R
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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
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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 2014 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 2013, KPMG Fees for Fiscal Year 2012,
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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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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350,000
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St. Charles
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Louisiana
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280,000
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Texas City
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Texas
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250,000
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Aruba
(c)
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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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165,000
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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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1,840,000
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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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3,105,000
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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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(c)
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The operations of the Aruba Refinery were suspended in March 2012. For further discussion of this matter, see
Note 4
in Notes to Consolidated Financial Statements.
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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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36
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%
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sweet crude oil
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39
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%
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residual fuel oil
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10
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%
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other feedstocks
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4
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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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48
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%
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distillates
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36
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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 petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt)
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13
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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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46
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%
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sweet crude oil
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20
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%
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residual fuel oil
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17
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%
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other feedstocks
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4
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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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45
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%
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distillates
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36
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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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15
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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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8
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%
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sweet crude oil
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83
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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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55
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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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5
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%
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Combined North Atlantic Region Charges and Yields
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Charges:
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sour crude oil
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6
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%
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sweet crude oil
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80
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%
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residual fuel oil
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6
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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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7
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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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70
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%
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sweet crude oil
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4
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%
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other feedstocks
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11
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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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59
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%
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distillates
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27
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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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14
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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 naphthenic 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 aromatics (benzene, toluene, and xylene) and two grades of propylene. Aromatics 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 serving the agricultural sector. Sulfur is used in manufacturing fertilizer.
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State
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City
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Ethanol Production
Capacity (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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120 million
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355,000
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42 million
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Iowa
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Albert City
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120 million
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355,000
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42 million
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Charles City
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125 million
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370,000
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44 million
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Fort Dodge
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125 million
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370,000
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44 million
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Hartley
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125 million
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370,000
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44 million
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Minnesota
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Welcome
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125 million
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370,000
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44 million
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Nebraska
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Albion
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120 million
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355,000
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42 million
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Ohio
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Bloomingburg
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120 million
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355,000
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42 million
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South Dakota
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Aurora
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125 million
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370,000
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44 million
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Wisconsin
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Jefferson
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100 million
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320,000
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37 million
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total
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1,205 million
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3,590,000
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425 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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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
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||||||||
Quarter Ended
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High
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Low
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|||||||
2013:
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December 31
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$
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50.40
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$
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33.73
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$
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0.225
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September 30
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37.13
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33.54
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0.225
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June 30
|
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44.97
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33.76
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0.200
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March 31
|
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48.51
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34.35
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|
0.200
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2012:
|
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||||||
December 31
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34.38
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28.20
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0.175
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|
|||
September 30
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33.75
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|
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23.64
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0.175
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June 30
|
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26.33
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20.37
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0.150
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March 31
|
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28.56
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19.61
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0.150
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Period
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Total Number
of Shares
Purchased
|
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Average
Price Paid
per Share
|
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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
|
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Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs (b)
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October 2013
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2,692,850
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$
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34.10
|
|
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85,708
|
|
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2,607,142
|
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$ 2.9 billion
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November 2013
|
|
2,413,232
|
|
|
$
|
41.76
|
|
|
343,227
|
|
|
2,070,005
|
|
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$ 2.8 billion
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December 2013
|
|
3,172,462
|
|
|
$
|
46.37
|
|
|
1,134
|
|
|
3,171,328
|
|
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$ 2.6 billion
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Total
|
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8,278,544
|
|
|
$
|
41.04
|
|
|
430,069
|
|
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7,848,475
|
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$ 2.6 billion
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(a)
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The shares reported in this column represent purchases settled in the fourth quarter of
2013
relating to (i) our purchases of shares in open-market transactions to meet our obligations under stock-based compensation plans, and (ii) 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 stock-based 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. During 2013, we completed the $6 billion program. On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program, which was in addition to the $6 billion program. This $3 billion program has no expiration date.
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|
12/2008
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12/2009
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12/2010
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12/2011
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12/2012
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12/2013
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||||||||||||
Valero Common Stock
|
$
|
100.00
|
|
|
$
|
79.77
|
|
|
$
|
111.31
|
|
|
$
|
102.57
|
|
|
$
|
170.45
|
|
|
$
|
281.24
|
|
S&P 500
|
100.00
|
|
|
126.46
|
|
|
145.51
|
|
|
148.59
|
|
|
172.37
|
|
|
228.19
|
|
||||||
Old Peer Group
|
100.00
|
|
|
126.98
|
|
|
122.17
|
|
|
127.90
|
|
|
138.09
|
|
|
170.45
|
|
||||||
New Peer Group
|
100.00
|
|
|
127.95
|
|
|
120.42
|
|
|
129.69
|
|
|
136.92
|
|
|
166.57
|
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1
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Assumes that an investment in Valero common stock and each index was $100 on
December 31, 2008
. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from
December 31, 2008
through
December 31, 2013
.
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Year Ended December 31,
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||||||||||||||||||
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2013 (a)
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2012 (b)
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2011 (c)
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2010 (d)
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2009 (d)
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||||||
Operating revenues
|
$
|
138,074
|
|
|
$
|
139,250
|
|
|
$
|
125,987
|
|
|
$
|
82,233
|
|
|
$
|
64,599
|
|
Income (loss) from
continuing operations
|
2,728
|
|
|
2,080
|
|
|
2,096
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|
|
923
|
|
|
(273
|
)
|
|||||
Earnings per common
share from continuing
operations – assuming dilution
|
4.97
|
|
|
3.75
|
|
|
3.69
|
|
|
1.62
|
|
|
(0.50
|
)
|
|||||
Dividends per common share
|
0.85
|
|
|
0.65
|
|
|
0.30
|
|
|
0.20
|
|
|
0.60
|
|
|||||
Total assets
|
47,260
|
|
|
44,477
|
|
|
42,783
|
|
|
37,621
|
|
|
35,572
|
|
|||||
Debt and capital lease
obligations, less current portion
|
6,261
|
|
|
6,463
|
|
|
6,732
|
|
|
7,515
|
|
|
7,163
|
|
(a)
|
Includes the operations of our retail business prior to its separation from us on May 1, 2013, as further described in
Note 3
of Notes to Consolidated Financial Statements.
|
(b)
|
The operations of the Aruba Refinery were suspended in March 2012, as further described in
Note 4
of Notes to Consolidated Financial Statements.
|
(c)
|
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.
|
(d)
|
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 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, 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, 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 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 level 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,
|
||||||||||
|
|
2013
|
|
2012
|
|
Change
|
||||||
Operating income (loss) by business segment:
|
|
|
|
|
|
|
||||||
Refining
|
|
$
|
4,217
|
|
|
$
|
4,450
|
|
|
$
|
(233
|
)
|
Retail
|
|
81
|
|
|
348
|
|
|
(267
|
)
|
|||
Ethanol
|
|
491
|
|
|
(47
|
)
|
|
538
|
|
|||
Corporate
|
|
(826
|
)
|
|
(741
|
)
|
|
(85
|
)
|
|||
Total
|
|
$
|
3,963
|
|
|
$
|
4,010
|
|
|
$
|
(47
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2013 (a)
|
|
2012
|
|
Change
|
||||||
Operating revenues
|
$
|
138,074
|
|
|
$
|
139,250
|
|
|
$
|
(1,176
|
)
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
127,316
|
|
|
127,268
|
|
|
48
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining (b)
|
3,704
|
|
|
3,668
|
|
|
36
|
|
|||
Retail
|
226
|
|
|
686
|
|
|
(460
|
)
|
|||
Ethanol
|
387
|
|
|
332
|
|
|
55
|
|
|||
General and administrative expenses
|
758
|
|
|
698
|
|
|
60
|
|
|||
Depreciation and amortization expense:
|
|
|
|
|
|
||||||
Refining
|
1,566
|
|
|
1,370
|
|
|
196
|
|
|||
Retail
|
41
|
|
|
119
|
|
|
(78
|
)
|
|||
Ethanol
|
45
|
|
|
42
|
|
|
3
|
|
|||
Corporate
|
68
|
|
|
43
|
|
|
25
|
|
|||
Asset impairment losses (c)
|
—
|
|
|
1,014
|
|
|
(1,014
|
)
|
|||
Total costs and expenses
|
134,111
|
|
|
135,240
|
|
|
(1,129
|
)
|
|||
Operating income
|
3,963
|
|
|
4,010
|
|
|
(47
|
)
|
|||
Gain on disposition of retained interest in CST Brands, Inc. (a)
|
325
|
|
|
—
|
|
|
325
|
|
|||
Other income, net
|
59
|
|
|
9
|
|
|
50
|
|
|||
Interest and debt expense, net of capitalized interest
|
(365
|
)
|
|
(313
|
)
|
|
(52
|
)
|
|||
Income before income tax expense
|
3,982
|
|
|
3,706
|
|
|
276
|
|
|||
Income tax expense
|
1,254
|
|
|
1,626
|
|
|
(372
|
)
|
|||
Net income
|
2,728
|
|
|
2,080
|
|
|
648
|
|
|||
Less: Net income (loss) attributable to noncontrolling interests
|
8
|
|
|
(3
|
)
|
|
11
|
|
|||
Net income attributable to Valero stockholders
|
$
|
2,720
|
|
|
$
|
2,083
|
|
|
$
|
637
|
|
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution
|
$
|
4.97
|
|
|
$
|
3.75
|
|
|
$
|
1.22
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
Change
|
||||||
Refining (b) (c):
|
|
|
|
|
|
||||||
Operating income
|
$
|
4,217
|
|
|
$
|
4,450
|
|
|
$
|
(233
|
)
|
Throughput margin per barrel (e)
|
$
|
9.69
|
|
|
$
|
10.96
|
|
|
$
|
(1.27
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.78
|
|
|
3.79
|
|
|
(0.01
|
)
|
|||
Depreciation and amortization expense
|
1.60
|
|
|
1.44
|
|
|
0.16
|
|
|||
Total operating costs per barrel
|
5.38
|
|
|
5.23
|
|
|
0.15
|
|
|||
Operating income per barrel
|
$
|
4.31
|
|
|
$
|
5.73
|
|
|
$
|
(1.42
|
)
|
|
|
|
|
|
|
||||||
Throughput volumes (thousand BPD):
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude
|
486
|
|
|
453
|
|
|
33
|
|
|||
Medium/light sour crude
|
466
|
|
|
547
|
|
|
(81
|
)
|
|||
Sweet crude
|
1,039
|
|
|
991
|
|
|
48
|
|
|||
Residuals
|
282
|
|
|
200
|
|
|
82
|
|
|||
Other feedstocks
|
106
|
|
|
120
|
|
|
(14
|
)
|
|||
Total feedstocks
|
2,379
|
|
|
2,311
|
|
|
68
|
|
|||
Blendstocks and other
|
303
|
|
|
302
|
|
|
1
|
|
|||
Total throughput volumes
|
2,682
|
|
|
2,613
|
|
|
69
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD):
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,287
|
|
|
1,251
|
|
|
36
|
|
|||
Distillates
|
984
|
|
|
918
|
|
|
66
|
|
|||
Other products (f)
|
440
|
|
|
467
|
|
|
(27
|
)
|
|||
Total yields
|
2,711
|
|
|
2,636
|
|
|
75
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
Change
|
||||||
U.S. Gulf Coast (b) (c):
|
|
|
|
|
|
||||||
Operating income
|
$
|
2,381
|
|
|
$
|
2,541
|
|
|
$
|
(160
|
)
|
Throughput volumes (thousand BPD)
|
1,523
|
|
|
1,488
|
|
|
35
|
|
|||
Throughput margin per barrel (e)
|
$
|
9.57
|
|
|
$
|
9.65
|
|
|
$
|
(0.08
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.66
|
|
|
3.55
|
|
|
0.11
|
|
|||
Depreciation and amortization expense
|
1.63
|
|
|
1.44
|
|
|
0.19
|
|
|||
Total operating costs per barrel
|
5.29
|
|
|
4.99
|
|
|
0.30
|
|
|||
Operating income per barrel
|
$
|
4.28
|
|
|
$
|
4.66
|
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
|
||||||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Operating income
|
$
|
1,293
|
|
|
$
|
2,044
|
|
|
$
|
(751
|
)
|
Throughput volumes (thousand BPD)
|
435
|
|
|
430
|
|
|
5
|
|
|||
Throughput margin per barrel (e)
|
$
|
13.37
|
|
|
$
|
18.49
|
|
|
$
|
(5.12
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.58
|
|
|
4.02
|
|
|
(0.44
|
)
|
|||
Depreciation and amortization expense
|
1.64
|
|
|
1.48
|
|
|
0.16
|
|
|||
Total operating costs per barrel
|
5.22
|
|
|
5.50
|
|
|
(0.28
|
)
|
|||
Operating income per barrel
|
$
|
8.15
|
|
|
$
|
12.99
|
|
|
$
|
(4.84
|
)
|
|
|
|
|
|
|
||||||
North Atlantic:
|
|
|
|
|
|
||||||
Operating income
|
$
|
570
|
|
|
$
|
752
|
|
|
$
|
(182
|
)
|
Throughput volumes (thousand BPD)
|
459
|
|
|
428
|
|
|
31
|
|
|||
Throughput margin per barrel (e)
|
$
|
7.93
|
|
|
$
|
9.24
|
|
|
$
|
(1.31
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.50
|
|
|
3.59
|
|
|
(0.09
|
)
|
|||
Depreciation and amortization expense
|
1.03
|
|
|
0.85
|
|
|
0.18
|
|
|||
Total operating costs per barrel
|
4.53
|
|
|
4.44
|
|
|
0.09
|
|
|||
Operating income per barrel
|
$
|
3.40
|
|
|
$
|
4.80
|
|
|
$
|
(1.40
|
)
|
|
|
|
|
|
|
||||||
U.S. West Coast:
|
|
|
|
|
|
||||||
Operating income (loss)
|
$
|
(27
|
)
|
|
$
|
147
|
|
|
$
|
(174
|
)
|
Throughput volumes (thousand BPD)
|
265
|
|
|
267
|
|
|
(2
|
)
|
|||
Throughput margin per barrel (e)
|
$
|
7.43
|
|
|
$
|
8.84
|
|
|
$
|
(1.41
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
5.35
|
|
|
5.09
|
|
|
0.26
|
|
|||
Depreciation and amortization expense
|
2.35
|
|
|
2.25
|
|
|
0.10
|
|
|||
Total operating costs per barrel
|
7.70
|
|
|
7.34
|
|
|
0.36
|
|
|||
Operating income (loss) per barrel
|
$
|
(0.27
|
)
|
|
$
|
1.50
|
|
|
$
|
(1.77
|
)
|
|
|
|
|
|
|
||||||
Operating income for regions above
|
$
|
4,217
|
|
|
$
|
5,484
|
|
|
$
|
(1,267
|
)
|
Severance expense (b)
|
—
|
|
|
(41
|
)
|
|
41
|
|
|||
Asset impairment losses (c)
|
—
|
|
|
(993
|
)
|
|
993
|
|
|||
Total refining operating income
|
$
|
4,217
|
|
|
$
|
4,450
|
|
|
$
|
(233
|
)
|
|
Year Ended December 31,
|
|||||||||
|
2013
|
|
2012
|
|
Change
|
|||||
Feedstocks:
|
|
|
|
|
|
|||||
Brent crude oil
|
$
|
108.74
|
|
|
$
|
111.70
|
|
|
(2.96
|
)
|
Brent less West Texas Intermediate (WTI) crude oil
|
10.80
|
|
|
17.55
|
|
|
(6.75
|
)
|
||
Brent less Alaska North Slope (ANS) crude oil
|
1.00
|
|
|
1.08
|
|
|
(0.08
|
)
|
||
Brent less Louisiana Light Sweet (LLS) crude oil
|
0.41
|
|
|
(0.91
|
)
|
|
1.32
|
|
||
Brent less Mars crude oil
|
5.52
|
|
|
3.97
|
|
|
1.55
|
|
||
Brent less Maya crude oil
|
11.31
|
|
|
12.06
|
|
|
(0.75
|
)
|
||
LLS crude oil
|
108.33
|
|
|
112.61
|
|
|
(4.28
|
)
|
||
LLS less Mars crude oil
|
5.11
|
|
|
4.88
|
|
|
0.23
|
|
||
LLS less Maya crude oil
|
10.90
|
|
|
12.97
|
|
|
(2.07
|
)
|
||
WTI crude oil
|
97.94
|
|
|
94.15
|
|
|
3.79
|
|
||
|
|
|
|
|
|
|||||
Natural gas (dollars per million British thermal units)
|
3.69
|
|
|
2.71
|
|
|
0.98
|
|
||
|
|
|
|
|
|
|||||
Products:
|
|
|
|
|
|
|||||
U.S. Gulf Coast:
|
|
|
|
|
|
|||||
CBOB gasoline less Brent
|
2.69
|
|
|
4.89
|
|
|
(2.20
|
)
|
||
Ultra-low-sulfur diesel less Brent
|
15.95
|
|
|
16.48
|
|
|
(0.53
|
)
|
||
Propylene less Brent
|
(2.72
|
)
|
|
(22.38
|
)
|
|
19.66
|
|
||
CBOB gasoline less LLS
|
3.10
|
|
|
3.98
|
|
|
(0.88
|
)
|
||
Ultra-low-sulfur diesel less LLS
|
16.36
|
|
|
15.57
|
|
|
0.79
|
|
||
Propylene less LLS
|
(2.31
|
)
|
|
(23.29
|
)
|
|
20.98
|
|
||
U.S. Mid-Continent:
|
|
|
|
|
|
|||||
CBOB gasoline less WTI (d)
|
16.77
|
|
|
25.40
|
|
|
(8.63
|
)
|
||
Ultra-low-sulfur diesel less WTI
|
28.33
|
|
|
34.96
|
|
|
(6.63
|
)
|
||
North Atlantic:
|
|
|
|
|
|
|||||
CBOB gasoline less Brent
|
8.50
|
|
|
10.66
|
|
|
(2.16
|
)
|
||
Ultra-low-sulfur diesel less Brent
|
17.84
|
|
|
19.06
|
|
|
(1.22
|
)
|
||
U.S. West Coast:
|
|
|
|
|
|
|||||
CARBOB 87 gasoline less ANS
|
12.69
|
|
|
15.39
|
|
|
(2.70
|
)
|
||
CARB diesel less ANS
|
18.83
|
|
|
19.93
|
|
|
(1.10
|
)
|
||
CARBOB 87 gasoline less WTI
|
22.49
|
|
|
31.86
|
|
|
(9.37
|
)
|
||
CARB diesel less WTI
|
28.63
|
|
|
36.40
|
|
|
(7.77
|
)
|
||
New York Harbor corn crush (dollars per gallon)
|
0.42
|
|
|
(0.15
|
)
|
|
0.57
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
Change
|
||||||
Retail:
|
|
|
|
|
|
||||||
Operating income (a) (c)
|
$
|
81
|
|
|
$
|
348
|
|
|
$
|
(267
|
)
|
|
|
|
|
|
|
||||||
Ethanol:
|
|
|
|
|
|
||||||
Operating income (loss)
|
$
|
491
|
|
|
$
|
(47
|
)
|
|
$
|
538
|
|
Ethanol production (thousand gallons per day)
|
3,294
|
|
|
2,967
|
|
|
327
|
|
|||
Gross margin per gallon of production (e)
|
$
|
0.77
|
|
|
$
|
0.30
|
|
|
$
|
0.47
|
|
Operating costs per gallon of production:
|
|
|
|
|
|
||||||
Operating expenses
|
0.32
|
|
|
0.30
|
|
|
0.02
|
|
|||
Depreciation and amortization expense
|
0.04
|
|
|
0.04
|
|
|
—
|
|
|||
Total operating costs per gallon of production
|
0.36
|
|
|
0.34
|
|
|
0.02
|
|
|||
Operating income (loss) per gallon of production
|
$
|
0.41
|
|
|
$
|
(0.04
|
)
|
|
$
|
0.45
|
|
(a)
|
On May 1, 2013, we completed the separation of our retail business by spinning off 80 percent of CST. This transaction is more fully discussed in
Note 3
of Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us through November 14, 2013, which is reflected in “other income, net” for the year ended
December 31, 2013
. The nature and significance of our post-separation participation in the supply of motor fuel to CST represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations related to CST have not been reported as discontinued operations in the statements of income. In October 2013, we borrowed $525 million under a short-term debt agreement with a third-party financial institution in anticipation of liquidating our retained interest in CST. This liquidation was completed on November 14, 2013 by transferring all remaining shares of CST common stock owned by us to the financial institution in exchange for $467 million of our short-term debt, and we paid the remaining $58 million of short-term debt in cash. After paying $19 million of fees, we recognized a $325 million nontaxable gain.
|
(b)
|
In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. The reorganization resulted in the termination of the majority of our employees in Aruba, and we recognized severance expense of $41 million in September 2012. This expense is reflected in refining segment operating income for the year ended December 31, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.
|
(c)
|
Asset impairment losses for the year ended December 31, 2012 include a $928 million loss on the write-down of the Aruba Refinery. In addition, we recorded asset impairment losses of $65 million ($42 million after taxes) related to equipment associated with permanently cancelled capital projects at several of our refineries and $21 million ($13 million after taxes) related to certain retail stores in 2012 that we owned prior to the separation of our retail business. The total asset impairment losses of $1.0 billion are reflected in the operating income of the respective segments for the year ended December 31, 2012, but the asset impairment losses associated with the Aruba Refinery and the cancelled capital projects are excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.
|
(d)
|
U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 from Conventional 87 gasoline to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are now being provided for all periods presented.
|
(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, sulfur, and asphalt.
|
(g)
|
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Aruba, Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.
|
•
|
Decrease in gasoline margins
- We experienced a decline in gasoline margins throughout all of our regions during
2013
compared to
2012
. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was
$16.77
per barrel during
2013
compared to
$25.40
per barrel during
2012
, representing an unfavorable decrease of
$8.63
per barrel. We estimate that the decline in gasoline margins per barrel during
2013
compared to
2012
had a negative impact to our refining margin of approximately $790 million for all refining regions.
|
•
|
Lower discounts on WTI-type crude oils in the U.S. Mid-Continent region
- Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. In
2013
, the discount in the price of WTI compared to the price of Brent crude oil narrowed compared to
2012
. WTI crude oil sold at a discount of
$10.80
per barrel to Brent crude oil in
2013
compared to a discount of
$17.55
per barrel in
2012
, representing an unfavorable decrease of
$6.75
per barrel. Therefore, the lower discount on WTI-type crude oils that we processed negatively impacted our refining margin. We estimate that the decrease in the discounts for WTI-type crude oils that we processed during
2013
reduced our refining margin by approximately $640 million.
|
•
|
Higher costs of biofuel credits
- As more fully described in
Note 21
of Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $267 million from
$250 million
in
2012
to
$517 million
in
2013
. This increase was due to an increase in the market price of RINs caused by an expectation in the market of a shortage in available RINs.
|
•
|
Increase in distillate margins
- Despite lower distillate prices throughout all of our regions during
2013
compared to
2012
, we experienced an increase in distillate margins during
2013
compared to
2012
as a
|
•
|
Higher discounts on medium sour crude oils
- In
2013
, the discount in the price of medium
sour crude oils compared to the price of Brent crude oil widened. For example, Mars crude oil, which is a medium sour crude oil, sold at a discount of
$5.52
per barrel to Brent crude oil in
2013
compared to a discount of
$3.97
per barrel during
2012
, representing a favorable increase of
$1.55
per barrel.Therefore, the higher discounts on the medium sour crude oils we processed favorably impacted our refining margin. We estimate that the increase in the discounts for medium sour crude oils that we processed during
2013
had a favorable impact to our refining margin of approximately $260 million.
|
•
|
Lower corn prices
- Corn prices decreased year over year as many of the corn-producing regions of the U.S. Mid-Continent recovered from a drought that began in the second quarter of 2012. For example, the Chicago Board of Trade corn price was $5.80 per bushel in
2013
compared to $6.94 per bushel in
2012
. The decrease in the price of corn that we processed during
2013
favorably impacted our ethanol margin by approximately $290 million.
|
•
|
Higher ethanol prices
- Ethanol prices increased year over year due to a decrease in the supply of ethanol in the market. The decrease in supply resulted from reduced production in 2012 and early 2013 as the industry responded to a narrowing of ethanol gross margin per gallon, which were due to higher corn prices primarily caused by the drought in the corn-producing regions of the U.S. Mid-
|
•
|
Increased production volumes
- Ethanol margin also improved due to increased production volumes between the years of
327,000
gallons per day in
2013
compared to
2012
in response to the improved ethanol gross margin per gallon. The increase in production volumes during
2013
had a favorable impact to our ethanol gross margin of approximately $85 million.
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
Operating revenues
|
$
|
139,250
|
|
|
$
|
125,987
|
|
|
$
|
13,263
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales (c)
|
127,268
|
|
|
115,719
|
|
|
11,549
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining (d)
|
3,668
|
|
|
3,406
|
|
|
262
|
|
|||
Retail
|
686
|
|
|
678
|
|
|
8
|
|
|||
Ethanol
|
332
|
|
|
399
|
|
|
(67
|
)
|
|||
General and administrative expenses
|
698
|
|
|
571
|
|
|
127
|
|
|||
Depreciation and amortization expense:
|
|
|
|
|
|
||||||
Refining
|
1,370
|
|
|
1,338
|
|
|
32
|
|
|||
Retail
|
119
|
|
|
115
|
|
|
4
|
|
|||
Ethanol
|
42
|
|
|
39
|
|
|
3
|
|
|||
Corporate
|
43
|
|
|
42
|
|
|
1
|
|
|||
Asset impairment loss (e)
|
1,014
|
|
|
—
|
|
|
1,014
|
|
|||
Total costs and expenses
|
135,240
|
|
|
122,307
|
|
|
12,933
|
|
|||
Operating income
|
4,010
|
|
|
3,680
|
|
|
330
|
|
|||
Other income, net
|
9
|
|
|
43
|
|
|
(34
|
)
|
|||
Interest and debt expense, net of capitalized interest
|
(313
|
)
|
|
(401
|
)
|
|
88
|
|
|||
Income from continuing operations
before income tax expense
|
3,706
|
|
|
3,322
|
|
|
384
|
|
|||
Income tax expense
|
1,626
|
|
|
1,226
|
|
|
400
|
|
|||
Income from continuing operations
|
2,080
|
|
|
2,096
|
|
|
(16
|
)
|
|||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
(7
|
)
|
|
7
|
|
|||
Net income
|
2,080
|
|
|
2,089
|
|
|
(9
|
)
|
|||
Less: Net loss attributable to noncontrolling interest
|
(3
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|||
Net income attributable to Valero stockholders
|
$
|
2,083
|
|
|
$
|
2,090
|
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
||||||
Net income attributable to Valero stockholders:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
2,083
|
|
|
$
|
2,097
|
|
|
$
|
(14
|
)
|
Discontinued operations
|
—
|
|
|
(7
|
)
|
|
7
|
|
|||
Total
|
$
|
2,083
|
|
|
$
|
2,090
|
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
3.75
|
|
|
$
|
3.69
|
|
|
$
|
0.06
|
|
Discontinued operations
|
—
|
|
|
(0.01
|
)
|
|
0.01
|
|
|||
Total
|
$
|
3.75
|
|
|
$
|
3.68
|
|
|
$
|
0.07
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
Refining (a) (b):
|
|
|
|
|
|
||||||
Operating income (c) (d) (e)
|
$
|
4,450
|
|
|
$
|
3,516
|
|
|
$
|
934
|
|
Throughput margin per barrel (c) (f)
|
$
|
10.96
|
|
|
$
|
9.91
|
|
|
$
|
1.05
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses (d)
|
3.79
|
|
|
3.83
|
|
|
(0.04
|
)
|
|||
Depreciation and amortization expense
|
1.44
|
|
|
1.51
|
|
|
(0.07
|
)
|
|||
Total operating costs per barrel (e)
|
5.23
|
|
|
5.34
|
|
|
(0.11
|
)
|
|||
Operating income per barrel
|
$
|
5.73
|
|
|
$
|
4.57
|
|
|
$
|
1.16
|
|
|
|
|
|
|
|
||||||
Throughput volumes (thousand BPD):
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude
|
453
|
|
|
454
|
|
|
(1
|
)
|
|||
Medium/light sour crude
|
547
|
|
|
442
|
|
|
105
|
|
|||
Sweet crude
|
991
|
|
|
861
|
|
|
130
|
|
|||
Residuals
|
200
|
|
|
282
|
|
|
(82
|
)
|
|||
Other feedstocks
|
120
|
|
|
122
|
|
|
(2
|
)
|
|||
Total feedstocks
|
2,311
|
|
|
2,161
|
|
|
150
|
|
|||
Blendstocks and other
|
302
|
|
|
273
|
|
|
29
|
|
|||
Total throughput volumes
|
2,613
|
|
|
2,434
|
|
|
179
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD):
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,251
|
|
|
1,120
|
|
|
131
|
|
|||
Distillates
|
918
|
|
|
834
|
|
|
84
|
|
|||
Other products (g)
|
467
|
|
|
494
|
|
|
(27
|
)
|
|||
Total yields
|
2,636
|
|
|
2,448
|
|
|
188
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
U.S. Gulf Coast (a):
|
|
|
|
|
|
||||||
Operating income (c) (d) (e)
|
$
|
2,541
|
|
|
$
|
2,205
|
|
|
$
|
336
|
|
Throughput volumes (thousand BPD)
|
1,488
|
|
|
1,450
|
|
|
38
|
|
|||
Throughput margin per barrel (c) (f)
|
$
|
9.65
|
|
|
$
|
9.33
|
|
|
$
|
0.32
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses (d)
|
3.55
|
|
|
3.66
|
|
|
(0.11
|
)
|
|||
Depreciation and amortization expense
|
1.44
|
|
|
1.50
|
|
|
(0.06
|
)
|
|||
Total operating costs per barrel (d) (e)
|
4.99
|
|
|
5.16
|
|
|
(0.17
|
)
|
|||
Operating income per barrel
|
$
|
4.66
|
|
|
$
|
4.17
|
|
|
$
|
0.49
|
|
|
|
|
|
|
|
||||||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
Operating income (c)
|
$
|
2,044
|
|
|
$
|
1,535
|
|
|
$
|
509
|
|
Throughput volumes (thousand BPD)
|
430
|
|
|
411
|
|
|
19
|
|
|||
Throughput margin per barrel (c) (f)
|
$
|
18.49
|
|
|
$
|
15.91
|
|
|
$
|
2.58
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
4.02
|
|
|
4.15
|
|
|
(0.13
|
)
|
|||
Depreciation and amortization expense
|
1.48
|
|
|
1.52
|
|
|
(0.04
|
)
|
|||
Total operating costs per barrel
|
5.50
|
|
|
5.67
|
|
|
(0.17
|
)
|
|||
Operating income per barrel
|
$
|
12.99
|
|
|
$
|
10.24
|
|
|
$
|
2.75
|
|
|
|
|
|
|
|
||||||
North Atlantic (b):
|
|
|
|
|
|
||||||
Operating income
|
$
|
752
|
|
|
$
|
171
|
|
|
$
|
581
|
|
Throughput volumes (thousand BPD)
|
428
|
|
|
317
|
|
|
111
|
|
|||
Throughput margin per barrel (f)
|
$
|
9.24
|
|
|
$
|
5.43
|
|
|
$
|
3.81
|
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
3.59
|
|
|
3.08
|
|
|
0.51
|
|
|||
Depreciation and amortization expense
|
0.85
|
|
|
0.87
|
|
|
(0.02
|
)
|
|||
Total operating costs per barrel
|
4.44
|
|
|
3.95
|
|
|
0.49
|
|
|||
Operating income per barrel
|
$
|
4.80
|
|
|
$
|
1.48
|
|
|
$
|
3.32
|
|
|
|
|
|
|
|
||||||
U.S. West Coast:
|
|
|
|
|
|
||||||
Operating income (c)
|
$
|
147
|
|
|
$
|
147
|
|
|
$
|
—
|
|
Throughput volumes (thousand BPD)
|
267
|
|
|
256
|
|
|
11
|
|
|||
Throughput margin per barrel (c) (f)
|
$
|
8.84
|
|
|
$
|
9.11
|
|
|
$
|
(0.27
|
)
|
Operating costs per barrel:
|
|
|
|
|
|
||||||
Operating expenses
|
5.09
|
|
|
5.25
|
|
|
(0.16
|
)
|
|||
Depreciation and amortization expense
|
2.25
|
|
|
2.29
|
|
|
(0.04
|
)
|
|||
Total operating costs per barrel
|
7.34
|
|
|
7.54
|
|
|
(0.20
|
)
|
|||
Operating income per barrel
|
$
|
1.50
|
|
|
$
|
1.57
|
|
|
$
|
(0.07
|
)
|
|
|
|
|
|
|
||||||
Operating income for regions above
|
$
|
5,484
|
|
|
$
|
4,058
|
|
|
$
|
1,426
|
|
Loss on derivative contracts related to the forward sales of refined product (c)
|
—
|
|
|
(542
|
)
|
|
542
|
|
|||
Severance expense (d)
|
(41
|
)
|
|
—
|
|
|
(41
|
)
|
|||
Asset impairment loss applicable to refining (e)
|
(993
|
)
|
|
—
|
|
|
(993
|
)
|
|||
Total refining operating income
|
$
|
4,450
|
|
|
$
|
3,516
|
|
|
$
|
934
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Brent crude oil
|
$
|
111.70
|
|
|
$
|
110.93
|
|
|
$
|
0.77
|
|
Brent less WTI crude oil
|
17.55
|
|
|
15.88
|
|
|
1.67
|
|
|||
Brent less ANS crude oil
|
1.08
|
|
|
1.39
|
|
|
(0.31
|
)
|
|||
Brent less LLS crude oil
|
(0.91
|
)
|
|
(0.54
|
)
|
|
(0.37
|
)
|
|||
Brent less Mars crude oil
|
3.97
|
|
|
3.46
|
|
|
0.51
|
|
|||
Brent less Maya crude oil
|
12.06
|
|
|
12.18
|
|
|
(0.12
|
)
|
|||
LLS crude oil
|
112.61
|
|
|
111.47
|
|
|
1.14
|
|
|||
LLS less Mars crude oil
|
4.88
|
|
|
4.00
|
|
|
0.88
|
|
|||
LLS less Maya crude oil
|
12.97
|
|
|
12.72
|
|
|
0.25
|
|
|||
WTI crude oil
|
94.15
|
|
|
95.05
|
|
|
(0.90
|
)
|
|||
|
|
|
|
|
|
||||||
Natural gas (dollars per million British thermal units)
|
2.71
|
|
|
3.96
|
|
|
(1.25
|
)
|
|||
|
|
|
|
|
|
||||||
Products:
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
4.89
|
|
|
5.17
|
|
|
(0.28
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
16.48
|
|
|
13.78
|
|
|
2.70
|
|
|||
Propylene less Brent
|
(22.38
|
)
|
|
8.23
|
|
|
(30.61
|
)
|
|||
CBOB gasoline less LLS
|
3.98
|
|
|
4.63
|
|
|
(0.65
|
)
|
|||
Ultra-low-sulfur diesel less LLS
|
15.57
|
|
|
13.24
|
|
|
2.33
|
|
|||
Propylene less LLS
|
(23.29
|
)
|
|
7.69
|
|
|
(30.98
|
)
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
CBOB gasoline less WTI (i)
|
25.40
|
|
|
22.37
|
|
|
3.03
|
|
|||
Ultra-low-sulfur diesel less WTI
|
34.96
|
|
|
31.06
|
|
|
3.90
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
10.66
|
|
|
5.95
|
|
|
4.71
|
|
|||
Ultra-low-sulfur diesel less Brent
|
19.06
|
|
|
15.64
|
|
|
3.42
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
CARBOB 87 gasoline less ANS
|
15.39
|
|
|
11.48
|
|
|
3.91
|
|
|||
CARB diesel less ANS
|
19.93
|
|
|
18.47
|
|
|
1.46
|
|
|||
CARBOB 87 gasoline less WTI
|
31.86
|
|
|
25.97
|
|
|
5.89
|
|
|||
CARB diesel less WTI
|
36.40
|
|
|
32.96
|
|
|
3.44
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
(0.15
|
)
|
|
0.25
|
|
|
(0.40
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
Retail–U.S.:
|
|
|
|
|
|
||||||
Operating income (e)
|
$
|
240
|
|
|
$
|
213
|
|
|
$
|
27
|
|
Company-operated fuel sites (average)
|
1,013
|
|
|
994
|
|
|
19
|
|
|||
Fuel volumes (gallons per day per site)
|
5,083
|
|
|
5,060
|
|
|
23
|
|
|||
Fuel margin per gallon
|
$
|
0.162
|
|
|
$
|
0.144
|
|
|
$
|
0.018
|
|
Merchandise sales
|
$
|
1,239
|
|
|
$
|
1,223
|
|
|
$
|
16
|
|
Merchandise margin (percentage of sales)
|
29.7
|
%
|
|
28.7
|
%
|
|
1.0
|
%
|
|||
Margin on miscellaneous sales
|
$
|
89
|
|
|
$
|
88
|
|
|
$
|
1
|
|
Operating expenses
|
$
|
434
|
|
|
$
|
416
|
|
|
$
|
18
|
|
Depreciation and amortization expense
|
$
|
77
|
|
|
$
|
77
|
|
|
$
|
—
|
|
Asset impairment loss (e)
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
|
|
|
|
|
||||||
Retail–Canada:
|
|
|
|
|
|
||||||
Operating income (e)
|
$
|
108
|
|
|
$
|
168
|
|
|
$
|
(60
|
)
|
Fuel volumes (thousand gallons per day)
|
3,096
|
|
|
3,195
|
|
|
(99
|
)
|
|||
Fuel margin per gallon
|
$
|
0.258
|
|
|
$
|
0.299
|
|
|
$
|
(0.041
|
)
|
Merchandise sales
|
$
|
257
|
|
|
$
|
261
|
|
|
$
|
(4
|
)
|
Merchandise margin (percentage of sales)
|
29.0
|
%
|
|
29.4
|
%
|
|
(0.4
|
)%
|
|||
Margin on miscellaneous sales
|
$
|
44
|
|
|
$
|
43
|
|
|
$
|
1
|
|
Operating expenses
|
$
|
252
|
|
|
$
|
262
|
|
|
$
|
(10
|
)
|
Depreciation and amortization expense
|
$
|
42
|
|
|
$
|
38
|
|
|
$
|
4
|
|
Asset impairment loss (e)
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
|
|
|
|
|
||||||
Ethanol:
|
|
|
|
|
|
||||||
Operating income (loss)
|
$
|
(47
|
)
|
|
$
|
396
|
|
|
$
|
(443
|
)
|
Ethanol production (thousand gallons per day)
|
2,967
|
|
|
3,352
|
|
|
(385
|
)
|
|||
Gross margin per gallon of production (f)
|
$
|
0.30
|
|
|
$
|
0.68
|
|
|
$
|
(0.38
|
)
|
Operating costs per gallon of production:
|
|
|
|
|
|
||||||
Operating expenses
|
0.30
|
|
|
0.33
|
|
|
(0.03
|
)
|
|||
Depreciation and amortization expense
|
0.04
|
|
|
0.03
|
|
|
0.01
|
|
|||
Total operating costs per gallon of production
|
0.34
|
|
|
0.36
|
|
|
(0.02
|
)
|
|||
Operating income (loss) per gallon of production
|
$
|
(0.04
|
)
|
|
$
|
0.32
|
|
|
$
|
(0.36
|
)
|
(a)
|
The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region reflect the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.
|
(b)
|
The financial highlights and operating highlights for the refining segment and North Atlantic region reflect 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.
|
(c)
|
Cost of sales for the year ended December 31, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. This loss is reflected in refining segment operating income for the year ended December 31, 2011, but throughput margin per barrel for the refining segment excludes this $542 million loss ($0.61 per barrel). In addition, operating income and throughput margin per barrel for the U.S. Gulf Coast, the U.S. Mid-Continent, and the U.S. West Coast regions for the year ended December 31, 2011 exclude the portion of this loss that had been allocated to them of $372 million ($0.70 per barrel), $122 million ($0.81 per barrel), and $48 million ($0.51 per barrel), respectively.
|
(d)
|
In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. The reorganization resulted in the termination of the majority of our employees in Aruba, and we recognized severance expense of $41 million in September 2012. This expense is reflected in refining segment operating income for the year ended December 31, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.
|
(e)
|
Asset impairment losses for the year ended December 31, 2012 include a $928 million loss on the write-down of the Aruba Refinery. In addition, we recorded asset impairment losses of $65 million ($42 million after taxes) related to equipment associated with a permanently cancelled capital project at another refinery and $21 million ($13 million after taxes) related to certain retail stores in 2012. The total asset impairment losses of $1.0 billion are reflected in the operating income of the respective segments for the year ended December 31, 2012, but the asset impairment losses associated with the Aruba Refinery and the cancelled capital projects are excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.
|
(f)
|
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.
|
(g)
|
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
|
(h)
|
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes Aruba, Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S.West Coast region includes the Benicia and Wilmington Refineries.
|
(i)
|
U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are now being provided for all periods presented.
|
•
|
fund
$2.8 billion
of capital expenditures and deferred turnaround and catalyst costs;
|
•
|
make scheduled long-term note repayments of
$480 million
;
|
•
|
make a short-term debt repayment of
$58 million
;
|
•
|
purchase common stock for treasury of
$928 million
;
|
•
|
pay common stock dividends of
$462 million
; and
|
•
|
increase available cash on hand by
$2.2 billion
.
|
•
|
fund $3.4 billion of capital expenditures and deferred turnaround and catalyst costs;
|
•
|
redeem our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds for $108 million;
|
•
|
make scheduled long-term note repayments of $754 million;
|
•
|
repay borrowings under our revolving credit facility of $1.1 billion;
|
•
|
make repayments under our accounts receivable sales facility of $1.7 billion;
|
•
|
purchase common stock for treasury of $281 million;
|
•
|
pay common stock dividends of $360 million; and
|
•
|
increase available cash on hand by $699 million.
|
|
Payments Due by Period
|
|
|
||||||||||||||||||||||||
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
|
Total
|
||||||||||||||
Debt and capital
lease obligations
(including interest on
capital lease obligations)
|
$
|
308
|
|
|
$
|
483
|
|
|
$
|
7
|
|
|
$
|
957
|
|
|
$
|
6
|
|
|
$
|
4,851
|
|
|
$
|
6,612
|
|
Operating lease obligations
|
305
|
|
|
230
|
|
|
162
|
|
|
111
|
|
|
95
|
|
|
321
|
|
|
1,224
|
|
|||||||
Purchase obligations
|
33,159
|
|
|
3,501
|
|
|
994
|
|
|
453
|
|
|
279
|
|
|
1,126
|
|
|
39,512
|
|
|||||||
Other long-term liabilities
|
—
|
|
|
138
|
|
|
113
|
|
|
112
|
|
|
103
|
|
|
863
|
|
|
1,329
|
|
|||||||
Total
|
$
|
33,772
|
|
|
$
|
4,352
|
|
|
$
|
1,276
|
|
|
$
|
1,633
|
|
|
$
|
483
|
|
|
$
|
7,161
|
|
|
$
|
48,677
|
|
Rating Agency
|
|
Rating
|
Moody’s Investors Service
|
|
Baa2 (stable outlook)
|
Standard & Poor’s Ratings Services
|
|
BBB (negative outlook)
|
Fitch Ratings
|
|
BBB (stable outlook)
|
|
|
Borrowing
Capacity
|
|
Expiration
|
|
Outstanding
Letters of Credit
|
||||
Letter of credit facilities
|
|
$
|
550
|
|
|
June 2014
|
|
$
|
278
|
|
U.S. revolving credit facility
|
|
$
|
3,000
|
|
|
November 2018
|
|
$
|
59
|
|
Canadian revolving credit facility
|
|
C$
|
50
|
|
|
November 2014
|
|
C$
|
10
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
Increase in projected benefit obligation resulting from:
|
|
|
|
||||
Discount rate decrease
|
$
|
83
|
|
|
$
|
10
|
|
Compensation rate increase
|
6
|
|
|
n/a
|
|
||
Health care cost trend rate increase
|
n/a
|
|
|
1
|
|
||
|
|
|
|
||||
Increase in expense resulting from:
|
|
|
|
||||
Discount rate decrease
|
8
|
|
|
—
|
|
||
Expected return on plan assets decrease
|
4
|
|
|
n/a
|
|
||
Compensation rate increase
|
2
|
|
|
n/a
|
|
||
Health care cost trend rate increase
|
n/a
|
|
|
—
|
|
•
|
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 those forecasted transactions at existing market prices that we deem favorable.
|
|
Derivative Instruments Held For
|
||||||
|
Non-Trading Purposes
|
|
Trading
Purposes
|
||||
December 31, 2013:
|
|
|
|
||||
Gain (loss) in fair value resulting from:
|
|
|
|
||||
10% increase in underlying commodity prices
|
$
|
(91
|
)
|
|
$
|
3
|
|
10% decrease in underlying commodity prices
|
91
|
|
|
(2
|
)
|
||
|
|
|
|
||||
December 31, 2012:
|
|
|
|
||||
Gain (loss) in fair value resulting from:
|
|
|
|
||||
10% increase in underlying commodity prices
|
(131
|
)
|
|
(9
|
)
|
||
10% decrease in underlying commodity prices
|
135
|
|
|
(1
|
)
|
|
December 31, 2013
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
There-
after
|
|
Total
|
|
Fair
Value
|
||||||||||||||||
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed rate
|
$
|
200
|
|
|
$
|
475
|
|
|
$
|
—
|
|
|
$
|
950
|
|
|
$
|
—
|
|
|
$
|
4,824
|
|
|
$
|
6,449
|
|
|
$
|
7,559
|
|
Average interest rate
|
4.8
|
%
|
|
5.2
|
%
|
|
—
|
%
|
|
6.4
|
%
|
|
—
|
%
|
|
7.3
|
%
|
|
6.9
|
%
|
|
|
|||||||||
Floating rate
|
$
|
100
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
100
|
|
Average interest rate
|
0.9
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
0.9
|
%
|
|
|
|
December 31, 2012
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
There-
after
|
|
Total
|
|
Fair
Value
|
||||||||||||||||
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed rate
|
$
|
480
|
|
|
$
|
200
|
|
|
$
|
475
|
|
|
$
|
—
|
|
|
$
|
950
|
|
|
$
|
4,824
|
|
|
$
|
6,929
|
|
|
$
|
8,521
|
|
Average interest rate
|
5.5
|
%
|
|
4.8
|
%
|
|
5.2
|
%
|
|
—
|
%
|
|
6.4
|
%
|
|
7.3
|
%
|
|
6.8
|
%
|
|
|
|||||||||
Floating rate
|
$
|
100
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
100
|
|
Average interest rate
|
0.9
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
0.9
|
%
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Operating revenues
|
$
|
138,074
|
|
|
$
|
139,250
|
|
|
$
|
125,987
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
127,316
|
|
|
127,268
|
|
|
115,719
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Refining
|
3,704
|
|
|
3,668
|
|
|
3,406
|
|
|||
Retail
|
226
|
|
|
686
|
|
|
678
|
|
|||
Ethanol
|
387
|
|
|
332
|
|
|
399
|
|
|||
General and administrative expenses
|
758
|
|
|
698
|
|
|
571
|
|
|||
Depreciation and amortization expense
|
1,720
|
|
|
1,574
|
|
|
1,534
|
|
|||
Asset impairment losses
|
—
|
|
|
1,014
|
|
|
—
|
|
|||
Total costs and expenses
|
134,111
|
|
|
135,240
|
|
|
122,307
|
|
|||
Operating income
|
3,963
|
|
|
4,010
|
|
|
3,680
|
|
|||
Gain on disposition of retained interest in CST Brands, Inc.
|
325
|
|
|
—
|
|
|
—
|
|
|||
Other income, net
|
59
|
|
|
9
|
|
|
43
|
|
|||
Interest and debt expense, net of capitalized interest
|
(365
|
)
|
|
(313
|
)
|
|
(401
|
)
|
|||
Income from continuing operations before income tax expense
|
3,982
|
|
|
3,706
|
|
|
3,322
|
|
|||
Income tax expense
|
1,254
|
|
|
1,626
|
|
|
1,226
|
|
|||
Income from continuing operations
|
2,728
|
|
|
2,080
|
|
|
2,096
|
|
|||
Loss from discontinued operations, net of income taxes
|
—
|
|
|
—
|
|
|
(7
|
)
|
|||
Net income
|
2,728
|
|
|
2,080
|
|
|
2,089
|
|
|||
Less: Net income (loss) attributable to noncontrolling interests
|
8
|
|
|
(3
|
)
|
|
(1
|
)
|
|||
Net income attributable to Valero Energy Corporation stockholders
|
$
|
2,720
|
|
|
$
|
2,083
|
|
|
$
|
2,090
|
|
Net income attributable to Valero Energy Corporation stockholders:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
2,720
|
|
|
$
|
2,083
|
|
|
$
|
2,097
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
(7
|
)
|
|||
Total
|
$
|
2,720
|
|
|
$
|
2,083
|
|
|
$
|
2,090
|
|
Earnings per common share:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
4.99
|
|
|
$
|
3.77
|
|
|
$
|
3.70
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
(0.01
|
)
|
|||
Total
|
$
|
4.99
|
|
|
$
|
3.77
|
|
|
$
|
3.69
|
|
Weighted-average common shares outstanding (in millions)
|
542
|
|
|
550
|
|
|
563
|
|
|||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
4.97
|
|
|
$
|
3.75
|
|
|
$
|
3.69
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
(0.01
|
)
|
|||
Total
|
$
|
4.97
|
|
|
$
|
3.75
|
|
|
$
|
3.68
|
|
Weighted-average common shares outstanding – assuming dilution (in millions)
|
548
|
|
|
556
|
|
|
569
|
|
|||
Dividends per common share
|
$
|
0.85
|
|
|
$
|
0.65
|
|
|
$
|
0.30
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Net income
|
$
|
2,728
|
|
|
$
|
2,080
|
|
|
$
|
2,089
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
(98
|
)
|
|
164
|
|
|
(122
|
)
|
|||
Net gain (loss) on pension
and other postretirement benefits
|
763
|
|
|
(211
|
)
|
|
(292
|
)
|
|||
Net gain (loss) on derivative instruments designated and
qualifying as cash flow hedges
|
(2
|
)
|
|
(28
|
)
|
|
29
|
|
|||
Other comprehensive income (loss) before
income tax expense (benefit)
|
663
|
|
|
(75
|
)
|
|
(385
|
)
|
|||
Income tax expense (benefit) related to
items of other comprehensive income (loss)
|
262
|
|
|
(87
|
)
|
|
(93
|
)
|
|||
Other comprehensive income (loss)
|
401
|
|
|
12
|
|
|
(292
|
)
|
|||
Comprehensive income
|
3,129
|
|
|
2,092
|
|
|
1,797
|
|
|||
Less: Comprehensive income (loss) attributable to
noncontrolling interests
|
8
|
|
|
(3
|
)
|
|
(1
|
)
|
|||
Comprehensive income attributable to
Valero Energy Corporation stockholders
|
$
|
3,121
|
|
|
$
|
2,095
|
|
|
$
|
1,798
|
|
|
Valero Energy Corporation Stockholders’ Equity
|
|
|
|
|
||||||||||||||||||||||||||
|
Common
Stock
|
|
Additional
Paid-in
Capital
|
|
Treasury
Stock
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total
|
|
Non-controlling
Interests
|
|
Total
Equity
|
||||||||||||||||
Balance as of December 31, 2010
|
$
|
7
|
|
|
$
|
7,704
|
|
|
$
|
(6,462
|
)
|
|
$
|
13,388
|
|
|
$
|
388
|
|
|
$
|
15,025
|
|
|
$
|
—
|
|
|
$
|
15,025
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
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
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
23
|
|
||||||||
Recognition of noncontrolling interests in Mainline Pipelines Limited in connection with Pembroke Acquisition
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||||
Acquisition of noncontrolling interests in Mainline Pipelines Limited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(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
|
|
||||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
2,083
|
|
|
—
|
|
|
2,083
|
|
|
(3
|
)
|
|
2,080
|
|
||||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(360
|
)
|
|
—
|
|
|
(360
|
)
|
|
—
|
|
|
(360
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
|
—
|
|
|
57
|
|
||||||||
Tax deduction in excess of stock-
based compensation expense
|
—
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
||||||||
Transactions in connection with
stock-based compensation plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stock issuances
|
—
|
|
|
(260
|
)
|
|
319
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
59
|
|
||||||||
Stock repurchases
|
—
|
|
|
10
|
|
|
(163
|
)
|
|
—
|
|
|
—
|
|
|
(153
|
)
|
|
—
|
|
|
(153
|
)
|
||||||||
Stock repurchases under buyback program
|
—
|
|
|
—
|
|
|
(118
|
)
|
|
—
|
|
|
—
|
|
|
(118
|
)
|
|
—
|
|
|
(118
|
)
|
||||||||
Contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
44
|
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
|
—
|
|
|
12
|
|
||||||||
Balance as of December 31, 2012
|
7
|
|
|
7,322
|
|
|
(6,437
|
)
|
|
17,032
|
|
|
108
|
|
|
18,032
|
|
|
63
|
|
|
18,095
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
2,720
|
|
|
—
|
|
|
2,720
|
|
|
8
|
|
|
2,728
|
|
||||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(462
|
)
|
|
—
|
|
|
(462
|
)
|
|
—
|
|
|
(462
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
64
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64
|
|
|
—
|
|
|
64
|
|
||||||||
Tax deduction in excess of stock-
based compensation expense
|
—
|
|
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|
—
|
|
|
47
|
|
||||||||
Transactions in connection with
stock-based compensation plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Stock issuances
|
—
|
|
|
(243
|
)
|
|
302
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
59
|
|
||||||||
Stock repurchases
|
—
|
|
|
—
|
|
|
(236
|
)
|
|
—
|
|
|
—
|
|
|
(236
|
)
|
|
—
|
|
|
(236
|
)
|
||||||||
Stock repurchases under buyback program
|
—
|
|
|
—
|
|
|
(692
|
)
|
|
—
|
|
|
—
|
|
|
(692
|
)
|
|
—
|
|
|
(692
|
)
|
||||||||
Separation of retail business
|
—
|
|
|
(9
|
)
|
|
9
|
|
|
(320
|
)
|
|
(159
|
)
|
|
(479
|
)
|
|
—
|
|
|
(479
|
)
|
||||||||
Net proceeds from initial public offering of common units of Valero Energy Partners LP
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
369
|
|
|
369
|
|
||||||||
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
46
|
|
||||||||
Other
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
401
|
|
|
401
|
|
|
—
|
|
|
401
|
|
||||||||
Balance as of December 31, 2013
|
$
|
7
|
|
|
$
|
7,187
|
|
|
$
|
(7,054
|
)
|
|
$
|
18,970
|
|
|
$
|
350
|
|
|
$
|
19,460
|
|
|
$
|
486
|
|
|
$
|
19,946
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
2,728
|
|
|
$
|
2,080
|
|
|
$
|
2,089
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
1,720
|
|
|
1,574
|
|
|
1,534
|
|
|||
Gain on disposition of retained interest in CST Brands, Inc.
|
(325
|
)
|
|
—
|
|
|
—
|
|
|||
Asset impairment losses
|
—
|
|
|
1,014
|
|
|
—
|
|
|||
Loss on sales of refinery assets, net
|
—
|
|
|
—
|
|
|
12
|
|
|||
Stock-based compensation expense
|
64
|
|
|
58
|
|
|
58
|
|
|||
Deferred income tax expense
|
501
|
|
|
963
|
|
|
461
|
|
|||
Changes in current assets and current liabilities
|
922
|
|
|
(302
|
)
|
|
81
|
|
|||
Changes in deferred charges and credits and other operating activities, net
|
(46
|
)
|
|
(117
|
)
|
|
(197
|
)
|
|||
Net cash provided by operating activities
|
5,564
|
|
|
5,270
|
|
|
4,038
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(2,121
|
)
|
|
(2,931
|
)
|
|
(2,355
|
)
|
|||
Deferred turnaround and catalyst costs
|
(634
|
)
|
|
(479
|
)
|
|
(629
|
)
|
|||
Acquisition of Pembroke Refinery, net of cash acquired
|
—
|
|
|
—
|
|
|
(1,691
|
)
|
|||
Acquisition of Meraux Refinery
|
—
|
|
|
—
|
|
|
(547
|
)
|
|||
Proceeds from the sale of the Paulsboro Refinery
|
—
|
|
|
160
|
|
|
—
|
|
|||
Other investing activities, net
|
(57
|
)
|
|
(101
|
)
|
|
(76
|
)
|
|||
Net cash used in investing activities
|
(2,812
|
)
|
|
(3,351
|
)
|
|
(5,298
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from debt borrowings
|
—
|
|
|
2,900
|
|
|
150
|
|
|||
Repayments of debt
|
(480
|
)
|
|
(3,612
|
)
|
|
(778
|
)
|
|||
Proceeds from the exercise of stock options
|
59
|
|
|
59
|
|
|
49
|
|
|||
Purchase of common stock for treasury
|
(928
|
)
|
|
(281
|
)
|
|
(349
|
)
|
|||
Common stock dividends
|
(462
|
)
|
|
(360
|
)
|
|
(169
|
)
|
|||
Net proceeds from initial public offering of common units of
Valero Energy Partners LP
|
369
|
|
|
—
|
|
|
—
|
|
|||
Contributions from noncontrolling interests
|
45
|
|
|
44
|
|
|
22
|
|
|||
Disposition of retail business:
|
|
|
|
|
|
||||||
Proceeds from short-term debt in anticipation of separation
|
550
|
|
|
—
|
|
|
—
|
|
|||
Cash distributed to Valero by CST Brands, Inc.
|
500
|
|
|
—
|
|
|
—
|
|
|||
Cash held and retained by CST Brands, Inc. upon separation
|
(315
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from short-term debt related to disposition of retained interest
|
525
|
|
|
—
|
|
|
—
|
|
|||
Repayments of short-term debt related to disposition of retained interest
|
(58
|
)
|
|
—
|
|
|
—
|
|
|||
Other financing activities, net
|
32
|
|
|
17
|
|
|
9
|
|
|||
Net cash used in financing activities
|
(163
|
)
|
|
(1,233
|
)
|
|
(1,066
|
)
|
|||
Effect of foreign exchange rate changes on cash
|
(20
|
)
|
|
13
|
|
|
16
|
|
|||
Net increase (decrease) in cash and temporary cash investments
|
2,569
|
|
|
699
|
|
|
(2,310
|
)
|
|||
Cash and temporary cash investments at beginning of year
|
1,723
|
|
|
1,024
|
|
|
3,334
|
|
|||
Cash and temporary cash investments at end of year
|
$
|
4,292
|
|
|
$
|
1,723
|
|
|
$
|
1,024
|
|
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.
|
•
|
Valero Energy Partners LP (VLP) is a master limited partnership formed in July 2013 to own, operate, develop, and acquire primarily fee-based crude oil and refined petroleum product pipelines and terminals. As further described in
Note 5
, VLP completed an initial public offering of its common units on December 16, 2013 and we owned a
70.6 percent
controlling financial interest in VLP as of
December 31, 2013
.
|
•
|
Diamond Green Diesel Holdings LLC (DGD Holdings) is a
50/50
joint venture with Darling Green Energy LLC, a subsidiary of Darling International, Inc., that constructed and now operates a biomass-
|
•
|
PI Dock Facilities LLC (PI Dock) is a
50/50
joint venture with TGSD PI, LLC that will construct and operate crude oil docks and related facilities near our Port Arthur Refinery. In December 2012, we agreed to lend PI Dock up to
$90 million
to finance the construction of the initial crude dock, which is expected to be completed in late third quarter or early fourth quarter of 2014. As of
December 31, 2013
, we had loaned PI Dock
$13 million
to finance its construction projects.
|
•
|
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 investments of certain benefit plans (related primarily to certain U.S. nonqualified defined benefit plans whose plan assets are not protected from our creditors and therefore cannot be reflected as a reduction from our obligations under those pension plans), debt issuance costs, and various other costs.
|
2.
|
ACQUISITIONS
|
Inventories
|
$
|
227
|
|
Property, plant, and equipment
|
293
|
|
|
Deferred charges and other assets, net
|
28
|
|
|
Other long-term liabilities
|
(1
|
)
|
|
Purchase price
|
$
|
547
|
|
Current assets, net of cash acquired
|
$
|
2,215
|
|
Property, plant, and equipment
|
947
|
|
|
Intangible assets
|
22
|
|
|
Deferred charges and other assets, net
|
37
|
|
|
Current liabilities, less current portion of debt
and capital lease obligations
|
(1,294
|
)
|
|
Debt and capital leases assumed, including current portion
|
(12
|
)
|
|
Deferred income taxes
|
(159
|
)
|
|
Other long-term liabilities
|
(60
|
)
|
|
Noncontrolling interest
|
(5
|
)
|
|
Purchase price, net of cash acquired
|
$
|
1,691
|
|
3.
|
DISPOSITIONS OF BUSINESSES
|
Assets
|
|
||
Cash and temporary cash investments
|
$
|
315
|
|
Credit card receivables from Valero
|
44
|
|
|
Other receivables, net
|
109
|
|
|
Inventories
|
170
|
|
|
Deferred income taxes
|
14
|
|
|
Prepaid expenses and other
|
13
|
|
|
Total current assets
|
665
|
|
|
Property, plant, and equipment, at cost
|
1,891
|
|
|
Accumulated depreciation
|
(611
|
)
|
|
Property, plant, and equipment, net
|
1,280
|
|
|
Intangible assets, net
|
38
|
|
|
Deferred charges and other assets, net
|
191
|
|
|
Total assets
|
$
|
2,174
|
|
|
|
||
Liabilities
|
|
||
Current portion of capital lease obligations
|
$
|
2
|
|
Trade payable to Valero
|
242
|
|
|
Other accounts payable
|
96
|
|
|
Accrued expenses
|
31
|
|
|
Taxes other than income taxes
|
20
|
|
|
Total current liabilities
|
391
|
|
|
Debt and capital lease obligations, less current portion
|
1,053
|
|
|
Deferred income taxes
|
83
|
|
|
Other long-term liabilities
|
112
|
|
|
Total liabilities
|
$
|
1,639
|
|
4.
|
IMPAIRMENTS
|
5.
|
INITIAL PUBLIC OFFERING OF VALERO ENERGY PARTNERS LP
|
Total proceeds from the Offering
|
$
|
397
|
|
Less offering costs
|
(28
|
)
|
|
Net proceeds from the Offering
|
$
|
369
|
|
6.
|
RECEIVABLES
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Accounts receivable
|
$
|
8,650
|
|
|
$
|
8,061
|
|
Commodity derivative and foreign currency
contract receivables
|
98
|
|
|
136
|
|
||
Notes receivable and other
|
49
|
|
|
26
|
|
||
|
8,797
|
|
|
8,223
|
|
||
Allowance for doubtful accounts
|
(46
|
)
|
|
(56
|
)
|
||
Receivables, net
|
$
|
8,751
|
|
|
$
|
8,167
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Balance as of beginning of year
|
$
|
56
|
|
|
$
|
48
|
|
|
$
|
42
|
|
Increase in allowance charged to expense
|
13
|
|
|
21
|
|
|
21
|
|
|||
Accounts charged against the allowance,
net of recoveries
|
(23
|
)
|
|
(13
|
)
|
|
(14
|
)
|
|||
Foreign currency translation
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Balance as of end of year
|
$
|
46
|
|
|
$
|
56
|
|
|
$
|
48
|
|
7.
|
INVENTORIES
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Refinery feedstocks
|
$
|
2,135
|
|
|
$
|
2,458
|
|
Refined products and blendstocks
|
3,231
|
|
|
2,995
|
|
||
Ethanol feedstocks and products
|
166
|
|
|
191
|
|
||
Convenience store merchandise
|
—
|
|
|
112
|
|
||
Materials and supplies
|
226
|
|
|
217
|
|
||
Inventories
|
$
|
5,758
|
|
|
$
|
5,973
|
|
8.
|
PROPERTY, PLANT, AND EQUIPMENT
|
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Land
|
|
$
|
404
|
|
|
$
|
802
|
|
Crude oil processing facilities
|
|
27,260
|
|
|
24,865
|
|
||
Pipeline and terminal facilities
|
|
1,513
|
|
|
1,471
|
|
||
Grain processing equipment
|
|
719
|
|
|
694
|
|
||
Retail facilities
|
|
—
|
|
|
1,480
|
|
||
Administrative buildings
|
|
800
|
|
|
734
|
|
||
Other
|
|
2,109
|
|
|
1,457
|
|
||
Construction in progress
|
|
1,128
|
|
|
2,629
|
|
||
Property, plant, and equipment, at cost
|
|
33,933
|
|
|
34,132
|
|
||
Accumulated depreciation
|
|
(8,226
|
)
|
|
(7,832
|
)
|
||
Property, plant, and equipment, net
|
|
$
|
25,707
|
|
|
$
|
26,300
|
|
9.
|
DEFERRED CHARGES AND OTHER ASSETS
|
10.
|
ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES
|
|
|
Accrued
Expenses
|
|
Other Long-
Term Liabilities
|
||||||||||||
|
|
December 31,
|
||||||||||||||
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Defined benefit plan liabilities (see Note 14)
|
|
$
|
30
|
|
|
$
|
32
|
|
|
$
|
507
|
|
|
$
|
982
|
|
Wage and other employee-related liabilities
|
|
257
|
|
|
282
|
|
|
97
|
|
|
91
|
|
||||
Uncertain income tax position liabilities,
including related penalties and interest (see Note 16)
(a)
|
|
—
|
|
|
—
|
|
|
205
|
|
|
391
|
|
||||
Environmental liabilities
|
|
24
|
|
|
27
|
|
|
277
|
|
|
242
|
|
||||
Accrued interest expense
|
|
90
|
|
|
96
|
|
|
—
|
|
|
—
|
|
||||
Derivative liabilities
|
|
13
|
|
|
14
|
|
|
—
|
|
|
—
|
|
||||
Asset retirement obligations
|
|
5
|
|
|
5
|
|
|
26
|
|
|
103
|
|
||||
Other accrued liabilities
|
|
103
|
|
|
134
|
|
|
217
|
|
|
321
|
|
||||
Accrued expenses and other long-term liabilities
|
|
$
|
522
|
|
|
$
|
590
|
|
|
$
|
1,329
|
|
|
$
|
2,130
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Balance as of beginning of year
|
$
|
269
|
|
|
$
|
274
|
|
|
$
|
268
|
|
Pembroke Acquisition
|
—
|
|
|
—
|
|
|
30
|
|
|||
Additions to liability
|
67
|
|
|
23
|
|
|
18
|
|
|||
Reductions to liability
|
(1
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|||
Payments, net of third-party recoveries
|
(28
|
)
|
|
(29
|
)
|
|
(35
|
)
|
|||
Separation of retail business
|
(4
|
)
|
|
—
|
|
|
—
|
|
|||
Foreign currency translation
|
(2
|
)
|
|
2
|
|
|
(2
|
)
|
|||
Balance as of end of year
|
$
|
301
|
|
|
$
|
269
|
|
|
$
|
274
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Balance as of beginning of year
|
$
|
108
|
|
|
$
|
87
|
|
|
$
|
101
|
|
Additions to accrual
|
2
|
|
|
14
|
|
|
3
|
|
|||
Revisions in estimated cash flows
|
—
|
|
|
13
|
|
|
1
|
|
|||
Accretion expense
|
2
|
|
|
5
|
|
|
4
|
|
|||
Settlements
|
(1
|
)
|
|
(11
|
)
|
|
(22
|
)
|
|||
Separation of retail business
|
(80
|
)
|
|
—
|
|
|
—
|
|
|||
Balance as of end of year
|
$
|
31
|
|
|
$
|
108
|
|
|
$
|
87
|
|
11.
|
DEBT AND CAPITAL LEASE OBLIGATIONS
|
|
Final
Maturity
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
|||||
Bank credit facilities
|
Various
|
|
$
|
—
|
|
|
$
|
—
|
|
Senior Notes:
|
|
|
|
|
|
||||
4.5%
|
2015
|
|
400
|
|
|
400
|
|
||
4.75%
|
2013
|
|
—
|
|
|
300
|
|
||
4.75%
|
2014
|
|
200
|
|
|
200
|
|
||
6.125%
|
2017
|
|
750
|
|
|
750
|
|
||
6.125%
|
2020
|
|
850
|
|
|
850
|
|
||
6.625%
|
2037
|
|
1,500
|
|
|
1,500
|
|
||
6.7%
|
2013
|
|
—
|
|
|
180
|
|
||
6.75%
|
2037
|
|
24
|
|
|
24
|
|
||
7.2%
|
2017
|
|
200
|
|
|
200
|
|
||
7.45%
|
2097
|
|
100
|
|
|
100
|
|
||
7.5%
|
2032
|
|
750
|
|
|
750
|
|
||
8.75%
|
2030
|
|
200
|
|
|
200
|
|
||
9.375%
|
2019
|
|
750
|
|
|
750
|
|
||
10.5%
|
2039
|
|
250
|
|
|
250
|
|
||
Debentures:
|
|
|
|
|
|
||||
7.65%
|
2026
|
|
100
|
|
|
100
|
|
||
8.75%
|
2015
|
|
75
|
|
|
75
|
|
||
Gulf Opportunity Zone Revenue Bonds, Series 2010, 4.0%
|
2040
|
|
300
|
|
|
300
|
|
||
Accounts receivable sales facility
|
2014
|
|
100
|
|
|
100
|
|
||
Net unamortized discount, including fair value adjustments
|
|
|
(24
|
)
|
|
(29
|
)
|
||
Total debt
|
|
|
6,525
|
|
|
7,000
|
|
||
Capital lease obligations, including unamortized fair value adjustments
|
|
39
|
|
|
49
|
|
|||
Total debt and capital lease obligations
|
|
|
6,564
|
|
|
7,049
|
|
||
Less current portion
|
|
|
(303
|
)
|
|
(586
|
)
|
||
Debt and capital lease obligations, less current portion
|
|
|
$
|
6,261
|
|
|
$
|
6,463
|
|
|
|
|
|
|
|
Amounts Outstanding
|
||||||||
|
|
Borrowing Capacity
|
|
Expiration
|
|
December 31, 2013
|
|
December 31, 2012
|
||||||
Letter of credit facilities
|
|
$
|
550
|
|
|
June 2014
|
|
$
|
278
|
|
|
$
|
418
|
|
Revolver
|
|
$
|
3,000
|
|
|
November 2018
|
|
$
|
59
|
|
|
$
|
59
|
|
Canadian revolving credit facility
|
|
C$
|
50
|
|
|
November 2014
|
|
C$
|
10
|
|
|
C$
|
10
|
|
•
|
in January 2013, we made a scheduled debt repayment of
$180 million
related to our
6.7%
senior notes; and
|
•
|
in June 2013, we made a scheduled debt repayment of
$300 million
related to our
4.75%
senior notes.
|
•
|
in March 2012, we exercised the call provisions on our Series 1997
5.6%
, Series 1998
5.6%
, Series 1999
5.7%
, Series 2001
6.65%
, and Series 1997A
5.45%
industrial revenue bonds, which were redeemed on May 3, 2012 for
$108 million
, or
100%
of their outstanding stated values;
|
•
|
in April 2012, we made scheduled debt repayments of
$4 million
related to our Series 1997A
5.45%
industrial revenue bonds and
$750 million
related to our
6.875%
notes; and
|
•
|
in June 2012, we remarketed and received proceeds of
$300 million
related to the
4.0%
Gulf Opportunity Zone Revenue Bonds Series 2010 issued by the Parish of St. Charles, State of Louisiana (GO Zone Bonds), which are due
December 1, 2040
, but are subject to mandatory tender on
June 1, 2022
.
|
•
|
in February 2011, we paid
$300 million
to acquire the GO Zone Bonds, which had originally been issued in December 2010. These bonds were remarketed in June 2012, as previously discussed;
|
•
|
in February 2011, we made a scheduled debt repayment of
$210 million
related to our
6.75%
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 May 2011, we made a scheduled debt repayment of
$200 million
related to our
6.125%
senior notes; and
|
•
|
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.
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Balance as of beginning of year
|
$
|
100
|
|
|
$
|
250
|
|
|
$
|
100
|
|
Proceeds from the sale of receivables
|
—
|
|
|
1,500
|
|
|
150
|
|
|||
Repayments
|
—
|
|
|
(1,650
|
)
|
|
—
|
|
|||
Balance as of end of year
|
$
|
100
|
|
|
$
|
100
|
|
|
$
|
250
|
|
|
Debt
|
|
Capital
Lease
Obligations
|
||||
2014
|
$
|
300
|
|
|
$
|
8
|
|
2015
|
475
|
|
|
8
|
|
||
2016
|
—
|
|
|
7
|
|
||
2017
|
950
|
|
|
7
|
|
||
2018
|
—
|
|
|
6
|
|
||
Thereafter
|
4,824
|
|
|
27
|
|
||
Net unamortized discount
and fair value adjustments
|
(24
|
)
|
|
1
|
|
||
Less interest expense
|
—
|
|
|
(25
|
)
|
||
Total
|
$
|
6,525
|
|
|
$
|
39
|
|
12.
|
COMMITMENTS AND CONTINGENCIES
|
2014
|
$
|
305
|
|
2015
|
230
|
|
|
2016
|
162
|
|
|
2017
|
111
|
|
|
2018
|
95
|
|
|
Thereafter
|
321
|
|
|
Total minimum rental payments
|
$
|
1,224
|
|
Minimum rentals to be received
under subleases
|
$
|
21
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Minimum rental expense
|
$
|
574
|
|
|
$
|
508
|
|
|
$
|
523
|
|
Contingent rental expense
|
7
|
|
|
23
|
|
|
23
|
|
|||
Total rental expense
|
581
|
|
|
531
|
|
|
546
|
|
|||
Less sublease rental income
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||
Net rental expense
|
$
|
581
|
|
|
$
|
529
|
|
|
$
|
544
|
|
•
|
The LCFS is currently subject to legal challenges in both state and federal court. The program currently is in effect, but the progressive reductions in the carbon intensity of fuel required under the LCFS currently are frozen at 2013 levels by order of a California state court until the CARB addresses certain deficiencies under the California Environmental Quality Act. Meanwhile, the Ninth Circuit Court of Appeals recently reversed a lower-court finding that the LCFS violates the Commerce Clause of the U.S. Constitution. It is anticipated that this case will be appealed to the U.S. Supreme Court, although it remains unclear whether the U.S. Supreme Court will agree to review the case.
|
•
|
The California statewide cap-and-trade program became effective in 2012, with the auctioning of emission credits commencing in the fourth quarter of 2012. Initially, the program will apply only to stationary sources of greenhouse gases (
e.g.
, refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program, but we expect that compliance costs will escalate as free allocations compromise a smaller portion of the progressive compliance obligation. Further, overall cap-and-trade program costs are expected to increase significantly beginning in 2015, when transportation fuels are included in the program.
|
•
|
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, 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
|
)
|
Transactions in connection with
stock-based compensation plans:
|
|
|
|
||
Stock issuances
|
—
|
|
|
6
|
|
Stock repurchases
|
—
|
|
|
(6
|
)
|
Stock repurchases under buyback program
|
—
|
|
|
(4
|
)
|
Balance as of December 31, 2012
|
673
|
|
|
(121
|
)
|
Transactions in connection with
stock-based compensation plans:
|
|
|
|
||
Stock issuances
|
—
|
|
|
6
|
|
Stock repurchases
|
—
|
|
|
(6
|
)
|
Stock repurchases under buyback program
|
—
|
|
|
(17
|
)
|
Balance as of December 31, 2013
|
673
|
|
|
(138
|
)
|
|
Before-Tax Amount
|
|
Tax Expense (Benefit)
|
|
Net Amount
|
||||||
Year Ended December 31, 2013:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
(98
|
)
|
|
$
|
—
|
|
|
$
|
(98
|
)
|
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Gain arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial gain
|
367
|
|
|
125
|
|
|
242
|
|
|||
Plan amendments
|
371
|
|
|
130
|
|
|
241
|
|
|||
(Gain) loss reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
57
|
|
|
20
|
|
|
37
|
|
|||
Prior service credit
|
(33
|
)
|
|
(12
|
)
|
|
(21
|
)
|
|||
Settlement
|
1
|
|
|
—
|
|
|
1
|
|
|||
Net gain on pension and other
postretirement benefits
|
763
|
|
|
263
|
|
|
500
|
|
|||
Derivative instruments designated and
qualifying as cash flow hedges:
|
|
|
|
|
|
||||||
Net loss arising during the year
|
(4
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Net loss reclassified into income
|
2
|
|
|
1
|
|
|
1
|
|
|||
Net loss on cash flow hedges
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||
Other comprehensive income
|
$
|
663
|
|
|
$
|
262
|
|
|
$
|
401
|
|
|
Before-Tax Amount
|
|
Tax Expense (Benefit)
|
|
Net Amount
|
||||||
Year Ended December 31, 2012:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
164
|
|
|
$
|
—
|
|
|
$
|
164
|
|
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Loss arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
(228
|
)
|
|
(79
|
)
|
|
(149
|
)
|
|||
Prior service cost
|
(9
|
)
|
|
(3
|
)
|
|
(6
|
)
|
|||
(Gain) loss reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
34
|
|
|
12
|
|
|
22
|
|
|||
Prior service credit
|
(20
|
)
|
|
(7
|
)
|
|
(13
|
)
|
|||
Settlement
|
12
|
|
|
—
|
|
|
12
|
|
|||
Net loss on pension and other
postretirement benefits
|
(211
|
)
|
|
(77
|
)
|
|
(134
|
)
|
|||
Derivative instruments designated and
qualifying as cash flow hedges:
|
|
|
|
|
|
||||||
Net gain arising during the year
|
45
|
|
|
16
|
|
|
29
|
|
|||
Net gain reclassified into income
|
(73
|
)
|
|
(26
|
)
|
|
(47
|
)
|
|||
Net loss on cash flow hedges
|
(28
|
)
|
|
(10
|
)
|
|
(18
|
)
|
|||
Other comprehensive income (loss)
|
$
|
(75
|
)
|
|
$
|
(87
|
)
|
|
$
|
12
|
|
Year Ended December 31, 2011:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
(122
|
)
|
|
$
|
—
|
|
|
$
|
(122
|
)
|
Pension and other postretirement benefits:
|
|
|
|
|
|
|
|||||
Loss arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
(285
|
)
|
|
(100
|
)
|
|
(185
|
)
|
|||
Prior service cost
|
(4
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
(Gain) loss reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
14
|
|
|
4
|
|
|
10
|
|
|||
Prior service credit
|
(21
|
)
|
|
(7
|
)
|
|
(14
|
)
|
|||
Settlement
|
4
|
|
|
1
|
|
|
3
|
|
|||
Net loss on pension and other
postretirement benefits
|
(292
|
)
|
|
(103
|
)
|
|
(189
|
)
|
|||
Derivative instruments designated and
qualifying as cash flow hedges:
|
|
|
|
|
|
|
|||||
Net gain arising during the year
|
32
|
|
|
11
|
|
|
21
|
|
|||
Net gain reclassified into income
|
(3
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|||
Net gain on cash flow hedges
|
29
|
|
|
10
|
|
|
19
|
|
|||
Other comprehensive loss
|
$
|
(385
|
)
|
|
$
|
(93
|
)
|
|
$
|
(292
|
)
|
|
Foreign
Currency
Translation
Adjustment
|
|
Defined
Benefit
Pension
Items
|
|
Gains and
(Losses) on
Cash Flow
Hedges
|
|
Total
|
||||||||
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
|
|
||||
Other comprehensive income (loss)
|
164
|
|
|
(134
|
)
|
|
(18
|
)
|
|
12
|
|
||||
Balance as of December 31, 2012
|
665
|
|
|
(558
|
)
|
|
1
|
|
|
108
|
|
||||
Other comprehensive income (loss)
before reclassifications
|
(98
|
)
|
|
483
|
|
|
(2
|
)
|
|
383
|
|
||||
Amounts reclassified from
accumulated other comprehensive
income (loss)
|
—
|
|
|
17
|
|
|
1
|
|
|
18
|
|
||||
Net other comprehensive income
(loss)
|
(98
|
)
|
|
500
|
|
|
(1
|
)
|
|
401
|
|
||||
Separation of retail business
|
(159
|
)
|
|
—
|
|
|
—
|
|
|
(159
|
)
|
||||
Balance as of December 31, 2013
|
$
|
408
|
|
|
$
|
(58
|
)
|
|
$
|
—
|
|
|
$
|
350
|
|
Details about
Accumulated Other
Comprehensive Income
(Loss) Components
|
|
Year Ended December 31, 2013
|
|
Affected Line
Item in the
Statement of
Income
|
||
Amortization of items related to
defined benefit pension plans:
|
|
|
|
|
||
Net actuarial loss
|
|
$
|
(57
|
)
|
|
(a)
|
Prior service credit
|
|
33
|
|
|
(a)
|
|
Settlement
|
|
(1
|
)
|
|
(a)
|
|
|
|
(25
|
)
|
|
Total before tax
|
|
|
|
8
|
|
|
Tax benefit
|
|
|
|
$
|
(17
|
)
|
|
Net of tax
|
|
|
|
|
|
||
Losses on cash flow hedges:
|
|
|
|
|
||
Commodity contracts
|
|
$
|
(2
|
)
|
|
Cost of sales
|
|
|
(2
|
)
|
|
Total before tax
|
|
|
|
1
|
|
|
Tax benefit
|
|
|
|
$
|
(1
|
)
|
|
Net of tax
|
|
|
|
|
|
||
Total reclassifications for the year
|
|
$
|
(18
|
)
|
|
Net of tax
|
14 .
|
EMPLOYEE BENEFIT PLANS
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Changes in benefit obligation:
|
|
|
|
|
|
|
|
||||||||
Benefit obligation as of beginning of year
|
$
|
2,307
|
|
|
$
|
1,881
|
|
|
$
|
436
|
|
|
$
|
438
|
|
Service cost
|
137
|
|
|
140
|
|
|
12
|
|
|
12
|
|
||||
Interest cost
|
86
|
|
|
93
|
|
|
18
|
|
|
21
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
15
|
|
|
14
|
|
||||
Plan amendments
|
(274
|
)
|
|
9
|
|
|
(43
|
)
|
|
—
|
|
||||
Curtailment gain
|
(6
|
)
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
(170
|
)
|
|
(90
|
)
|
|
(37
|
)
|
|
(35
|
)
|
||||
Actuarial (gain) loss
|
(169
|
)
|
|
289
|
|
|
(77
|
)
|
|
(17
|
)
|
||||
Other
|
3
|
|
|
1
|
|
|
—
|
|
|
3
|
|
||||
Benefit obligation as of end of year
|
$
|
1,914
|
|
|
$
|
2,307
|
|
|
$
|
324
|
|
|
$
|
436
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets
(a)
:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets as of beginning of year
|
$
|
1,729
|
|
|
$
|
1,487
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
306
|
|
|
167
|
|
|
—
|
|
|
—
|
|
||||
Valero contributions
|
41
|
|
|
164
|
|
|
19
|
|
|
19
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
15
|
|
|
14
|
|
||||
Benefits paid
|
(170
|
)
|
|
(90
|
)
|
|
(37
|
)
|
|
(35
|
)
|
||||
Other
|
3
|
|
|
1
|
|
|
3
|
|
|
2
|
|
||||
Fair value of plan assets as of end of year
|
$
|
1,909
|
|
|
$
|
1,729
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Reconciliation of funded status
(a)
:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets as of end of year
|
$
|
1,909
|
|
|
$
|
1,729
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Less benefit obligation as of end of year
|
1,914
|
|
|
2,307
|
|
|
324
|
|
|
436
|
|
||||
Funded status as of end of year
|
$
|
(5
|
)
|
|
$
|
(578
|
)
|
|
$
|
(324
|
)
|
|
$
|
(436
|
)
|
|
|
|
|
|
|
|
|
||||||||
Accumulated benefit obligation
|
$
|
1,811
|
|
|
$
|
1,857
|
|
|
n/a
|
|
|
n/a
|
|
(a)
|
Plan assets include only the assets associated with pension plans subject to legal minimum funding standards. Plan assets associated with U.S. nonqualified pension plans are not included here because they are not protected from our creditors and therefore cannot be reflected as a reduction from our obligations under the pension plans. As a result, the reconciliation of funded status does not reflect the effect of plan assets that exist for all of our defined benefit plans. See
Note 20
for the assets associated with certain U.S. nonqualified pension plans.
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Deferred charges and other assets, net
|
$
|
208
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accrued expenses
|
(11
|
)
|
|
(11
|
)
|
|
(19
|
)
|
|
(21
|
)
|
||||
Other long-term liabilities
|
(202
|
)
|
|
(567
|
)
|
|
(305
|
)
|
|
(415
|
)
|
||||
|
$
|
(5
|
)
|
|
$
|
(578
|
)
|
|
$
|
(324
|
)
|
|
$
|
(436
|
)
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Projected benefit obligation
|
$
|
215
|
|
|
$
|
250
|
|
Accumulated benefit obligation
|
168
|
|
|
191
|
|
||
Fair value of plan assets
|
3
|
|
|
31
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
2014
|
$
|
100
|
|
|
$
|
19
|
|
2015
|
125
|
|
|
19
|
|
||
2016
|
116
|
|
|
20
|
|
||
2017
|
127
|
|
|
20
|
|
||
2018
|
146
|
|
|
21
|
|
||
2019-2023
|
820
|
|
|
107
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Components of net periodic
benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
137
|
|
|
$
|
140
|
|
|
$
|
104
|
|
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
11
|
|
Interest cost
|
86
|
|
|
93
|
|
|
85
|
|
|
18
|
|
|
21
|
|
|
22
|
|
||||||
Expected return on plan assets
|
(131
|
)
|
|
(125
|
)
|
|
(112
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Prior service cost (credit)
|
(19
|
)
|
|
3
|
|
|
2
|
|
|
(14
|
)
|
|
(23
|
)
|
|
(23
|
)
|
||||||
Net actuarial loss
|
57
|
|
|
33
|
|
|
12
|
|
|
—
|
|
|
1
|
|
|
2
|
|
||||||
Special charges (credits)
|
(5
|
)
|
|
(3
|
)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||||
Net periodic benefit cost
|
$
|
125
|
|
|
$
|
141
|
|
|
$
|
95
|
|
|
$
|
16
|
|
|
$
|
11
|
|
|
$
|
16
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Net gain (loss) arising during
the year:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
290
|
|
|
$
|
(245
|
)
|
|
$
|
(294
|
)
|
|
$
|
77
|
|
|
$
|
17
|
|
|
$
|
9
|
|
Prior service cost
|
—
|
|
|
(9
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Remeasurement due to plan amendments
|
328
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
—
|
|
|
—
|
|
||||||
Net (gain) loss reclassified into
income:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss
|
57
|
|
|
33
|
|
|
12
|
|
|
—
|
|
|
1
|
|
|
2
|
|
||||||
Prior service cost (credit)
|
(19
|
)
|
|
3
|
|
|
2
|
|
|
(14
|
)
|
|
(23
|
)
|
|
(23
|
)
|
||||||
Curtailment and settlement loss
|
1
|
|
|
12
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total changes in other
comprehensive income (loss)
|
$
|
657
|
|
|
$
|
(206
|
)
|
|
$
|
(280
|
)
|
|
$
|
106
|
|
|
$
|
(5
|
)
|
|
$
|
(12
|
)
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Prior service cost (credit)
|
$
|
(233
|
)
|
|
$
|
21
|
|
|
$
|
(110
|
)
|
|
$
|
(81
|
)
|
Net actuarial loss (gain)
|
479
|
|
|
882
|
|
|
(44
|
)
|
|
34
|
|
||||
Total
|
$
|
246
|
|
|
$
|
903
|
|
|
$
|
(154
|
)
|
|
$
|
(47
|
)
|
|
Pension Plans
|
|
Other
Postretirement
Benefit Plans
|
||||
Amortization of prior service credit
|
$
|
(22
|
)
|
|
$
|
(18
|
)
|
Amortization of net actuarial loss (gain)
|
35
|
|
|
(1
|
)
|
||
Total
|
$
|
13
|
|
|
$
|
(19
|
)
|
|
Pension Plans
|
|
Other
Postretirement
Benefit Plans
|
||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||
Discount rate
|
4.92
|
%
|
|
4.28
|
%
|
|
4.88
|
%
|
|
4.19
|
%
|
Rate of compensation increase
|
3.81
|
%
|
|
3.73
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||
Discount rate
|
4.33
|
%
|
|
5.08
|
%
|
|
5.40
|
%
|
|
4.19
|
%
|
|
4.97
|
%
|
|
5.22
|
%
|
Expected long-term rate of return
on plan assets
|
7.62
|
%
|
|
7.67
|
%
|
|
7.69
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Rate of compensation increase
|
3.73
|
%
|
|
3.68
|
%
|
|
3.56
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
2013
|
|
2012
|
||
Health care cost trend rate assumed for the next year
|
7.39
|
%
|
|
7.32
|
%
|
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
|
2020
|
|
|
2020
|
|
|
1% Increase
|
|
1% Decrease
|
||||
Effect on total of service and interest cost components
|
$
|
—
|
|
|
$
|
—
|
|
Effect on accumulated postretirement benefit obligation
|
3
|
|
|
(3
|
)
|
|
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, 2013 |
||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
U.S. companies
(a)
|
$
|
529
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
529
|
|
International companies
|
155
|
|
|
—
|
|
|
—
|
|
|
155
|
|
||||
Preferred stock
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
131
|
|
|
—
|
|
|
—
|
|
|
131
|
|
||||
Index funds
(b)
|
160
|
|
|
—
|
|
|
—
|
|
|
160
|
|
||||
Corporate debt instruments
|
—
|
|
|
260
|
|
|
—
|
|
|
260
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
81
|
|
|
—
|
|
|
—
|
|
|
81
|
|
||||
Other government securities
|
—
|
|
|
79
|
|
|
—
|
|
|
79
|
|
||||
Common collective trusts
|
—
|
|
|
373
|
|
|
—
|
|
|
373
|
|
||||
Private fund
|
—
|
|
|
38
|
|
|
—
|
|
|
38
|
|
||||
Insurance contracts
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||
Interest and dividends receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
72
|
|
|
6
|
|
|
—
|
|
|
78
|
|
||||
Total
|
$
|
1,136
|
|
|
$
|
773
|
|
|
$
|
—
|
|
|
$
|
1,909
|
|
|
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, 2012 |
||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
U.S. companies
(a)
|
$
|
441
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
441
|
|
International companies
|
135
|
|
|
—
|
|
|
—
|
|
|
135
|
|
||||
Preferred stock
|
2
|
|
|
1
|
|
|
—
|
|
|
3
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
127
|
|
|
—
|
|
|
—
|
|
|
127
|
|
||||
Index funds
(b)
|
117
|
|
|
—
|
|
|
—
|
|
|
117
|
|
||||
Corporate debt instruments
|
—
|
|
|
290
|
|
|
—
|
|
|
290
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
107
|
|
|
—
|
|
|
—
|
|
|
107
|
|
||||
Other government securities
|
3
|
|
|
65
|
|
|
—
|
|
|
68
|
|
||||
Common collective trusts
|
—
|
|
|
294
|
|
|
—
|
|
|
294
|
|
||||
Insurance contracts
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||
Interest and dividends receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
98
|
|
|
27
|
|
|
—
|
|
|
125
|
|
||||
Total
|
$
|
1,035
|
|
|
$
|
694
|
|
|
$
|
—
|
|
|
$
|
1,729
|
|
(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 includes primarily investments in approximately
60 percent
equities and
40 percent
bonds.
|
15.
|
STOCK-BASED COMPENSATION
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Stock-based compensation expense
|
$
|
64
|
|
|
$
|
58
|
|
|
$
|
58
|
|
Tax benefit recognized on stock-based compensation expense
|
22
|
|
|
20
|
|
|
20
|
|
|||
Tax benefit realized for tax deductions resulting from exercises and vestings
|
66
|
|
|
45
|
|
|
35
|
|
|||
Effect of tax deductions in excess of recognized stock-based compensation expense reported as a financing cash flow
|
47
|
|
|
27
|
|
|
23
|
|
|
Year Ended December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
Expected life in years
|
6.0
|
|
|
6.0
|
|
|
6.0
|
|
Expected volatility
|
49.63
|
%
|
|
49.11
|
%
|
|
49.30
|
%
|
Expected dividend yield
|
2.27
|
%
|
|
2.39
|
%
|
|
2.28
|
%
|
Risk-free interest rate
|
1.77
|
%
|
|
0.85
|
%
|
|
1.44
|
%
|
|
Number of
Stock
Options
|
|
Weighted-
Average
Exercise
Price Per
Share
|
|
Weighted-
Average
Remaining
Contractual
Term
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in years)
|
|
(in millions)
|
|||||
Outstanding as of January 1, 2013
|
13,214,728
|
|
|
$
|
28.54
|
|
|
|
|
|
||
Granted
|
201,300
|
|
|
39.67
|
|
|
|
|
|
|||
Exercised
|
(3,837,090
|
)
|
|
15.21
|
|
|
|
|
|
|||
Expired
|
(1,780,113
|
)
|
|
49.45
|
|
|
|
|
|
|||
Options granted on conversion related
to separation of retail business
|
759,268
|
|
|
28.84
|
|
|
|
|
|
|||
Outstanding as of December 31, 2013
|
8,558,093
|
|
|
27.88
|
|
|
3.5
|
|
$
|
216
|
|
|
|
|
|
|
|
|
|
|
|||||
Exercisable as of December 31, 2013
|
8,037,807
|
|
|
27.66
|
|
|
3.1
|
|
206
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Weighted average grant-date fair value price per share
|
$
|
15.83
|
|
|
$
|
10.98
|
|
|
$
|
10.10
|
|
Intrinsic value of stock options exercised
|
101
|
|
|
78
|
|
|
63
|
|
|||
Cash received from stock option exercises
|
59
|
|
|
59
|
|
|
49
|
|
|
Number of
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
Per Share
|
|||
Nonvested shares as of January 1, 2013
|
2,920,288
|
|
|
$
|
24.76
|
|
Granted
|
1,255,742
|
|
|
39.55
|
|
|
Vested
|
(2,113,647
|
)
|
|
23.73
|
|
|
Forfeited
|
(31,546
|
)
|
|
23.73
|
|
|
Shares granted on conversion related
to separation of retail business
|
174,477
|
|
|
23.42
|
|
|
Nonvested shares as of December 31, 2013
|
2,205,314
|
|
|
32.23
|
|
|
Nonvested
Awards
|
|
Vested
Awards
|
||
Awards outstanding as of January 1, 2013
|
989,414
|
|
|
208,916
|
|
Granted
|
415,317
|
|
|
—
|
|
Vested
|
(442,274
|
)
|
|
442,274
|
|
Converted
|
—
|
|
|
(534,515
|
)
|
Forfeited
|
(50,076
|
)
|
|
(116,675
|
)
|
Shares granted on conversion related
to separation of retail business |
34,784
|
|
|
—
|
|
Awards outstanding as of December 31, 2013
|
947,165
|
|
|
—
|
|
|
Awards
Granted
|
|
Expected
Conversion
Rate
|
|
Fair Value
Per Share
|
|||
Third tranche of 2011 awards
|
227,565
|
|
|
100%
|
|
$
|
38.77
|
|
Second tranche of 2012 awards
|
105,030
|
|
|
100%
|
|
38.77
|
|
|
First tranche of 2013 awards
|
82,722
|
|
|
100%
|
|
38.77
|
|
|
Total
|
415,317
|
|
|
|
|
|
|
Vested
Awards
Converted
|
|
Actual
Conversion
Rate
|
|
Number of
Shares
Issued
|
|
Awards
Forfeited
|
|||
2010 awards
|
417,833
|
|
|
100%
|
|
417,833
|
|
|
—
|
|
2011 awards
|
233,357
|
|
|
50%
|
|
116,682
|
|
|
116,675
|
|
Total
|
651,190
|
|
|
|
|
534,515
|
|
|
116,675
|
|
16.
|
INCOME TAXES
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
U.S. operations
|
$
|
3,531
|
|
|
$
|
4,015
|
|
|
$
|
3,190
|
|
International operations
|
451
|
|
|
(309
|
)
|
|
132
|
|
|||
Income from continuing operations before income tax expense
|
$
|
3,982
|
|
|
$
|
3,706
|
|
|
$
|
3,322
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Federal income tax expense
at the U.S. federal statutory rate
|
$
|
1,394
|
|
|
$
|
1,297
|
|
|
$
|
1,163
|
|
U.S. state income tax expense,
net of U.S. federal income tax effect
|
62
|
|
|
64
|
|
|
29
|
|
|||
U.S. manufacturing deduction
|
(36
|
)
|
|
(33
|
)
|
|
(28
|
)
|
|||
International operations
|
(71
|
)
|
|
266
|
|
|
46
|
|
|||
Permanent differences
|
(104
|
)
|
|
20
|
|
|
8
|
|
|||
Change in tax law
|
(32
|
)
|
|
—
|
|
|
—
|
|
|||
Other, net
|
41
|
|
|
12
|
|
|
8
|
|
|||
Income tax expense
|
$
|
1,254
|
|
|
$
|
1,626
|
|
|
$
|
1,226
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Current:
|
|
|
|
|
|
||||||
U.S. federal
|
$
|
635
|
|
|
$
|
515
|
|
|
$
|
562
|
|
U.S. state
|
36
|
|
|
22
|
|
|
13
|
|
|||
International
|
82
|
|
|
126
|
|
|
186
|
|
|||
Total current
|
753
|
|
|
663
|
|
|
761
|
|
|||
|
|
|
|
|
|
||||||
Deferred:
|
|
|
|
|
|
||||||
U.S. federal
|
459
|
|
|
854
|
|
|
527
|
|
|||
U.S. state
|
59
|
|
|
77
|
|
|
32
|
|
|||
International
|
(17
|
)
|
|
32
|
|
|
(94
|
)
|
|||
Total deferred
|
501
|
|
|
963
|
|
|
465
|
|
|||
Income tax expense
|
$
|
1,254
|
|
|
$
|
1,626
|
|
|
$
|
1,226
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Deferred income tax assets:
|
|
|
|
||||
Tax credit carryforwards
|
$
|
48
|
|
|
$
|
61
|
|
Net operating losses (NOLs)
|
338
|
|
|
247
|
|
||
Inventories
|
264
|
|
|
258
|
|
||
Property, plant, and equipment
|
8
|
|
|
78
|
|
||
Compensation and employee benefit liabilities
|
178
|
|
|
383
|
|
||
Environmental liabilities
|
92
|
|
|
83
|
|
||
Other
|
187
|
|
|
157
|
|
||
Total deferred income tax assets
|
1,115
|
|
|
1,267
|
|
||
Less: Valuation allowance
|
(347
|
)
|
|
(304
|
)
|
||
Net deferred income tax assets
|
768
|
|
|
963
|
|
||
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Property, plant, and equipment
|
6,536
|
|
|
6,143
|
|
||
Deferred turnaround costs
|
331
|
|
|
300
|
|
||
Inventories
|
310
|
|
|
381
|
|
||
Investments, primarily in VLP and DGD
|
94
|
|
|
—
|
|
||
Other
|
81
|
|
|
103
|
|
||
Total deferred income tax liabilities
|
7,352
|
|
|
6,927
|
|
||
Net deferred income tax liabilities
|
$
|
6,584
|
|
|
$
|
5,964
|
|
|
Amount
|
|
Expiration
|
||
U.S. state income tax credits
|
$
|
71
|
|
|
2014 through 2027
|
U.S. state NOLs (gross amount)
|
5,609
|
|
|
2014 through 2033
|
|
International NOLs
|
1,289
|
|
|
Unlimited
|
Income tax benefit
|
$
|
340
|
|
Additional paid-in capital
|
7
|
|
|
Total
|
$
|
347
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Balance as of beginning of year
|
$
|
341
|
|
|
$
|
326
|
|
|
$
|
330
|
|
Additions based on tax positions related to the current year
|
64
|
|
|
11
|
|
|
14
|
|
|||
Additions for tax positions related to prior years
|
576
|
|
|
40
|
|
|
55
|
|
|||
Reductions for tax positions related to prior years
|
(26
|
)
|
|
(36
|
)
|
|
(66
|
)
|
|||
Reductions for tax positions related to the lapse of
applicable statute of limitations
|
(4
|
)
|
|
—
|
|
|
(3
|
)
|
|||
Settlements
|
(1
|
)
|
|
—
|
|
|
(4
|
)
|
|||
Balance as of end of year
|
$
|
950
|
|
|
$
|
341
|
|
|
$
|
326
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Unrecognized tax benefits
|
$
|
950
|
|
|
$
|
341
|
|
Tax refund claim not recognized in our financial statements
|
(556
|
)
|
|
—
|
|
||
Penalties, interest (net of U.S. federal and state income tax
effect), and the U.S. federal income tax effect of state
unrecognized tax benefits
|
49
|
|
|
50
|
|
||
Uncertain tax position liabilities
|
$
|
443
|
|
|
$
|
391
|
|
17.
|
EARNINGS PER COMMON SHARE
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||||||||
|
Restricted
Stock
|
|
Common
Stock
|
|
Restricted
Stock
|
|
Common
Stock
|
|
Restricted
Stock
|
|
Common
Stock
|
||||||||||||
Earnings per common share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income attributable to Valero stockholders from continuing operations
|
|
|
$
|
2,720
|
|
|
|
|
$
|
2,083
|
|
|
|
|
$
|
2,097
|
|
||||||
Less dividends paid:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common stock
|
|
|
460
|
|
|
|
|
358
|
|
|
|
|
168
|
|
|||||||||
Nonvested restricted stock
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|||||||||
Undistributed earnings
|
|
|
$
|
2,258
|
|
|
|
|
$
|
1,723
|
|
|
|
|
$
|
1,928
|
|
||||||
Weighted-average common shares outstanding
|
3
|
|
|
542
|
|
|
3
|
|
|
550
|
|
|
3
|
|
|
563
|
|
||||||
Earnings per common share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Distributed earnings
|
$
|
0.85
|
|
|
$
|
0.85
|
|
|
$
|
0.65
|
|
|
$
|
0.65
|
|
|
$
|
0.30
|
|
|
$
|
0.30
|
|
Undistributed earnings
|
4.14
|
|
|
4.14
|
|
|
3.12
|
|
|
3.12
|
|
|
3.40
|
|
|
3.40
|
|
||||||
Total earnings per common share from continuing operations
|
$
|
4.99
|
|
|
$
|
4.99
|
|
|
$
|
3.77
|
|
|
$
|
3.77
|
|
|
$
|
3.70
|
|
|
$
|
3.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Earnings per common share from continuing operations – assuming dilution:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income attributable to Valero stockholders from continuing operations
|
|
|
$
|
2,720
|
|
|
|
|
$
|
2,083
|
|
|
|
|
$
|
2,097
|
|
||||||
Weighted-average common shares outstanding
|
|
|
542
|
|
|
|
|
550
|
|
|
|
|
563
|
|
|||||||||
Common equivalent shares:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Stock options
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
4
|
|
|||||||||
Performance awards and nonvested restricted stock
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
2
|
|
|||||||||
Weighted-average common shares outstanding –
assuming dilution
|
|
|
548
|
|
|
|
|
556
|
|
|
|
|
569
|
|
|||||||||
Earnings per common share from continuing operations – assuming dilution
|
|
|
$
|
4.97
|
|
|
|
|
$
|
3.75
|
|
|
|
|
$
|
3.69
|
|
|
Year Ended December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
Stock options
|
1
|
|
|
4
|
|
|
6
|
|
18.
|
SEGMENT INFORMATION
|
|
Refining
|
|
Retail
|
|
Ethanol
|
|
Corporate
|
|
Total
|
||||||||||
Year ended December 31, 2013:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external
customers
|
$
|
129,064
|
|
|
$
|
3,896
|
|
|
$
|
5,114
|
|
|
$
|
—
|
|
|
$
|
138,074
|
|
Intersegment revenues
|
2,876
|
|
|
—
|
|
|
128
|
|
|
—
|
|
|
3,004
|
|
|||||
Depreciation and amortization expense
|
1,566
|
|
|
41
|
|
|
45
|
|
|
68
|
|
|
1,720
|
|
|||||
Operating income (loss)
|
4,217
|
|
|
81
|
|
|
491
|
|
|
(826
|
)
|
|
3,963
|
|
|||||
Total expenditures for long-lived assets
|
2,597
|
|
|
62
|
|
|
33
|
|
|
65
|
|
|
2,757
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Year ended December 31, 2012:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external
customers
|
122,925
|
|
|
12,008
|
|
|
4,317
|
|
|
—
|
|
|
139,250
|
|
|||||
Intersegment revenues
|
8,946
|
|
|
—
|
|
|
115
|
|
|
—
|
|
|
9,061
|
|
|||||
Depreciation and amortization expense
|
1,370
|
|
|
119
|
|
|
42
|
|
|
43
|
|
|
1,574
|
|
|||||
Operating income (loss)
|
4,450
|
|
|
348
|
|
|
(47
|
)
|
|
(741
|
)
|
|
4,010
|
|
|||||
Total expenditures for long-lived assets
|
3,147
|
|
|
164
|
|
|
36
|
|
|
66
|
|
|
3,413
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
2,708
|
|
|
134
|
|
|
32
|
|
|
113
|
|
|
2,987
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Refining:
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
$
|
57,806
|
|
|
$
|
55,647
|
|
|
$
|
49,019
|
|
Distillates
|
56,921
|
|
|
51,504
|
|
|
43,713
|
|
|||
Petrochemicals
|
4,281
|
|
|
3,908
|
|
|
4,253
|
|
|||
Lubes and asphalts
|
1,643
|
|
|
2,033
|
|
|
1,948
|
|
|||
Other product revenues
|
8,413
|
|
|
9,833
|
|
|
10,205
|
|
|||
Total refining operating revenues
|
129,064
|
|
|
122,925
|
|
|
109,138
|
|
|||
Retail:
|
|
|
|
|
|
||||||
Fuel sales (gasoline and diesel)
|
3,226
|
|
|
10,045
|
|
|
9,730
|
|
|||
Merchandise sales and other
|
524
|
|
|
1,649
|
|
|
1,635
|
|
|||
Home heating oil
|
146
|
|
|
314
|
|
|
334
|
|
|||
Total retail operating revenues
|
3,896
|
|
|
12,008
|
|
|
11,699
|
|
|||
Ethanol:
|
|
|
|
|
|
||||||
Ethanol
|
4,245
|
|
|
3,545
|
|
|
4,436
|
|
|||
Distillers grains
|
869
|
|
|
772
|
|
|
714
|
|
|||
Total ethanol operating revenues
|
5,114
|
|
|
4,317
|
|
|
5,150
|
|
|||
Total operating revenues
|
$
|
138,074
|
|
|
$
|
139,250
|
|
|
$
|
125,987
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
U.S.
|
$
|
100,418
|
|
|
$
|
100,733
|
|
|
$
|
98,806
|
|
Canada
|
9,974
|
|
|
10,376
|
|
|
10,110
|
|
|||
U.K.
|
11,358
|
|
|
10,779
|
|
|
4,297
|
|
|||
Other countries
|
16,324
|
|
|
17,362
|
|
|
12,774
|
|
|||
Total operating revenues
|
$
|
138,074
|
|
|
$
|
139,250
|
|
|
$
|
125,987
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
U.S.
|
$
|
23,572
|
|
|
$
|
23,760
|
|
Canada
|
2,260
|
|
|
2,639
|
|
||
U.K.
|
1,148
|
|
|
1,110
|
|
||
Aruba
|
53
|
|
|
41
|
|
||
Ireland
|
26
|
|
|
37
|
|
||
Total long-lived assets
|
$
|
27,059
|
|
|
$
|
27,587
|
|
19.
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Decrease (increase) in current assets:
|
|
|
|
|
|
||||||
Receivables, net
|
$
|
(753
|
)
|
|
$
|
437
|
|
|
$
|
(3,110
|
)
|
Inventories
|
(13
|
)
|
|
(282
|
)
|
|
643
|
|
|||
Income taxes receivable
|
10
|
|
|
51
|
|
|
128
|
|
|||
Prepaid expenses and other
|
2
|
|
|
(28
|
)
|
|
(2
|
)
|
|||
Increase (decrease) in current liabilities:
|
|
|
|
|
|
||||||
Accounts payable
|
977
|
|
|
(113
|
)
|
|
2,004
|
|
|||
Accrued expenses
|
53
|
|
|
13
|
|
|
(18
|
)
|
|||
Taxes other than income taxes
|
337
|
|
|
(260
|
)
|
|
312
|
|
|||
Income taxes payable
|
309
|
|
|
(120
|
)
|
|
124
|
|
|||
Changes in current assets and current liabilities
|
$
|
922
|
|
|
$
|
(302
|
)
|
|
$
|
81
|
|
•
|
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 for the year ended December 31, 2013 exclude the change in current assets and current liabilities resulting from the separation of our retail business as described in
Note 3
;
|
•
|
the amounts shown above exclude the current assets and current liabilities acquired in connection with the Meraux Acquisition in October 2011 and the Pembroke Acquisition in August 2011;
|
•
|
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; and
|
•
|
certain differences between balance sheet changes and the changes reflected above result from translating foreign currency denominated balances at the applicable exchange rates as of each balance sheet date.
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Interest paid in excess of amount capitalized
|
$
|
361
|
|
|
$
|
302
|
|
|
$
|
397
|
|
Income taxes paid, net
|
387
|
|
|
705
|
|
|
486
|
|
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. 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.
|
|
December 31, 2012
|
||||||||||||||||||||||||||||||
|
|
|
Total Gross Fair Value
|
|
Effect of Counter-party Netting
|
|
Effect of Cash Collateral Netting
|
|
Net Carrying Value on Balance Sheet
|
|
Cash Collateral Paid or Received Not Offset
|
||||||||||||||||||||
|
Fair Value Hierarchy
|
|
|
|
|
||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
||||||||||||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity derivative contracts
|
$
|
1,143
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
1,203
|
|
|
$
|
(1,189
|
)
|
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
—
|
|
Physical purchase contracts
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
|
n/a
|
|
|
n/a
|
|
|
11
|
|
|
n/a
|
|
||||||||
Foreign currency contracts
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
n/a
|
|
|
n/a
|
|
|
1
|
|
|
n/a
|
|
||||||||
Investments of certain benefit plans
|
87
|
|
|
—
|
|
|
11
|
|
|
98
|
|
|
n/a
|
|
|
n/a
|
|
|
98
|
|
|
n/a
|
|
||||||||
Total
|
$
|
1,231
|
|
|
$
|
71
|
|
|
$
|
11
|
|
|
$
|
1,313
|
|
|
$
|
(1,189
|
)
|
|
$
|
—
|
|
|
$
|
124
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity derivative contracts
|
$
|
1,138
|
|
|
$
|
70
|
|
|
$
|
—
|
|
|
$
|
1,208
|
|
|
$
|
(1,189
|
)
|
|
$
|
(13
|
)
|
|
$
|
6
|
|
|
$
|
(114
|
)
|
Biofuels blending obligation
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
|
n/a
|
|
|
n/a
|
|
|
10
|
|
|
n/a
|
|
||||||||
Foreign currency contracts
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
n/a
|
|
|
n/a
|
|
|
1
|
|
|
n/a
|
|
||||||||
Total
|
$
|
1,139
|
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
1,219
|
|
|
$
|
(1,189
|
)
|
|
$
|
(13
|
)
|
|
$
|
17
|
|
|
|
•
|
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 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 or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.
|
•
|
Investments of certain benefit plans 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 quoted prices 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.
|
•
|
Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into by our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.
|
•
|
Our biofuels blending obligation represents a liability for the purchase of biofuel credits (primarily RINs in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce. To the degree we are unable to blend at percentages required under various governmental and regulatory programs, we must purchase biofuel credits to comply with these programs. These programs are further described in
Note 21
under
“Compliance Program Risk.”
This liability is based on our deficit in biofuel credits as of the balance sheet date, if any, after considering any biofuel credits acquired or under contract, and is equal to the product of the biofuel credits deficit and the market price of these credits as of the balance sheet date. This liability is categorized in Level 2 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
|
||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Balance as of beginning of year
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Purchases
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
21
|
|
||||||
Total losses included in refining operating expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
||||||
Transfers in and/or out of Level 3
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Balance as of end of year
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The amount of total losses included in income attributable to the change in unrealized losses relating to assets still held at end of year
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(21
|
)
|
|
|
|
Total
Fair Value
as of
December 31,
2012
|
|
Total Losses
Recognized
During the
Year Ended
December 31,
2012
|
||||||||||||||
|
Fair Value Hierarchy
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-lived assets of
the Aruba Refinery
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
903
|
|
Materials and supplies
inventories of
the Aruba Refinery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|||||
Cancelled capital projects
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
65
|
|
|||||
Property, plant, and equipment
of convenience stores
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|
21
|
|
|
December 31, 2013
|
|
December 31, 2012
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Financial assets:
|
|
|
|
|
|
|
|
||||||||
Cash and temporary cash investments
|
$
|
4,292
|
|
|
$
|
4,292
|
|
|
$
|
1,723
|
|
|
$
|
1,723
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
||||||||
Debt (excluding capital leases)
|
6,525
|
|
|
7,659
|
|
|
7,000
|
|
|
8,621
|
|
•
|
The fair value of cash and temporary cash investments approximates the carrying value due to the low level of credit risk of these assets combined with their short maturities and market interest rates (Level 1).
|
•
|
The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services (Level 2).
|
21.
|
PRICE RISK MANAGEMENT ACTIVITIES
|
•
|
Fair Value Hedges
– Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.
|
|
|
Notional
Contract
Volumes by
Year of
Maturity
|
|
Derivative Instrument
|
|
2014
|
|
Crude oil and refined products:
|
|
|
|
Futures – long
|
|
11,857
|
|
Futures – short
|
|
12,169
|
|
Physical contracts – long
|
|
312
|
|
•
|
Cash Flow Hedges
– Cash flow hedges are used to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, refined product or natural gas purchases, or refined product sales at existing market prices that we deem favorable.
|
|
|
Notional
Contract
Volumes by
Year of
Maturity
|
|
Derivative Instrument
|
|
2014
|
|
Crude oil and refined products:
|
|
|
|
Futures – long
|
|
7,629
|
|
Futures – short
|
|
2,314
|
|
Physical contracts – short
|
|
5,315
|
|
•
|
Economic Hedges
– Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, and corn inventories, (ii) forecasted refinery feedstock, refined product, and corn purchases, and refined product sales, and (iii) fixed-price corn purchase contracts. Our objective for entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2014
|
|
2015
|
||
Crude oil and refined products:
|
|
|
|
|
||
Swaps – long
|
|
7,261
|
|
|
—
|
|
Swaps – short
|
|
7,276
|
|
|
—
|
|
Futures – long
|
|
42,205
|
|
|
—
|
|
Futures – short
|
|
52,158
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
17,110
|
|
|
—
|
|
Futures – short
|
|
26,095
|
|
|
145
|
|
Physical contracts – long
|
|
12,554
|
|
|
156
|
|
Soybean oil:
|
|
|
|
|
||
Futures – short
|
|
25,320
|
|
|
—
|
|
•
|
Trading Derivatives
– Our objective for entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to future results of operations and cash flows.
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2014
|
|
2015
|
||
Crude oil and refined products:
|
|
|
|
|
||
Swaps – long
|
|
25,200
|
|
|
—
|
|
Swaps – short
|
|
25,200
|
|
|
—
|
|
Futures – long
|
|
84,766
|
|
|
3,490
|
|
Futures – short
|
|
84,397
|
|
|
3,665
|
|
Options – long
|
|
28,850
|
|
|
—
|
|
Options – short
|
|
28,600
|
|
|
—
|
|
Natural gas:
|
|
|
|
|
||
Futures – long
|
|
600
|
|
|
1,000
|
|
Futures – short
|
|
1,150
|
|
|
—
|
|
Options – short
|
|
250
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
435
|
|
|
—
|
|
Futures – short
|
|
435
|
|
|
—
|
|
|
Balance Sheet
Location
|
|
December 31, 2013
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
25
|
|
|
$
|
36
|
|
|
|
|
|
|
|
||||
Derivatives not designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
474
|
|
|
$
|
455
|
|
Swaps
|
Receivables, net
|
|
33
|
|
|
18
|
|
||
Swaps
|
Prepaid expenses and other
|
|
3
|
|
|
—
|
|
||
Swaps
|
Accrued expenses
|
|
—
|
|
|
5
|
|
||
Options
|
Receivables, net
|
|
2
|
|
|
2
|
|
||
Physical purchase contracts
|
Inventories
|
|
—
|
|
|
5
|
|
||
Foreign currency contracts
|
Accrued expenses
|
|
—
|
|
|
8
|
|
||
Total
|
|
|
$
|
512
|
|
|
$
|
493
|
|
Total derivatives
|
|
|
$
|
537
|
|
|
$
|
529
|
|
|
Balance Sheet
Location
|
|
December 31, 2012
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
77
|
|
|
$
|
64
|
|
Swaps
|
Receivables, net
|
|
15
|
|
|
13
|
|
||
Swaps
|
Prepaid expenses and other
|
|
2
|
|
|
2
|
|
||
Total
|
|
|
$
|
94
|
|
|
$
|
79
|
|
|
|
|
|
|
|
||||
Derivatives not designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
1,066
|
|
|
$
|
1,073
|
|
Swaps
|
Receivables, net
|
|
9
|
|
|
6
|
|
||
Swaps
|
Accrued expenses
|
|
32
|
|
|
46
|
|
||
Options
|
Receivables, net
|
|
1
|
|
|
4
|
|
||
Options
|
Accrued expenses
|
|
1
|
|
|
—
|
|
||
Physical purchase contracts
|
Inventories
|
|
11
|
|
|
—
|
|
||
Foreign currency contracts
|
Receivables, net
|
|
1
|
|
|
—
|
|
||
Foreign currency contracts
|
Accrued expenses
|
|
—
|
|
|
1
|
|
||
Total
|
|
|
$
|
1,121
|
|
|
$
|
1,130
|
|
Total derivatives
|
|
|
$
|
1,215
|
|
|
$
|
1,209
|
|
Derivatives in Fair Value
Hedging Relationships
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
||||||
Loss recognized in
income on derivatives
|
|
Cost of sales
|
|
$
|
(12
|
)
|
|
$
|
(250
|
)
|
|
$
|
(6
|
)
|
Gain (loss) recognized in
income on hedged item
|
|
Cost of sales
|
|
18
|
|
|
183
|
|
|
(23
|
)
|
|||
Gain (loss) recognized in
income on derivatives
(ineffective portion)
|
|
Cost of sales
|
|
6
|
|
|
(67
|
)
|
|
(29
|
)
|
Derivatives in Cash Flow
Hedging Relationships
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
||||||
Gain (loss) recognized in
OCI on derivatives
(effective portion)
|
|
|
|
$
|
(4
|
)
|
|
$
|
45
|
|
|
$
|
32
|
|
Gain (loss) reclassified from
accumulated OCI into
income (effective portion)
|
|
Cost of sales
|
|
(2
|
)
|
|
73
|
|
|
3
|
|
|||
Gain recognized in
income on derivatives
(ineffective portion)
|
|
Cost of sales
|
|
21
|
|
|
48
|
|
|
5
|
|
Derivatives Designated as
Economic Hedges and Other
Derivative Instruments
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||||
Commodity contracts
|
|
Cost of sales
|
|
$
|
193
|
|
|
$
|
1
|
|
|
$
|
(349
|
)
|
Foreign currency contracts
|
|
Cost of sales
|
|
14
|
|
|
(38
|
)
|
|
18
|
|
|||
Other contract
|
|
Cost of sales
|
|
—
|
|
|
—
|
|
|
29
|
|
|||
Total
|
|
|
|
$
|
207
|
|
|
$
|
(37
|
)
|
|
$
|
(302
|
)
|
Trading Derivatives
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||||
Commodity contracts
|
|
Cost of sales
|
|
$
|
21
|
|
|
$
|
(16
|
)
|
|
$
|
23
|
|
RINs fixed-price contracts
|
|
Cost of sales
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
22.
|
QUARTERLY FINANCIAL DATA (Unaudited)
|
|
2013 Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30 (a)
|
|
September 30
|
|
December 31
|
||||||||
Operating revenues
|
$
|
33,474
|
|
|
$
|
34,034
|
|
|
$
|
36,137
|
|
|
$
|
34,429
|
|
Operating income
|
1,061
|
|
|
808
|
|
|
532
|
|
|
1,562
|
|
||||
Net income
|
652
|
|
|
465
|
|
|
324
|
|
|
1,287
|
|
||||
Net income attributable to
Valero Energy Corporation
stockholders
|
654
|
|
|
466
|
|
|
312
|
|
|
1,288
|
|
||||
Earnings per common share –
assuming dilution
|
1.18
|
|
|
0.85
|
|
|
0.57
|
|
|
2.38
|
|
||||
|
|
|
|
|
|
|
|
||||||||
|
2012 Quarter Ended
|
||||||||||||||
|
March 31 (b)
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
Operating revenues
|
$
|
35,167
|
|
|
$
|
34,662
|
|
|
$
|
34,726
|
|
|
$
|
34,695
|
|
Operating income (loss)
|
(244
|
)
|
|
1,361
|
|
|
1,309
|
|
|
1,584
|
|
||||
Net income (loss)
|
(432
|
)
|
|
830
|
|
|
673
|
|
|
1,009
|
|
||||
Net income (loss) attributable to
Valero Energy Corporation
stockholders
|
(432
|
)
|
|
831
|
|
|
674
|
|
|
1,010
|
|
||||
Earnings (loss) per common share –
assuming dilution
|
(0.78
|
)
|
|
1.50
|
|
|
1.21
|
|
|
1.82
|
|
(a)
|
The separation of our retail business was completed on May 1, 2013.
|
(b)
|
The operations of the Aruba Refinery were suspended in March 2012.
|
|
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 (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).
|
|
|
|
|
+10.09
|
|
--
|
Valero Energy Corporation Amended and Restated Supplemental Executive Retirement Plan, amended and restated as of November 10, 2008 - incorporated by reference to Exhibit 10.08 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
|
|
|
|
|
+10.10
|
|
--
|
Valero Energy Corporation Excess Pension Plan, as amended and restated effective December 31, 2011 - incorporated by reference to Exhibit 10.10 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
+10.11
|
|
--
|
Valero Energy Corporation Restricted Stock Plan for Non-Employee Directors, as amended and restated July 11, 2007 - incorporated by reference to Exhibit 10.02 to Valero’s Current Report on Form 8-K/A dated July 11, 2007, and filed September 18, 2007 (SEC File No. 1-13175).
|
|
|
|
|
+10.12
|
|
--
|
Form of Indemnity Agreement between Valero Energy Corporation (formerly known as Valero Refining and Marketing Company) and certain officers and directors - incorporated by reference to Exhibit 10.8 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
|
|
|
|
|
+10.13
|
|
--
|
Schedule of Indemnity Agreements - incorporated by reference to Exhibit 10.14 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
+10.14
|
|
--
|
Change of Control Severance Agreement (Tier I) dated January 18, 2007, between Valero Energy Corporation and William R. Klesse - incorporated by reference to Exhibit 10.15 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
+10.15
|
|
--
|
Schedule of Change of Control Severance Agreements (Tier I) - incorporated by reference to Exhibit 10.16 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
*+10.16
|
|
--
|
Change of Control Severance Agreement (Tier II) dated March 15, 2007, between Valero Energy Corporation and Jay D. Browning.
|
|
|
|
|
+10.17
|
|
--
|
Form of Amendment to Change of Control Severance Agreements (to eliminate excise tax gross-up benefit) - incorporated by reference to Exhibit 10.17 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
|
|
|
|
|
*+10.18
|
|
--
|
Schedule of Amendments to Change of Control Severance Agreements.
|
|
|
|
|
*+10.19
|
|
--
|
Form of Performance Share Award Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan.
|
|
|
|
|
+10.20
|
|
--
|
Form of Stock Option Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan - incorporated by reference to Exhibit 10.21 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
+10.21
|
|
--
|
Form of Performance Stock Option Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan - incorporated by reference to Exhibit 10.21 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
|
|
|
|
|
+10.22
|
|
--
|
Form of Stock Option Agreement pursuant to the Valero Energy Corporation Non-Employee Director Stock Option Plan - incorporated by reference to Exhibit 10.04 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (SEC File No. 1-13175).
|
|
|
|
|
+10.23
|
|
--
|
Form of Restricted Stock Agreement pursuant to the Valero Energy Corporation 2005 Omnibus Stock Incentive Plan - incorporated by reference to Exhibit 10.02 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (SEC File No. 1-13175).
|
|
|
|
|
+10.24
|
|
--
|
Form of Restricted Stock Agreement (with acceleration feature) pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan - incorporated by reference to Exhibit 10.24 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
+10.25
|
|
--
|
Form of Restricted Stock Agreement (without acceleration feature) pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan - incorporated by reference to Exhibit 10.25 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
|
|
|
|
|
+10.26
|
|
--
|
Form of Restricted Stock Agreement pursuant to the Valero Energy Corporation Restricted Stock Plan for Non-Employee Directors - incorporated by reference to Exhibit 10.03 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (SEC File No. 1-13175).
|
|
|
|
|
*10.27
|
|
--
|
$3,000,000,000 5-Year Second Amended and Restated Revolving Credit Agreement, dated as of November 22, 2013, among Valero Energy Corporation, as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent; and the lenders named therein.
|
|
|
|
|
*12.01
|
|
--
|
Statements of Computations of Ratios of Earnings to Fixed Charges.
|
|
|
|
|
14.01
|
|
--
|
Code of Ethics for Senior Financial Officers - incorporated by reference to Exhibit 14.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
|
|
|
|
|
*21.01
|
|
--
|
Valero Energy Corporation subsidiaries.
|
|
|
|
|
*23.01
|
|
--
|
Consent of KPMG LLP dated February 27, 2014.
|
|
|
|
|
*24.01
|
|
--
|
Power of Attorney dated February 27, 2014 (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 - incorporated by reference to Exhibit 99.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
|
|
|
|
|
***101
|
|
--
|
Interactive Data Files
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
***
|
Submitted electronically herewith.
|
+
|
Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto.
|
|
VALERO ENERGY CORPORATION
(Registrant)
|
|
|
By:
|
/s/ William R. Klesse
|
|
|
(William R. Klesse)
|
|
|
Chief Executive Officer and
Chairman of the Board
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ William R. Klesse
|
|
Chief Executive Officer and
Chairman of the Board
(Principal Executive Officer)
|
|
February 27, 2014
|
(William R. Klesse)
|
|
|
||
|
|
|
|
|
/s/ Michael S. Ciskowski
|
|
Executive Vice President
and Chief Financial Officer
(Principal Financial and Accounting Officer)
|
|
February 27, 2014
|
(Michael S. Ciskowski)
|
|
|
||
|
|
|
|
|
/s/ Jerry D. Choate
|
|
Director
|
|
February 27, 2014
|
(Jerry D. Choate)
|
|
|
||
|
|
|
|
|
/s/ Ruben M. Escobedo
|
|
Director
|
|
February 27, 2014
|
(Ruben M. Escobedo)
|
|
|
||
|
|
|
|
|
/s/ Deborah P. Majoras
|
|
Director
|
|
February 27, 2014
|
(Deborah P. Majoras)
|
|
|
||
|
|
|
|
|
/s/ Bob Marbut
|
|
Director
|
|
February 27, 2014
|
(Bob Marbut)
|
|
|
||
|
|
|
|
|
/s/ Donald L. Nickles
|
|
Director
|
|
February 27, 2014
|
(Donald L. Nickles)
|
|
|
||
|
|
|
|
|
/s/ Philip J. Pfeiffer
|
|
Director
|
|
February 27, 2014
|
(Philip J. Pfeiffer)
|
|
|
||
|
|
|
|
|
/s/ Robert A. Profusek
|
|
Director
|
|
February 27, 2014
|
(Robert A. Profusek)
|
|
|
||
|
|
|
|
|
/s/ Susan Kaufman Purcell
|
|
Director
|
|
February 27, 2014
|
(Susan Kaufman Purcell)
|
|
|
||
|
|
|
|
|
/s/ Stephen M. Waters
|
|
Director
|
|
February 27, 2014
|
(Stephen M. Waters)
|
|
|
||
|
|
|
|
|
/s/ Randall J. Weisenburger
|
|
Director
|
|
February 27, 2014
|
(Randall J. Weisenburger)
|
|
|
||
|
|
|
|
|
/s/ Rayford Wilkins, Jr.
|
|
Director
|
|
February 27, 2014
|
(Rayford Wilkins, Jr.)
|
|
|
¨
|
I hereby elect to defer a portion of my compensation for the period
commencing January 1, 2014 and ending December 31, 2014
(the “Plan Year”) as follows:
|
Participant's Signature
|
|
Date
|
|
|
|
Participant's Name
|
|
Participant's Employee ID Number
|
_ _ _ _ _%
|
Dreyfus
Appreciation (DGAGX)
|
_ _ _ _ _%
|
Fidelity
Intermediate Government (FSTGX)
|
_ _ _ _ _%
|
Janus
Worldwide (JAWWX)
|
_ _ _ _ _%
|
Milestone
Funds Treasury Obligations Portfolio (MTIXX)
|
_ _ _ _ _%
|
Oakmark I
(OAKMX)
|
_ _ _ _ _%
|
Price
Mid-Cap Growth (RPMGX)
|
_ _ _ _ _%
|
Columbia
Income Z (SRINX)
|
_ _ _ _ _%
|
Vanguard
Balanced Index (VBINX)
|
_ _ _ _ _%
|
Vanguard
Index Extended Market (VEXMX)
|
_ _ _ _ _%
|
Vanguard
Index 500 (VFINX)
|
_ _ _ _ _%
|
Vanguard
Growth and Income (VQNPX)
|
100 %
|
|
Participant's Signature
|
|
Date
|
|
|
|
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
2014 Plan Year
will be paid at the time and in the manner elected below:
Payment Commencement
(choose one):
¨
As soon as administratively possible following retirement
(this is the default if no election is made)
¨
January 1 after the year of retirement
AND
Form of Distribution
(choose one):
¨
Lump sum payment
¨
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
2014 Plan Year
will be paid at the time and in the manner elected below:
Payment Commencement
(choose one):
¨
As soon as administratively possible following separation
(this is the default if no election is made)
¨
January 1 after the year of separation
AND
Form of Distribution
(choose one):
¨
Lump sum
(this is the default payment if no election is made)
¨
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
2014 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 2014 deferrals is January 1, 2018.)
|
|||||
|
Specified Date
|
|
Amount of Elective Deferral or
Total Amount of the Account (Whichever is Less)
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Participant's Signature
|
|
Date
|
|
|
|
Participant's Name
|
|
Participant's Employee ID Number
|
|
|
/s/ Jay D. Browning
|
Jay D. Browning
|
||
|
|
|
|
|
|
|
|
|
|
|
|
VALERO ENERGY CORPORATION
|
||
|
|
|
By:
|
|
/s/ Gregory C. King
|
Name:
|
Gregory C. King
|
|
Title:
|
President
|
Sincerely,
|
|
|
|
Valero Energy Corporation
|
|
|
|
By:
|
/s/ R. Michael Crownover
|
|
R. Michael Crownover
|
|
Senior Vice President
|
|
Human Resources
|
AGREED AND ACCEPTED:
|
|
|
|
|
|
|
|
/s/ Jay D. Browning
|
|
[Executive]
|
|
|
|
|
|
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 2015, and the second and third increments vesting on the Committee’s meeting dates in January 2016 and January 2017, 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 2015) shall be the calendar year ending on December 31, 2014.
|
B.
|
Second Segment
. The Performance Period for the second one-third vesting of Performance Shares (those vesting on the Normal Vesting Date in January 2016) shall be the two calendar years ending December 31, 2015.
|
C.
|
Third Segment
. The Performance Period for the final one-third vesting of Performance Shares (those vesting on the Normal Vesting Date in January 2017) shall be the three calendar years ending December 31, 2016.
|
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%)
|
|
25%
|
(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
|
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.
|
•
|
28,000 Performance Shares granted on November 8, 2013,
|
•
|
normal retirement date of Participant is effective April 30, 2014,
|
•
|
working period is calculated as 6 months (5 full months plus partial month
|
•
|
original grant is adjusted by 6/12ths (50%) resulting in 14,000 Performance Shares to
|
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
|
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.
|
VALERO ENERGY CORPORATION
|
||
|
|
|
By:
|
|
|
|
R. Michael Crownover
, Senior Vice President
|
|
|
|
|
Participant
|
ARTICLE I
|
||
DEFINITIONS
|
||
|
|
|
Section 1.01
|
Defined Terms
|
|
Section 1.02
|
Classification of Loans and Borrowings
|
|
Section 1.03
|
Terms Generally
|
|
Section 1.04
|
Accounting Terms; GAAP
|
|
Section 1.05
|
Letter of Credit Amounts
|
|
|
|
|
ARTICLE II
|
||
THE CREDITS
|
||
|
|
|
Section 2.01
|
Commitments
|
|
Section 2.02
|
Commitment Increase
|
|
Section 2.03
|
Swingline Loans
|
|
Section 2.04
|
Loans and Borrowings
|
|
Section 2.05
|
Requests for Borrowings
|
|
Section 2.06
|
Letters of Credit
|
|
Section 2.07
|
Funding of Borrowings
|
|
Section 2.08
|
Interest Elections
|
|
Section 2.09
|
Termination and Reduction of Commitments
|
|
Section 2.10
|
Repayment of Loans; Evidence of Debt
|
|
Section 2.11
|
Prepayment of Loans
|
|
Section 2.12
|
Fees
|
|
Section 2.13
|
Interest
|
|
Section 2.14
|
Alternate Rate of Interest
|
|
Section 2.15
|
Increased Costs
|
|
Section 2.16
|
Break Funding Payments
|
|
Section 2.17
|
Taxes
|
|
Section 2.18
|
Payments Generally; Pro Rata Treatment; Sharing of Setoffs
|
|
Section 2.19
|
Mitigation Obligations; Replacement of Lenders
|
|
Section 2.20
|
Illegality
|
|
Section 2.21
|
Extension of Maturity Date
|
|
Section 2.22
|
Defaulting Lenders
|
|
|
|
|
ARTICLE III
|
||
REPRESENTATIONS AND WARRANTIES
|
||
|
|
|
Section 3.01
|
Organization; Powers
|
|
Section 3.02
|
Authorization; Enforceability
|
|
Section 3.03
|
Governmental Approvals; No Conflicts
|
|
Section 3.04
|
Financial Condition
|
|
Section 3.05
|
Environmental Matters
|
|
Section 3.06
|
No Default
|
|
Section 3.07
|
Investment Company Status
|
Section 3.08
|
Taxes
|
|
Section 3.09
|
ERISA
|
|
Section 3.10
|
Disclosure
|
|
Section 3.11
|
Anti-Corruption Laws and Sanctions; Use of Proceeds
|
|
|
|
|
ARTICLE IV
|
||
CONDITIONS
|
||
|
|
|
Section 4.01
|
Revolving Effective Date
|
|
Section 4.02
|
Each Credit Event
|
|
|
|
|
ARTICLE V
|
||
AFFIRMATIVE COVENANTS
|
||
|
|
|
Section 5.01
|
Financial Statements and Other Information
|
|
Section 5.02
|
Notices of Material Events
|
|
Section 5.03
|
Existence; Conduct of Business
|
|
Section 5.04
|
Payment of Obligations
|
|
Section 5.05
|
Maintenance of Properties; Insurance
|
|
Section 5.06
|
Books and Records; Inspection Rights
|
|
Section 5.07
|
Compliance with Laws
|
|
Section 5.08
|
Use of Proceeds
|
|
|
|
|
ARTICLE VI
|
||
NEGATIVE COVENANTS
|
||
|
|
|
Section 6.01
|
Indebtedness
|
|
Section 6.02
|
Liens
|
|
Section 6.03
|
Fundamental Changes
|
|
Section 6.04
|
Hedging Agreements
|
|
Section 6.05
|
Transactions with Affiliates
|
|
|
|
|
ARTICLE VII
|
||
EVENTS OF DEFAULT
|
||
|
||
ARTICLE VIII
|
||
THE ADMINISTRATIVE AGENT
|
||
|
||
ARTICLE IX
|
||
MISCELLANEOUS
|
||
|
|
|
Section 9.01
|
Notices
|
|
Section 9.02
|
Waivers; Amendments
|
|
Section 9.03
|
Expenses; Indemnity; Damage Waiver
|
|
Section 9.04
|
Successors and Assigns
|
|
Section 9.05
|
Survival
|
Section 9.06
|
Counterparts; Integration; Effectiveness
|
|
Section 9.07
|
Severability
|
|
Section 9.08
|
Right of Setoff
|
|
Section 9.09
|
Governing Law; Jurisdiction; Consent to Service of Process
|
|
Section 9.10
|
Waiver of Jury Trial
|
|
Section 9.11
|
Headings
|
|
Section 9.12
|
Confidentiality
|
|
Section 9.13
|
Interest Rate Limitation
|
|
Section 9.14
|
USA PATRIOT Act
|
|
Section 9.15
|
Amendment and Restatement
|
|
Section 9.16
|
Assignment and Reallocation of Commitments, Etc
|
|
|
|
|
SCHEDULES
:
|
||
Schedule 1.01
|
- Pricing Schedule
|
|
Schedule 2.01
|
- Commitments
|
|
Schedule 2.06
|
- Outstanding Letters of Credit
|
|
Schedule 6.01
|
- Existing Indebtedness of Subsidiaries
|
|
Schedule 6.02(j)
|
- Existing Liens
|
|
|
|
|
EXHIBITS
:
|
||
Exhibit A
|
- Form of Assignment and Assumption
|
|
Exhibit B
|
- Notice of Commitment Increase
|
|
Exhibit C
|
- Form of Borrowing Request
|
|
Exhibit D
|
- Form of Promissory Note
|
|
VALERO ENERGY CORPORATION, a
|
||
|
Delaware corporation, as Borrower
|
|
|
|
|
|
|
|
By:
|
|
/s/ Donna M. Titzman
|
Name:
|
Donna M. Titzman
|
|
Title:
|
Vice President and Treasurer
|
JPMORGAN CHASE BANK, N.A., as the
|
||
|
Administrative Agent, the Swingline
|
|
|
Lender, an Issuing Bank and a Lender.
|
|
|
|
|
|
|
|
By:
|
|
/s/ Muhammad Hasan
|
Name:
|
Muhammad Hasan
|
|
Title:
|
Vice President
|
1.
|
Assignor:
|
____________________________________________
|
2.
|
Assignee:
|
____________________________________________
[and is an Affiliate/Approved Fund of [
identify Lender
]
1
]
|
3.
|
Credit Agreement:
|
The $3,000,000,000 5-Year Second Amended and Restated Revolving Credit Agreement dated as of November 22, 2013 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.
|
4.
|
Assigned Interest:
|
|
Aggregate Amount of Commitment/Loans for all Lenders
|
Amount of Commitment/Loans Assigned
|
Percentage Assigned of Commitment/Loans
2
|
$
|
$
|
%
|
$
|
$
|
%
|
$
|
$
|
%
|
ASSIGNOR
|
||
|
|
|
[NAME OF ASSIGNOR]
|
||
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
ASSIGNEE
|
||
|
|
|
[NAME OF ASSIGNEE]
|
||
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
JPMORGAN CHASE BANK, N.A., as
|
||
|
[Administrative Agent,]
3
Swingline Lender
|
|
|
and Issuing Bank
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
CITIBANK, N.A.,
|
||
|
as an Issuing Bank
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION
|
||
|
as an Issuing Bank
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
MIZUHO BANK, LTD.,
|
||
|
as an Issuing Bank
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
THE ROYAL BANK OF SCOTLAND PLC,
|
||
|
as an Issuing Bank
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
[Consented to:]
4
|
||
|
|
|
VALERO ENERGY CORPORATION,
|
||
|
as Borrower
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
Very truly yours,
|
||
|
|
|
VALERO ENERGY CORPORATION
|
||
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
On _________
2
, acknowledged by:
|
||
|
|
|
JPMORGAN CHASE BANK, N.A.,
|
||
|
as Administrative Agent
|
|
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
Very truly yours,
|
||
|
|
|
VALERO ENERGY CORPORATION
|
||
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
$_________
|
New York, New York
[ ], 2013 |
VALERO ENERGY CORPORATION
|
||
|
|
|
By:
|
|
|
|
Name:
|
|
|
Title:
|
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,
|
||||||||||||||||||||||
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
before income tax expense (benefit),
excluding income from equity investees
|
$
|
3,957
|
|
|
|
$
|
3,702
|
|
|
|
$
|
3,322
|
|
|
|
$
|
1,481
|
|
|
|
$
|
(334
|
)
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
677
|
|
|
|
711
|
|
|
|
735
|
|
|
|
743
|
|
|
|
701
|
|
|||||
Amortization of capitalized interest
|
32
|
|
|
|
25
|
|
|
|
23
|
|
|
|
20
|
|
|
|
18
|
|
|||||
Distributions from equity investees
|
3
|
|
|
|
1
|
|
|
|
—
|
|
|
|
10
|
|
|
|
—
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest capitalized
|
(118
|
)
|
|
|
(221
|
)
|
|
|
(152
|
)
|
|
|
(90
|
)
|
|
|
(105
|
)
|
|||||
Total earnings
|
$
|
4,551
|
|
|
|
$
|
4,218
|
|
|
|
$
|
3,928
|
|
|
|
$
|
2,164
|
|
|
|
$
|
280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense, net
of capitalized interest
|
$
|
365
|
|
|
|
$
|
313
|
|
|
|
$
|
401
|
|
|
|
$
|
484
|
|
|
|
$
|
416
|
|
Interest capitalized
|
118
|
|
|
|
221
|
|
|
|
152
|
|
|
|
90
|
|
|
|
105
|
|
|||||
Rental expense interest factor (a)
|
194
|
|
|
|
177
|
|
|
|
182
|
|
|
|
169
|
|
|
|
180
|
|
|||||
Total fixed charges
|
$
|
677
|
|
|
|
$
|
711
|
|
|
|
$
|
735
|
|
|
|
$
|
743
|
|
|
|
$
|
701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
6.7
|
|
x
|
|
5.9
|
|
x
|
|
5.3
|
|
x
|
|
2.9
|
|
x
|
|
(b)
|
|
(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
|
|
|
|
CANADIAN ULTRAMAR COMPANY
|
|
Nova Scotia
|
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 REFINING COMPANY, L.P.
|
|
Delaware
|
DIAMOND UNIT INVESTMENTS, L.L.C.
|
|
Delaware
|
DSRM NATIONAL BANK
|
|
U.S.A.
|
EASTVIEW FUEL OILS LIMITED
|
|
Ontario
|
ENTERPRISE CLAIMS MANAGEMENT, INC.
|
|
Texas
|
GOLDEN EAGLE ASSURANCE LIMITED
|
|
British Columbia
|
HUNTWAY REFINING COMPANY
|
|
Delaware
|
MAINLINE PIPELINES LIMITED
|
|
England and Wales
|
MICHIGAN REDEVELOPMENT GP, LLC
|
|
Delaware
|
MICHIGAN REDEVELOPMENT, L.P.
|
|
Delaware
|
MRP PROPERTIES COMPANY, LLC
|
|
Michigan
|
NECHES RIVER HOLDING CORP.
|
|
Delaware
|
OCEANIC TANKERS AGENCY LIMITED
|
|
Quebec
|
PI DOCK FACILITIES LLC
|
|
Delaware
|
PORT ARTHUR COKER COMPANY L.P.
|
|
Delaware
|
PREMCOR USA INC.
|
|
Delaware
|
PROPERTY RESTORATION, L.P.
|
|
Delaware
|
SABINE RIVER HOLDING CORP.
|
|
Delaware
|
SABINE RIVER LLC
|
|
Delaware
|
SUNBELT REFINING COMPANY, L.P.
|
|
Delaware
|
THE PREMCOR PIPELINE CO.
|
|
Delaware
|
THE PREMCOR REFINING GROUP INC.
|
|
Delaware
|
THE SHAMROCK PIPE LINE CORPORATION
|
|
Delaware
|
ULTRAMAR ACCEPTANCE INC.
|
|
Canada
|
ULTRAMAR ENERGY INC.
|
|
Delaware
|
ULTRAMAR INC.
|
|
Nevada
|
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.)
|
Name of Entity
|
|
State of Incorporation/Organization
|
VALERO ARUBA MAINTENANCE/OPERATIONS
COMPANY N.V.
|
|
Aruba
|
VALERO BROWNSVILLE TERMINAL LLC
|
|
Texas
|
VALERO CANADA FINANCE, INC.
|
|
Delaware
|
VALERO CANADA L.P.
|
|
Newfoundland
|
VALERO CAPITAL CORPORATION
|
|
Delaware
|
VALERO CARIBBEAN SERVICES COMPANY
|
|
Delaware
|
VALERO COKER CORPORATION ARUBA N.V.
|
|
Aruba
|
VALERO CUSTOMS & TRADE SERVICES, INC.
|
|
Delaware
|
VALERO ENERGY ARUBA II COMPANY
|
|
Cayman Islands
|
VALERO ENERGY INC.
|
|
Canada
|
VALERO ENERGY (IRELAND) LIMITED
|
|
Ireland
|
VALERO ENERGY LTD
|
|
England and Wales
|
VALERO ENERGY PARTNERS GP LLC
|
|
Delaware
|
VALERO ENERGY PARTNERS LP
|
|
Delaware
|
VALERO ENERGY UK LTD
|
|
England and Wales
|
VALERO ENTERPRISES, INC.
|
|
Delaware
|
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 LIVE OAK LLC
|
|
Texas
|
VALERO LOGISTICS UK LTD
|
|
England and Wales
|
VALERO MARKETING & SUPPLY-ARUBA N.V.
|
|
Aruba
|
VALERO MARKETING AND SUPPLY COMPANY
|
|
Delaware
|
VALERO MARKETING AND SUPPY INTERNATIONAL LTD.
|
|
Cayman Islands
|
VALERO MARKETING IRELAND LIMITED
|
|
Ireland
|
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 PARTNERS EP, LLC
|
|
Delaware
|
VALERO PARTNERS LUCAS, LLC
|
|
Delaware
|
VALERO PARTNERS MEMPHIS, LLC
|
|
Delaware
|
VALERO PARTNERS OPERATING CO. LLC
|
|
Delaware
|
VALERO PARTNERS PAPS, LLC
|
|
Delaware
|
VALERO PARTNERS WEST MEMPHIS, LLC
|
|
Delaware
|
VALERO PAYMENT SERVICES COMPANY
|
|
Virginia
|
VALERO PEMBROKESHIRE LLC
|
|
Delaware
|
Name of Entity
|
|
State of Incorporation/Organization
|
VALERO PLAINS COMPANY LLC
|
|
Texas
|
VALERO POWER MARKETING LLC
|
|
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 SECURITY SYSTEMS, INC.
|
|
Delaware
|
VALERO SERVICES, INC.
|
|
Delaware
|
VALERO TEJAS COMPANY LLC
|
|
Delaware
|
VALERO TERMINALING AND DISTRIBUTION COMPANY
|
|
Delaware
|
VALERO TEXAS POWER MARKETING, INC.
|
|
Delaware
|
VALERO ULTRAMAR HOLDINGS INC.
|
|
Delaware
|
VALERO UNIT INVESTMENTS, L.L.C.
|
|
Delaware
|
VALERO WEST WALES LLC
|
|
Delaware
|
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
|
|
|
/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 27, 2014
|
|
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 27, 2014
|
|