel
|
$
|
1.06
|
|
|
$
|
0.95
|
|
|
$
|
0.11
|
|
|
|
|
|
|
|
||||||
Operating income for regions above
|
$
|
3,516
|
|
|
$
|
1,905
|
|
|
$
|
1,611
|
|
Asset impairment loss applicable to refining
|
—
|
|
|
(2
|
)
|
|
2
|
|
|||
Total refining operating income
|
$
|
3,516
|
|
|
$
|
1,903
|
|
|
$
|
1,613
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
LLS crude oil
|
$
|
111.47
|
|
|
$
|
81.62
|
|
|
$
|
29.85
|
|
LLS less WTI crude oil
|
16.42
|
|
|
2.21
|
|
|
14.21
|
|
|||
LLS less Alaska North Slope (ANS) crude oil
|
1.93
|
|
|
2.55
|
|
|
(0.62
|
)
|
|||
LLS less Brent crude oil
|
0.54
|
|
|
2.09
|
|
|
(1.55
|
)
|
|||
LLS less Mars crude oil
|
4.00
|
|
|
3.62
|
|
|
0.38
|
|
|||
LLS less Maya crude oil
|
12.72
|
|
|
11.34
|
|
|
1.38
|
|
|||
WTI crude oil
|
95.05
|
|
|
79.41
|
|
|
15.64
|
|
|||
WTI less Mars crude oil
|
(12.42
|
)
|
|
1.41
|
|
|
(13.83
|
)
|
|||
WTI less Maya crude oil
|
(3.70
|
)
|
|
9.13
|
|
|
(12.83
|
)
|
|||
|
|
|
|
|
|
||||||
Products:
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less LLS
|
$
|
5.04
|
|
|
$
|
5.30
|
|
|
$
|
(0.26
|
)
|
Ultra-low-sulfur diesel less LLS
|
13.24
|
|
|
8.93
|
|
|
4.31
|
|
|||
Propylene less LLS
|
7.69
|
|
|
5.71
|
|
|
1.98
|
|
|||
Conventional 87 gasoline less WTI
|
21.46
|
|
|
7.51
|
|
|
13.95
|
|
|||
Ultra-low-sulfur diesel less WTI
|
29.66
|
|
|
11.14
|
|
|
18.52
|
|
|||
Propylene less WTI
|
24.11
|
|
|
7.92
|
|
|
16.19
|
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less WTI
|
22.37
|
|
|
8.20
|
|
|
14.17
|
|
|||
Ultra-low-sulfur diesel less WTI
|
31.06
|
|
|
11.91
|
|
|
19.15
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less Brent
|
6.24
|
|
|
8.38
|
|
|
(2.14
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
15.64
|
|
|
12.63
|
|
|
3.01
|
|
|||
Conventional 87 gasoline less WTI
|
22.12
|
|
|
8.50
|
|
|
13.62
|
|
|||
Ultra-low-sulfur diesel less WTI
|
31.52
|
|
|
12.76
|
|
|
18.76
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
CARBOB 87 gasoline less ANS
|
11.48
|
|
|
14.21
|
|
|
(2.73
|
)
|
|||
CARB diesel less ANS
|
18.47
|
|
|
13.79
|
|
|
4.68
|
|
|||
CARBOB 87 gasoline less WTI
|
25.97
|
|
|
13.88
|
|
|
12.09
|
|
|||
CARB diesel less WTI
|
32.96
|
|
|
13.45
|
|
|
19.51
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.25
|
|
|
0.39
|
|
|
(0.14
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
Change
|
||||||
Retail–U.S.:
|
|
|
|
|
|
||||||
Operating income
|
$
|
213
|
|
|
$
|
200
|
|
|
$
|
13
|
|
Company-operated fuel sites (average)
|
994
|
|
|
990
|
|
|
4
|
|
|||
Fuel volumes (gallons per day per site)
|
5,060
|
|
|
5,086
|
|
|
(26
|
)
|
|||
Fuel margin per gallon
|
$
|
0.144
|
|
|
$
|
0.140
|
|
|
$
|
0.004
|
|
Merchandise sales
|
$
|
1,223
|
|
|
$
|
1,205
|
|
|
$
|
18
|
|
Merchandise margin (percentage of sales)
|
28.7
|
%
|
|
28.3
|
%
|
|
0.4
|
%
|
|||
Margin on miscellaneous sales
|
$
|
88
|
|
|
$
|
86
|
|
|
$
|
2
|
|
Operating expenses
|
$
|
416
|
|
|
$
|
412
|
|
|
$
|
4
|
|
Depreciation and amortization expense
|
$
|
77
|
|
|
$
|
73
|
|
|
$
|
4
|
|
|
|
|
|
|
|
||||||
Retail–Canada:
|
|
|
|
|
|
||||||
Operating income
|
$
|
168
|
|
|
$
|
146
|
|
|
$
|
22
|
|
Fuel volumes (thousand gallons per day)
|
3,195
|
|
|
3,168
|
|
|
27
|
|
|||
Fuel margin per gallon
|
$
|
0.299
|
|
|
$
|
0.271
|
|
|
$
|
0.028
|
|
Merchandise sales
|
$
|
261
|
|
|
$
|
240
|
|
|
$
|
21
|
|
Merchandise margin (percentage of sales)
|
29.4
|
%
|
|
30.1
|
%
|
|
(0.7
|
)%
|
|||
Margin on miscellaneous sales
|
$
|
43
|
|
|
$
|
38
|
|
|
$
|
5
|
|
Operating expenses
|
$
|
262
|
|
|
$
|
242
|
|
|
$
|
20
|
|
Depreciation and amortization expense
|
$
|
38
|
|
|
$
|
35
|
|
|
$
|
3
|
|
|
|
|
|
|
|
||||||
Ethanol (d):
|
|
|
|
|
|
||||||
Operating income
|
$
|
396
|
|
|
$
|
209
|
|
|
$
|
187
|
|
Ethanol production (thousand gallons per day)
|
3,352
|
|
|
3,021
|
|
|
331
|
|
|||
Gross margin per gallon of ethanol production (e)
|
$
|
0.68
|
|
|
$
|
0.55
|
|
|
$
|
0.13
|
|
Operating costs per gallon of production:
|
|
|
|
|
|
||||||
Operating expenses
|
0.33
|
|
|
0.33
|
|
|
—
|
|
|||
Depreciation and amortization expense
|
0.03
|
|
|
0.03
|
|
|
—
|
|
|||
Total operating costs per gallon of production
|
0.36
|
|
|
0.36
|
|
|
—
|
|
|||
Operating income per gallon of production
|
$
|
0.32
|
|
|
$
|
0.19
|
|
|
$
|
0.13
|
|
(a)
|
The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011 through December 31, 2011.
|
(b)
|
The financial highlights and operating highlights for the refining segment and North Atlantic region include the results of operations of our Pembroke Refinery, including the related market and logistics business from the date of its acquisition on August 1, 2011 through December 31, 2011.
|
(c)
|
In 2010, we sold our Paulsboro Refinery and our shutdown Delaware City refinery assets and associated terminal and pipeline assets. The results of operations of these refineries have been presented as discontinued operations for the year ended December 31, 2010. In addition, the operating highlights for the refining segment and North Atlantic region exclude these refineries for the year ended December 31, 2010.
|
(d)
|
We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of these plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each year divided by actual calendar days per year.
|
(e)
|
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
|
(f)
|
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
|
(g)
|
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, Port Arthur, and Meraux Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic (formerly known as Northeast) region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.
|
(h)
|
Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides the best indicator of product margins for each region. Prior to the first quarter of 2011, feedstock and product differentials were based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI crude oil began to price at a discount to benchmark sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. Therefore, the use of the price of WTI crude oil as a benchmark price for regions that do not process WTI crude oil is no longer reasonable.
|
|
Year Ended December 31,
|
||||||||||
|
2010
|
|
2009
|
|
Change
|
||||||
Operating revenues
|
$
|
82,233
|
|
|
$
|
64,599
|
|
|
$
|
17,634
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
74,458
|
|
|
58,686
|
|
|
15,772
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining
|
2,944
|
|
|
2,880
|
|
|
64
|
|
|||
Retail
|
654
|
|
|
626
|
|
|
28
|
|
|||
Ethanol
|
363
|
|
|
169
|
|
|
194
|
|
|||
General and administrative expenses
|
531
|
|
|
572
|
|
|
(41
|
)
|
|||
Depreciation and amortization expense:
|
|
|
|
|
|
||||||
Refining
|
1,210
|
|
|
1,194
|
|
|
16
|
|
|||
Retail
|
108
|
|
|
101
|
|
|
7
|
|
|||
Ethanol
|
36
|
|
|
18
|
|
|
18
|
|
|||
Corporate
|
51
|
|
|
48
|
|
|
3
|
|
|||
Asset impairment loss (d)
|
2
|
|
|
222
|
|
|
(220
|
)
|
|||
Total costs and expenses
|
80,357
|
|
|
64,516
|
|
|
15,841
|
|
|||
Operating income
|
1,876
|
|
|
83
|
|
|
1,793
|
|
|||
Other income, net
|
106
|
|
|
17
|
|
|
89
|
|
|||
Interest and debt expense, net of capitalized interest
|
(484
|
)
|
|
(416
|
)
|
|
(68
|
)
|
|||
Income (loss) from continuing operations
before income tax expense (benefit)
|
1,498
|
|
|
(316
|
)
|
|
1,814
|
|
|||
Income tax expense (benefit)
|
575
|
|
|
(43
|
)
|
|
618
|
|
|||
Income (loss) from continuing operations
|
923
|
|
|
(273
|
)
|
|
1,196
|
|
|||
Loss from discontinued operations, net of income taxes
|
(599
|
)
|
|
(1,709
|
)
|
|
1,110
|
|
|||
Net income (loss)
|
324
|
|
|
(1,982
|
)
|
|
2,306
|
|
|||
Less: Net loss attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income (loss) attributable to Valero stockholders
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
|
$
|
2,306
|
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Valero stockholders:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
923
|
|
|
$
|
(273
|
)
|
|
$
|
1,196
|
|
Discontinued operations
|
(599
|
)
|
|
(1,709
|
)
|
|
1,110
|
|
|||
Total
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
|
$
|
2,306
|
|
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
1.62
|
|
|
$
|
(0.50
|
)
|
|
$
|
2.12
|
|
Discontinued operations
|
(1.05
|
)
|
|
(3.17
|
)
|
|
2.12
|
|
|||
Total
|
$
|
0.57
|
|
|
$
|
(3.67
|
)
|
|
$
|
4.24
|
|
|
Year Ended December 31,
|
||||||||||
|
2010
|
|
2009
|
|
Change
|
||||||
Refining (a) (b):
|
|
|
|
|
|
||||||
Operating income (d)
|
$
|
1,903
|
|
|
$
|
247
|
|
|
$
|
1,656
|
|
Throughput margin per barrel (e)
|
$
|
7.80
|
|
|
$
|
6.00
|
|
|
$
|
1.80
|
|
Operating costs per barrel (d):
|
|
|
|
|
|
||||||
Operating expenses
|
3.79
|
|
|
3.71
|
|
|
0.08
|
|
|||
Depreciation and amortization expense
|
1.56
|
|
|
1.55
|
|
|
0.01
|
|
|||
Total operating costs per barrel
|
5.35
|
|
|
5.26
|
|
|
0.09
|
|
|||
Operating income per barrel
|
$
|
2.45
|
|
|
$
|
0.74
|
|
|
$
|
1.71
|
|
|
|
|
|
|
|
||||||
Throughput volumes (thousand BPD):
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude
|
458
|
|
|
457
|
|
|
1
|
|
|||
Medium/light sour crude
|
386
|
|
|
417
|
|
|
(31
|
)
|
|||
Acidic sweet crude
|
60
|
|
|
64
|
|
|
(4
|
)
|
|||
Sweet crude
|
668
|
|
|
616
|
|
|
52
|
|
|||
Residuals
|
204
|
|
|
170
|
|
|
34
|
|
|||
Other feedstocks
|
110
|
|
|
136
|
|
|
(26
|
)
|
|||
Total feedstocks
|
1,886
|
|
|
1,860
|
|
|
26
|
|
|||
Blendstocks and other
|
243
|
|
|
264
|
|
|
(21
|
)
|
|||
Total throughput volumes
|
2,129
|
|
|
2,124
|
|
|
5
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD):
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,048
|
|
|
1,040
|
|
|
8
|
|
|||
Distillates
|
712
|
|
|
692
|
|
|
20
|
|
|||
Other products (f)
|
395
|
|
|
402
|
|
|
(7
|
)
|
|||
Total yields
|
2,155
|
|
|
2,134
|
|
|
21
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2010
|
|
2009
|
|
Change
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
Operating income (loss)
|
$
|
1,349
|
|
|
$
|
(56
|
)
|
|
$
|
1,405
|
|
Throughput volumes (thousand BPD)
|
1,280
|
|
|
1,274
|
|
|
6
|
|
|||
Throughput margin per barrel (e)
|
$
|
8.20
|
|
|
$
|
5.13
|
|
|
$
|
3.07
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.71
|
|
|
3.71
|
|
|
—
|
|
|||
Depreciation and amortization expense
|
1.60
|
|
|
1.54
|
|
|
0.06
|
|
|||
Total operating costs per barrel
|
5.31
|
|
|
5.25
|
|
|
0.06
|
|
|||
Operating income (loss) per barrel
|
$
|
2.89
|
|
|
$
|
(0.12
|
)
|
|
$
|
3.01
|
|
|
|
|
|
|
|
||||||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Operating income
|
$
|
339
|
|
|
$
|
189
|
|
|
$
|
150
|
|
Throughput volumes (thousand BPD)
|
398
|
|
|
387
|
|
|
11
|
|
|||
Throughput margin per barrel (e)
|
$
|
7.33
|
|
|
$
|
6.52
|
|
|
$
|
0.81
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.60
|
|
|
3.66
|
|
|
(0.06
|
)
|
|||
Depreciation and amortization expense
|
1.40
|
|
|
1.53
|
|
|
(0.13
|
)
|
|||
Total operating costs per barrel
|
5.00
|
|
|
5.19
|
|
|
(0.19
|
)
|
|||
Operating income per barrel
|
$
|
2.33
|
|
|
$
|
1.33
|
|
|
$
|
1.00
|
|
|
|
|
|
|
|
||||||
North Atlantic (a) (b):
|
|
|
|
|
|
||||||
Operating income
|
$
|
129
|
|
|
$
|
196
|
|
|
$
|
(67
|
)
|
Throughput volumes (thousand BPD)
|
195
|
|
|
196
|
|
|
(1
|
)
|
|||
Throughput margin per barrel (e)
|
$
|
6.18
|
|
|
$
|
6.36
|
|
|
$
|
(0.18
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
2.99
|
|
|
2.31
|
|
|
0.68
|
|
|||
Depreciation and amortization expense
|
1.39
|
|
|
1.33
|
|
|
0.06
|
|
|||
Total operating costs per barrel
|
4.38
|
|
|
3.64
|
|
|
0.74
|
|
|||
Operating income per barrel
|
$
|
1.80
|
|
|
$
|
2.72
|
|
|
$
|
(0.92
|
)
|
|
|
|
|
|
|
||||||
U.S. West Coast:
|
|
|
|
|
|
||||||
Operating income
|
$
|
88
|
|
|
$
|
252
|
|
|
$
|
(164
|
)
|
Throughput volumes (thousand BPD)
|
256
|
|
|
267
|
|
|
(11
|
)
|
|||
Throughput margin per barrel (e)
|
$
|
7.73
|
|
|
$
|
9.16
|
|
|
$
|
(1.43
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
5.09
|
|
|
4.83
|
|
|
0.26
|
|
|||
Depreciation and amortization expense
|
1.69
|
|
|
1.74
|
|
|
(0.05
|
)
|
|||
Total operating costs per barrel
|
6.78
|
|
|
6.57
|
|
|
0.21
|
|
|||
Operating income per barrel
|
$
|
0.95
|
|
|
$
|
2.59
|
|
|
$
|
(1.64
|
)
|
|
|
|
|
|
|
||||||
Operating income for regions above
|
$
|
1,905
|
|
|
$
|
581
|
|
|
$
|
1,324
|
|
Asset impairment loss applicable to refining
|
(2
|
)
|
|
(220
|
)
|
|
218
|
|
|||
Loss contingency accrual related to Aruba tax matter (h)
|
—
|
|
|
(114
|
)
|
|
114
|
|
|||
Total refining operating income
|
$
|
1,903
|
|
|
$
|
247
|
|
|
$
|
1,656
|
|
|
Year Ended December 31,
|
||||||||||
|
2010
|
|
2009
|
|
Change
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
LLS crude oil
|
$
|
81.62
|
|
|
$
|
62.25
|
|
|
$
|
19.37
|
|
LLS less WTI crude oil
|
2.21
|
|
|
0.56
|
|
|
1.65
|
|
|||
WTI crude oil
|
79.41
|
|
|
61.69
|
|
|
17.72
|
|
|||
WTI less Mars crude oil
|
1.41
|
|
|
1.36
|
|
|
0.05
|
|
|||
WTI less Maya crude oil
|
9.13
|
|
|
5.19
|
|
|
3.94
|
|
|||
|
|
|
|
|
|
||||||
Products:
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less WTI
|
$
|
7.51
|
|
|
$
|
7.61
|
|
|
$
|
(0.10
|
)
|
Ultra-low-sulfur diesel less WTI
|
11.14
|
|
|
8.02
|
|
|
3.12
|
|
|||
Propylene less WTI
|
7.92
|
|
|
(1.31
|
)
|
|
9.23
|
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less WTI
|
8.20
|
|
|
8.01
|
|
|
0.19
|
|
|||
Ultra-low-sulfur diesel less WTI
|
11.91
|
|
|
8.26
|
|
|
3.65
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
Conventional 87 gasoline less WTI
|
8.50
|
|
|
7.99
|
|
|
0.51
|
|
|||
Ultra-low-sulfur diesel less WTI
|
12.76
|
|
|
9.55
|
|
|
3.21
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
CARBOB 87 gasoline less WTI
|
13.88
|
|
|
15.75
|
|
|
(1.87
|
)
|
|||
CARB diesel less WTI
|
13.45
|
|
|
9.86
|
|
|
3.59
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.39
|
|
|
0.47
|
|
|
(0.08
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2010
|
|
2009
|
|
Change
|
||||||
Retail–U.S.:
|
|
|
|
|
|
||||||
Operating income
|
$
|
200
|
|
|
$
|
170
|
|
|
$
|
30
|
|
Company-operated fuel sites (average)
|
990
|
|
|
999
|
|
|
(9
|
)
|
|||
Fuel volumes (gallons per day per site)
|
5,086
|
|
|
4,983
|
|
|
103
|
|
|||
Fuel margin per gallon
|
$
|
0.140
|
|
|
$
|
0.126
|
|
|
$
|
0.014
|
|
Merchandise sales
|
$
|
1,205
|
|
|
$
|
1,171
|
|
|
$
|
34
|
|
Merchandise margin (percentage of sales)
|
28.3
|
%
|
|
28.1
|
%
|
|
0.2
|
%
|
|||
Margin on miscellaneous sales
|
$
|
86
|
|
|
$
|
87
|
|
|
$
|
(1
|
)
|
Operating expenses
|
$
|
412
|
|
|
$
|
405
|
|
|
$
|
7
|
|
Depreciation and amortization expense
|
$
|
73
|
|
|
$
|
70
|
|
|
$
|
3
|
|
|
|
|
|
|
|
||||||
Retail–Canada:
|
|
|
|
|
|
||||||
Operating income
|
$
|
146
|
|
|
$
|
123
|
|
|
$
|
23
|
|
Fuel volumes (thousand gallons per day)
|
3,168
|
|
|
3,159
|
|
|
9
|
|
|||
Fuel margin per gallon
|
$
|
0.271
|
|
|
$
|
0.247
|
|
|
$
|
0.024
|
|
Merchandise sales
|
$
|
240
|
|
|
$
|
201
|
|
|
$
|
39
|
|
Merchandise margin (percentage of sales)
|
30.1
|
%
|
|
28.3
|
%
|
|
1.8
|
%
|
|||
Margin on miscellaneous sales
|
$
|
38
|
|
|
$
|
33
|
|
|
$
|
5
|
|
Operating expenses
|
$
|
242
|
|
|
$
|
221
|
|
|
$
|
21
|
|
Depreciation and amortization expense
|
$
|
35
|
|
|
$
|
31
|
|
|
$
|
4
|
|
|
|
|
|
|
|
||||||
Ethanol (c):
|
|
|
|
|
|
||||||
Operating income
|
$
|
209
|
|
|
$
|
165
|
|
|
$
|
44
|
|
Ethanol production (thousand gallons per day)
|
3,021
|
|
|
1,479
|
|
|
1,542
|
|
|||
Gross margin per gallon of ethanol production (e)
|
$
|
0.55
|
|
|
$
|
0.65
|
|
|
$
|
(0.10
|
)
|
Operating costs per gallon of ethanol production:
|
|
|
|
|
|
||||||
Operating expenses
|
0.33
|
|
|
0.31
|
|
|
0.02
|
|
|||
Depreciation and amortization expense
|
0.03
|
|
|
0.03
|
|
|
—
|
|
|||
Total operating costs per gallon of production
|
0.36
|
|
|
0.34
|
|
|
0.02
|
|
|||
Operating income per gallon of production
|
$
|
0.19
|
|
|
$
|
0.31
|
|
|
$
|
(0.12
|
)
|
(a)
|
In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC for $547 million of cash proceeds and a
$160 million
one-year note, resulting in a pre-tax loss on the sale of
$980 million
(
$610 million
after taxes). The results of operations of the refinery, including the loss on the sale, have been presented as discontinued operations for both years presented. The refining segment and North Atlantic Region operating highlights exclude the Paulsboro Refinery for both years presented.
|
(b)
|
During the fourth quarter of 2009, we permanently shut down our Delaware City Refinery and wrote down the book value of the refinery assets to net realizable value, resulting in a pre-tax loss on the shutdown of $1.9 billion ($1.2 billion after taxes). In June 2010, we sold the shutdown refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP for
$220 million
of cash proceeds, resulting in a pre-tax gain on the sale of the refinery assets of
$92 million
(
$58 million
after taxes) and an insignificant gain on the sale of the terminal and pipeline assets. The results of operations of the shutdown refinery, including the gain on the sale in 2010 and the loss on the shutdown in 2009, have been presented as discontinued operations for both years presented. The refining segment and North Atlantic Region operating highlights exclude the Delaware City Refinery for both years presented. The terminal and pipeline assets associated with the refinery were not shut down in 2009 and continued to be operated until they were sold; the results of these operations are reflected in continuing operations for both years presented.
|
(c)
|
We acquired three ethanol plants in the first quarter of 2010 and seven ethanol plants in the second quarter of 2009. The information presented includes the results of operations of these plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each year divided by actual calendar days per year.
|
(d)
|
The asset impairment loss relates primarily to the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the economic slowdown on refining industry fundamentals. The asset impairment loss amounts are included in the refining segment operating income but are excluded from the regional operating income amounts and the consolidated and regional operating costs per barrel.
|
(e)
|
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
|
(f)
|
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
|
(g)
|
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, and Port Arthur Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Quebec City Refinery; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.
|
(h)
|
A loss contingency accrual of $140 million was recorded in the third quarter of 2009 related to our dispute with the GOA regarding a turnover tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was recorded in cost of sales for the year ended December 31, 2009, and therefore is included in refining operating income (loss) but has been excluded in determining throughput margin per barrel.
|
•
|
Changes in the margin we receive for our products have a material impact on our results of operations. For example, the WTI-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was
$11.14
per barrel for the year ended
December 31, 2010
compared to
$8.02
per barrel for the year ended
December 31, 2009
, representing a favorable increase of
$3.12
per barrel. Similar increases in distillate margins were experienced in other regions. We estimate that the increase in margin for distillates had an $820 million positive impact on our overall refining margin, year over year, as we produced
712,000
BPD of distillates during the year ended
December 31, 2010
. Similarly, the WTI-based benchmark reference margin for U.S. Gulf Coast propylene was $7.92 per barrel for the year ended
December 31, 2010
compared to a negative margin of $1.31 for the year ended
December 31, 2009
, representing a favorable increase of $9.23 per barrel. We estimate that the increase in margin for petrochemicals (primarily propylene) had a $199 million positive impact on our refining margin, year over year. Distillate and propylene margins were higher in 2010 as compared to 2009 due to an increase in the industrial demand for these products resulting from the ongoing recovery of the U.S. and worldwide economies and exports.
|
•
|
The WTI-based benchmark reference margin for U.S. Gulf Coast conventional 87 gasoline was
$7.51
per barrel for the year ended
December 31, 2010
compared to
$7.61
per barrel for the year ended
December 31, 2009
, representing an unfavorable decrease of
$0.10
per barrel. The WTI-based CARBOB 87 gasoline benchmark reference margins decreased year over year to an even greater extent in the U.S. West Coast region (a
$1.87
per barrel unfavorable decrease). We estimate that the decrease in gasoline margins had a $119 million negative impact to our overall refining margin, year over year, as we produced
1.05 million
BPD of gasoline during the year ended
December 31, 2010
. Gasoline margins were lower in 2010 as compared to 2009 despite an increase in gasoline prices during 2010. We believe that the margins for gasoline were constrained due to continued weak consumer demand and high levels of inventory. In addition, our downstream customers increased the use of ethanol as a component in transportation fuels because its price was lower than the price of gasoline.
|
•
|
For the year ended
December 31, 2010
, the differential applicable to the price of sour crude oil as compared to the price of sweet crude oil was wider than the differential for the year ended
December 31, 2009
. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of
$9.13
per barrel to WTI crude oil, a type of sweet crude oil, during the year ended
December 31, 2010
. This compared to a discount of
$5.19
per barrel during the year ended
December 31, 2009
, representing a favorable increase of
$3.94
per barrel. The benefit of this wider differential, however, was offset by a reduction of 30,000 BPD of sour crude oil that we processed during 2010 as compared to 2009. We estimate that the wider differentials for all types of sour crude oil that we process, offset by reduced throughput volumes, had a $196 million positive impact to our overall refining margin for 2010 as we processed
844,000
BPD of sour crude oils.
|
•
|
fund
$3.0 billion
of capital expenditures and deferred turnaround and catalyst costs;
|
•
|
purchase the Pembroke Refinery and the related marketing and logistics business for
$1.7 billion
;
|
•
|
purchase the Meraux Refinery for
$547 million
;
|
•
|
redeem our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for
$56 million
;
|
•
|
make scheduled long-term note repayments of $418 million;
|
•
|
acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds) for $300 million;
|
•
|
purchase our common stock for
$349 million
; and
|
•
|
pay common stock dividends of
$169 million
.
|
•
|
fund $2.3 billion of capital expenditures and deferred turnaround and catalyst costs;
|
•
|
redeem our 7.5% senior notes for $294 million and our 6.75% senior notes for $190 million;
|
•
|
make scheduled long-term note repayments of $33 million;
|
•
|
make net repayments under our accounts receivable sales facility of $100 million;
|
•
|
pay common stock dividends of $114 million;
|
•
|
purchase additional ethanol facilities for $260 million; and
|
•
|
increase available cash on hand by $2.5 billion.
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Cash provided by (used in)
operating activities:
|
|
|
|
|
|
||||||
Paulsboro Refinery
|
$
|
—
|
|
|
$
|
88
|
|
|
$
|
10
|
|
Delaware City Refinery
|
—
|
|
|
(26
|
)
|
|
(126
|
)
|
|||
Cash used in investing activities:
|
|
|
|
|
|
||||||
Paulsboro Refinery
|
—
|
|
|
(41
|
)
|
|
(121
|
)
|
|||
Delaware City Refinery
|
—
|
|
|
—
|
|
|
(153
|
)
|
|
Payments Due by Period
|
|
|
||||||||||||||||||||||||
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
Thereafter
|
|
Total
|
||||||||||||||
Debt and capital
lease obligations (including
interest on capital lease
obligations)
|
$
|
1,015
|
|
|
$
|
494
|
|
|
$
|
209
|
|
|
$
|
483
|
|
|
$
|
8
|
|
|
$
|
5,615
|
|
|
$
|
7,824
|
|
Operating lease obligations
|
291
|
|
|
198
|
|
|
131
|
|
|
106
|
|
|
86
|
|
|
294
|
|
|
1,106
|
|
|||||||
Purchase obligations
|
36,303
|
|
|
3,088
|
|
|
962
|
|
|
407
|
|
|
360
|
|
|
899
|
|
|
42,019
|
|
|||||||
Other long-term liabilities
|
—
|
|
|
176
|
|
|
152
|
|
|
145
|
|
|
137
|
|
|
1,271
|
|
|
1,881
|
|
|||||||
Total
|
$
|
37,609
|
|
|
$
|
3,956
|
|
|
$
|
1,454
|
|
|
$
|
1,141
|
|
|
$
|
591
|
|
|
$
|
8,079
|
|
|
$
|
52,830
|
|
•
|
in December 2011, we redeemed our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for $56 million, or 100% of their stated values;
|
•
|
in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;
|
•
|
in April 2011, we made scheduled debt repayments of $8 million related to our Series 1997A 5.45%, Series 1997B 5.4%, and Series 1997C 5.4% industrial revenue bonds;
|
•
|
in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and
|
•
|
in February 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender.
|
Rating Agency
|
|
Rating
|
Standard & Poor’s Ratings Services
|
|
BBB (stable outlook)
|
Moody’s Investors Service
|
|
Baa2 (stable outlook)
|
Fitch Ratings
|
|
BBB (stable outlook)
|
|
|
Borrowing
Capacity
|
|
Expiration
|
|
Outstanding
Letters of Credit
|
||||
Letter of credit facilities
|
|
$
|
500
|
|
|
June 2012
|
|
$
|
300
|
|
U.S. revolving credit facility
|
|
$
|
3,000
|
|
|
December 2016
|
|
$
|
119
|
|
Canadian revolving credit facility
|
|
C$
|
115
|
|
|
December 2012
|
|
C$
|
20
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
Increase in projected benefit obligation resulting from:
|
|
|
|
||||
Discount rate decrease
|
$
|
85
|
|
|
$
|
13
|
|
Compensation rate increase
|
33
|
|
|
—
|
|
||
Health care cost trend rate increase
|
—
|
|
|
5
|
|
||
|
|
|
|
||||
Increase in expense resulting from:
|
|
|
|
||||
Discount rate decrease
|
14
|
|
|
1
|
|
||
Expected return on plan assets decrease
|
4
|
|
|
—
|
|
||
Compensation rate increase
|
8
|
|
|
—
|
|
||
Health care cost trend rate increase
|
—
|
|
|
1
|
|
•
|
inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a last-in, first-out (LIFO) basis) differ from our previous year-end LIFO inventory levels and
|
•
|
forecasted feedstock and refined product purchases, refined product sales, natural gas purchases, and corn purchases to lock in the price of these forecasted transactions at existing market prices that we deem favorable.
|
|
Derivative Instruments Held For
|
||||||
|
Non-Trading Purposes
|
|
Trading
Purposes
|
||||
December 31, 2011
|
|
|
|
||||
Gain (loss) in fair value resulting from:
|
|
|
|
||||
10% increase in underlying commodity prices
|
$
|
(156
|
)
|
|
$
|
1
|
|
10% decrease in underlying commodity prices
|
156
|
|
|
2
|
|
||
|
|
|
|
||||
December 31, 2010
|
|
|
|
||||
Gain (loss) in fair value resulting from:
|
|
|
|
||||
10% increase in underlying commodity prices
|
(199
|
)
|
|
—
|
|
||
10% decrease in underlying commodity prices
|
189
|
|
|
(1
|
)
|
|
December 31, 2011
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
There-
after
|
|
Total
|
|
Fair
Value
|
||||||||||||||||
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed rate
|
$
|
754
|
|
|
$
|
484
|
|
|
$
|
200
|
|
|
$
|
475
|
|
|
$
|
—
|
|
|
$
|
5,578
|
|
|
$
|
7,491
|
|
|
$
|
9,048
|
|
Average interest rate
|
6.9
|
%
|
|
5.5
|
%
|
|
4.8
|
%
|
|
5.2
|
%
|
|
—
|
%
|
|
7.3
|
%
|
|
6.9
|
%
|
|
|
|||||||||
Floating rate
|
$
|
250
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250
|
|
|
$
|
250
|
|
Average interest rate
|
0.6
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
0.6
|
%
|
|
|
|
December 31, 2010
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
There-
after
|
|
Total
|
|
Fair
Value
|
||||||||||||||||
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed rate
|
$
|
418
|
|
|
$
|
759
|
|
|
$
|
489
|
|
|
$
|
209
|
|
|
$
|
484
|
|
|
$
|
5,605
|
|
|
$
|
7,964
|
|
|
$
|
9,092
|
|
Average interest rate
|
6.4
|
%
|
|
6.9
|
%
|
|
5.5
|
%
|
|
4.8
|
%
|
|
5.2
|
%
|
|
7.2
|
%
|
|
6.9
|
%
|
|
|
|||||||||
Floating rate
|
$
|
400
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
400
|
|
|
$
|
400
|
|
Average interest rate
|
0.5
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
0.5
|
%
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Operating revenues (a)
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
64,599
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
115,719
|
|
|
74,458
|
|
|
58,686
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining
|
3,406
|
|
|
2,944
|
|
|
2,880
|
|
|||
Retail
|
678
|
|
|
654
|
|
|
626
|
|
|||
Ethanol
|
399
|
|
|
363
|
|
|
169
|
|
|||
General and administrative expenses
|
571
|
|
|
531
|
|
|
572
|
|
|||
Depreciation and amortization expense
|
1,534
|
|
|
1,405
|
|
|
1,361
|
|
|||
Asset impairment loss
|
—
|
|
|
2
|
|
|
222
|
|
|||
Total costs and expenses
|
122,307
|
|
|
80,357
|
|
|
64,516
|
|
|||
Operating income
|
3,680
|
|
|
1,876
|
|
|
83
|
|
|||
Other income, net
|
43
|
|
|
106
|
|
|
17
|
|
|||
Interest and debt expense, net of capitalized interest
|
(401
|
)
|
|
(484
|
)
|
|
(416
|
)
|
|||
Income (loss) from continuing operations before income tax expense (benefit)
|
3,322
|
|
|
1,498
|
|
|
(316
|
)
|
|||
Income tax expense (benefit)
|
1,226
|
|
|
575
|
|
|
(43
|
)
|
|||
Income (loss) from continuing operations
|
2,096
|
|
|
923
|
|
|
(273
|
)
|
|||
Loss from discontinued operations, net of income taxes
|
(7
|
)
|
|
(599
|
)
|
|
(1,709
|
)
|
|||
Net income (loss)
|
2,089
|
|
|
324
|
|
|
(1,982
|
)
|
|||
Less: Net loss attributable to noncontrolling interests
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Net income (loss) attributable to Valero Energy Corporation stockholders
|
$
|
2,090
|
|
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Valero Energy Corporation stockholders:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
2,097
|
|
|
$
|
923
|
|
|
$
|
(273
|
)
|
Discontinued operations
|
(7
|
)
|
|
(599
|
)
|
|
(1,709
|
)
|
|||
Total
|
$
|
2,090
|
|
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
Earnings per common share:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
3.70
|
|
|
$
|
1.63
|
|
|
$
|
(0.50
|
)
|
Discontinued operations
|
(0.01
|
)
|
|
(1.06
|
)
|
|
(3.17
|
)
|
|||
Total
|
$
|
3.69
|
|
|
$
|
0.57
|
|
|
$
|
(3.67
|
)
|
Weighted-average common shares outstanding (in millions)
|
563
|
|
|
563
|
|
|
541
|
|
|||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
3.69
|
|
|
$
|
1.62
|
|
|
$
|
(0.50
|
)
|
Discontinued operations
|
(0.01
|
)
|
|
(1.05
|
)
|
|
(3.17
|
)
|
|||
Total
|
$
|
3.68
|
|
|
$
|
0.57
|
|
|
$
|
(3.67
|
)
|
Weighted-average common shares outstanding – assuming dilution (in millions)
|
569
|
|
|
568
|
|
|
541
|
|
|||
Dividends per common share
|
$
|
0.30
|
|
|
$
|
0.20
|
|
|
$
|
0.60
|
|
_____________________________
|
|
|
|
|
|
||||||
Supplemental information:
|
|
|
|
|
|
||||||
(a) Includes excise taxes on sales by our U.S. retail system
|
$
|
892
|
|
|
$
|
891
|
|
|
$
|
873
|
|
|
Valero Energy Corporation Stockholders’ Equity
|
|
|
|
|
||||||||||||||||||||||||||
|
Common
Stock
|
|
Additional
Paid-in
Capital
|
|
Treasury
Stock
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total
|
|
Non-controlling
Interest
|
|
Total
Equity
|
||||||||||||||||
Balance as of December 31, 2008
|
$
|
6
|
|
|
$
|
7,190
|
|
|
$
|
(6,884
|
)
|
|
$
|
15,484
|
|
|
$
|
(176
|
)
|
|
$
|
15,620
|
|
|
$
|
—
|
|
|
$
|
15,620
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,982
|
)
|
|
—
|
|
|
(1,982
|
)
|
|
—
|
|
|
(1,982
|
)
|
||||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(324
|
)
|
|
—
|
|
|
(324
|
)
|
|
—
|
|
|
(324
|
)
|
||||||||
Sale of common stock
|
1
|
|
|
798
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
799
|
|
|
—
|
|
|
799
|
|
||||||||
Stock-based compensation expense
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
||||||||
Tax deduction less than stock-based compensation expense
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
||||||||
Transactions in connection with stock-based compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stock issuances
|
—
|
|
|
(156
|
)
|
|
167
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
||||||||
Stock repurchases
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
541
|
|
|
541
|
|
|
—
|
|
|
541
|
|
||||||||
Balance as of December 31, 2009
|
7
|
|
|
7,896
|
|
|
(6,721
|
)
|
|
13,178
|
|
|
365
|
|
|
14,725
|
|
|
—
|
|
|
14,725
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
324
|
|
|
—
|
|
|
324
|
|
|
—
|
|
|
324
|
|
||||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(114
|
)
|
|
—
|
|
|
(114
|
)
|
|
—
|
|
|
(114
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
|
—
|
|
|
54
|
|
||||||||
Tax deduction in excess of stock-based compensation expense
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||||||
Transactions in connection with stock-based compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stock issuances
|
—
|
|
|
(252
|
)
|
|
272
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
20
|
|
||||||||
Stock repurchases
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
23
|
|
|
—
|
|
|
23
|
|
||||||||
Balance as of December 31, 2010
|
7
|
|
|
7,704
|
|
|
(6,462
|
)
|
|
13,388
|
|
|
388
|
|
|
15,025
|
|
|
—
|
|
|
15,025
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
2,090
|
|
|
—
|
|
|
2,090
|
|
|
(1
|
)
|
|
2,089
|
|
||||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(169
|
)
|
|
—
|
|
|
(169
|
)
|
|
—
|
|
|
(169
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
|
—
|
|
|
57
|
|
||||||||
Tax deduction in excess of stock-based compensation expense
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
22
|
|
||||||||
Transactions in connection with stock-based compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stock issuances
|
—
|
|
|
(287
|
)
|
|
336
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|
—
|
|
|
49
|
|
||||||||
Stock repurchases
|
—
|
|
|
(10
|
)
|
|
(349
|
)
|
|
—
|
|
|
—
|
|
|
(359
|
)
|
|
—
|
|
|
(359
|
)
|
||||||||
Contributions from noncontrolling interest in DGD
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
23
|
|
||||||||
Recognition of noncontrolling interests in MLP in connection with Pembroke Acquisition
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||||
Acquisition of noncontrolling interests in MLP
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
(5
|
)
|
||||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(292
|
)
|
|
(292
|
)
|
|
—
|
|
|
(292
|
)
|
||||||||
Balance as of December 31, 2011
|
$
|
7
|
|
|
$
|
7,486
|
|
|
$
|
(6,475
|
)
|
|
$
|
15,309
|
|
|
$
|
96
|
|
|
$
|
16,423
|
|
|
$
|
22
|
|
|
$
|
16,445
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
2,089
|
|
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
1,534
|
|
|
1,473
|
|
|
1,527
|
|
|||
Asset impairment loss
|
—
|
|
|
2
|
|
|
607
|
|
|||
Loss on shutdown and sales of refinery assets, net
|
12
|
|
|
888
|
|
|
1,868
|
|
|||
Gain on sale of investment in Cameron Highway Oil Pipeline Company
|
—
|
|
|
(55
|
)
|
|
—
|
|
|||
Stock-based compensation expense
|
58
|
|
|
54
|
|
|
66
|
|
|||
Deferred income tax expense (benefit)
|
461
|
|
|
347
|
|
|
(343
|
)
|
|||
Changes in current assets and current liabilities
|
81
|
|
|
68
|
|
|
255
|
|
|||
Changes in deferred charges and credits and other operating activities, net
|
(197
|
)
|
|
(56
|
)
|
|
(175
|
)
|
|||
Net cash provided by operating activities
|
4,038
|
|
|
3,045
|
|
|
1,823
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(2,355
|
)
|
|
(1,730
|
)
|
|
(2,306
|
)
|
|||
Deferred turnaround and catalyst costs
|
(629
|
)
|
|
(535
|
)
|
|
(415
|
)
|
|||
Acquisition of Pembroke Refinery, net of cash acquired
|
(1,691
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisition of Meraux Refinery
|
(547
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisitions of ethanol plants
|
—
|
|
|
(260
|
)
|
|
(577
|
)
|
|||
Minor acquisitions
|
(37
|
)
|
|
—
|
|
|
(29
|
)
|
|||
Proceeds from the sale of the Paulsboro Refinery
|
—
|
|
|
547
|
|
|
—
|
|
|||
Proceeds from the sale of the Delaware City Refinery assets and
associated terminal and pipeline assets
|
—
|
|
|
220
|
|
|
—
|
|
|||
Proceeds from the sale of investment in Cameron Highway Oil Pipeline Company
|
—
|
|
|
330
|
|
|
—
|
|
|||
Other investing activities, net
|
(39
|
)
|
|
23
|
|
|
35
|
|
|||
Net cash used in investing activities
|
(5,298
|
)
|
|
(1,405
|
)
|
|
(3,292
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Non-bank debt:
|
|
|
|
|
|
||||||
Borrowings
|
—
|
|
|
1,544
|
|
|
998
|
|
|||
Repayments
|
(774
|
)
|
|
(517
|
)
|
|
(285
|
)
|
|||
Bank credit agreements:
|
|
|
|
|
|
||||||
Borrowings
|
—
|
|
|
—
|
|
|
39
|
|
|||
Repayments
|
(4
|
)
|
|
—
|
|
|
(39
|
)
|
|||
Accounts receivable sales facility:
|
|
|
|
|
|
||||||
Proceeds from the sale of receivables
|
150
|
|
|
1,225
|
|
|
950
|
|
|||
Repayments
|
—
|
|
|
(1,325
|
)
|
|
(850
|
)
|
|||
Proceeds from the sale of common stock, net of issuance costs
|
—
|
|
|
—
|
|
|
799
|
|
|||
Proceeds from the exercise of stock options
|
49
|
|
|
20
|
|
|
11
|
|
|||
Purchase of common stock for treasury
|
(349
|
)
|
|
(13
|
)
|
|
(4
|
)
|
|||
Common stock dividends
|
(169
|
)
|
|
(114
|
)
|
|
(324
|
)
|
|||
Contributions from noncontrolling interests
|
22
|
|
|
—
|
|
|
—
|
|
|||
Other financing activities, net
|
9
|
|
|
(4
|
)
|
|
(6
|
)
|
|||
Net cash provided by (used in) financing activities
|
(1,066
|
)
|
|
816
|
|
|
1,289
|
|
|||
Effect of foreign exchange rate changes on cash
|
16
|
|
|
53
|
|
|
65
|
|
|||
Net increase (decrease) in cash and temporary cash investments
|
(2,310
|
)
|
|
2,509
|
|
|
(115
|
)
|
|||
Cash and temporary cash investments at beginning of year
|
3,334
|
|
|
825
|
|
|
940
|
|
|||
Cash and temporary cash investments at end of year
|
$
|
1,024
|
|
|
$
|
3,334
|
|
|
$
|
825
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Net income (loss)
|
$
|
2,089
|
|
|
$
|
324
|
|
|
$
|
(1,982
|
)
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|||||
Foreign currency translation adjustment,
net of income tax expense of $ - , $ - , and $ - |
(122
|
)
|
|
158
|
|
|
375
|
|
|||
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Net gain (loss) arising during the year,
net of income tax (expense) benefit of $101, $5, and $(132) |
(188
|
)
|
|
(14
|
)
|
|
219
|
|
|||
Net (gain) loss reclassified into income,
net of income tax expense (benefit) of $2, $3, and $(2) |
(1
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|||
Net gain (loss) on pension
and other postretirement benefits
|
(189
|
)
|
|
(18
|
)
|
|
218
|
|
|||
Derivative instruments designated
and qualifying as cash flow hedges:
|
|
|
|
|
|
||||||
Net gain (loss) arising during the year,
net of income tax (expense) benefit of $(11), $1, and $(44) |
21
|
|
|
(1
|
)
|
|
81
|
|
|||
Net (gain) loss reclassified into income,
net of income tax expense (benefit) of $1, $62, and $72 |
(2
|
)
|
|
(116
|
)
|
|
(133
|
)
|
|||
Net gain (loss) on cash flow hedges
|
19
|
|
|
(117
|
)
|
|
(52
|
)
|
|||
Other comprehensive income (loss)
|
(292
|
)
|
|
23
|
|
|
541
|
|
|||
Comprehensive income (loss)
|
1,797
|
|
|
347
|
|
|
(1,441
|
)
|
|||
Less: Comprehensive loss attributable to noncontrolling interests
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Comprehensive income (loss) attributable to
Valero Energy Corporation stockholders
|
$
|
1,798
|
|
|
$
|
347
|
|
|
$
|
(1,441
|
)
|
1.
|
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
•
|
company-specific factors, primarily refinery utilization rates and refinery maintenance turnarounds;
|
•
|
seasonal factors, such as the demand for refined products during the summer driving season and heating oil during the winter season; and
|
•
|
industry factors, such as movements in and the level of crude oil prices including the effect of quality differentials between grades of crude oil, the demand for and prices of refined products, industry supply capacity, and competitor refinery maintenance turnarounds.
|
•
|
turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries and ethanol plants and which are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs;
|
•
|
fixed-bed catalyst costs, representing the cost of catalyst that is changed out at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function, which are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst;
|
•
|
investments in entities that we do not control; and
|
•
|
other noncurrent assets such as convenience store dealer incentive programs, investments of certain benefit plans, debt issuance costs, and various other costs.
|
2.
|
ACQUISITIONS
|
Inventories
|
$
|
219
|
|
Property, plant and equipment
|
320
|
|
|
Deferred charges and other assets, net
|
9
|
|
|
Other long-term liabilities
|
(1
|
)
|
|
Purchase price
|
$
|
547
|
|
Current assets, net of cash acquired
|
$
|
2,214
|
|
Property, plant and equipment
|
804
|
|
|
Deferred charges and other assets, net
|
32
|
|
|
Intangible assets
|
23
|
|
|
Current liabilities, less current portion of debt
and capital lease obligations
|
(1,287
|
)
|
|
Debt and capital leases assumed, including current portion
|
(12
|
)
|
|
Other long-term liabilities
|
(78
|
)
|
|
Noncontrolling interests
|
(5
|
)
|
|
Purchase price, net of cash acquired
|
$
|
1,691
|
|
|
Meraux Acquisition
|
|
Pembroke Acquisition
|
||||
Operating revenues
|
$
|
1,343
|
|
|
$
|
7,522
|
|
Loss from continuing operations
|
(74
|
)
|
|
(10
|
)
|
||
Acquisition-related costs (included in general and administrative expenses)
|
2
|
|
|
27
|
|
|
Year Ended December 31,
|
||||||
|
2011
|
|
2010
|
||||
Operating revenues
|
$
|
142,109
|
|
|
$
|
99,824
|
|
Income from continuing operations
attributable to Valero stockholders
|
2,071
|
|
|
953
|
|
||
Earnings per common share from
continuing operations – basic
|
3.66
|
|
|
1.68
|
|
||
Earnings per common share from
continuing operations – assuming dilution
|
3.64
|
|
|
1.68
|
|
3.
|
SALES OF ASSETS
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Operating revenues
|
$
|
—
|
|
|
$
|
4,692
|
|
|
$
|
3,545
|
|
Loss before income taxes
|
(9
|
)
|
|
(53
|
)
|
|
(133
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,764
|
|
Loss before income taxes
|
(3
|
)
|
|
(29
|
)
|
|
(769
|
)
|
4.
|
IMPAIRMENT ANALYSIS
|
5.
|
RECEIVABLES
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Accounts receivable
|
$
|
8,366
|
|
|
$
|
4,299
|
|
Commodity derivative receivables
|
174
|
|
|
144
|
|
||
Notes receivable and other
|
214
|
|
|
182
|
|
||
|
8,754
|
|
|
4,625
|
|
||
Allowance for doubtful accounts
|
(48
|
)
|
|
(42
|
)
|
||
Receivables, net
|
$
|
8,706
|
|
|
$
|
4,583
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Balance as of beginning of year
|
$
|
42
|
|
|
$
|
45
|
|
|
$
|
58
|
|
Increase in allowance charged to expense
|
21
|
|
|
14
|
|
|
28
|
|
|||
Accounts charged against the allowance,
net of recoveries
|
(14
|
)
|
|
(17
|
)
|
|
(42
|
)
|
|||
Foreign currency translation
|
(1
|
)
|
|
—
|
|
|
1
|
|
|||
Balance as of end of year
|
$
|
48
|
|
|
$
|
42
|
|
|
$
|
45
|
|
6.
|
INVENTORIES
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Refinery feedstocks
|
$
|
2,474
|
|
|
$
|
2,225
|
|
Refined products and blendstocks
|
2,633
|
|
|
2,233
|
|
||
Ethanol feedstocks and products
|
195
|
|
|
201
|
|
||
Convenience store merchandise
|
103
|
|
|
101
|
|
||
Materials and supplies
|
218
|
|
|
187
|
|
||
Inventories
|
$
|
5,623
|
|
|
$
|
4,947
|
|
7.
|
PROPERTY, PLANT AND EQUIPMENT
|
|
|
December 31,
|
||||||
|
|
2011
|
|
2010
|
||||
Land
|
|
$
|
722
|
|
|
$
|
624
|
|
Crude oil processing facilities
|
|
23,322
|
|
|
21,421
|
|
||
Pipeline and terminal facilities
|
|
856
|
|
|
709
|
|
||
Grain processing equipment
|
|
673
|
|
|
656
|
|
||
Retail facilities
|
|
1,346
|
|
|
1,277
|
|
||
Administrative buildings
|
|
712
|
|
|
705
|
|
||
Other
|
|
1,290
|
|
|
1,226
|
|
||
Construction in progress
|
|
3,332
|
|
|
2,303
|
|
||
Property, plant and equipment, at cost
|
|
32,253
|
|
|
28,921
|
|
||
Accumulated depreciation
|
|
(7,076
|
)
|
|
(6,252
|
)
|
||
Property, plant and equipment, net
|
|
$
|
25,177
|
|
|
$
|
22,669
|
|
8.
|
INTANGIBLE ASSETS
|
9.
|
DEFERRED CHARGES AND OTHER ASSETS
|
10.
|
ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES
|
|
Accrued Expenses
|
|
Other Long-Term Liabilities
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Defined benefit plan liabilities (see Note 14)
|
$
|
37
|
|
|
$
|
54
|
|
|
$
|
796
|
|
|
$
|
636
|
|
Wage and other employee-related liabilities
|
259
|
|
|
172
|
|
|
79
|
|
|
85
|
|
||||
Uncertain income tax position liabilities (see Note 16)
|
—
|
|
|
—
|
|
|
337
|
|
|
343
|
|
||||
Other tax liabilities
|
—
|
|
|
—
|
|
|
103
|
|
|
106
|
|
||||
Environmental liabilities
|
39
|
|
|
40
|
|
|
235
|
|
|
228
|
|
||||
Accrued interest expense
|
108
|
|
|
116
|
|
|
—
|
|
|
—
|
|
||||
Derivative liabilities
|
25
|
|
|
39
|
|
|
—
|
|
|
—
|
|
||||
Insurance liabilities
|
13
|
|
|
13
|
|
|
79
|
|
|
80
|
|
||||
Asset retirement obligations
|
6
|
|
|
20
|
|
|
81
|
|
|
81
|
|
||||
Other
|
108
|
|
|
136
|
|
|
171
|
|
|
208
|
|
||||
Accrued expenses and other long-term liabilities
|
$
|
595
|
|
|
$
|
590
|
|
|
$
|
1,881
|
|
|
$
|
1,767
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Balance as of beginning of year
|
$
|
268
|
|
|
$
|
279
|
|
|
$
|
297
|
|
Pembroke Acquisition
|
30
|
|
|
—
|
|
|
—
|
|
|||
Additions to liability
|
18
|
|
|
50
|
|
|
21
|
|
|||
Reductions to liability
|
(5
|
)
|
|
(21
|
)
|
|
(5
|
)
|
|||
Payments, net of third-party recoveries
|
(35
|
)
|
|
(42
|
)
|
|
(40
|
)
|
|||
Foreign currency translation
|
(2
|
)
|
|
2
|
|
|
6
|
|
|||
Balance as of end of year
|
$
|
274
|
|
|
$
|
268
|
|
|
$
|
279
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Balance as of beginning of year
|
$
|
101
|
|
|
$
|
179
|
|
|
$
|
72
|
|
Additions to accrual
|
4
|
|
|
3
|
|
|
98
|
|
|||
Reductions to accrual
|
—
|
|
|
(34
|
)
|
|
—
|
|
|||
Accretion expense
|
4
|
|
|
7
|
|
|
14
|
|
|||
Settlements
|
(22
|
)
|
|
(54
|
)
|
|
(5
|
)
|
|||
Balance as of end of year
|
$
|
87
|
|
|
$
|
101
|
|
|
$
|
179
|
|
11.
|
DEBT AND CAPITAL LEASE OBLIGATIONS
|
|
Final
Maturity
|
|
December 31,
|
||||||
|
|
2011
|
|
2010
|
|||||
Bank credit facilities
|
Various
|
|
$
|
—
|
|
|
$
|
—
|
|
Industrial revenue bonds:
|
|
|
|
|
|
||||
Tax-exempt Revenue Refunding Bonds:
|
|
|
|
|
|
||||
Series 1997A, 5.45%
|
2027
|
|
18
|
|
|
21
|
|
||
Series 1997B, 5.4%
|
2018
|
|
—
|
|
|
30
|
|
||
Series 1997C, 5.4%
|
2018
|
|
—
|
|
|
30
|
|
||
Tax-exempt Waste Disposal Revenue Bonds:
|
|
|
|
|
|
||||
Series 1997, 5.6%
|
2031
|
|
25
|
|
|
25
|
|
||
Series 1998, 5.6%
|
2032
|
|
25
|
|
|
25
|
|
||
Series 1999, 5.7%
|
2032
|
|
25
|
|
|
25
|
|
||
Series 2001, 6.65%
|
2032
|
|
19
|
|
|
19
|
|
||
4.5% notes
|
2015
|
|
400
|
|
|
400
|
|
||
4.75% notes
|
2013
|
|
300
|
|
|
300
|
|
||
4.75% notes
|
2014
|
|
200
|
|
|
200
|
|
||
6.125% notes
|
2017
|
|
750
|
|
|
750
|
|
||
6.125% notes
|
2020
|
|
850
|
|
|
850
|
|
||
6.625% notes
|
2037
|
|
1,500
|
|
|
1,500
|
|
||
6.875% notes
|
2012
|
|
750
|
|
|
750
|
|
||
7.5% notes
|
2032
|
|
750
|
|
|
750
|
|
||
8.75% notes
|
2030
|
|
200
|
|
|
200
|
|
||
Debentures:
|
|
|
|
|
|
||||
7.65%
|
2026
|
|
100
|
|
|
100
|
|
||
8.75%
|
2015
|
|
75
|
|
|
75
|
|
||
Senior Notes:
|
|
|
|
|
|
||||
6.125%
|
2011
|
|
—
|
|
|
200
|
|
||
6.7%
|
2013
|
|
180
|
|
|
180
|
|
||
6.75%
|
2011
|
|
—
|
|
|
210
|
|
||
6.75%
|
2037
|
|
24
|
|
|
24
|
|
||
7.2%
|
2017
|
|
200
|
|
|
200
|
|
||
7.45%
|
2097
|
|
100
|
|
|
100
|
|
||
9.375%
|
2019
|
|
750
|
|
|
750
|
|
||
10.5%
|
2039
|
|
250
|
|
|
250
|
|
||
Gulf Opportunity Zone Revenue Bonds, Series 2010, variable rate
|
2040
|
|
—
|
|
|
300
|
|
||
Accounts receivable sales facility
|
2012
|
|
250
|
|
|
100
|
|
||
Net unamortized discount, including fair value adjustments
|
|
|
(51
|
)
|
|
(64
|
)
|
||
Total debt
|
|
|
7,690
|
|
|
8,300
|
|
||
Capital lease obligations, including unamortized fair value adjustments
|
|
51
|
|
|
37
|
|
|||
Total debt and capital lease obligations
|
|
|
7,741
|
|
|
8,337
|
|
||
Less current portion
|
|
|
(1,009
|
)
|
|
(822
|
)
|
||
Debt and capital lease obligations, less current portion
|
|
|
$
|
6,732
|
|
|
$
|
7,515
|
|
|
|
|
|
|
|
Amounts Outstanding
|
||||||||
|
|
Borrowing Capacity
|
|
Expiration
|
|
December 31,
2011
|
|
December 31,
2010
|
||||||
Letter of credit facilities
|
|
$
|
500
|
|
|
June 2012
|
|
$
|
300
|
|
|
$
|
100
|
|
Revolver
|
|
$
|
3,000
|
|
|
December 2016
|
|
$
|
119
|
|
|
$
|
399
|
|
Canadian revolving credit facility
|
|
C$
|
115
|
|
|
December 2012
|
|
C$
|
20
|
|
|
C$
|
20
|
|
•
|
in December 2011, we redeemed our Series 1997B
5.4%
and Series 1997C
5.4%
industrial revenue bonds for
$56 million
, or
100%
of their stated values;
|
•
|
in May 2011, we made a scheduled debt repayment of
$200 million
related to our
6.125%
senior notes;
|
•
|
in April 2011, we made scheduled debt repayments of
$8 million
related to our Series 1997A
5.45%
, Series 1997B
5.4%
, and Series 1997C
5.4%
industrial revenue bonds;
|
•
|
in February 2011, we made a scheduled debt repayment of
$210 million
related to our
6.75%
senior
|
•
|
in February 2011, we paid
$300 million
to acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), which were subject to mandatory tender. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us.
|
•
|
in December 2010, the Parish of St. Charles, State of Louisiana (Issuer) issued GO Zone Bonds totaling
$300 million
, with a maturity date of
December 1, 2040
. The GO Zone Bonds initially bore interest at a weekly rate with interest payable monthly, commencing January 5, 2011. Pursuant to a financing agreement, the Issuer lent the proceeds of the sale of the GO Zone Bonds to us to finance a portion of the construction costs of a hydrocracker project at our St. Charles Refinery. We received proceeds of
$300 million
. Under the financing agreement, we were obligated to pay the Issuer amounts sufficient for the Issuer to pay principal and interest on the GO Zone Bonds;
|
•
|
in June 2010, we made a scheduled debt repayment of
$25 million
related to our
7.25%
debentures;
|
•
|
in May 2010, we redeemed our
6.75%
senior notes with a maturity date of
May 1, 2014
for
$190 million
, or
102.25%
of stated value;
|
•
|
in April 2010, we made scheduled debt repayments of
$8 million
related to our Series 1997A
5.45%
, Series 1997B
5.4%
, and Series 1997C
5.4%
industrial revenue bonds;
|
•
|
in March 2010, we redeemed our
7.5%
senior notes with a maturity date of
June 15, 2015
for
$294 million
, or
102.5%
of stated value, and
|
•
|
in February 2010, we issued
$400 million
of
4.5%
notes due
February 1, 2015
and
$850 million
of
6.125%
notes due in
February 1, 2020
for total net proceeds of
$1.2 billion
.
|
•
|
in October 2009, we redeemed
$76 million
of our
6.75%
senior notes with a maturity date of
October 15, 2037
at
100%
of stated value;
|
•
|
in April 2009, we made scheduled debt repayments of
$200 million
related to our
3.5%
notes and
$9 million
related to our
5.125%
Series 1997D industrial revenue bonds; and
|
•
|
in March 2009, we issued
$750 million
of
9.375%
notes due
March 15, 2019
and
$250 million
of
10.5%
notes due
March 15, 2039
. Proceeds from the issuance of these notes totaled
$998 million
.
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Balance as of beginning of year
|
$
|
100
|
|
|
$
|
200
|
|
|
$
|
100
|
|
Proceeds from the sale of receivables
|
150
|
|
|
1,225
|
|
|
950
|
|
|||
Repayments
|
—
|
|
|
(1,325
|
)
|
|
(850
|
)
|
|||
Balance as of end of year
|
$
|
250
|
|
|
$
|
100
|
|
|
$
|
200
|
|
|
Debt
|
|
Capital
Lease
Obligations
|
||||
2012
|
$
|
1,004
|
|
|
$
|
11
|
|
2013
|
484
|
|
|
10
|
|
||
2014
|
200
|
|
|
9
|
|
||
2015
|
475
|
|
|
8
|
|
||
2016
|
—
|
|
|
8
|
|
||
Thereafter
|
5,578
|
|
|
37
|
|
||
Net unamortized discount
and fair value adjustments
|
(51
|
)
|
|
—
|
|
||
Less interest expense
|
—
|
|
|
(32
|
)
|
||
Total
|
$
|
7,690
|
|
|
$
|
51
|
|
12.
|
COMMITMENTS AND CONTINGENCIES
|
2012
|
$
|
291
|
|
2013
|
198
|
|
|
2014
|
131
|
|
|
2015
|
106
|
|
|
2016
|
86
|
|
|
Thereafter
|
294
|
|
|
Total minimum rental payments
|
1,106
|
|
|
Less minimum rentals to be received under subleases
|
(41
|
)
|
|
Net minimum rental payments
|
$
|
1,065
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Minimum rental expense
|
$
|
523
|
|
|
$
|
485
|
|
|
$
|
519
|
|
Contingent rental expense
|
23
|
|
|
23
|
|
|
21
|
|
|||
Total rental expense
|
546
|
|
|
508
|
|
|
540
|
|
|||
Less sublease rental income
|
(2
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||
Net rental expense
|
$
|
544
|
|
|
$
|
505
|
|
|
$
|
536
|
|
•
|
The LCFS was scheduled to become effective in 2011, but recent rulings by the U.S. District Court have stayed enforcement of the LCFS until certain legal challenges to the LCFS have been resolved. Most notably, the court determined that the LCFS violates the Commerce Clause of the U.S. Constitution to the extent that the standard discriminates against out-of-state crude oils and corn ethanol. CARB has appealed the lower court’s ruling to the U.S. Court of Appeals for the Ninth Circuit.
|
▪
|
As initially designed, the LCFS called for initially small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity were thereafter scheduled to increase through 2020, after which another step-change in reductions is anticipated.
|
▪
|
CARB designed the LCFS to encourage substitution of traditional petroleum fuels, and, over time, lead to greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels.
|
•
|
A California statewide cap-and-trade program will begin in 2013. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas
|
•
|
Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.
|
13.
|
EQUITY
|
|
Common Stock
|
|
Treasury
Stock
|
||
Balance as of December 31, 2008
|
627
|
|
|
(111
|
)
|
Sale of common stock
|
46
|
|
|
—
|
|
Transactions in connection with
stock-based compensation plans:
|
|
|
|
||
Stock issuances
|
—
|
|
|
2
|
|
Balance as of December 31, 2009
|
673
|
|
|
(109
|
)
|
Transactions in connection with
stock-based compensation plans:
|
|
|
|
||
Stock issuances
|
—
|
|
|
5
|
|
Stock repurchases
|
—
|
|
|
(1
|
)
|
Balance as of December 31, 2010
|
673
|
|
|
(105
|
)
|
Transactions in connection with
stock-based compensation plans:
|
|
|
|
||
Stock issuances
|
—
|
|
|
5
|
|
Stock repurchases
|
—
|
|
|
(17
|
)
|
Balance as of December 31, 2011
|
673
|
|
|
(117
|
)
|
|
Foreign
Currency
Translation
Adjustment
|
|
Pension/
OPEB
Liability
Adjustment
|
|
Net Gain (Loss) On Cash Flow Hedges
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
||||||||
Balance as of December 31, 2008
|
$
|
90
|
|
|
$
|
(435
|
)
|
|
$
|
169
|
|
|
$
|
(176
|
)
|
Other comprehensive income (loss)
|
375
|
|
|
218
|
|
|
(52
|
)
|
|
541
|
|
||||
Balance as of December 31, 2009
|
465
|
|
|
(217
|
)
|
|
117
|
|
|
365
|
|
||||
Other comprehensive income (loss)
|
158
|
|
|
(18
|
)
|
|
(117
|
)
|
|
23
|
|
||||
Balance as of December 31, 2010
|
623
|
|
|
(235
|
)
|
|
—
|
|
|
388
|
|
||||
Other comprehensive income (loss)
|
(122
|
)
|
|
(189
|
)
|
|
19
|
|
|
(292
|
)
|
||||
Balance as of December 31, 2011
|
$
|
501
|
|
|
$
|
(424
|
)
|
|
$
|
19
|
|
|
$
|
96
|
|
14.
|
EMPLOYEE BENEFIT PLANS
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
$
|
1,626
|
|
|
$
|
1,454
|
|
|
$
|
426
|
|
|
$
|
466
|
|
Service cost
|
104
|
|
|
88
|
|
|
11
|
|
|
10
|
|
||||
Interest cost
|
85
|
|
|
83
|
|
|
22
|
|
|
26
|
|
||||
Acquisitions
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||
Plan amendments
|
4
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
||||
Special termination benefits
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
||||
Medicare subsidy for prescription drugs
|
—
|
|
|
—
|
|
|
3
|
|
|
1
|
|
||||
Benefits paid
|
(117
|
)
|
|
(109
|
)
|
|
(30
|
)
|
|
(31
|
)
|
||||
Actuarial (gain) loss
|
179
|
|
|
106
|
|
|
(9
|
)
|
|
(28
|
)
|
||||
Foreign currency exchange rate changes
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
||||
Benefit obligation at end of year
|
$
|
1,881
|
|
|
$
|
1,626
|
|
|
$
|
438
|
|
|
$
|
426
|
|
|
|
|
|
|
|
|
|
||||||||
Change in plan assets:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
$
|
1,362
|
|
|
$
|
1,251
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
(2
|
)
|
|
149
|
|
|
—
|
|
|
—
|
|
||||
Valero contributions
|
244
|
|
|
71
|
|
|
15
|
|
|
18
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||
Medicare subsidy for prescription drugs
|
—
|
|
|
—
|
|
|
3
|
|
|
1
|
|
||||
Benefits paid
|
(117
|
)
|
|
(109
|
)
|
|
(30
|
)
|
|
(31
|
)
|
||||
Fair value of plan assets at end of year
|
$
|
1,487
|
|
|
$
|
1,362
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Reconciliation of funded status:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at end of year
|
$
|
1,487
|
|
|
$
|
1,362
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Less benefit obligation at end of year
|
1,881
|
|
|
1,626
|
|
|
438
|
|
|
426
|
|
||||
Funded status at end of year
|
$
|
(394
|
)
|
|
$
|
(264
|
)
|
|
$
|
(438
|
)
|
|
$
|
(426
|
)
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Projected benefit obligation
|
$
|
244
|
|
|
$
|
231
|
|
Accumulated benefit obligation
|
189
|
|
|
192
|
|
||
Fair value of plan assets
|
40
|
|
|
44
|
|
|
Pension
Benefits
|
|
Other Postretirement Benefits
|
|
Medicare Subsidy
|
||||||
2012
|
$
|
84
|
|
|
$
|
23
|
|
|
$
|
(2
|
)
|
2013
|
99
|
|
|
24
|
|
|
n/a
|
|
|||
2014
|
101
|
|
|
26
|
|
|
n/a
|
|
|||
2015
|
107
|
|
|
28
|
|
|
n/a
|
|
|||
2016
|
117
|
|
|
29
|
|
|
n/a
|
|
|||
2017-2021
|
766
|
|
|
159
|
|
|
n/a
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011
|
|
2010
|
|
2009
|
||||||||||||
Components of net periodic
benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
104
|
|
|
$
|
88
|
|
|
$
|
104
|
|
|
$
|
11
|
|
|
$
|
10
|
|
|
$
|
12
|
|
Interest cost
|
85
|
|
|
83
|
|
|
79
|
|
|
22
|
|
|
26
|
|
|
25
|
|
||||||
Expected return on plan assets
|
(112
|
)
|
|
(112
|
)
|
|
(108
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Prior service cost (credit)
|
2
|
|
|
3
|
|
|
3
|
|
|
(23
|
)
|
|
(20
|
)
|
|
(19
|
)
|
||||||
Net loss
|
12
|
|
|
2
|
|
|
10
|
|
|
2
|
|
|
4
|
|
|
6
|
|
||||||
Net periodic benefit cost before special charges
|
91
|
|
|
64
|
|
|
88
|
|
|
12
|
|
|
20
|
|
|
24
|
|
||||||
Special charges
|
4
|
|
|
8
|
|
|
7
|
|
|
4
|
|
|
—
|
|
|
1
|
|
||||||
Net periodic benefit cost
|
$
|
95
|
|
|
$
|
72
|
|
|
$
|
95
|
|
|
$
|
16
|
|
|
$
|
20
|
|
|
$
|
25
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011
|
|
2010
|
|
2009
|
||||||||||||
Net loss (gain) arising during
the year:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
294
|
|
|
$
|
68
|
|
|
$
|
(273
|
)
|
|
$
|
(9
|
)
|
|
$
|
(28
|
)
|
|
$
|
(27
|
)
|
Prior service credit
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|
(51
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net gain (loss) reclassified into income:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss
|
(12
|
)
|
|
(2
|
)
|
|
(10
|
)
|
|
(2
|
)
|
|
(4
|
)
|
|
(6
|
)
|
||||||
Prior service (cost) credit
|
(2
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
23
|
|
|
20
|
|
|
19
|
|
||||||
Curtailment and settlement
|
(4
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total changes in other
comprehensive (income) loss
|
$
|
280
|
|
|
$
|
59
|
|
|
$
|
(287
|
)
|
|
$
|
12
|
|
|
$
|
(43
|
)
|
|
$
|
(65
|
)
|
|
Pension Plans
|
|
Other Postretirement Benefit Plans
|
||||||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||||||
Prior service cost (credit)
|
$
|
16
|
|
|
$
|
14
|
|
|
$
|
(103
|
)
|
|
$
|
(126
|
)
|
Net actuarial loss
|
681
|
|
|
403
|
|
|
50
|
|
|
61
|
|
||||
Total
|
$
|
697
|
|
|
$
|
417
|
|
|
$
|
(53
|
)
|
|
$
|
(65
|
)
|
|
Pension Plans
|
|
Other
Postretirement
Benefit Plans
|
||||
Amortization of prior service cost (credit)
|
$
|
3
|
|
|
$
|
(23
|
)
|
Amortization of net actuarial loss
|
33
|
|
|
1
|
|
||
Total
|
$
|
36
|
|
|
$
|
(22
|
)
|
|
Pension Plans
|
|
Other
Postretirement
Benefit Plans
|
||||||||
|
2011
|
|
2010
|
|
2011
|
|
2010
|
||||
Discount rate
|
5.08
|
%
|
|
5.40
|
%
|
|
4.97
|
%
|
|
5.22
|
%
|
Rate of compensation increase
|
3.68
|
%
|
|
3.56
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011
|
|
2010
|
|
2009
|
||||||
Discount rate
|
5.40
|
%
|
|
5.80
|
%
|
|
5.40
|
%
|
|
5.22
|
%
|
|
5.68
|
%
|
|
5.39
|
%
|
Expected long-term rate of return on plan assets
|
7.69
|
%
|
|
7.71
|
%
|
|
7.72
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Rate of compensation increase
|
3.56
|
%
|
|
4.18
|
%
|
|
4.18
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
2011
|
|
2010
|
||
Health care cost trend rate assumed for the next year
|
7.43
|
%
|
|
7.46
|
%
|
Rate to which the cost trend rate was assumed to decline
(the ultimate trend rate)
|
5.00
|
%
|
|
5.00
|
%
|
Year that the rate reaches the ultimate trend rate
|
2018
|
|
|
2018
|
|
|
1% Increase
|
|
1% Decrease
|
||||
Effect on total of service and interest cost components
|
$
|
1
|
|
|
$
|
(1
|
)
|
Effect on accumulated postretirement benefit obligation
|
18
|
|
|
(16
|
)
|
|
Fair Value Measurements Using
|
|
|
||||||||||||
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total as of
December 31, 2011 |
||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
Valero Energy Corporation
common stock
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
Other U.S. companies (a)
|
375
|
|
|
—
|
|
|
—
|
|
|
375
|
|
||||
International companies
|
120
|
|
|
—
|
|
|
—
|
|
|
120
|
|
||||
Preferred stock
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
102
|
|
|
—
|
|
|
—
|
|
|
102
|
|
||||
Index funds (b)
|
63
|
|
|
—
|
|
|
—
|
|
|
63
|
|
||||
Corporate debt instruments
|
246
|
|
|
—
|
|
|
—
|
|
|
246
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
67
|
|
|
—
|
|
|
—
|
|
|
67
|
|
||||
Mortgage-backed securities
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Other government
securities
|
81
|
|
|
—
|
|
|
—
|
|
|
81
|
|
||||
Common collective trusts
|
—
|
|
|
247
|
|
|
—
|
|
|
247
|
|
||||
Insurance contracts
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||
Interest and dividends
receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
154
|
|
|
—
|
|
|
—
|
|
|
154
|
|
||||
Total
|
$
|
1,223
|
|
|
$
|
264
|
|
|
$
|
—
|
|
|
$
|
1,487
|
|
|
Fair Value Measurements Using
|
|
|
||||||||||||
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total as of
December 31, 2010 |
||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
Valero Energy Corporation
common stock
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
Other U.S. companies (a)
|
369
|
|
|
—
|
|
|
—
|
|
|
369
|
|
||||
International companies
|
107
|
|
|
—
|
|
|
—
|
|
|
107
|
|
||||
Preferred stock
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
117
|
|
|
—
|
|
|
—
|
|
|
117
|
|
||||
Index funds (b)
|
64
|
|
|
—
|
|
|
—
|
|
|
64
|
|
||||
Corporate debt instruments
|
274
|
|
|
—
|
|
|
—
|
|
|
274
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
30
|
|
|
—
|
|
|
—
|
|
|
30
|
|
||||
Mortgage-backed securities
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Other government
securities
|
93
|
|
|
—
|
|
|
—
|
|
|
93
|
|
||||
Common collective trusts
|
—
|
|
|
231
|
|
|
—
|
|
|
231
|
|
||||
Insurance contracts
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
||||
Interest and dividends
receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
||||
Total
|
$
|
1,113
|
|
|
$
|
249
|
|
|
$
|
—
|
|
|
$
|
1,362
|
|
(a)
|
Equity securities are held in a wide range of industrial sectors, including consumer goods, information technology, healthcare, industrials, and financial services.
|
(b)
|
This class include primarily investments in approximately
60 percent
equities and
40 percent
bonds.
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Valero Energy Corporation Thrift Plan
|
$
|
35
|
|
|
$
|
36
|
|
|
$
|
37
|
|
Valero Savings Plan
|
8
|
|
|
6
|
|
|
5
|
|
|||
Premcor Retirement Savings Plan
|
5
|
|
|
5
|
|
|
6
|
|
|||
Ultramar Ltd. Savings Plan
|
10
|
|
|
9
|
|
|
8
|
|
|||
Valero Refining Company – Aruba N.V.
Thrift Plan
|
1
|
|
|
1
|
|
|
1
|
|
15.
|
STOCK-BASED COMPENSATION
|
•
|
The 2011 Omnibus Stock Incentive Plan (the OSIP) authorizes the grant of various stock and stock-based awards to our employees and our non-employee directors. Awards available under the OSIP include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock that vests over a period determined by our compensation committee. The OSIP was approved by our stockholders on April 28, 2011. As of
December 31, 2011
,
18,498,630
shares of our common stock remained available to be awarded under the OSIP.
|
•
|
Prior to the approval of the OSIP by our stockholders, most of the equity awards granted to our employees and non-employee directors were made under our 2005 Omnibus Stock Incentive Plan. Prior awards granted under this plan included options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, and restricted stock that vests over a period determined by our compensation committee.
No
additional grants may be awarded under this plan.
|
•
|
The Restricted Stock Plan for Non-Employee Directors authorizes an annual grant of our common stock valued at
$160,000
to each non-employee director. Vesting generally will occur based on the number of grants received as follows: (i) initial grants will vest in
three
equal annual installments, (ii) second grants will vest
one-third
on the first anniversary of the grant date and the remaining
two-thirds
on the second anniversary of the grant date, and (iii) all grants thereafter will vest
100 percent
on the first anniversary of the grant date. As of
December 31, 2011
,
8,289
shares of our common stock remained available to be awarded under this plan.
|
•
|
The 2003 Employee Stock Incentive Plan authorizes the grant of various stock and stock-related awards to employees and prospective employees. Awards include options to purchase shares of common stock, performance awards that vest upon the achievement of an objective performance goal, stock appreciation rights, and restricted stock that vests over a period determined by our compensation committee. As of
December 31, 2011
,
536,141
shares of our common stock remained available to be awarded under this plan.
|
•
|
In addition, we maintained other stock option and incentive plans under which previously granted equity awards remain outstanding.
No
additional grants may be awarded under these plans.
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Stock-based compensation expense
|
$
|
58
|
|
|
$
|
54
|
|
|
$
|
68
|
|
Tax benefit recognized on stock-based compensation expense
|
20
|
|
|
19
|
|
|
24
|
|
|||
Tax benefit realized for tax deductions resulting from exercises and vestings
|
35
|
|
|
23
|
|
|
9
|
|
|||
Effect of tax deductions in excess of recognized stock-based compensation expense reported as a financing cash flow
|
23
|
|
|
11
|
|
|
5
|
|
|
Year Ended December 31,
|
|||||||
|
2011
|
|
2010
|
|
2009
|
|||
Expected life in years
|
6.0
|
|
|
6.0
|
|
|
6.0
|
|
Expected volatility
|
49.30
|
%
|
|
48.21
|
%
|
|
47.8
|
%
|
Expected dividend yield
|
2.28
|
%
|
|
1.05
|
%
|
|
3.1
|
%
|
Risk-free interest rate
|
1.44
|
%
|
|
1.83
|
%
|
|
2.8
|
%
|
|
Number of
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
Per Share
|
|||
Nonvested shares as of January 1, 2011
|
3,360,213
|
|
|
$
|
21.05
|
|
Granted
|
1,297,464
|
|
|
26.32
|
|
|
Vested
|
(1,350,658
|
)
|
|
23.17
|
|
|
Forfeited
|
(57,929
|
)
|
|
20.66
|
|
|
Nonvested shares as of December 31, 2011
|
3,249,090
|
|
|
22.28
|
|
|
Nonvested
Awards
|
|
Vested
Awards
|
||
Awards outstanding as of January 1, 2011
|
253,611
|
|
|
24,219
|
|
Granted
|
468,941
|
|
|
—
|
|
Vested
|
(31,361
|
)
|
|
31,361
|
|
Converted
|
—
|
|
|
—
|
|
Forfeited
|
—
|
|
|
(30,945
|
)
|
Awards outstanding as of December 31, 2011
|
691,191
|
|
|
24,635
|
|
16.
|
INCOME TAXES
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
U.S. operations
|
$
|
3,190
|
|
|
$
|
1,436
|
|
|
$
|
(371
|
)
|
International operations
|
132
|
|
|
62
|
|
|
55
|
|
|||
Income (loss) from continuing operations before income tax expense (benefit)
|
$
|
3,322
|
|
|
$
|
1,498
|
|
|
$
|
(316
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Federal income tax expense (benefit)
at the U.S. statutory rate
|
$
|
1,163
|
|
|
$
|
524
|
|
|
$
|
(111
|
)
|
U.S. state income tax expense (benefit),
net of U.S. federal income tax effect
|
29
|
|
|
(21
|
)
|
|
(2
|
)
|
|||
U.S. manufacturing deduction
|
(28
|
)
|
|
5
|
|
|
7
|
|
|||
International operations
|
46
|
|
|
27
|
|
|
75
|
|
|||
Permanent differences
|
8
|
|
|
8
|
|
|
(7
|
)
|
|||
Change in tax law
|
—
|
|
|
16
|
|
|
—
|
|
|||
Other, net
|
8
|
|
|
16
|
|
|
(5
|
)
|
|||
Income tax expense (benefit)
|
$
|
1,226
|
|
|
$
|
575
|
|
|
$
|
(43
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Current:
|
|
|
|
|
|
||||||
U.S. federal
|
$
|
562
|
|
|
$
|
(75
|
)
|
|
$
|
(309
|
)
|
U.S. state
|
13
|
|
|
(13
|
)
|
|
(16
|
)
|
|||
International
|
186
|
|
|
22
|
|
|
142
|
|
|||
Total current
|
761
|
|
|
(66
|
)
|
|
(183
|
)
|
|||
|
|
|
|
|
|
||||||
Deferred:
|
|
|
|
|
|
||||||
U.S. federal
|
527
|
|
|
634
|
|
|
181
|
|
|||
U.S. state
|
32
|
|
|
(19
|
)
|
|
12
|
|
|||
International
|
(94
|
)
|
|
26
|
|
|
(53
|
)
|
|||
Total deferred
|
465
|
|
|
641
|
|
|
140
|
|
|||
Income tax expense (benefit)
|
$
|
1,226
|
|
|
$
|
575
|
|
|
$
|
(43
|
)
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Deferred income tax assets:
|
|
|
|
||||
Tax credit carryforwards
|
$
|
158
|
|
|
$
|
99
|
|
Net operating losses (NOL)
|
300
|
|
|
265
|
|
||
Compensation and employee benefit liabilities
|
324
|
|
|
286
|
|
||
Environmental liabilities
|
78
|
|
|
85
|
|
||
Inventories
|
273
|
|
|
170
|
|
||
Property, plant and equipment
|
14
|
|
|
—
|
|
||
Other
|
160
|
|
|
184
|
|
||
Total deferred income tax assets
|
1,307
|
|
|
1,089
|
|
||
Less: Valuation allowance
|
(295
|
)
|
|
(270
|
)
|
||
Net deferred income tax assets
|
1,012
|
|
|
819
|
|
||
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Turnarounds
|
(310
|
)
|
|
(256
|
)
|
||
Property, plant and equipment
|
(5,292
|
)
|
|
(4,835
|
)
|
||
Inventories
|
(274
|
)
|
|
(260
|
)
|
||
Other
|
(119
|
)
|
|
(65
|
)
|
||
Total deferred income tax liabilities
|
(5,995
|
)
|
|
(5,416
|
)
|
||
Net deferred income tax liabilities
|
$
|
(4,983
|
)
|
|
$
|
(4,597
|
)
|
|
Amount
|
|
Expiration
|
||
U.S. state income tax credits
|
$
|
63
|
|
|
2013 through 2027
|
U.S. state income tax credits
|
42
|
|
|
Unlimited
|
|
U.S. foreign tax credits
|
30
|
|
|
2012
|
|
U.S. state NOL (gross amount)
|
5,431
|
|
|
2012 through 2031
|
|
International NOL
|
249
|
|
|
Unlimited
|
|
U.S. alternative minimum tax credit
|
59
|
|
|
Unlimited
|
Income tax benefit
|
$
|
286
|
|
Additional paid-in capital
|
9
|
|
|
Total
|
$
|
295
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Balance as of beginning of year
|
$
|
330
|
|
|
$
|
484
|
|
|
$
|
238
|
|
Additions based on tax positions related to the current year
|
14
|
|
|
4
|
|
|
158
|
|
|||
Additions for tax positions related to prior years
|
55
|
|
|
49
|
|
|
106
|
|
|||
Reductions for tax positions related to prior years
|
(66
|
)
|
|
(203
|
)
|
|
(6
|
)
|
|||
Reductions for tax positions related to the lapse of
applicable statute of limitations
|
(3
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|||
Settlements
|
(4
|
)
|
|
—
|
|
|
(11
|
)
|
|||
Balance as of end of year
|
$
|
326
|
|
|
$
|
330
|
|
|
$
|
484
|
|
17.
|
EARNINGS PER COMMON SHARE
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||||||||||||||
|
Restricted
Stock
|
|
Common
Stock
|
|
Restricted
Stock
|
|
Common
Stock
|
|
Restricted
Stock
|
|
Common
Stock
|
||||||||||||
Earnings per common share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income (loss) attributable to Valero stockholders from continuing operations
|
|
|
$
|
2,097
|
|
|
|
|
$
|
923
|
|
|
|
|
$
|
(273
|
)
|
||||||
Less dividends paid:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common stock
|
|
|
168
|
|
|
|
|
113
|
|
|
|
|
323
|
|
|||||||||
Nonvested restricted stock
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|||||||||
Undistributed earnings (loss)
|
|
|
$
|
1,928
|
|
|
|
|
$
|
809
|
|
|
|
|
$
|
(597
|
)
|
||||||
Weighted-average common shares outstanding
|
3
|
|
|
563
|
|
|
3
|
|
|
563
|
|
|
2
|
|
|
541
|
|
||||||
Earnings per common share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Distributed earnings
|
$
|
0.30
|
|
|
$
|
0.30
|
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
0.60
|
|
|
$
|
0.60
|
|
Undistributed earnings (loss)
|
3.40
|
|
|
3.40
|
|
|
1.43
|
|
|
1.43
|
|
|
—
|
|
|
(1.10
|
)
|
||||||
Total earnings per common share from continuing operations
|
$
|
3.70
|
|
|
$
|
3.70
|
|
|
$
|
1.63
|
|
|
$
|
1.63
|
|
|
$
|
0.60
|
|
|
$
|
(0.50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Earnings per common share from continuing operations – assuming dilution:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income (loss) attributable to Valero stockholders from continuing operations
|
|
|
$
|
2,097
|
|
|
|
|
$
|
923
|
|
|
|
|
$
|
(273
|
)
|
||||||
Weighted-average common shares outstanding
|
|
|
563
|
|
|
|
|
563
|
|
|
|
|
541
|
|
|||||||||
Common equivalent shares:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Stock options
|
|
|
4
|
|
|
|
|
3
|
|
|
|
|
—
|
|
|||||||||
Performance awards and unvested restricted stock
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
—
|
|
|||||||||
Weighted-average common shares outstanding – assuming dilution
|
|
|
569
|
|
|
|
|
568
|
|
|
|
|
541
|
|
|||||||||
Earnings per common share from continuing operations – assuming dilution
|
|
|
$
|
3.69
|
|
|
|
|
$
|
1.62
|
|
|
|
|
$
|
(0.50
|
)
|
|
Year Ended December 31,
|
|||||||
|
2011
|
|
2010
|
|
2009
|
|||
Common equivalent shares
|
—
|
|
|
—
|
|
|
4
|
|
Stock options
|
6
|
|
|
14
|
|
|
12
|
|
18.
|
SEGMENT INFORMATION
|
|
Refining
|
|
Retail
|
|
Ethanol
|
|
Corporate
|
|
Total
|
||||||||||
Year ended December 31, 2011:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external
customers
|
$
|
109,138
|
|
|
$
|
11,699
|
|
|
$
|
5,150
|
|
|
$
|
—
|
|
|
$
|
125,987
|
|
Intersegment revenues
|
8,665
|
|
|
—
|
|
|
145
|
|
|
—
|
|
|
8,810
|
|
|||||
Depreciation and amortization expense
|
1,338
|
|
|
115
|
|
|
39
|
|
|
42
|
|
|
1,534
|
|
|||||
Operating income (loss)
|
3,516
|
|
|
381
|
|
|
396
|
|
|
(613
|
)
|
|
3,680
|
|
|||||
Total expenditures for long-lived assets
|
2,556
|
|
|
134
|
|
|
32
|
|
|
265
|
|
|
2,987
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external
customers
|
69,854
|
|
|
9,339
|
|
|
3,040
|
|
|
—
|
|
|
82,233
|
|
|||||
Intersegment revenues
|
6,416
|
|
|
—
|
|
|
245
|
|
|
—
|
|
|
6,661
|
|
|||||
Depreciation and amortization expense
|
1,210
|
|
|
108
|
|
|
36
|
|
|
51
|
|
|
1,405
|
|
|||||
Operating income (loss)
|
1,903
|
|
|
346
|
|
|
209
|
|
|
(582
|
)
|
|
1,876
|
|
|||||
Total expenditures for long-lived assets
|
2,084
|
|
|
102
|
|
|
—
|
|
|
48
|
|
|
2,234
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external
customers
|
55,516
|
|
|
7,885
|
|
|
1,198
|
|
|
—
|
|
|
64,599
|
|
|||||
Intersegment revenues
|
5,137
|
|
|
—
|
|
|
137
|
|
|
—
|
|
|
5,274
|
|
|||||
Depreciation and amortization expense
|
1,194
|
|
|
101
|
|
|
18
|
|
|
48
|
|
|
1,361
|
|
|||||
Operating income (loss)
|
247
|
|
|
293
|
|
|
165
|
|
|
(622
|
)
|
|
83
|
|
|||||
Total expenditures for long-lived assets
|
2,338
|
|
|
66
|
|
|
5
|
|
|
39
|
|
|
2,448
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Refining:
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
$
|
49,019
|
|
|
$
|
33,491
|
|
|
$
|
27,322
|
|
Distillates
|
43,713
|
|
|
26,402
|
|
|
20,526
|
|
|||
Petrochemicals
|
4,253
|
|
|
3,161
|
|
|
2,177
|
|
|||
Lubes and asphalts
|
1,948
|
|
|
1,315
|
|
|
1,126
|
|
|||
Other product revenues
|
10,205
|
|
|
5,485
|
|
|
4,365
|
|
|||
Total refining operating revenues
|
109,138
|
|
|
69,854
|
|
|
55,516
|
|
|||
Retail:
|
|
|
|
|
|
||||||
Fuel sales (gasoline and diesel)
|
9,730
|
|
|
7,498
|
|
|
6,148
|
|
|||
Merchandise sales and other
|
1,635
|
|
|
1,581
|
|
|
1,505
|
|
|||
Home heating oil
|
334
|
|
|
260
|
|
|
232
|
|
|||
Total retail operating revenues
|
11,699
|
|
|
9,339
|
|
|
7,885
|
|
|||
Ethanol:
|
|
|
|
|
|
||||||
Ethanol
|
4,436
|
|
|
2,647
|
|
|
1,032
|
|
|||
Distillers grains
|
714
|
|
|
393
|
|
|
166
|
|
|||
Total ethanol operating revenues
|
5,150
|
|
|
3,040
|
|
|
1,198
|
|
|||
Consolidated operating revenues
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
64,599
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
U.S.
|
$
|
98,806
|
|
|
$
|
67,392
|
|
|
$
|
55,247
|
|
Canada
|
10,110
|
|
|
6,945
|
|
|
6,048
|
|
|||
U.K.
|
4,297
|
|
|
149
|
|
|
—
|
|
|||
Other countries
|
12,774
|
|
|
7,747
|
|
|
3,304
|
|
|||
Consolidated operating revenues
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
64,599
|
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
U.S.
|
$
|
22,317
|
|
|
$
|
20,488
|
|
Canada
|
2,362
|
|
|
2,308
|
|
||
U.K.
|
848
|
|
|
—
|
|
||
Aruba
|
958
|
|
|
981
|
|
||
Total long-lived assets
|
$
|
26,485
|
|
|
$
|
23,777
|
|
19.
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Decrease (increase) in current assets:
|
|
|
|
|
|
||||||
Receivables, net
|
$
|
(3,110
|
)
|
|
$
|
(679
|
)
|
|
$
|
(806
|
)
|
Inventories
|
643
|
|
|
(407
|
)
|
|
(77
|
)
|
|||
Income taxes receivable
|
128
|
|
|
545
|
|
|
(668
|
)
|
|||
Prepaid expenses and other
|
(2
|
)
|
|
107
|
|
|
56
|
|
|||
Increase (decrease) in current liabilities:
|
|
|
|
|
|
||||||
Accounts payable
|
2,004
|
|
|
670
|
|
|
1,475
|
|
|||
Accrued expenses
|
(18
|
)
|
|
(99
|
)
|
|
73
|
|
|||
Taxes other than income taxes
|
312
|
|
|
(66
|
)
|
|
107
|
|
|||
Income taxes payable
|
124
|
|
|
(3
|
)
|
|
95
|
|
|||
Changes in current assets and current liabilities
|
$
|
81
|
|
|
$
|
68
|
|
|
$
|
255
|
|
•
|
the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;
|
•
|
the amounts shown above exclude the current assets and current liabilities acquired in connection with the Meraux Acquisition in October 2011, the Pembroke Acquisition in August 2011, and the acquisitions of ethanol plants in 2010 and 2009;
|
•
|
amounts accrued for capital expenditures and deferred turnaround and catalyst costs are reflected in investing activities when such amounts are paid;
|
•
|
amounts accrued for common stock purchases in the open market that are not settled as of the balance sheet date are reflected in financing activities when the purchases are settled and paid;
|
•
|
changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Paulsboro and Delaware City Refineries prior to their sale are reflected in the line items to which the changes relate in the table above; and
|
•
|
certain differences between balance sheet changes and the changes reflected above result from translating foreign currency denominated amounts at the applicable exchange rates as of each balance sheet date.
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Interest paid in excess of amount capitalized
|
$
|
(397
|
)
|
|
$
|
(457
|
)
|
|
$
|
(390
|
)
|
Income taxes received (paid), net
|
(486
|
)
|
|
690
|
|
|
(165
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2010
|
|
2009
|
||||||
Cash provided by (used in) operating activities:
|
|
|
|
|
|
||||||
Paulsboro Refinery
|
$
|
—
|
|
|
$
|
88
|
|
|
$
|
10
|
|
Delaware City Refinery
|
—
|
|
|
(26
|
)
|
|
(126
|
)
|
|||
Cash used in investing activities:
|
|
|
|
|
|
||||||
Paulsboro Refinery
|
—
|
|
|
(41
|
)
|
|
(121
|
)
|
|||
Delaware City Refinery
|
—
|
|
|
—
|
|
|
(153
|
)
|
20.
|
FAIR VALUE MEASUREMENTS
|
•
|
Level 1
- Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.
|
•
|
Level 2
- Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.
|
•
|
Level 3
- Unobservable inputs for the asset or liability for which there is little, if any, market activity at the measurement date. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Netting
Adjustments
|
|
Total as of
December 31, 2011 |
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
$
|
2,038
|
|
|
$
|
78
|
|
|
$
|
—
|
|
|
$
|
(1,940
|
)
|
|
$
|
176
|
|
Physical purchase contracts
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|||||
Investments of certain benefit plans
|
84
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
95
|
|
|||||
Other investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
1,864
|
|
|
101
|
|
|
—
|
|
|
(1,940
|
)
|
|
25
|
|
|||||
Obligations of certain benefit plans
|
34
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Netting
Adjustments
|
|
Total as of
December 31, 2010 |
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
$
|
3,240
|
|
|
$
|
489
|
|
|
$
|
—
|
|
|
$
|
(3,560
|
)
|
|
$
|
169
|
|
Physical purchase contracts
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|||||
Investments of certain benefit plans
|
104
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
114
|
|
|||||
Other investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
3,097
|
|
|
502
|
|
|
—
|
|
|
(3,560
|
)
|
|
39
|
|
|||||
Biofuels blending obligation
|
51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|||||
Obligations of certain benefit plans
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
•
|
Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in
Note 21
, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.
|
•
|
Physical purchase contracts to purchase inventories represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in
Note 21
, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange, but because these commitments have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, they are categorized in Level 2 of the fair value hierarchy.
|
•
|
Investments of certain benefit plan assets consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer. Obligations of certain benefit plans relate to certain U.S. nonqualified defined contribution plans under which our obligations to eligible employees are equal to the fair value of the assets held by those plans.
|
•
|
Other investments consist of (i) equity securities of private companies over which we do not exercise significant influence nor whose financial statements are consolidated into our financial statements
|
•
|
Our biofuels blending obligation represents a liability for the purchase of RINs and RTFCs, as defined and described in
Note 21
under
“Compliance Program Price Risk,”
to satisfy our obligation to blend biofuels into the products we produce. Our obligation is based on our deficiency in RINs and RTFCs and the price of these instruments as of the balance sheet date. Our obligation is categorized in Level 1 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
|
|
Investments of
Certain
Benefit Plans
|
|
Other Investments
|
|
Earn-Out
Agreement
|
||||||||||||||||||||||||||||||
|
2011
|
|
2010
|
|
2009
|
|
2011
|
|
2010
|
|
2009
|
|
2011
|
|
2010
|
|
2009
|
||||||||||||||||||
Balance as of beginning of year
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
13
|
|
Purchases
|
1
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(33
|
)
|
|||||||||
Total losses included in income
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|||||||||
Transfers in and/or out of Level 3
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Balance as of end of year
|
$
|
11
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The amount of total losses included in income attributable to the change in unrealized losses relating to assets still held at end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(21
|
)
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31,
|
||||||
|
2011
|
|
2010
|
||||
Carrying amount
|
$
|
7,690
|
|
|
$
|
8,300
|
|
Fair value
|
9,298
|
|
|
9,492
|
|
21.
|
PRICE RISK MANAGEMENT ACTIVITIES
|
|
|
Notional Contract Volumes by Year of Maturity
|
|
Derivative Instrument
|
|
2012
|
|
Crude oil and refined products:
|
|
|
|
Futures – long
|
|
15,398
|
|
Futures – short
|
|
35,708
|
|
Physical contracts – long
|
|
20,310
|
|
|
|
Notional Contract Volumes by Year of Maturity
|
|
Derivative Instrument
|
|
2012
|
|
Crude oil and refined products:
|
|
|
|
Swaps – long
|
|
5,961
|
|
Swaps – short
|
|
5,961
|
|
Futures – long
|
|
38,201
|
|
Futures – short
|
|
36,637
|
|
Physical contracts – short
|
|
1,564
|
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2012
|
|
2013
|
||
Crude oil and refined products:
|
|
|
|
|
||
Swaps – long
|
|
67,862
|
|
|
—
|
|
Swaps – short
|
|
67,040
|
|
|
—
|
|
Futures – long
|
|
70,211
|
|
|
—
|
|
Futures – short
|
|
65,339
|
|
|
—
|
|
Options – long
|
|
10
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
18,530
|
|
|
—
|
|
Futures – short
|
|
49,565
|
|
|
780
|
|
Physical contracts – long
|
|
20,377
|
|
|
833
|
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2012
|
|
2013
|
||
Crude oil and refined products:
|
|
|
|
|
||
Swaps – long
|
|
15,128
|
|
|
2,000
|
|
Swaps – short
|
|
14,968
|
|
|
2,000
|
|
Futures – long
|
|
50,126
|
|
|
825
|
|
Futures – short
|
|
50,133
|
|
|
825
|
|
Options – long
|
|
300
|
|
|
—
|
|
Options – short
|
|
600
|
|
|
—
|
|
Natural gas:
|
|
|
|
|
||
Futures – long
|
|
400
|
|
|
—
|
|
Futures – short
|
|
400
|
|
|
—
|
|
Options – long
|
|
2,000
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Swaps – long
|
|
1,050
|
|
|
—
|
|
Swaps – short
|
|
3,355
|
|
|
—
|
|
Futures – long
|
|
2,510
|
|
|
—
|
|
Futures – short
|
|
2,310
|
|
|
—
|
|
|
Balance Sheet
Location
|
|
December 31, 2011
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives designated as hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
264
|
|
|
$
|
240
|
|
Swaps
|
Accrued expenses
|
|
36
|
|
|
46
|
|
||
Total
|
|
|
$
|
300
|
|
|
$
|
286
|
|
|
|
|
|
|
|
||||
Derivatives not designated as hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
1,636
|
|
|
$
|
1,624
|
|
Swaps
|
Prepaid expenses and other
|
|
4
|
|
|
2
|
|
||
Swaps
|
Accrued expenses
|
|
38
|
|
|
51
|
|
||
Options
|
Receivables, net
|
|
2
|
|
|
—
|
|
||
Options
|
Accrued expenses
|
|
—
|
|
|
2
|
|
||
Physical purchase contracts
|
Inventories
|
|
—
|
|
|
2
|
|
||
Total
|
|
|
$
|
1,680
|
|
|
$
|
1,681
|
|
Total derivatives
|
|
|
$
|
1,980
|
|
|
$
|
1,967
|
|
|
Balance Sheet
Location
|
|
December 31, 2010
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives designated as hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
120
|
|
|
$
|
183
|
|
Swaps
|
Prepaid expenses and other
|
|
55
|
|
|
39
|
|
||
Swaps
|
Accrued expenses
|
|
31
|
|
|
32
|
|
||
Total
|
|
|
$
|
206
|
|
|
$
|
254
|
|
|
|
|
|
|
|
||||
Derivatives not designated as hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
2,717
|
|
|
$
|
2,914
|
|
Swaps
|
Prepaid expenses and other
|
|
287
|
|
|
277
|
|
||
Swaps
|
Accrued expenses
|
|
116
|
|
|
148
|
|
||
Options
|
Accrued expenses
|
|
—
|
|
|
6
|
|
||
Physical purchase contracts
|
Inventories
|
|
17
|
|
|
—
|
|
||
Total
|
|
|
$
|
3,137
|
|
|
$
|
3,345
|
|
Total derivatives
|
|
|
$
|
3,343
|
|
|
$
|
3,599
|
|
Derivatives in Fair Value
Hedging Relationships
|
|
Location of Gain (Loss)
Recognized in Income on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
2009
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
||||||
Gain (loss) recognized in
income on derivatives
|
|
Cost of sales
|
|
$
|
(6
|
)
|
|
$
|
45
|
|
|
$
|
(75
|
)
|
Gain (loss) recognized in
income on hedged item
|
|
Cost of sales
|
|
(23
|
)
|
|
(40
|
)
|
|
69
|
|
|||
Gain (loss) recognized in
income on derivatives
(ineffective portion)
|
|
Cost of sales
|
|
(29
|
)
|
|
5
|
|
|
(6
|
)
|
Derivatives in Cash Flow
Hedging Relationships
|
|
Location of Gain (Loss)
Recognized in Income on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
2009
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
||||||
Gain (loss) recognized in
OCI on derivatives
(effective portion)
|
|
|
|
$
|
32
|
|
|
$
|
(2
|
)
|
|
$
|
125
|
|
Gain (loss) reclassified from
accumulated OCI into
income (effective portion)
|
|
Cost of sales
|
|
3
|
|
|
178
|
|
|
337
|
|
|||
|
|
Loss from
discontinued operations,
net of income taxes
|
|
—
|
|
|
—
|
|
|
(132
|
)
|
|||
Gain (loss) recognized in
income on derivatives
(ineffective portion)
|
|
Cost of sales
|
|
5
|
|
|
—
|
|
|
3
|
|
Derivatives Designated as
Economic Hedges and Other
Derivative Instruments
|
|
Location of Gain
Recognized in Income on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
2009
|
||||||||
Commodity contracts
|
|
Cost of sales
|
|
$
|
(349
|
)
|
|
$
|
(210
|
)
|
|
$
|
55
|
|
Foreign currency contracts
|
|
Cost of sales
|
|
18
|
|
|
(24
|
)
|
|
(22
|
)
|
|||
Other contract
|
|
Cost of sales
|
|
29
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
(302
|
)
|
|
(234
|
)
|
|
33
|
|
|||
Alon earn-out agreement
|
|
Other income, net
|
|
—
|
|
|
—
|
|
|
20
|
|
|||
Alon earn-out hedge commodity contracts
|
|
Other income, net
|
|
—
|
|
|
—
|
|
|
(62
|
)
|
|||
|
|
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|||
Total
|
|
|
|
$
|
(302
|
)
|
|
$
|
(234
|
)
|
|
$
|
(9
|
)
|
Trading Derivatives
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
2009
|
||||||||
Commodity contracts
|
|
Cost of sales
|
|
$
|
23
|
|
|
$
|
8
|
|
|
$
|
126
|
|
22.
|
QUARTERLY FINANCIAL DATA (Unaudited)
|
|
2011 Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30 (a)
|
|
December 31 (b)
|
||||||||
Operating revenues
|
$
|
26,308
|
|
|
$
|
31,293
|
|
|
$
|
33,713
|
|
|
$
|
34,673
|
|
Operating income
|
244
|
|
|
1,290
|
|
|
1,979
|
|
|
167
|
|
||||
Income from continuing
operations
|
104
|
|
|
744
|
|
|
1,203
|
|
|
45
|
|
||||
Net income
|
98
|
|
|
743
|
|
|
1,203
|
|
|
45
|
|
||||
Net income attributable to
Valero Energy Corporation
stockholders
|
98
|
|
|
744
|
|
|
1,203
|
|
|
45
|
|
||||
Earnings per common share
from continuing operations –
assuming dilution
|
0.18
|
|
|
1.30
|
|
|
2.11
|
|
|
0.08
|
|
||||
Earnings per common share –
assuming dilution
|
0.17
|
|
|
1.30
|
|
|
2.11
|
|
|
0.08
|
|
||||
|
|
|
|
|
|
|
|
||||||||
|
2010 Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30 (c)
|
|
September 30
|
|
December 31 (d)
|
||||||||
Operating revenues
|
$
|
18,493
|
|
|
$
|
20,561
|
|
|
$
|
21,015
|
|
|
$
|
22,164
|
|
Operating income
|
4
|
|
|
904
|
|
|
590
|
|
|
378
|
|
||||
Income (loss) from continuing
operations
|
(80
|
)
|
|
520
|
|
|
303
|
|
|
180
|
|
||||
Net income (loss)
|
(113
|
)
|
|
583
|
|
|
292
|
|
|
(438
|
)
|
||||
Net income (loss) attributable to
Valero Energy Corporation
stockholders
|
(113
|
)
|
|
583
|
|
|
292
|
|
|
(438
|
)
|
||||
Earnings per common share
from continuing operations –
assuming dilution
|
(0.14
|
)
|
|
0.92
|
|
|
0.53
|
|
|
0.32
|
|
||||
Earnings per common share –
assuming dilution
|
(0.20
|
)
|
|
1.03
|
|
|
0.51
|
|
|
(0.77
|
)
|
(a)
|
Includes the operations related to the Pembroke Acquisition beginning August 1, 2011.
|
(b)
|
Includes the operations related to the Meraux Acquisition beginning October 1, 2011.
|
(c)
|
Net income for the quarter ended June 30, 2010 includes the
$92 million
pre-tax gain related to the sale of the Delaware City Refinery as discussed in
Note 3
.
|
(d)
|
Net loss for the quarter ended December 31, 2010 includes the
$980 million
pre-tax loss related to the sale of the Paulsboro Refinery as discussed in
Note 3
.
|
|
Page
|
|
|
|
|
3.01
|
|
--
|
Amended and Restated Certificate of Incorporation of Valero Energy Corporation, formerly known as Valero Refining and Marketing Company - incorporated by reference to Exhibit 3.1 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
|
|
|
|
|
3.02
|
|
--
|
Certificate of Amendment (effective July 31, 1997) to Restated Certificate of Incorporation of Valero Energy Corporation - incorporated by reference to Exhibit 3.02 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
|
|
|
|
|
3.03
|
|
--
|
Certificate of Merger of Ultramar Diamond Shamrock Corporation with and into Valero Energy Corporation dated December 31, 2001 - incorporated by reference to Exhibit 3.03 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
|
|
|
|
|
3.04
|
|
--
|
Amendment (effective December 31, 2001) to Restated Certificate of Incorporation of Valero Energy Corporation - incorporated by reference to Exhibit 3.1 to Valero’s Current Report on Form 8-K dated December 31, 2001, and filed January 11, 2002 (SEC File No. 1-13175).
|
|
|
|
|
3.05
|
|
--
|
Second Certificate of Amendment (effective September 17, 2004) to Restated Certificate of Incorporation of Valero Energy Corporation - incorporated by reference to Exhibit 3.04 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (SEC File No. 1-13175).
|
|
|
|
|
3.06
|
|
--
|
Certificate of Merger of Premcor Inc. with and into Valero Energy Corporation effective September 1, 2005 - incorporated by reference to Exhibit 2.01 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (SEC File No. 1-13175).
|
*24.01
|
|
--
|
Power of Attorney dated February 23, 2012 (on the signature page of this Form 10-K).
|
|
|
|
|
*31.01
|
|
--
|
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
|
|
|
|
|
*31.02
|
|
--
|
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
|
|
|
|
|
*32.01
|
|
--
|
Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002).
|
|
|
|
|
*99.01
|
|
--
|
Audit Committee Pre-Approval Policy.
|
|
|
|
|
**101
|
|
--
|
Interactive Data Files
|
*
|
Filed herewith.
|
+
|
Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto.
|
**
|
Submitted electronically herewith.
|
|
VALERO ENERGY CORPORATION
(Registrant)
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|
|
By:
|
/s/ William R. Klesse
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(William R. Klesse)
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Chief Executive Officer, President, and Chairman of the Board
|
Signature
|
|
Title
|
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Date
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/s/ William R. Klesse
|
|
Chief Executive Officer, President, and
Chairman of the Board
(Principal Executive Officer)
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February 23, 2012
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(William R. Klesse)
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||
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/s/ Michael S. Ciskowski
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Executive Vice President
and Chief Financial Officer
(Principal Financial and Accounting Officer)
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February 23, 2012
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(Michael S. Ciskowski)
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||
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/s/ Ronald K. Calgaard
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Director
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February 23, 2012
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(Ronald K. Calgaard)
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||
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/s/ Jerry D. Choate
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Director
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February 23, 2012
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(Jerry D. Choate)
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||
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/s/ Ruben M. Escobedo
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Director
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February 23, 2012
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(Ruben M. Escobedo)
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||
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/s/ Bob Marbut
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Director
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February 23, 2012
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(Bob Marbut)
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||
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/s/ Donald L. Nickles
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Director
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February 23, 2012
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(Donald L. Nickles)
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||
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/s/ Robert A. Profusek
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Director
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February 23, 2012
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(Robert A. Profusek)
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||
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/s/ Susan Kaufman Purcell
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Director
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February 23, 2012
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(Susan Kaufman Purcell)
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||
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/s/ Stephen M. Waters
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Director
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February 23, 2012
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(Stephen M. Waters)
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|
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||
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/s/ Randall J. Weisenburger
|
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Director
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February 23, 2012
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(Randall J. Weisenburger)
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||
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/s/ Rayford Wilkins, Jr.
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Director
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February 23, 2012
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(Rayford Wilkins, Jr.)
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Participant's Signature
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Date
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Participant's Name
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Participant's Employee ID Number
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Participant's Signature
|
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Date
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|
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|
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Participant's Name
|
|
Participant's Employee ID Number
|
Payment Election
Upon Retirement
|
DEFAULT PAYMENT IF NO ELECTION IS MADE:
Fifteen annual installments commencing at date of retirement
|
I elect that, upon retirement, the value of my Plan account related to deferrals made for the
2012 Plan Year
will be paid at the time and in the manner elected below:
Payment Commencement (choose one): o As soon as administratively possible following retirement (this is the default if no election is made) o January 1 after the year of retirement
AND
Form of Distribution
(choose one):
o Lump sum payment o Annual installments for _______ years (choose 2 - 15 years) |
Payment Election
Upon Other Separation
|
DEFAULT PAYMENT IF NO ELECTION IS MADE:
Immediate lump sum payable upon separation
|
I elect that, upon my separation from employment for a reason other than retirement, the value of my Plan account related to deferrals made for the
2012 Plan Year
will be paid at the time and in the manner elected below:
Payment Commencement (choose one): o As soon as administratively possible following separation (this is the default if no election is made)
o
January 1 after the year of separation
AND
Form of Distribution
(choose one):
o Lump sum (this is the default payment if no election is made) o Five annual installments |
Distribution on Specified Date
|
||
In accordance with Section 6.4 of the Plan, I hereby elect to receive in one lump sum payment my Account derived from deferrals made during the
2012 Plan Year
on the date or dates specified below, or the balance of the Account, if less. Any amounts distributed pursuant to this election shall immediately reduce my Account accordingly.
(The earliest date that can be elected to receive 2012 deferrals is January 1, 2016.)
|
||
Specified Date
|
|
Amount of Elective Deferral or
Total Amount of the Account (Whichever is Less)
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Participant's Signature
|
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Date
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Participant's Name
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Participant's Employee ID Number
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Page
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|
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|
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|
|
ARTICLE I
|
|
DEFINITIONS
|
1
|
|
|
|
|
|
|
||
1.1
|
|
Accrued Benefit
|
1
|
|
|
1.2
|
|
Actuarial Equivalent or Actuarially Equivalent Basis
|
1
|
|
|
1.3
|
|
Board of Directors.
|
1
|
|
|
1.4
|
|
Change of Control
|
1
|
|
|
1.5
|
|
Code
|
2
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|
|
1.6
|
|
Company or Valero
|
2
|
|
|
1.7
|
|
Committee
|
2
|
|
|
1.8
|
|
Credited Service
|
2
|
|
|
1.9
|
|
Eligible Earnings
|
3
|
|
|
1.10
|
|
Final Average Compensation
|
3
|
|
|
1.11
|
|
Normal Retirement Date
|
3
|
|
|
1.12
|
|
Participant
|
3
|
|
|
1.13
|
|
Participating Employer
|
3
|
|
|
1.14
|
|
Plan
|
3
|
|
|
1.15
|
|
Plan of Deferred Compensation
|
3
|
|
|
1.16
|
|
Plan Year
|
3
|
|
|
1.17
|
|
Retirement
|
3
|
|
|
1.18
|
|
Subsidiary
|
4
|
|
|
1.19
|
|
Surviving Spouse
|
4
|
|
|
1.20
|
|
Valero Pension Plan
|
4
|
|
|
1.21
|
|
Voting Securities
|
4
|
|
|
|
|
|
|
||
ARTICLE II
|
|
ELIGIBILITY
|
4
|
|
|
|
|
|
|
||
2.1
|
|
Initial Eligibility
|
4
|
|
|
2.2
|
|
Frozen Participation
|
5
|
|
|
2.3
|
|
Renewed Eligibility
|
5
|
|
|
|
|
|
|
||
ARTICLE III
|
|
VESTING
|
5
|
|
|
|
|
|
|
||
ARTICLE IV
|
|
RETIREMENT BENEFIT
|
6
|
|
|
|
|
|
|
||
4.1
|
|
Calculation of Retirement Benefits; Commencement of Benefit Payments
|
6
|
|
|
4.2
|
|
Form and Time of Payment
|
6
|
|
|
|
|
|
|
ARTICLE V
|
|
PRE-RETIREMENT SPOUSAL DEATH BENEFIT
|
6
|
|
|
|
|
|
|
||
5.1
|
|
Death Prior to Retirement
|
6
|
|
|
5.2
|
|
Beneficiary Designation Prohibited
|
6
|
|
|
|
|
|
|
||
ARTICLE VI
|
|
PROVISIONS RELATING TO ALL BENEFITS
|
7
|
|
|
|
|
|
|
||
6.1
|
|
Effect of This Article
|
7
|
|
|
6.2
|
|
No Duplication of Benefits
|
7
|
|
|
6.3
|
|
Forfeiture for Cause
|
7
|
|
|
6.4
|
|
Forfeiture for Competition
|
7
|
|
|
6.5
|
|
Expenses Incurred in Enforcing the Plan
|
7
|
|
|
|
|
|
|
||
ARTICLE VII
|
|
ADMINISTRATIOIN
|
8
|
|
|
|
|
|
|
||
7.1
|
|
Administration of the Plan by the Committee
|
8
|
|
|
7.2
|
|
Committee Discretion
|
8
|
|
|
7.3
|
|
Reliance Upon Information
|
8
|
|
|
|
|
|
|
||
ARTICLE VIII
|
|
ADOPTION BY SUBSIDIARIES
|
9
|
|
|
|
|
|
|
||
8.1
|
|
Procedure for Adoption
|
9
|
|
|
8.2
|
|
Termination of Participation by Adopting Subsidiary
|
9
|
|
|
|
|
|
|
||
ARTICLE IX
|
|
AMENDMENT AND/OR TERMINATION
|
9
|
|
|
|
|
|
|
||
9.1
|
|
Amendment or Termination of the Plan
|
9
|
|
|
9.2
|
|
No Retroactive Effect on Accrued Benefits
|
9
|
|
|
9.3
|
|
Effect of Termination
|
9
|
|
|
9.4
|
|
Effect of Change of Control
|
10
|
|
|
|
|
|
|
||
ARTICLE X
|
|
MISCELLANEOUS
|
10
|
|
|
|
|
|
|
||
10.1
|
|
Mandatory Arbitration
|
10
|
|
|
10.2
|
|
Responsibility for Distributions and Withholding of Taxes
|
10
|
|
|
10.3
|
|
Limitation of Rights
|
10
|
|
|
10.4
|
|
Distributions to Incompetents
|
11
|
|
|
10.5
|
|
Nonalienation of Benefits
|
11
|
|
|
10.6
|
|
Severability
|
11
|
|
|
10.7
|
|
Notice
|
11
|
|
|
10.8
|
|
Gender and Number
|
11
|
|
|
10.9
|
|
Governing Law
|
11
|
|
|
10.10
|
|
Code Section 409A
|
11
|
|
PAGE
|
|
||
PART I. GRANDFATHERED PLAN
|
|
3
|
|
PART II. CURRENT PLAN
|
|
3
|
|
SECTION 1. DEFINITIONS
|
|
3
|
|
SECTION 2. PARTICIPATION - §415(b) BENEFIT PLAN COMPONENT
|
|
6
|
|
SECTION 3. PARTICIPATION - §401(a)(17) BENEFIT PLAN COMPONENT
|
|
6
|
|
SECTION 4. AMOUNT OF BENEFIT - TRADITIONAL FORMULA
|
|
7
|
|
SECTION 4A. AMOUNT OF BENEFIT - CASH BALANCE FORMULA
|
|
8
|
|
SECTION 5. VESTING
|
|
9
|
|
SECTION 6. PROVISIONS REGARDING PAYMENT OF BENEFITS
|
|
9
|
|
SECTION 7. DEATH BENEFIT
|
|
10
|
|
SECTION 8. ADMINISTRATION
|
|
10
|
|
SECTION 9. AMENDMENT AND TERMINATION
|
|
12
|
|
SECTION 10. CHANGE IN CONTROL
|
|
12
|
|
SECTION 11. GENERAL
|
|
12
|
|
(a)
|
Change in Ownership of Valero
. The acquisition by any one person, or more than one person acting as a group (within the meaning of Code section 409A), of ownership of stock of Valero that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of Valero.
|
(b)
|
Change in Effective Control of Valero
. Either of the following:
|
(i)
|
The acquisition, during any 12-month period, by any one person, or more than one person acting as a group (within the meaning of Code section 409A), of stock of Valero comprising thirty percent (30%) or more of the total voting power of the stock of Valero; or
|
(ii)
|
The replacement, during any 12-month period, of a majority of the members of the Board of Directors with directors whose appointment or election is not endorsed by the majority of the members of the Board of Directors before the date of such appointment or election.
|
(c)
|
Change in Ownership of a Substantial Portion of Valero's Assets
. The acquisition by any one person, or more than one person acting as a group (within the meaning of Code section 409A), during the 12 month period ending on the date of the most recent acquisition by such person or persons, of assets of Valero that have a total gross fair market value equal to or more than forty percent (40%) of the total gross fair market value of all of the assets of Valero immediately before such acquisition or acquisitions. For purposes of this provision, “gross fair market value” means the value of the assets of Valero, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
|
1.2
|
“Code” shall mean the Internal Revenue Code of 1986, as amended.
|
1.3
|
“Committee” shall mean the Valero Benefit Plans Administrative Committee.
|
1.4
|
“Company” shall include the Employer and any Affiliated Employer as such terms are respectively defined in the Pension Plan.
|
1.5
|
“Considered Compensation” shall mean Considered Compensation as such term is defined in the Pension Plan, but determined without regard to the Compensation Limit.
|
1.6
|
“Compensation Limit” shall mean the maximum annual compensation allowed to be taken into account under the Pension Plan for any Plan Year pursuant to the provisions of Code section 401(a)(17), or any successor provision thereto.
|
1.7
|
“Credited Service” shall have the meaning provided under the Pension Plan, except that Credited Service shall not include any period for which a Participant has received a payment hereunder, under the SERP, under the NuStar Excess Pension Plan, or under the NuStar SERP.
|
1.8
|
“Former Eligible NuStar Employees” shall mean (a) individuals who, as of July 1, 2006, were employees of Valero GP, LLC, as well as any other individuals who transferred from the Company to NuStar on or before December 22, 2006; and (b) individuals who are identified on the list of Former Eligible NuStar Employees attached to this Plan as Exhibit “A”.
|
1.9
|
“Employee” shall mean any individual who is characterized on the internal payroll records of the Company as an employee.
|
1.10
|
“Equivalent Actuarial Value” shall mean equality in value of the aggregate amounts expected to be received under different forms of payment based on the same mortality and interest rate assumptions. For this purpose, the mortality and interest rate assumptions used in computing benefits under the Pension Plan will be used.
|
1.11
|
“Excess Pension Plan” or “Plan” shall mean the Valero Energy Corporation Excess Pension Plan, as evidenced hereby.
|
1.12
|
“Final Average Monthly Earnings” shall mean Final Average Salary as such term is defined in the Pension Plan, but determined without regard to the Compensation Limit, and inclusive of amounts that would otherwise be excluded because of having been contributed to a Plan of Deferred Compensation.
|
1.13
|
“Grandfathered Plan” shall mean all of the terms and provisions of the Valero Energy Corporation Excess Pension Plan as in effect on October 3, 2004, which said provisions are attached hereto as Addendum 1, and are hereby incorporated in this Plan by reference with respect to Participants who incurred a Separation from Service, and whose benefits hereunder had fully accrued and were fully vested on or prior to December 31, 2004, as provided for in Part I of this Plan.
|
1.14
|
“NuStar” shall mean NuStar GP, LLC, formerly known as Valero GP, LLC.
|
1.15
|
“NuStar Excess Pension Plan” shall mean the NuStar Excess Pension Plan, as amended from time to time, or any successor plan.
|
1.16
|
“NuStar SERP” shall mean the NuStar Supplemental Executive Retirement Plan, as amended from time to time, or any successor plan.
|
1.17
|
“Participant” shall mean an Employee who meets the eligibility criteria of, and is a participant in, this Plan.
|
1.18
|
“Pension Plan” shall mean the Valero Energy Corporation Pension Plan, as amended from time to time, or any successor defined Benefit pension plan.
|
1.19
|
“Plan of Deferred Compensation” shall mean (a) the Valero Energy Corporation Deferred Compensation Plan, as amended, any successor, alternative or additional nonqualified deferred compensation plan maintained by the Company, and (b) any Code section 125 cafeteria plan or Code section 401(k) cash or deferred arrangement maintained by the Company.
|
1.20
|
“Separation from Service” shall mean a separation from service within the meaning of Code section 409A.
|
1.21
|
“SERP” shall mean Valero Energy Corporation Supplemental Executive Retirement Plan, as amended from time to time, or any successor plan.
|
1.22
|
“Trust” shall mean the Valero Energy Corporation Excess Pension Plan Trust as is created by the terms and conditions of said Trust and as may be amended from time to time.
|
1.23
|
“Valero” shall mean Valero Energy Corporation, or any successor entity.
|
(a)
|
Except as otherwise provided herein, each Employee actively participating in the Pension Plan whose benefit under the Pension Plan would exceed the annual addition limitations of Code section 415(b) but for the limitations provided in the Pension Plan, shall automatically become a Participant in the §415(b) benefit plan component of this Plan as of the date it is determined that such excess benefit applies.
|
(b)
|
Notwithstanding paragraph (a) above, any Employee who is covered under a collective bargaining agreement and whose benefits are the subject of good faith bargaining shall not be eligible to participate in the §415(b) benefit plan component of the Plan, except to the extent such collective bargaining agreement expressly provides for participation in the Plan.
|
(c)
|
Additionally, effective as of July 1, 2006, Employees of NuStar ceased to be eligible to participate in this Plan or accrue any additional benefits hereunder. Additionally, the benefit obligations relating to Former Eligible NuStar Employees were transferred to the NuStar Excess Pension Plan as provided for in Section 11.8 hereof.
|
(d)
|
Except as otherwise provided herein, each Employee whose Considered Compensation exceeds the Compensation Limit shall become a Participant in the §401(a)(17) benefit plan component of the Plan as of the first date of such excess
|
(e)
|
Notwithstanding paragraph (a) above, any Employee who is covered under a collective bargaining agreement and whose benefits are the subject of good faith bargaining shall not be eligible to participate in the §401(a)(17) benefit plan component of the Plan, except to the extent such collective bargaining agreement expressly provides for participation in this Plan.
|
(f)
|
Notwithstanding Section 3.1(a) above, effective as of July 1, 2006, Employees of NuStar ceased to be eligible to participate in this Plan or accrue additional benefits hereunder. Additionally, the benefit obligations relating to Former Eligible NuStar Employees were transferred to the NuStar Excess Pension Plan as provided for in Section 11.8 hereof.
|
4.1
|
Amount of Benefit.
For Participants whose Pension Plan benefit is calculated and determined under Article 4 of the Pension Plan, the benefit payable under this Plan shall, subject to the provisions of Sections 4.2 and 4.3, be an amount equal to “x” minus “y”, where:
|
4.2
|
Early Retirement Factors; Modification of Benefit Calculation. If a Participant's Plan benefit commences prior to his Normal Retirement Date, the Plan benefit payable to such Participant shall be determined by applying the early retirement reduction factors contained in the schedule of such factors set forth in the Pension Plan. Additionally, the benefit payable hereunder shall be reduced by the Equivalent Actuarial Value increase in the amount of the Pension Plan benefit and/or Prior Pension Plan benefit as the result of increases in the amount of maximum benefits payable from qualified plans in accordance with Code section 415.
|
4.3
|
Additionally, the Committee shall have the right to modify the calculation of Amount “x”, identified in Section 4.1, as to any Participant as it may desire from time to time; provided, however, that any such modification shall not result in a reduction of Amount “x” below the basic level provided in Section 4.1, and shall not affect the timing of the payment, or the form, of benefits hereunder.
|
4A.1
|
Amount of Benefit
. For Participants whose Pension Plan benefit is calculated and determined under Article 4A of the Pension Plan, the benefit payable under this Plan in the form of a lump sum payment shall be an amount equal to “x” minus “y”, where:
|
4A.2
|
Modification of Benefit Calculation
. The Committee shall have the right to
modify the calculation of amount “x” identified in Section 4A.1, as to any Participant as it may desire from time to time; provided, however, that any such modification shall not result in a reduction of amount “x” below the basic level provided for in Section 4A.1, and shall not affect the timing of the payment or the form, of benefits hereunder.
|
5.1
|
Vesting. A Participant's benefits under this Plan shall vest concurrently with the vesting of the Participant's benefits under the Pension Plan.
|
a.
|
to make rules and regulations for the administration of this Plan;
|
b.
|
to construe all terms, provisions, conditions and limitations of this Plan;
|
c.
|
to correct any defect, supply any omission or reconcile any inconsistency that may appear in this Plan;
|
d.
|
to determine all controversies relating to the administration of this Plan, including but not limited to:
|
1.
|
differences of opinion arising between a Company and a Participant;
|
2.
|
any question it deems advisable to determine in order to promote the uniform administration of this Plan for the benefit of all interested parties; and
|
3.
|
delegating powers of investment and administration, as well as those clerical and recordation duties of the Committee, as it deems necessary or advisable for the proper and efficient administration of this Plan.
|
|
Sincerely,
|
|
|
|
|
|
Valero Energy Corporation
|
|
|
|
|
|
By:
|
|
|
|
R. Michael Crownover
|
|
|
Senior Vice President
|
|
|
Human Resources
|
1
.
|
Grant of Performance Shares
. Valero hereby grants to Participant [________] Performance Shares pursuant to Section 6.7 of the Plan. The Performance Shares represent rights to receive shares of Common Stock of Valero, subject to the terms and conditions of this Agreement and the Plan.
|
2
.
|
Vesting and Delivery of Shares
.
|
A.
|
Vesting
. The Performance Shares granted hereunder shall vest over a period of three years in equal, one-third increments with the first increment vesting on the date of the regularly scheduled meeting of the Board's Compensation Committee in January 2013, and the second and third increments vesting on the Committee's meeting dates in January 2014 and January 2015, respectively (each of these three vesting dates is referred to as a “
Normal Vesting Date
”); any award(s) of shares of Common Stock resulting in connection with such vesting shall be subject to verification of attainment of the Performance Objectives described in Section 4 (below) by the Compensation Committee. If the Committee is unable to meet in January of a given year, then the Normal Vesting Date for that year will be the date not later than March 31 of that year as selected by the Compensation Committee.
|
B.
|
Rights
.
Until shares of Common Stock are actually issued to Participant (or his or her estate) in settlement of the Performance Shares, neither Participant nor any person claiming by, through or under Participant shall have any rights as a stockholder of Valero (including, without limitation, voting rights or any right to receive dividends or other distributions) with respect to such shares.
|
C.
|
Distribution
. Any shares of Common Stock to be distributed under the terms of this Agreement shall be distributed as soon as administratively practicable after Performance Objectives described in Section 4 below have been verified by the Compensation Committee, but not later than two-and-one-half months following the end of the year in which such verification occurred.
|
3
.
|
Performance Period
. Except as provided below with respect to a Change of Control (as defined in the Plan), the “
Performance Period
” for any Performance Shares eligible to vest on any given Normal Vesting Date shall be as follows:
|
A.
|
First Segment
. The Performance Period for the first one-third vesting of Performance Shares (those vesting on the Normal Vesting Date in January 2013) shall be the calendar year ending on December 31, 2012.
|
B.
|
Second Segment
. The Performance Period for the second one-third vesting of Performance Shares (those vesting on the Normal Vesting Date in January 2014) shall be the two calendar years ending December 31, 2013.
|
C.
|
Third Segment
. The Performance Period for the final one-third vesting of Performance Shares (those vesting on the Normal Vesting Date in January 2015) shall be the three calendar years ending December 31, 2014.
|
4.
|
Performance Objectives
.
|
A.
|
Total Shareholder Return
. Total Shareholder Return (“
TSR
”) will be compiled for a peer group of companies (the “
Target Group
”) for the Performance Period immediately preceding each Normal Vesting Date. TSR for each such company is measured by dividing (A) the sum of (i) the dividends on the common stock of such company during the Performance Period, assuming dividend reinvestment, and (ii) the difference between the average closing price of a share of such company's common stock for the 30 days of December 2 to December 31 at the end of the Performance Period and the average closing price of such shares for the 30 days of December 2 to December 31 immediately prior to the beginning of the Performance Period (appropriately adjusted for any stock dividend, stock split, spin-off, merger or other similar corporate events), by (B) the average closing price of a share of such company's common stock for the 30 days of December 2 to December 31 immediately prior to the beginning of the Performance Period.
|
B.
|
Target Group
. The applicable Target Group shall be selected by the Compensation Committee, acting in its sole discretion, each year not later than 90 days after the commencement of the calendar year preceding each Normal Vesting Date. The same Target Group shall be used to measure TSR with regard to all Performance Shares vesting under all Performance Award Agreements of Valero having a similar Normal Vesting Date.
|
C.
|
Performance Ranking and Award of Common Shares
. For each Performance Period, the TSR for Valero and each company in the Target Group shall be arranged by rank from best performer to worst performer according to the TSR achieved by each company. Shares of Common Stock will be awarded to Participant in accordance with Valero's percentile ranking within the Target Group. The number of shares of Common Stock, if any, that Participant will be entitled to receive in settlement of the vested Performance Shares will be determined on each Normal Vesting Date and, subject to the provisions of the Plan and this Agreement, on such Normal Vesting Date, the following percentage of the vested Performance Shares will be awarded as shares of Common Stock to the Participant when Valero's TSR during the Performance Period falls within the following percentiles (“
Percentiles
”), with awards of Common Stock to be interpolated between the “25th Percentile” and “50th Percentile” and between the “50th Percentile” and “75th Percentile”:
|
Valero Performance
|
|
Percent of vested Performance
Shares to be awarded as
Shares of Common Stock
|
75th Percentile or Higher
|
|
200%
|
50th Percentile (to 74.99%)
|
|
100% (to 199%)
|
25th Percentile (to 49.99%)
|
|
50% (to 99%)
|
Below 25th Percentile
|
|
0%
|
D.
|
Unearned Shares
. Any Performance Shares not awarded as shares of Common Stock on a Normal Vesting Date will expire and be forfeited; such Performance Shares may not be carried forward for any additional Performance Period.
|
5.
|
Termination of Employment
.
|
A.
|
Voluntary Termination, Termination for “Cause,” and Early Retirement
. If Participant's employment is
|
(i)
|
voluntarily terminated by the Participant (other than through normal retirement, death or disability), including termination in connection with Participant's voluntary early retirement (
i.e
., prior to age 62),
|
(ii)
|
terminated by Valero for “cause” (as defined pursuant to the Plan),
|
B.
|
Retirement
. If a Participant's employment is terminated through his or her normal retirement (
i.e
., age 62+ retirement), then any Performance Shares that (i) have not theretofore vested or been forfeited, and (ii) were granted at least one year prior to the Participant's effective date of retirement, shall continue to remain outstanding and shall vest on the Normal Vesting Dates according to their original vesting schedule. But any outstanding Performance Shares that were granted within one year of the Participant's effective date of retirement shall thereupon be forfeited.
|
C.
|
Death, Disability, Involuntary Termination Other Than for “Cause,” and Change of Control
. If a Participant's employment is terminated (i) through death or disability, or (ii) by Valero other than for cause (as determined pursuant to the Plan), or (iii) as a result of a Change of Control (as described in the Plan) (each of the foregoing is hereafter referred to as a “Trigger Date”), then each Performance Period with respect to any Performance Shares that have not vested or been forfeited shall be terminated effective as of such Trigger Date; the TSR for Valero and for each company in the Target Group shall be determined for each such shortened Performance Period and the percentage of Performance Shares to be received by the Participant for each such Performance Period shall be determined in accordance with Section 4 and shall be distributed as soon as administratively practicable thereafter. For purposes of determining the number of Performance Shares to be received as of any Trigger Date, the Target Group as most recently determined by the Compensation Committee prior to the Trigger Date shall be used.
|
6.
|
Plan Incorporated by Reference
. The Plan is incorporated into this Agreement by this reference and is made a part hereof for all purposes. Capitalized terms not otherwise defined in this Agreement shall have the meaning specified in the Plan.
|
7.
|
No Assignment
. This Agreement and the Participant's interest in the Performance Shares granted by this Agreement are of a personal nature, and, except as expressly permitted under the Plan, Participant's rights with respect thereto may not be sold, mortgaged, pledged, assigned, transferred, conveyed or disposed of in any manner by Participant, except by an executor or beneficiary pursuant to a will or pursuant to the laws of descent and distribution. Any such attempted sale, mortgage, pledge, assignment, transfer, conveyance or disposition is void, and Valero will not be bound thereby.
|
8.
|
Successors
. This Agreement shall be binding upon any successors of Valero and upon the beneficiaries, legatees, heirs, administrators, executors, legal representatives, successors and permitted assigns of Participant.
|
9.
|
Code Section 409A
. This Agreement is intended to comply, and shall be administered consistently in all respects, with Section 409A of the Internal Revenue Code of 1986, as amended (the “
Code
”), and the regulations and additional guidance promulgated thereunder to the extent applicable. Accordingly, Valero shall have the authority to take any action, or refrain from taking any action, with respect to this Agreement that is reasonably necessary to ensure compliance with Code Section 409A (provided that Valero shall choose the action that best preserves the value of payments and benefits provided to Participant under this Agreement that is consistent with Code Section 409A), and the parties agree that this Agreement shall be interpreted in a manner that is consistent with Code Section 409A. In furtherance, but not in limitation of the foregoing:
|
(a)
|
in no event may Participant designate, directly or indirectly, the calendar year of any payment to be made hereunder;
|
(b)
|
to the extent the Participant is a “specified employee” within the meaning of Code Section 409A, payments, if any, that constitute a “deferral of compensation” under Code Section 409A and that would otherwise become due during the first six months following Participant's termination of employment shall be delayed and all such delayed payments shall be paid in full in the seventh month after such termination date,
provided that
the above delay shall not apply to any payment that is excepted from coverage by Code Section 409A, such as a payment covered by the short-term deferral exception described in Treasury Regulations Section 1.409A-1(b)(4);
|
(c)
|
notwithstanding any other provision of this Agreement, a termination, resignation or retirement of Participant's employment hereunder shall mean and be interpreted consistent with a “separation from service” within the meaning of Code Section 409A.
|
Notice of Grant of Stock Option
|
|
Valero Energy Corporation
|
||
and Option Agreement
|
|
ID: 74-1828067
|
||
|
|
|
P. O. Box 696000
|
|
|
|
|
San Antonio, TX 78269-6000
|
|
|
|
|
|
|
«First_Name» «Middle_Name» «Last_Name»
|
|
Option Number:
|
«NUM»
|
|
|
|
|
Plan:
|
«PLAN_NAME»
|
|
|
|
ID:
|
«SSN»
|
By:
|
|
|
|
R Michael Crownover
|
|
Date
|
|
Senior Vice President - Human Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
«First_Name» «Middle_Name» «Last_Name»
|
|
Date
|
|
Employee
|
|
|
Section 1.01
|
Defined Terms
|
1
|
|
Section 1.02
|
Classification of Loans and Borrowings
|
18
|
|
Section 1.03
|
Terms Generally
|
19
|
|
Section 1.04
|
Accounting Terms; GAAP
|
19
|
|
Section 1.05
|
Letter of Credit Amounts
|
19
|
|
Section 2.01
|
Commitments
|
20
|
|
Section 2.02
|
Commitment Increase
|
20
|
|
Section 2.03
|
Swingline Loans
|
22
|
|
Section 2.04
|
Loans and Borrowings
|
23
|
|
Section 2.05
|
Requests for Borrowings
|
24
|
|
Section 2.06
|
Letters of Credit
|
24
|
|
Section 2.07
|
Funding of Borrowings
|
30
|
|
Section 2.08
|
Interest Elections
|
31
|
|
Section 2.09
|
Termination and Reduction of Commitments
|
32
|
|
Section 2.10
|
Repayment of Loans; Evidence of Debt
|
32
|
|
Section 2.11
|
Prepayment of Loans
|
33
|
|
Section 2.12
|
Fees
|
34
|
|
Section 2.13
|
Interest
|
35
|
|
Section 2.14
|
Alternate Rate of Interest
|
36
|
|
Section 2.15
|
Increased Costs
|
36
|
|
Section 2.16
|
Break Funding Payments
|
37
|
|
Section 2.17
|
Taxes
|
38
|
|
Section 2.18
|
Payments Generally; Pro Rata Treatment; Sharing of Setoffs
|
41
|
|
Section 2.19
|
Mitigation Obligations; Replacement of Lenders
|
42
|
|
Section 2.20
|
Illegality
|
43
|
|
Section 2.21
|
Extension of Maturity Date
|
43
|
|
Section 2.22
|
Defaulting Lenders
|
44
|
|
Section 3.01
|
Organization; Powers
|
47
|
|
Section 3.02
|
Authorization; Enforceability
|
47
|
|
Section 3.03
|
Governmental Approvals; No Conflicts
|
47
|
|
Section 3.04
|
Financial Condition
|
47
|
|
Section 3.05
|
Environmental Matters
|
48
|
|
Section 3.06
|
No Default
|
48
|
|
Section 3.07
|
Investment Company Status
|
48
|
|
Section 3.08
|
Taxes
|
48
|
|
Section 3.09
|
ERISA
|
48
|
|
Section 3.10
|
Disclosure
|
48
|
|
Section 4.01
|
Revolving Effective Date
|
49
|
|
Section 4.02
|
Each Credit Event
|
50
|
|
Section 5.01
|
Financial Statements and Other Information
|
51
|
|
Section 5.02
|
Notices of Material Events
|
52
|
|
Section 5.03
|
Existence; Conduct of Business
|
53
|
|
Section 5.04
|
Payment of Obligations
|
53
|
|
Section 5.05
|
Maintenance of Properties; Insurance
|
53
|
|
Section 5.06
|
Books and Records; Inspection Rights
|
54
|
|
Section 5.07
|
Compliance with Laws
|
54
|
|
Section 5.08
|
Use of Proceeds
|
54
|
|
Section 6.01
|
Indebtedness
|
54
|
|
Section 6.02
|
Liens
|
55
|
|
Section 6.03
|
Fundamental Changes
|
56
|
|
Section 6.04
|
Hedging Agreements
|
57
|
|
Section 6.05
|
Transactions with Affiliates
|
57
|
|
Section 9.01
|
Notices
|
62
|
|
Section 9.02
|
Waivers; Amendments
|
63
|
|
Section 9.03
|
Expenses; Indemnity; Damage Waiver
|
64
|
|
Section 9.04
|
Successors and Assigns
|
66
|
|
Section 9.05
|
Survival
|
69
|
|
Section 9.06
|
Counterparts; Integration; Effectiveness
|
69
|
|
Section 9.07
|
Severability
|
69
|
|
Section 9.08
|
Right of Setoff
|
70
|
|
Section 9.09
|
Governing Law; Jurisdiction; Consent to Service of Process
|
70
|
|
Section 9.10
|
Waiver of Jury Trial
|
71
|
|
Section 9.11
|
Headings
|
71
|
|
Section 9.12
|
Confidentiality
|
71
|
|
Section 9.13
|
Interest Rate Limitation
|
72
|
|
Section 9.14
|
USA PATRIOT Act
|
72
|
|
Section 9.15
|
Amendment and Restatement
|
72
|
|
Section 9.16
|
Assignment and Reallocation of Commitments, Etc
|
73
|
|
By:
|
_______________________________
|
By:
|
_______________________________
|
1. Assignor:
|
____________________________________
|
2. Assignee:
|
____________________________________
|
3. Credit Agreement:
|
The $3,000,000,000 5-Year Amended and Restated Revolving Credit Agreement dated as of December 5, 2011 among Valero Energy Corporation, the Lenders parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and an Issuing Bank and the other Persons from time to time party thereto.
|
Aggregate Amount of
Commitment/Loans
for all Lenderss
|
Amount of Commitment/Loans Assigned
|
Percentage Assigned
of
Commitment/Loans
2
|
$
|
$
|
%
|
$
|
$
|
%
|
$
|
$
|
%
|
By:
|
_____________________________________
|
By:
|
____________________________________
|
By:
|
__________________________________
|
By:
|
__________________________________
|
By:
|
__________________________________
|
By:
|
__________________________________
|
By:
|
___________________________________
|
By:
|
___________________________________
|
By:
|
___________________________________
|
Attention: Muhammad Hasan
|
[Date]
|
$________
|
New York, New York
|
By:
|
_____________________________________
|
Date
|
Amount of Eurodollar Loans
|
Amount Continued or Converted to Eurodollar Loans
|
Interest Period and Eurodollar Rate with Respect Thereto
|
Amount of Principal of Eurodollar Loans Repaid
|
Amount of Eurodollar Loans Converted to ABR Loans
|
Unpaid Principal Balance of Eurodollar Loans
|
Notation Made By
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date
|
Amount of ABR Loans
|
Amount Converted to ABR Loans
|
Amount of Principal of ABR Loans Repaid
|
Amount of ABR Loans Converted to Eurodollar Loans
|
Unpaid Principal Balance of ABR Loans
|
Notation Made By
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before
income tax expense (benefit), excluding income
from equity investee
|
|
$
|
3,322
|
|
|
|
$
|
1,481
|
|
|
|
$
|
(334
|
)
|
|
|
$
|
268
|
|
|
|
$
|
6,202
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
735
|
|
|
|
743
|
|
|
|
701
|
|
|
|
626
|
|
|
|
631
|
|
|
|||||
Amortization of capitalized interest
|
|
23
|
|
|
|
20
|
|
|
|
18
|
|
|
|
17
|
|
|
|
13
|
|
|
|||||
Distributions from equity investee
|
|
—
|
|
|
|
10
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest capitalized
|
|
(152
|
)
|
|
|
(90
|
)
|
|
|
(105
|
)
|
|
|
(92
|
)
|
|
|
(101
|
)
|
|
|||||
Total earnings
|
|
$
|
3,928
|
|
|
|
$
|
2,164
|
|
|
|
$
|
280
|
|
|
|
$
|
819
|
|
|
|
$
|
6,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
$
|
401
|
|
|
|
$
|
484
|
|
|
|
$
|
416
|
|
|
|
$
|
360
|
|
|
|
$
|
357
|
|
|
Interest capitalized
|
|
152
|
|
|
|
90
|
|
|
|
105
|
|
|
|
92
|
|
|
|
101
|
|
|
|||||
Rental expense interest factor (a)
|
|
182
|
|
|
|
169
|
|
|
|
180
|
|
|
|
174
|
|
|
|
173
|
|
|
|||||
Total fixed charges
|
|
$
|
735
|
|
|
|
$
|
743
|
|
|
|
$
|
701
|
|
|
|
$
|
626
|
|
|
|
$
|
631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
|
5.3
|
|
x
|
|
2.9
|
|
x
|
|
(b)
|
|
|
|
1.3
|
|
x
|
|
10.7
|
|
x
|
(a)
|
The interest portion of rental expense represents one-third of rents, which is deemed representative of the interest portion of rental expense.
|
(b)
|
For the year ended December 31, 2009, earnings were insufficient to cover fixed charges by $421 million. The deficiency included the effect of a $222 million pre-tax impairment loss resulting from the permanent cancellation of certain capital projects classified as “construction in progress” as a result of the unfavorable impact of the economic slowdown on refining industry fundamentals during the year. The deficiency was also partially attributable to a $120 million loss contingency accrual related to our dispute of a turnover tax on export sales in Aruba.
|
Name of Entity
|
|
State of Incorporation/Organization
|
|
|
|
AUTOTRONIC SYSTEMS, INC.
|
|
Delaware
|
BIG DIAMOND, INC.
|
|
Texas
|
BIG DIAMOND NUMBER 1, INC.
|
|
Texas
|
CANADIAN ULTRAMAR COMPANY
|
|
Nova Scotia
|
CANALUX L.P.
|
|
Newfoundland and Labrador
|
COLONNADE VERMONT INSURANCE COMPANY
|
|
Vermont
|
DIAMOND ALTERNATIVE ENERGY, LLC
|
|
Delaware
|
DIAMOND ALTERNATIVE ENERGY OF CANADA INC.
|
|
Canada
|
DIAMOND GREEN DIESEL HOLDINGS LLC
|
|
Delaware
|
DIAMOND GREEN DIESEL LLC
|
|
Delaware
|
DIAMOND K RANCH LLC
|
|
Texas
|
DIAMOND OMEGA COMPANY, L.L.C.
|
|
Delaware
|
DIAMOND SHAMROCK ARIZONA, INC.
|
|
Delaware
|
DIAMOND SHAMROCK REFINING COMPANY, L.P.
|
|
Delaware
|
DIAMOND SHAMROCK STATIONS, INC.
|
|
Delaware
|
DIAMOND UNIT INVESTMENTS, L.L.C.
|
|
Delaware
|
DSRM NATIONAL BANK
|
|
U.S.A.
|
EASTVIEW FUEL OILS LIMITED
|
|
Ontario
|
EMERALD MARKETING, INC.
|
|
Texas
|
GOLDEN EAGLE ASSURANCE LIMITED
|
|
British Columbia
|
HUNTWAY REFINING COMPANY
|
|
Delaware
|
KINROSS CELLULOSIC ETHANOL LLC
|
|
Delaware
|
MAINLINE PIPELINES LIMITED
|
|
England and Wales
|
MICHIGAN REDEVELOPMENT GP, LLC
|
|
Delaware
|
MICHIGAN REDEVELOPMENT, L.P.
|
|
Delaware
|
MRP PROPERTIES COMPANY, LLC
|
|
Michigan
|
NATIONAL CONVENIENCE STORES INCORPORATED
|
|
Delaware
|
NECHES RIVER HOLDING CORP.
|
|
Delaware
|
OCEANIC TANKERS AGENCY LIMITED
|
|
Quebec
|
PORT ARTHUR COKER COMPANY L.P.
|
|
Delaware
|
PREMCOR USA INC.
|
|
Delaware
|
PROPERTY RESTORATION, L.P.
|
|
Delaware
|
ROBINSON OIL COMPANY (1987) LIMITED
|
|
Nova Scotia
|
SABINE RIVER HOLDING CORP.
|
|
Delaware
|
SABINE RIVER LLC
|
|
Delaware
|
SIGMOR BEVERAGE, INC.
|
|
Texas
|
SIGMOR CORPORATION
|
|
Delaware
|
SIGMOR NUMBER 5, INC.
|
|
Texas
|
SIGMOR NUMBER 43, INC.
|
|
Texas
|
SIGMOR NUMBER 79, INC.
|
|
Texas
|
SIGMOR NUMBER 80, INC.
|
|
Texas
|
SIGMOR NUMBER 103, INC.
|
|
Texas
|
SIGMOR NUMBER 105, INC.
|
|
Texas
|
SIGMOR NUMBER 119, INC.
|
|
Texas
|
SIGMOR NUMBER 178, INC.
|
|
Texas
|
SIGMOR NUMBER 196, INC.
|
|
Texas
|
SIGMOR NUMBER 238, INC.
|
|
Texas
|
SIGMOR NUMBER 259, INC.
|
|
Texas
|
SIGMOR NUMBER 422, INC.
|
|
Texas
|
SKIPPER BEVERAGE COMPANY, INC.
|
|
Texas
|
SUNBELT REFINING COMPANY, L.P.
|
|
Delaware
|
SUNSHINE BEVERAGE CO.
|
|
Texas
|
TEXOIL LIMITED
|
|
Ireland
|
THE PREMCOR PIPELINE CO.
|
|
Delaware
|
THE PREMCOR REFINING GROUP INC.
|
|
Delaware
|
THE SHAMROCK PIPE LINE CORPORATION
|
|
Delaware
|
TOC-DS COMPANY
|
|
Delaware
|
ULTRAMAR ACCEPTANCE INC.
|
|
Canada
|
ULTRAMAR ENERGY INC.
|
|
Delaware
|
ULTRAMAR INC.
|
|
Nevada
|
ULTRAMAR LTD.
|
|
Canada
|
ULTRAMAR SERVICES INC.
|
|
Canada
|
VALERO ARUBA ACQUISITION COMPANY I, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA FINANCE INTERNATIONAL, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA HOLDING COMPANY N.V.
|
|
Aruba
|
VALERO ARUBA HOLDINGS INTERNATIONAL, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA MAINTENANCE/OPERATIONS
COMPANY N.V.
|
|
Aruba
|
VALERO CALIFORNIA RETAIL COMPANY
|
|
Delaware
|
VALERO CAMBRIA LLC
|
|
Delaware
|
VALERO CANADA FINANCE, INC.
|
|
Delaware
|
VALERO CANADA L.P.
|
|
Newfoundland
|
VALERO CAPITAL CORPORATION
|
|
Delaware
|
VALERO CARIBBEAN SERVICES COMPANY
|
|
Delaware
|
VALERO CLAIMS MANAGEMENT, INC.
|
|
Texas
|
VALERO COKER CORPORATION ARUBA N.V.
|
|
Aruba
|
VALERO CUSTOMS & TRADE SERVICES, INC.
|
|
Delaware
|
VALERO DIAMOND, L.P.
|
|
Texas
|
VALERO DIAMOND METRO, INC.
|
|
Michigan
|
VALERO ENERGY ARUBA II COMPANY
|
|
Cayman Islands
|
VALERO ENERGY CORPORATION (parent)
|
|
Delaware
|
VALERO ENERGY (IRELAND) LIMITED
|
|
Ireland
|
VALERO ENERGY LTD
|
|
England and Wales
|
VALERO EQUITY SERVICES LTD
|
|
England and Wales
|
VALERO FINANCE L.P. I
|
|
Newfoundland
|
VALERO FINANCE L.P. II
|
|
Newfoundland
|
VALERO FINANCE L.P. III
|
|
Newfoundland
|
VALERO GRAIN MARKETING, LLC
|
|
Texas
|
VALERO HOLDCO UK LTD
|
|
United Kingdom
|
VALERO HOLDINGS, INC.
|
|
Delaware
|
VALERO INTERNATIONAL HOLDINGS, INC.
|
|
Nevada
|
VALERO LUX COMPANY I S.à r.l.
|
|
Luxembourg
|
VALERO LUX COMPANY II S.à r.l.
|
|
Luxembourg
|
VALERO MARKETING & SUPPLY-ARUBA N.V.
|
|
Aruba
|
VALERO MARKETING AND SUPPLY COMPANY
|
|
Delaware
|
VALERO MARKETING AND SUPPLY INTERNATIONAL LTD.
|
|
Cayman Islands
|
VALERO MISSION COMPANY, LLC
|
|
Delaware
|
VALERO MKS LOGISTICS, L.L.C.
|
|
Delaware
|
VALERO MOSELLE COMPANY S.à r.l.
|
|
Luxembourg
|
VALERO NEDERLAND COÖPERATIEF U.A.
|
|
The Netherlands
|
VALERO NEW AMSTERDAM B.V.
|
|
The Netherlands
|
VALERO OMEGA COMPANY, L.L.C.
|
|
Delaware
|
VALERO OPERATIONS SUPPORT, LTD
|
|
England and Wales
|
VALERO PAYMENT SERVICES COMPANY
|
|
Virginia
|
VALERO PEMBROKESHIRE LLC
|
|
Delaware
|
VALERO POWER MARKETING COMPANY
|
|
Delaware
|
VALERO REFINING AND MARKETING COMPANY
|
|
Delaware
|
VALERO REFINING COMPANY-ARUBA N.V.
|
|
Aruba
|
VALERO REFINING COMPANY-CALIFORNIA
|
|
Delaware
|
VALERO REFINING COMPANY-OKLAHOMA
|
|
Michigan
|
VALERO REFINING COMPANY-TENNESSEE, L.L.C.
|
|
Delaware
|
VALERO REFINING-MERAUX LLC
|
|
Delaware
|
VALERO REFINING-NEW ORLEANS, L.L.C.
|
|
Delaware
|
VALERO REFINING-TEXAS, L.P.
|
|
Texas
|
VALERO RENEWABLE FUELS COMPANY, LLC
|
|
Texas
|
VALERO RETAIL HOLDINGS, INC.
|
|
Delaware
|
VALERO SECURITY SYSTEMS, INC.
|
|
Delaware
|
VALERO SERVICES, INC.
|
|
Delaware
|
VALERO TERMINALING AND DISTRIBUTION COMPANY
|
|
Delaware
|
VALERO TEXAS POWER MARKETING, INC.
|
|
Delaware
|
VALERO UK LTD
|
|
United Kingdom
|
VALERO ULTRAMAR HOLDINGS INC.
|
|
Delaware
|
VALERO UNIT INVESTMENTS, L.L.C.
|
|
Delaware
|
VALERO WEST WALES LLC
|
|
Delaware
|
VALLEY SHAMROCK, INC.
|
|
Texas
|
VEC TRUST I
|
|
Delaware
|
VEC TRUST III
|
|
Delaware
|
VEC TRUST IV
|
|
Delaware
|
VRG PROPERTIES COMPANY
|
|
Delaware
|
VTD PROPERTIES COMPANY
|
|
Delaware
|
/s/ William R. Klesse
|
|
|
William R. Klesse
Chief Executive Officer and President
|
|
|
/s/ Michael S. Ciskowski
|
|
|
Michael S. Ciskowski
Executive Vice President and Chief Financial Officer
|
|
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ William R. Klesse
|
|
William R. Klesse
|
|
Chief Executive Officer and President
|
|
February 24, 2012
|
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Michael S. Ciskowski
|
|
Michael S. Ciskowski
|
|
Executive Vice President and Chief Financial Officer
|
|
February 24, 2012
|
|
•
|
the Audit Committee may pre-approve each particular service on a case-by-case basis (“
separate pre-approval
”), and
|
•
|
the Audit Committee may adopt a pre-approval policy that is detailed as to the particular types of services that may be provided by the independent auditor without consideration by the Audit Committee on a case-by-case basis (“
policy-based pre-approval
”).
|
•
|
Audit Services
|
•
|
Audit-Related Services
|
•
|
Tax Services
|
•
|
All Other Services
|
•
|
the annual financial statement audit, including all audits, reviews, procedures and other services required to be performed by the independent auditor to form an opinion on the Company's consolidated financial statements, and
|
•
|
the annual audit of the Company's internal control over financial reporting, including all services required to be performed by the independent auditor to issue its report on the effectiveness of the Company's internal control over financial reporting.
|
•
|
services associated with SEC registration statements (
e.g.
, comfort letters, consents), periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings,
|
•
|
statutory audits or financial audits for subsidiaries or affiliates of the Company.
|
•
|
employee benefit plan audits, and
|
•
|
due diligence services related to proposed mergers and acquisitions.
|
Service
|
assistance with and review of documents filed with the SEC including registration statements, reports on Forms 10-K and 10-Q, and other documents
|
services associated with other documents issued in connection with securities offerings (
e.g.
, comfort letters, consents)
|
assistance in responding to SEC comment letters
|
statutory audits (
e.g.
, FERC and insurance audits) and financial audits for subsidiaries of the Company, to include services normally provided by the Company's independent auditor in connection with statutory and regulatory filings
|
certificates, letters and opinions issued to regulators, agencies and other third-parties (
e.g.
, insurance, banking, environmental) regarding the Company's assets and/or operations that only the Company's independent auditors reasonably can provide
|
consultations concerning principles of accounting and/or financial reporting treatment under standards or interpretations by the SEC, PCAOB, FASB or other regulatory or standard-setting bodies necessary to reach an audit judgment and/or opinion on the Company's financial statements
|
Annual pre-approval fee limit for Audit Services (other than services pertaining to registration statements or prospectuses in connection with securities offerings)
$500,000
|
Annual pre-approval fee limit for Audit Services pertaining to registration statements or prospectuses in connection with securities offerings
$250,000 per registration statement or prospectus
|
Service
|
due diligence services pertaining to potential business acquisitions or dispositions
|
financial statement audits of employee benefit plans
|
accounting consultations and audits in connection with acquisitions
|
consultations concerning principles of accounting and/or financial reporting treatment under standards or interpretations by the SEC, PCAOB, FASB or other regulatory or standard-setting bodies
outside
those consultations necessary to perform an audit or review of Valero's financial statements in accordance with generally accepted auditing standards
|
|
Annual pre-approval fee limit for Audit-Related Services
$500,000
|
Service
Note
: The following are subject to the terms of subsection C. of Section V. of this policy.
|
U.S. federal, state and local tax compliance, including the preparation of original and amended tax returns and claims for refunds
|
U.S. federal, state and local tax planning and advice, including assistance with tax audits and appeals (but expressly excluding advocacy or litigation services), tax advice related to mergers and acquisitions, tax advice relating to employee benefit plans, and requests for rulings or technical advice from taxing authorities
|
review of Canadian federal and provincial income tax returns
|
Canadian federal and provincial tax planning and advice, including assistance with tax audits and appeals (but expressly excluding advocacy or litigation services), and advice relating to the tax effects of certain employee benefit arrangements
|
review of federal, state, local and international income, franchise, and other tax returns
|
|
Annual pre-approval fee limit for Tax Services
$250,000
|
Services
|
none
|
|
Annual pre-approval fee limit for All Other Services
$ 0
|
•
|
Bookkeeping or other services related to the accounting records or financial statements of the audit client*
|
•
|
Financial information systems design and implementation*
|
•
|
Appraisal or valuation services, fairness opinions or contribution-in-kind reports*
|
•
|
Actuarial services*
|
•
|
Internal audit outsourcing services*
|
•
|
Management functions
|
•
|
Human resources
|
•
|
Broker-dealer, investment adviser or investment banking services
|
•
|
Legal services
|
•
|
Expert services unrelated to the audit
|
*
|
Provision of these non-audit services may be permitted if it is reasonable to conclude that the results of these services will not be subject to audit procedures. Materiality is not an appropriate basis upon which to overcome the rebuttable presumption that prohibited services will be subject to audit procedures.
|