þ
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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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San Antonio, Texas
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78249
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(Address of principal executive offices)
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(Zip Code)
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Registrant’s telephone number, including area code: (210) 345-2000
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Large accelerated filer
þ
Accelerated filer
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Non-accelerated filer
o
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Smaller reporting company
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Emerging growth company
o
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Form 10-K Item No. and Caption
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Heading in 2019 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, Executive Compensation, Director Compensation, Pay Ratio Disclosure,
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 LLP Fees
and
Audit Committee Pre-Approval Policy
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PAGE
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•
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Refining segment
includes our refining operations, the associated marketing activities, and certain logistics assets, which are not owned by VLP, that support our refining operations;
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•
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Ethanol segment
includes our ethanol operations, the associated marketing activities, and logistics assets that support our ethanol operations; and
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•
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VLP segment
includes the operations of VLP, which is a limited partnership that owns logistics assets that provide transportation and terminaling services to our refining segment.
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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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Port Arthur
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Texas
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395,000
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Corpus Christi (b)
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Texas
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370,000
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St. Charles
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Louisiana
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340,000
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Texas City
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Texas
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260,000
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Houston
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Texas
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250,000
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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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1,850,000
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U.S. Mid-Continent
:
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McKee
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Texas
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200,000
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Memphis
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Tennessee
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195,000
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Ardmore
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Oklahoma
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90,000
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485,000
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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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3,145,000
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(a)
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“Throughput capacity” represents estimated capacity for processing crude oil, inter-mediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.6 million BPD.
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(b)
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Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.
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Combined Total Refining System Charges and Yields
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Charges:
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sour crude oil
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30
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%
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sweet crude oil
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47
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%
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residual fuel oil
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8
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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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37
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%
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other products (primarily includes petrochemicals,
gas oils, No. 6 fuel oil, petroleum coke, sulfur
and asphalt)
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15
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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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40
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%
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sweet crude oil
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33
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%
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residual fuel oil
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11
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%
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other feedstocks
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5
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%
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blendstocks
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11
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%
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Yields:
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gasolines and blendstocks
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45
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%
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distillates
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38
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%
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other products (primarily includes petrochemicals,
gas oils, No. 6 fuel oil, petroleum coke, sulfur
and asphalt)
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17
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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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1
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%
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sweet crude oil
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91
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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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36
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%
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other products (primarily includes petrochemicals,
gas oils, No. 6 fuel oil, and asphalt)
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9
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%
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Combined North Atlantic Region Charges and Yields
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Charges:
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sweet crude oil
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81
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%
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residual fuel oil
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7
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%
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blendstocks
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12
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%
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Yields:
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gasoline and blendstocks
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45
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%
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distillates
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42
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%
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other products (primarily includes
petrochemicals, gas oils, and No. 6 fuel oil)
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13
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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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66
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%
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sweet crude oil
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9
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%
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other feedstocks
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12
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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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60
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%
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distillates
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26
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%
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other products (primarily includes gas oil, No. 6
fuel oil, petroleum coke, sulfur and asphalt)
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14
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%
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State
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City
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Ethanol
Production
Capacity
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Production
of DDGs
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Corn
Processed
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Indiana
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Bluffton
(c)
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115
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302,000
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40
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Linden
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135
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355,000
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47
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Mount Vernon
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100
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263,000
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35
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Iowa
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Albert City
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135
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355,000
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47
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Charles City
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140
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368,000
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49
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Fort Dodge
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140
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368,000
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49
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Hartley
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140
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368,000
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49
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Lakota
(c)
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110
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289,000
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38
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Michigan
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Riga
(c)
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55
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145,000
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19
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Minnesota
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Welcome
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140
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368,000
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49
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Nebraska
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Albion
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135
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355,000
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47
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Ohio
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Bloomingburg
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135
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355,000
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47
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South Dakota
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Aurora
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140
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368,000
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49
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Wisconsin
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Jefferson
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110
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352,000
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41
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Total
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1,730
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4,611,000
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606
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(a)
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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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(b)
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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 corn oil, modified distillers grains, or, after further drying, dried distillers grains. Distillers grains generally are an economical partial replacement for corn and soybeans in feeds for cattle, swine, and poultry. Corn oil is produced as fuel grade and feed grade (not for human consumption), and is sold primarily as a feedstock for biodiesel or renewable diesel production with a smaller percentage sold into animal feed markets.
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(c)
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The Bluffton, Lakota, and Riga plants were acquired from two subsidiaries of Green Plains Inc. in November 2018. The annual ethanol, DDG production, and corn processing capacities for these ethanol plants were only applicable for November and December of 2018.
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Pipeline
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Diameter
(inches)
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Length
(miles)
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Throughput
Capacity
(thousand BPD)
|
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Commodity
|
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Associated
Valero
Refinery
|
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Significant
Third-party
System Connections
|
Ardmore logistics system
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Hewitt segment of Red
River crude oil pipeline |
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16
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138
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60
(a)
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crude oil
|
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Ardmore
|
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Plains Red River, Plains Cushing
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Wynnewood refined
products pipeline |
|
12
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30
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90
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refined petroleum products
|
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Ardmore
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Magellan Central
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McKee logistics system
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McKee crude system
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multiple segments
|
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145
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72
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crude oil
|
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McKee
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—
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McKee products system
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McKee to El Paso pipeline
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10
|
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408
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21
(b)
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refined petroleum products
|
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McKee
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—
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SFPP pipeline connection
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16, 8
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12
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33
(c)
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refined petroleum products
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McKee
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Kinder Morgan
SFPP System
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Memphis logistics system
(d)
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Collierville crude system
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Collierville pipeline
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10-20
|
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52
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210
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crude oil
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Memphis
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Capline; Diamond
(e)
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Memphis products system
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Memphis Airport pipeline
system |
|
6
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11
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20
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jet fuel
|
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Memphis
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Memphis International Airport
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Shorthorn pipeline system
|
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14, 12
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|
9
|
|
120
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refined petroleum products
|
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Memphis
|
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Exxon Memphis
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Port Arthur logistics system
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Lucas crude system
|
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Lucas pipeline
|
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30
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|
12
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|
400
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crude oil
|
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Port Arthur
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Sunoco Logistics Nederland; Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway
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Nederland pipeline
|
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32
|
|
5
|
|
600
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|
crude oil
|
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Port Arthur
|
|
Sunoco Logistics Nederland
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Port Arthur products system
|
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|
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12-10 pipeline
|
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12, 10
|
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13
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|
60
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refined petroleum products
|
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Port Arthur
|
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Sunoco Logistics MagTex;
Enterprise TE Products, Enterprise Beaumont |
20-inch diesel pipeline
|
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20
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|
3
|
|
216
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|
diesel
|
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Port Arthur
|
|
Explorer; Colonial
|
20-inch gasoline pipeline
|
|
20
|
|
4
|
|
144
|
|
gasoline
|
|
Port Arthur
|
|
Explorer; Colonial
|
St.
Charles logistics system
|
|
|
|
|
|
|
|
|
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Parkway pipeline
|
|
16
|
|
140
|
|
110
|
|
refined petroleum products
|
|
St.
Charles
|
|
Plantation; Colonial
|
Three Rivers logistics system
|
|
|
|
|
|
|
|
|
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Three Rivers crude system
|
|
12
|
|
3
|
|
110
|
|
crude oil
|
|
Three Rivers
|
|
Harvest Arrowhead;
Plains Gardendale; EOG Eagle Ford West |
Terminal
|
|
Tank Storage
Capacity
(thousands of
barrels)
|
|
Throughput
Capacity
(thousand
BPD)
|
|
Commodity
|
|
Associated
Valero
Refinery
|
|
Significant
Third-party
System Connections
|
Port Arthur logistics system
|
|
|
|
|
|
|
|
|
|
|
Lucas crude system
|
|
|
|
|
|
|
|
|
|
|
Lucas terminal
|
|
1,915
|
|
—
|
|
crude oil
|
|
Port Arthur
|
|
Sunoco Logistics Nederland;
Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway |
Seaway connection
|
|
—
|
|
750
|
|
crude oil
|
|
Port Arthur
|
|
Seaway
|
TransCanada connection
|
|
—
|
|
400
|
|
crude oil
|
|
Port Arthur
|
|
TransCanada Cushing
MarketLink |
Port Arthur products system
|
|
|
|
|
|
|
|
|
|
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El Vista terminal
|
|
1,210
|
|
—
|
|
gasoline
|
|
Port Arthur
|
|
Explorer; Colonial
|
PAPS terminal
|
|
1,144
|
|
—
|
|
diesel
|
|
Port Arthur
|
|
Explorer; Colonial
|
Port Arthur terminal
|
|
8,500
|
|
—
|
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crude oil and refined petroleum products
|
|
Port Arthur
|
|
Sunoco Logistics Nederland; Explorer; Colonial; Sunoco Logistics MagTex; Cameron Highway; TransCanada Cushing MarketLink; Enterprise Beaumont
|
St.
Charles logistics system
|
|
|
|
|
|
|
|
|
|
|
St. Charles terminal
|
|
10,004
|
|
—
|
|
crude oil and refined petroleum products
|
|
St. Charles
|
|
LOOP; CAM; Plantation; Colonial
|
Diamond Green Diesel tank
|
|
180
|
|
|
|
renewable diesel
|
|
n/a
|
|
n/a
|
Three Rivers logistics system
|
|
|
|
|
|
|
|
|
|
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Three Rivers terminal
|
|
2,250
|
|
—
|
|
crude oil and refined petroleum products
|
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Three Rivers
|
|
NuStar South Texas;
Harvest Arrowhead; Plains Gardendale; EOG Eagle Ford West |
(a)
|
Capacity shown represents VLP’s 40 percent undivided interest in the pipeline segment. Total capacity for the pipeline segment is 150,000 BPD.
|
(b)
|
Capacity shown represents VLP’s 33⅓ percent undivided interest in the pipeline. Total capacity for the pipeline is 63,000 BPD.
|
(c)
|
Capacity shown represents VLP’s 33⅓ percent undivided interest in the pipeline connection. Total capacity for the pipeline connection is 98,400 BPD.
|
(d)
|
Portions of VLP’s Memphis logistics system pipelines are owned by Memphis Light, Gas and Water (MLGW), but they are operated and maintained exclusively by VLP under long-term arrangements with MLGW.
|
(e)
|
The Diamond pipeline is owned 50 percent by Valero and 50 percent by Plains All American Pipeline, L.P.
|
(f)
|
Capacity shown represents VLP’s 33⅓ percent undivided interest in the terminal. Total storage capacity is 499,000 barrels.
|
(g)
|
Capacity shown represents VLP’s 33⅓ percent undivided interest in the truck rack. Total capacity is 30,000 BPD.
|
(h)
|
Dock throughput is reflected in thousands of barrels per hour.
|
•
|
Item 1A, “Risk Factors”—
Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance
;
|
•
|
Item 1A, “Risk Factors”—
Compliance with the U.S. Environmental Protection Agency Renewable Fuel Standard could adversely affect our performance;
|
•
|
Item 1A, “Risk Factors”—
We may incur additional costs as a result of our use of rail cars for the transportation of crude oil and the products that we manufacture
;
|
•
|
Item 3, “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and;
|
•
|
Item 8, “Financial Statements and Supplementary Data” in
Note 8
of Notes to Consolidated Financial Statements and
Note 10
of Notes to Consolidated Financial Statements under the caption “
Environmental Matters.
”
|
Period
|
|
Total Number
of Shares
Purchased
|
|
Average
Price Paid
per Share
|
|
Total Number of
Shares Not
Purchased as Part of
Publicly Announced
Plans or Programs (a)
|
|
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
|
|
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs (b)
|
|||||
October 2018
|
|
939,957
|
|
|
$
|
87.23
|
|
|
8,826
|
|
|
931,131
|
|
|
$2.7 billion
|
November 2018
|
|
3,655,945
|
|
|
$
|
87.39
|
|
|
216,469
|
|
|
3,439,476
|
|
|
$2.4 billion
|
December 2018
|
|
3,077,364
|
|
|
$
|
73.43
|
|
|
4,522
|
|
|
3,072,842
|
|
|
$2.2 billion
|
Total
|
|
7,673,266
|
|
|
$
|
81.77
|
|
|
229,817
|
|
|
7,443,449
|
|
|
$2.2 billion
|
(a)
|
The shares reported in this column represent purchases settled in the fourth quarter of
2018
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.
|
(b)
|
On
January 23, 2018
, we announced that our board of directors authorized our purchase of up to
$2.5 billion
of our outstanding common stock (the 2018 Program), with no expiration date, which was in addition to the remaining amount available under a
$2.5 billion
program authorized on
September 21, 2016
(the 2016 Program). During the fourth quarter of 2018, we completed our purchases under the 2016 Program. As of
December 31, 2018
, we had
$2.2 billion
remaining available for purchase under the 2018 Program.
|
|
As of December 31,
|
||||||||||||||||||||||
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||||||||
Valero Common Stock
|
$
|
100.00
|
|
|
$
|
100.24
|
|
|
$
|
147.15
|
|
|
$
|
148.30
|
|
|
$
|
207.60
|
|
|
$
|
174.97
|
|
S&P 500
|
100.00
|
|
|
113.69
|
|
|
115.26
|
|
|
129.05
|
|
|
157.22
|
|
|
150.33
|
|
||||||
Peer Group
|
100.00
|
|
|
91.36
|
|
|
80.82
|
|
|
97.00
|
|
|
122.98
|
|
|
114.59
|
|
(a)
|
Assumes that an investment in Valero common stock and each index was $100 on
December 31, 2013
. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from
December 31, 2013
through
December 31, 2018
.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017 (a)
|
|
2016 (b)
|
|
2015 (c)
|
|
2014
|
||||||||||
Revenues
|
$
|
117,033
|
|
|
$
|
93,980
|
|
|
$
|
75,659
|
|
|
$
|
87,804
|
|
|
$
|
130,844
|
|
Income from continuing
operations
|
3,353
|
|
|
4,156
|
|
|
2,417
|
|
|
4,101
|
|
|
3,775
|
|
|||||
Earnings per common
share from continuing
operations – assuming dilution
|
7.29
|
|
|
9.16
|
|
|
4.94
|
|
|
7.99
|
|
|
6.97
|
|
|||||
Dividends per common share
|
3.20
|
|
|
2.80
|
|
|
2.40
|
|
|
1.70
|
|
|
1.05
|
|
|||||
Total assets
|
50,155
|
|
|
50,158
|
|
|
46,173
|
|
|
44,227
|
|
|
45,355
|
|
|||||
Debt and capital lease
obligations, less current portion
|
8,871
|
|
|
8,750
|
|
|
7,886
|
|
|
7,208
|
|
|
5,747
|
|
(a)
|
Includes the impact of Tax Reform that was enacted on December 22, 2017 and resulted in a net income tax benefit of
$1.9 billion
as described in
Note 15
of Notes to Consolidated Financial Statements.
|
(b)
|
Includes a noncash lower of cost or market inventory valuation reserve adjustment that resulted in a net benefit to our results of operations of
$747 million
as described in
Note 5
of Notes to Consolidated Financial Statements.
|
(c)
|
Includes a noncash lower of cost or market inventory valuation reserve adjustment that resulted in a net charge to our results of operations of $790 million.
|
•
|
future refining segment margins, including gasoline and distillate margins;
|
•
|
future ethanol segment margins;
|
•
|
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
|
•
|
anticipated levels of crude oil and refined petroleum product inventories;
|
•
|
our anticipated level of capital investments, including deferred costs for refinery turnarounds and catalyst, capital expenditures for environmental and other purposes, and joint venture investments, and the effect of those capital investments on our results of operations;
|
•
|
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined petroleum products in the regions where we operate, as well as globally;
|
•
|
expectations regarding environmental, tax, and other regulatory initiatives; and
|
•
|
the effect of general economic and other conditions on refining, ethanol, and midstream industry fundamentals.
|
•
|
acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined petroleum products or receive feedstocks;
|
•
|
political and economic conditions in nations that produce crude oil or consume refined petroleum products;
|
•
|
demand for, and supplies of, refined petroleum products such as gasoline, diesel, 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 petroleum products;
|
•
|
the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
|
•
|
the levels of government subsidies for alternative fuels;
|
•
|
the volatility in the market price of biofuel credits (primarily RINs needed to comply with the RFS) and GHG emission credits needed to comply with the requirements of various GHG emission programs;
|
•
|
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 petroleum 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 tariffs and tax and environmental regulations, such as those implemented under the California cap-and-trade system (also known as AB 32) and similar programs, and the U.S. EPA’s regulation of GHGs, 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, the euro, the Mexican peso, and the Peruvian sol 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 Item 1A, “Risk Factors” in this report.
|
•
|
Refining segment.
Refining segment adjusted operating income increased $961 million primarily due to improved distillate margins, favorable crude oil discounts, and lower costs of biofuel credits, partially offset by lower gasoline margins. This is more fully described on pages
36
through
37
.
|
•
|
Ethanol segment.
Ethanol segment operating income decreased by
$90 million
primarily due to lower ethanol prices and higher corn prices, partially offset by higher corn related co-products prices. This is more fully described on pages
37
through
38
.
|
•
|
VLP segment.
VLP segment adjusted operating income increased by $50 million primarily due to incremental revenues, partially offset by higher cost of sales, generated from transportation and terminaling services associated with a terminal and a product pipeline system acquired by VLP in November 2017 that were formerly a part of the refining segment. This is more fully described on page
38
.
|
•
|
Corporate and eliminations.
Adjusted corporate and eliminations decreased by $10 million primarily due to expenses in 2017 associated with the termination of the acquisition of certain assets from Plains All American Pipeline, L.P. (Plains). This is more fully described on page
38
.
|
•
|
Refining and ethanol margins are expected to remain near current levels.
|
•
|
Medium and heavy sour crude oil discounts are expected to remain weaker than their five-year averages as supplies of sour crude oils available in the market remain suppressed.
|
•
|
Sweet crude oil discounts are expected to remain near current levels as export demand remains strong and freight costs continue to rise. U.S. inland sweet crude oil discounts are also expected to remain wide with higher production and limited pipeline capacity to transport crude oil out of the Permian Basin and other producing regions in the U.S.
|
•
|
Our refining operations in the U.K. could be adversely affected by Brexit, which is currently scheduled to occur on March 29, 2019. The U.K. and the European Union have yet to finalize the terms of Brexit, and the U.K.’s exit from the European Union without an agreement on an overall structure for an ongoing relationship with the European Union could result in the imposition of border controls and customs duties on trade that could negatively impact the operations of our Pembroke Refinery. While we do not believe that Brexit will have a material impact on us, we are taking steps to minimize the impact of possible delays on importing certain materials critical to our refining operations. The ultimate effect of Brexit will depend on the specific terms of any agreement reached by the U.K. and the European Union. See Item 1A “Risk Factors”—
Changes in the U.K.’s economic and other relationships with the European Union could adversely affect us
.
|
|
Year Ended December 31, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
113,601
|
|
|
$
|
3,428
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
117,033
|
|
Intersegment revenues
|
14
|
|
|
210
|
|
|
546
|
|
|
(770
|
)
|
|
—
|
|
|||||
Total revenues
|
113,615
|
|
|
3,638
|
|
|
546
|
|
|
(766
|
)
|
|
117,033
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other (a)
|
102,489
|
|
|
3,008
|
|
|
—
|
|
|
(765
|
)
|
|
104,732
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
4,099
|
|
|
470
|
|
|
125
|
|
|
(4
|
)
|
|
4,690
|
|
|||||
Depreciation and amortization expense
|
1,863
|
|
|
78
|
|
|
76
|
|
|
—
|
|
|
2,017
|
|
|||||
Total cost of sales
|
108,451
|
|
|
3,556
|
|
|
201
|
|
|
(769
|
)
|
|
111,439
|
|
|||||
Other operating expenses
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below) (b)
|
—
|
|
|
—
|
|
|
—
|
|
|
925
|
|
|
925
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||
Operating income by segment
|
$
|
5,119
|
|
|
$
|
82
|
|
|
$
|
345
|
|
|
$
|
(974
|
)
|
|
4,572
|
|
|
Other income, net (c)
|
|
|
|
|
|
|
|
|
130
|
|
|||||||||
Interest and debt expense, net of capitalized
interest
|
|
|
|
|
|
|
|
|
(470
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
4,232
|
|
|||||||||
Income tax expense (d) (e)
|
|
|
|
|
|
|
|
|
879
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
3,353
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests (a)
|
|
|
|
|
|
|
|
|
231
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
3,122
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
90,651
|
|
|
$
|
3,324
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
93,980
|
|
Intersegment revenues
|
6
|
|
|
176
|
|
|
452
|
|
|
(634
|
)
|
|
—
|
|
|||||
Total revenues
|
90,657
|
|
|
3,500
|
|
|
452
|
|
|
(629
|
)
|
|
93,980
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
80,865
|
|
|
2,804
|
|
|
—
|
|
|
(632
|
)
|
|
83,037
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
3,959
|
|
|
443
|
|
|
104
|
|
|
(2
|
)
|
|
4,504
|
|
|||||
Depreciation and amortization expense
|
1,800
|
|
|
81
|
|
|
53
|
|
|
—
|
|
|
1,934
|
|
|||||
Total cost of sales
|
86,624
|
|
|
3,328
|
|
|
157
|
|
|
(634
|
)
|
|
89,475
|
|
|||||
Other operating expenses
|
58
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
61
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
829
|
|
|
829
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||
Operating income by segment
|
$
|
3,975
|
|
|
$
|
172
|
|
|
$
|
292
|
|
|
$
|
(876
|
)
|
|
3,563
|
|
|
Other income, net
|
|
|
|
|
|
|
|
|
112
|
|
|||||||||
Interest and debt expense, net of capitalized
interest
|
|
|
|
|
|
|
|
|
(468
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
3,207
|
|
|||||||||
Income tax benefit (d) (e)
|
|
|
|
|
|
|
|
|
(949
|
)
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
4,156
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
91
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
4,065
|
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Reconciliation of net income attributable to Valero Energy
Corporation stockholders to adjusted net income attributable to
Valero Energy Corporation stockholders (h)
|
|
|
|
||||
Net income attributable to Valero Energy Corporation stockholders
|
$
|
3,122
|
|
|
$
|
4,065
|
|
Exclude adjustments:
|
|
|
|
||||
Blender’s tax credit attributable to Valero Energy Corporation stockholders (a)
|
90
|
|
|
—
|
|
||
Income tax expense related to the blender’s tax credit
|
(11
|
)
|
|
—
|
|
||
Blender’s tax credit attributable to Valero Energy Corporation stockholders,
net of taxes
|
79
|
|
|
—
|
|
||
Texas City Refinery fire expenses
|
(17
|
)
|
|
—
|
|
||
Income tax benefit related to Texas City Refinery fire expenses
|
4
|
|
|
—
|
|
||
Texas City Refinery fire expenses, net of taxes
|
(13
|
)
|
|
—
|
|
||
Environmental reserve adjustments (b)
|
(108
|
)
|
|
—
|
|
||
Income tax benefit related to the environmental reserve adjustments
|
24
|
|
|
—
|
|
||
Environmental reserve adjustments, net of taxes
|
(84
|
)
|
|
—
|
|
||
Loss on early redemption of debt (c)
|
(38
|
)
|
|
—
|
|
||
Income tax benefit related to the loss on early redemption of debt
|
9
|
|
|
—
|
|
||
Loss on early redemption of debt, net of taxes
|
(29
|
)
|
|
—
|
|
||
Income tax benefit from Tax Reform (d)
|
12
|
|
|
1,862
|
|
||
Total adjustments
|
(35
|
)
|
|
1,862
|
|
||
Adjusted net income attributable to Valero Energy Corporation stockholders
|
$
|
3,157
|
|
|
$
|
2,203
|
|
|
Year Ended December 31, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Reconciliation of operating income to adjusted
operating income (h)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment
|
$
|
5,119
|
|
|
$
|
82
|
|
|
$
|
345
|
|
|
$
|
(974
|
)
|
|
$
|
4,572
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Blender’s tax credit (a)
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
170
|
|
|||||
Other operating expenses
|
(45
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|||||
Environmental reserve adjustments (b)
|
—
|
|
|
—
|
|
|
—
|
|
|
(108
|
)
|
|
(108
|
)
|
|||||
Adjusted operating income
|
$
|
4,994
|
|
|
$
|
82
|
|
|
$
|
345
|
|
|
$
|
(866
|
)
|
|
$
|
4,555
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Reconciliation of operating income to adjusted
operating income (h)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment
|
$
|
3,975
|
|
|
$
|
172
|
|
|
$
|
292
|
|
|
$
|
(876
|
)
|
|
$
|
3,563
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Other operating expenses
|
(58
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(61
|
)
|
|||||
Adjusted operating income
|
$
|
4,033
|
|
|
$
|
172
|
|
|
$
|
295
|
|
|
$
|
(876
|
)
|
|
$
|
3,624
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Throughput volumes (thousand barrels per day (BPD))
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude oil
|
469
|
|
|
469
|
|
|
—
|
|
|||
Medium/light sour crude oil
|
418
|
|
|
458
|
|
|
(40
|
)
|
|||
Sweet crude oil
|
1,410
|
|
|
1,323
|
|
|
87
|
|
|||
Residuals
|
232
|
|
|
219
|
|
|
13
|
|
|||
Other feedstocks
|
127
|
|
|
148
|
|
|
(21
|
)
|
|||
Total feedstocks
|
2,656
|
|
|
2,617
|
|
|
39
|
|
|||
Blendstocks and other
|
330
|
|
|
323
|
|
|
7
|
|
|||
Total throughput volumes
|
2,986
|
|
|
2,940
|
|
|
46
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD)
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,443
|
|
|
1,423
|
|
|
20
|
|
|||
Distillates
|
1,133
|
|
|
1,127
|
|
|
6
|
|
|||
Other products (i)
|
449
|
|
|
428
|
|
|
21
|
|
|||
Total yields
|
3,025
|
|
|
2,978
|
|
|
47
|
|
|||
|
|
|
|
|
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Refining segment margin (h)
|
$
|
10,956
|
|
|
$
|
9,792
|
|
|
$
|
1,164
|
|
Adjusted refining segment operating income
(see page 32) (h)
|
$
|
4,994
|
|
|
$
|
4,033
|
|
|
$
|
961
|
|
Throughput volumes (thousand BPD)
|
2,986
|
|
|
2,940
|
|
|
46
|
|
|||
|
|
|
|
|
|
||||||
Refining segment margin per barrel of throughput
|
$
|
10.05
|
|
|
$
|
9.12
|
|
|
$
|
0.93
|
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per barrel of
throughput
|
3.76
|
|
|
3.69
|
|
|
0.07
|
|
|||
Depreciation and amortization expense per barrel of
throughput
|
1.71
|
|
|
1.67
|
|
|
0.04
|
|
|||
Adjusted refining segment operating income per barrel of
throughput
|
$
|
4.58
|
|
|
$
|
3.76
|
|
|
$
|
0.82
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Ethanol segment margin (h)
|
$
|
630
|
|
|
$
|
696
|
|
|
$
|
(66
|
)
|
Ethanol segment operating income
(see page 32)
|
$
|
82
|
|
|
$
|
172
|
|
|
$
|
(90
|
)
|
Production volumes (thousand gallons per day)
|
4,109
|
|
|
3,972
|
|
|
137
|
|
|||
|
|
|
|
|
|
||||||
Ethanol segment margin per gallon of production
|
$
|
0.42
|
|
|
$
|
0.48
|
|
|
$
|
(0.06
|
)
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per gallon of
production
|
0.31
|
|
|
0.31
|
|
|
—
|
|
|||
Depreciation and amortization expense per gallon of
production
|
0.06
|
|
|
0.05
|
|
|
0.01
|
|
|||
Ethanol segment operating income per gallon of
production
|
$
|
0.05
|
|
|
$
|
0.12
|
|
|
$
|
(0.07
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Pipeline transportation revenue
|
$
|
124
|
|
|
$
|
101
|
|
|
$
|
23
|
|
Terminaling revenue
|
415
|
|
|
348
|
|
|
67
|
|
|||
Storage and other revenue
|
7
|
|
|
3
|
|
|
4
|
|
|||
Total VLP segment revenues
|
$
|
546
|
|
|
$
|
452
|
|
|
$
|
94
|
|
|
|
|
|
|
|
||||||
Pipeline transportation throughput
(thousand BPD)
|
1,092
|
|
|
964
|
|
|
128
|
|
|||
Pipeline transportation revenue per barrel of throughput
|
$
|
0.31
|
|
|
$
|
0.29
|
|
|
$
|
0.02
|
|
|
|
|
|
|
|
||||||
Terminaling throughput (thousand BPD)
|
3,594
|
|
|
2,889
|
|
|
705
|
|
|||
Terminaling revenue per barrel of throughput
|
$
|
0.32
|
|
|
$
|
0.33
|
|
|
$
|
(0.01
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Feedstocks
|
|
|
|
|
|
||||||
Brent crude oil
|
$
|
71.62
|
|
|
$
|
54.82
|
|
|
$
|
16.80
|
|
Brent less West Texas Intermediate (WTI) crude oil
|
6.71
|
|
|
3.92
|
|
|
2.79
|
|
|||
Brent less Alaska North Slope (ANS) crude oil
|
0.31
|
|
|
0.26
|
|
|
0.05
|
|
|||
Brent less Louisiana Light Sweet (LLS) crude oil
|
1.72
|
|
|
0.69
|
|
|
1.03
|
|
|||
Brent less Argus Sour Crude Index (ASCI) crude oil
|
5.20
|
|
|
4.18
|
|
|
1.02
|
|
|||
Brent less Maya crude oil
|
9.22
|
|
|
7.74
|
|
|
1.48
|
|
|||
LLS crude oil
|
69.90
|
|
|
54.13
|
|
|
15.77
|
|
|||
LLS less ASCI crude oil
|
3.48
|
|
|
3.49
|
|
|
(0.01
|
)
|
|||
LLS less Maya crude oil
|
7.50
|
|
|
7.05
|
|
|
0.45
|
|
|||
WTI crude oil
|
64.91
|
|
|
50.90
|
|
|
14.01
|
|
|||
|
|
|
|
|
|
||||||
Natural gas (dollars per million British thermal units (MMBtu))
|
3.23
|
|
|
2.98
|
|
|
0.25
|
|
|||
|
|
|
|
|
|
||||||
Products
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
4.81
|
|
|
10.50
|
|
|
(5.69
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
14.02
|
|
|
13.26
|
|
|
0.76
|
|
|||
Propylene less Brent
|
(2.86
|
)
|
|
0.48
|
|
|
(3.34
|
)
|
|||
CBOB gasoline less LLS
|
6.53
|
|
|
11.19
|
|
|
(4.66
|
)
|
|||
Ultra-low-sulfur diesel less LLS
|
15.74
|
|
|
13.95
|
|
|
1.79
|
|
|||
Propylene less LLS
|
(1.14
|
)
|
|
1.17
|
|
|
(2.31
|
)
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
CBOB gasoline less WTI
|
13.70
|
|
|
15.65
|
|
|
(1.95
|
)
|
|||
Ultra-low-sulfur diesel less WTI
|
22.82
|
|
|
18.50
|
|
|
4.32
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
7.59
|
|
|
12.57
|
|
|
(4.98
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
16.29
|
|
|
14.75
|
|
|
1.54
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
CARBOB 87 gasoline less ANS
|
13.05
|
|
|
18.12
|
|
|
(5.07
|
)
|
|||
CARB diesel less ANS
|
18.13
|
|
|
17.11
|
|
|
1.02
|
|
|||
CARBOB 87 gasoline less WTI
|
19.45
|
|
|
21.78
|
|
|
(2.33
|
)
|
|||
CARB diesel less WTI
|
24.53
|
|
|
20.77
|
|
|
3.76
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.15
|
|
|
0.26
|
|
|
(0.11
|
)
|
•
|
Increase in distillate margins.
We experienced improved distillate margins throughout all of our regions in
2018
compared to
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was
$14.02
per barrel for
2018
compared to
$13.26
per barrel for
2017
, representing a favorable increase of
$0.76
per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was
$22.82
per barrel for
2018
compared to
$18.50
per barrel for
2017
, representing a favorable increase of
$4.32
per barrel. We estimate that the increase in distillate margins per barrel in
2018
compared to
2017
had a favorable impact to our refining segment margin of approximately $1.3 billion.
|
•
|
Higher discounts on crude oils.
The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil. We benefitted from processing these types of crude oils in
2018
and that benefit improved compared to
2017
. For example, WTI crude oil, a light sweet crude oil, sold at a discount to Brent of
$6.71
per barrel for
2018
compared to a discount of
$3.92
per barrel for
2017
, representing a favorable increase of
$2.79
per barrel. Another example is Maya crude oil, a sour crude oil processed in our U.S. Gulf Coast region, which sold at a discount to Brent of
$9.22
per barrel for
2018
compared to
$7.74
per barrel for
2017
, representing a favorable increase of
$1.48
per barrel. We estimate that the increase in the discounts for crude oils that we processed during
2018
compared to 2017 had a favorable impact to our refining segment margin of approximately $561 million.
|
•
|
Lower costs of biofuel credits.
As described in
Note 20
of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs. The cost of these credits (primarily RINs in the U.S.) was
$536 million
in
2018
compared to
$942 million
in
2017
, a decrease of
$406 million
.
|
•
|
Higher throughput volumes.
Refining segment throughput volumes increased by
46,000
BPD in
2018
. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $153 million.
|
•
|
Decrease in gasoline margins.
We experienced a decrease in gasoline margins throughout all of our regions in
2018
compared to
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was
$4.81
per barrel for
2018
compared to
$10.50
per barrel for
2017
, representing an unfavorable decrease of
$5.69
per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARBOB 87 gasoline, which was
$13.05
per barrel for 2018 compared to
$18.12
per barrel for 2017, representing an unfavorable decrease of
$5.07
per barrel. We estimate that the decrease in gasoline margins per barrel in
2018
compared to
2017
had an unfavorable impact to our refining segment margin of approximately $1.3 billion.
|
•
|
Lower ethanol prices.
Ethanol prices were lower in
2018
compared to
2017
primarily due to an increase in production. For example, the New York Harbor ethanol price was $1.48 per gallon for
2018
compared to $1.56 per gallon for
2017
, representing an unfavorable decrease of $0.08 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $159 million.
|
•
|
Higher corn prices.
Corn prices were higher in 2018 compared to 2017. For example, the Chicago Board of Trade (CBOT) corn price was $3.68 per bushel for 2018 compared to $3.59 per bushel for 2017, representing an unfavorable increase of $0.09 per bushel. We estimate that the increase in the price of corn had an unfavorable impact to our ethanol segment margin of approximately $36 million.
|
•
|
Higher co-product prices.
An increase in protein values, as compared to soybean meal, had a favorable effect on the prices received for the corn related co-products that we produced. We estimate the increase in corn related co-product prices had a favorable impact to our ethanol segment margin of approximately $101 million.
|
•
|
Higher production volumes.
Ethanol segment margin was favorably impacted by increased production volumes of
137,000
gallons per day in
2018
compared to
2017
primarily due to reliability improvements at our ethanol plants and the additional production volumes associated with the three plants acquired from Green Plains in November 2018. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of approximately $26 million.
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
90,651
|
|
|
$
|
3,324
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
93,980
|
|
Intersegment revenues
|
6
|
|
|
176
|
|
|
452
|
|
|
(634
|
)
|
|
—
|
|
|||||
Total revenues
|
90,657
|
|
|
3,500
|
|
|
452
|
|
|
(629
|
)
|
|
93,980
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
80,865
|
|
|
2,804
|
|
|
—
|
|
|
(632
|
)
|
|
83,037
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
3,959
|
|
|
443
|
|
|
104
|
|
|
(2
|
)
|
|
4,504
|
|
|||||
Depreciation and amortization expense
|
1,800
|
|
|
81
|
|
|
53
|
|
|
—
|
|
|
1,934
|
|
|||||
Total cost of sales
|
86,624
|
|
|
3,328
|
|
|
157
|
|
|
(634
|
)
|
|
89,475
|
|
|||||
Other operating expenses
|
58
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
61
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
829
|
|
|
829
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||
Operating income by segment
|
$
|
3,975
|
|
|
$
|
172
|
|
|
$
|
292
|
|
|
$
|
(876
|
)
|
|
3,563
|
|
|
Other income, net
|
|
|
|
|
|
|
|
|
112
|
|
|||||||||
Interest and debt expense, net of capitalized
interest
|
|
|
|
|
|
|
|
|
(468
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
3,207
|
|
|||||||||
Income tax expense (benefit) (d) (e)
|
|
|
|
|
|
|
|
|
(949
|
)
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
4,156
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
91
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
4,065
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
71,968
|
|
|
$
|
3,691
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
75,659
|
|
Intersegment revenues
|
—
|
|
|
210
|
|
|
363
|
|
|
(573
|
)
|
|
—
|
|
|||||
Total revenues
|
71,968
|
|
|
3,901
|
|
|
363
|
|
|
(573
|
)
|
|
75,659
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
63,405
|
|
|
3,130
|
|
|
—
|
|
|
(573
|
)
|
|
65,962
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
3,740
|
|
|
415
|
|
|
96
|
|
|
—
|
|
|
4,251
|
|
|||||
Depreciation and amortization expense
|
1,734
|
|
|
66
|
|
|
46
|
|
|
—
|
|
|
1,846
|
|
|||||
Lower of cost or market inventory valuation
adjustment (f)
|
(697
|
)
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
(747
|
)
|
|||||
Total cost of sales
|
68,182
|
|
|
3,561
|
|
|
142
|
|
|
(573
|
)
|
|
71,312
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
709
|
|
|
709
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
|||||
Asset impairment loss (g)
|
56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|||||
Operating income by segment
|
$
|
3,730
|
|
|
$
|
340
|
|
|
$
|
221
|
|
|
$
|
(757
|
)
|
|
3,534
|
|
|
Other income, net
|
|
|
|
|
|
|
|
|
94
|
|
|||||||||
Interest and debt expense, net of capitalized
interest
|
|
|
|
|
|
|
|
|
(446
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
3,182
|
|
|||||||||
Income tax expense (g)
|
|
|
|
|
|
|
|
|
765
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
2,417
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
128
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
2,289
|
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Reconciliation of net income attributable to Valero Energy
Corporation stockholders to adjusted net income attributable to
Valero Energy Corporation stockholders (h)
|
|
|
|
||||
Net income attributable to Valero Energy Corporation stockholders
|
$
|
4,065
|
|
|
$
|
2,289
|
|
Exclude adjustments:
|
|
|
|
||||
Lower of cost or market inventory valuation adjustment (f)
|
—
|
|
|
747
|
|
||
Income tax expense related to the lower of cost or market inventory
valuation adjustment
|
—
|
|
|
(168
|
)
|
||
Lower of cost or market inventory valuation adjustment, net of taxes
|
—
|
|
|
579
|
|
||
Asset impairment loss (g)
|
—
|
|
|
(56
|
)
|
||
Income tax benefit on Aruba Disposition (g)
|
—
|
|
|
42
|
|
||
Income tax benefit from Tax Reform (d) (e)
|
1,862
|
|
|
—
|
|
||
Total adjustments
|
1,862
|
|
|
565
|
|
||
Adjusted net income attributable to
Valero Energy Corporation stockholders
|
$
|
2,203
|
|
|
$
|
1,724
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Reconciliation of operating income to adjusted
operating income (h)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment
|
$
|
3,975
|
|
|
$
|
172
|
|
|
$
|
292
|
|
|
$
|
(876
|
)
|
|
$
|
3,563
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Other operating expenses
|
(58
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(61
|
)
|
|||||
Adjusted operating income
|
$
|
4,033
|
|
|
$
|
172
|
|
|
$
|
295
|
|
|
$
|
(876
|
)
|
|
$
|
3,624
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
|
||||||||||
Reconciliation of operating income to adjusted
operating income (h)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment
|
$
|
3,730
|
|
|
$
|
340
|
|
|
$
|
221
|
|
|
$
|
(757
|
)
|
|
$
|
3,534
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lower of cost or market inventory valuation
adjustment (f)
|
697
|
|
|
50
|
|
|
—
|
|
|
—
|
|
|
747
|
|
|||||
Asset impairment loss (g)
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(56
|
)
|
|||||
Adjusted operating income
|
$
|
3,089
|
|
|
$
|
290
|
|
|
$
|
221
|
|
|
$
|
(757
|
)
|
|
$
|
2,843
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Throughput volumes (thousand BPD)
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude oil
|
469
|
|
|
396
|
|
|
73
|
|
|||
Medium/light sour crude oil
|
458
|
|
|
526
|
|
|
(68
|
)
|
|||
Sweet crude oil
|
1,323
|
|
|
1,193
|
|
|
130
|
|
|||
Residuals
|
219
|
|
|
272
|
|
|
(53
|
)
|
|||
Other feedstocks
|
148
|
|
|
152
|
|
|
(4
|
)
|
|||
Total feedstocks
|
2,617
|
|
|
2,539
|
|
|
78
|
|
|||
Blendstocks and other
|
323
|
|
|
316
|
|
|
7
|
|
|||
Total throughput volumes
|
2,940
|
|
|
2,855
|
|
|
85
|
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD)
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,423
|
|
|
1,404
|
|
|
19
|
|
|||
Distillates
|
1,127
|
|
|
1,066
|
|
|
61
|
|
|||
Other products (i)
|
428
|
|
|
421
|
|
|
7
|
|
|||
Total yields
|
2,978
|
|
|
2,891
|
|
|
87
|
|
|||
|
|
|
|
|
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Refining segment margin (h)
|
$
|
9,792
|
|
|
$
|
8,563
|
|
|
$
|
1,229
|
|
Adjusted refining segment operating income
(see page 41) (h)
|
$
|
4,033
|
|
|
$
|
3,089
|
|
|
$
|
944
|
|
Throughput volumes (thousand BPD)
|
2,940
|
|
|
2,855
|
|
|
85
|
|
|||
|
|
|
|
|
|
||||||
Refining segment margin per barrel of throughput
|
$
|
9.12
|
|
|
$
|
8.20
|
|
|
$
|
0.92
|
|
Less:
|
|
|
|
|
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per barrel of
throughput
|
3.69
|
|
|
3.58
|
|
|
0.11
|
|
|||
Depreciation and amortization expense per barrel of
throughput
|
1.67
|
|
|
1.66
|
|
|
0.01
|
|
|||
Adjusted refining segment operating income per barrel of
throughput
|
$
|
3.76
|
|
|
$
|
2.96
|
|
|
$
|
0.80
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Ethanol segment margin (h)
|
$
|
696
|
|
|
$
|
771
|
|
|
$
|
(75
|
)
|
Adjusted ethanol segment operating income
(see page 41) (h)
|
$
|
172
|
|
|
$
|
290
|
|
|
$
|
(118
|
)
|
Production volumes (thousand gallons per day)
|
3,972
|
|
|
3,842
|
|
|
130
|
|
|||
|
|
|
|
|
|
|
|||||
Ethanol segment margin per gallon of production
|
$
|
0.48
|
|
|
$
|
0.55
|
|
|
$
|
(0.07
|
)
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per gallon of
production
|
0.31
|
|
|
0.30
|
|
|
0.01
|
|
|||
Depreciation and amortization expense per gallon of
production
|
0.05
|
|
|
0.04
|
|
|
0.01
|
|
|||
Adjusted ethanol segment operating income
per gallon of production
|
$
|
0.12
|
|
|
$
|
0.21
|
|
|
$
|
(0.09
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Operating statistics (j)
|
|
|
|
|
|
||||||
Pipeline transportation revenue
|
$
|
101
|
|
|
$
|
78
|
|
|
$
|
23
|
|
Terminaling revenue
|
348
|
|
|
284
|
|
|
64
|
|
|||
Storage and other revenue
|
3
|
|
|
1
|
|
|
2
|
|
|||
Total VLP segment revenues
|
$
|
452
|
|
|
$
|
363
|
|
|
$
|
89
|
|
|
|
|
|
|
|
||||||
Pipeline transportation throughput
(thousand BPD)
|
964
|
|
|
829
|
|
|
135
|
|
|||
Pipeline transportation revenue per barrel of throughput
|
$
|
0.29
|
|
|
$
|
0.26
|
|
|
$
|
0.03
|
|
|
|
|
|
|
|
||||||
Terminaling throughput (thousand BPD)
|
2,889
|
|
|
2,265
|
|
|
624
|
|
|||
Terminaling revenue per barrel of throughput
|
$
|
0.33
|
|
|
$
|
0.34
|
|
|
$
|
(0.01
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
Change
|
||||||
Feedstocks
|
|
|
|
|
|
||||||
Brent crude oil
|
$
|
54.82
|
|
|
$
|
45.02
|
|
|
$
|
9.80
|
|
Brent less WTI crude oil
|
3.92
|
|
|
1.83
|
|
|
2.09
|
|
|||
Brent less ANS crude oil
|
0.26
|
|
|
1.25
|
|
|
(0.99
|
)
|
|||
Brent less LLS crude oil
|
0.69
|
|
|
0.15
|
|
|
0.54
|
|
|||
Brent less ASCI crude oil
|
4.18
|
|
|
5.18
|
|
|
(1.00
|
)
|
|||
Brent less Maya crude oil
|
7.74
|
|
|
8.63
|
|
|
(0.89
|
)
|
|||
LLS crude oil
|
54.13
|
|
|
44.87
|
|
|
9.26
|
|
|||
LLS less ASCI crude oil
|
3.49
|
|
|
5.03
|
|
|
(1.54
|
)
|
|||
LLS less Maya crude oil
|
7.05
|
|
|
8.48
|
|
|
(1.43
|
)
|
|||
WTI crude oil
|
50.90
|
|
|
43.19
|
|
|
7.71
|
|
|||
|
|
|
|
|
|
||||||
Natural gas (dollars per MMBtu)
|
2.98
|
|
|
2.46
|
|
|
0.52
|
|
|||
|
|
|
|
|
|
||||||
Products
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
10.50
|
|
|
9.17
|
|
|
1.33
|
|
|||
Ultra-low-sulfur diesel less Brent
|
13.26
|
|
|
10.21
|
|
|
3.05
|
|
|||
Propylene less Brent
|
0.48
|
|
|
(6.68
|
)
|
|
7.16
|
|
|||
CBOB gasoline less LLS
|
11.19
|
|
|
9.32
|
|
|
1.87
|
|
|||
Ultra-low-sulfur diesel less LLS
|
13.95
|
|
|
10.36
|
|
|
3.59
|
|
|||
Propylene less LLS
|
1.17
|
|
|
(6.53
|
)
|
|
7.70
|
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
CBOB gasoline less WTI
|
15.65
|
|
|
11.82
|
|
|
3.83
|
|
|||
Ultra-low-sulfur diesel less WTI
|
18.50
|
|
|
13.03
|
|
|
5.47
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
12.57
|
|
|
11.99
|
|
|
0.58
|
|
|||
Ultra-low-sulfur diesel less Brent
|
14.75
|
|
|
11.57
|
|
|
3.18
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
CARBOB 87 gasoline less ANS
|
18.12
|
|
|
17.04
|
|
|
1.08
|
|
|||
CARB diesel less ANS
|
17.11
|
|
|
14.52
|
|
|
2.59
|
|
|||
CARBOB 87 gasoline less WTI
|
21.78
|
|
|
17.62
|
|
|
4.16
|
|
|||
CARB diesel less WTI
|
20.77
|
|
|
15.10
|
|
|
5.67
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.26
|
|
|
0.30
|
|
|
(0.04
|
)
|
(a)
|
Cost of materials and other for the year ended December 31, 2018 includes a benefit of $170 million for the biodiesel blender’s tax credit attributable to volumes blended during 2017. The benefit was recognized in February 2018 because the legislation authorizing the credit was passed and signed into law in that month. The $170 million pre-tax benefit is included in the refining segment and includes $80 million attributable to noncontrolling interest and $90 million attributable to Valero Energy Corporation stockholders.
|
(b)
|
General and administrative expenses (excluding depreciation and amortization expense) for the year ended December 31, 2018 includes a charge of $108 million for an environmental reserve adjustment associated with certain non-operating sites.
|
(c)
|
Other income, net for the year ended December 31, 2018 includes a $38 million charge from the early redemption of $750 million of our 9.375 percent senior notes due March 15, 2019.
|
(d)
|
On December 22, 2017, Tax Reform was enacted, resulting in the remeasurement of our U.S. deferred taxes and the recognition of a liability for taxes on the deemed repatriation of our foreign earnings and profits. In addition, Tax Reform lowered the U.S. statutory income tax rate from 35 percent to 21 percent, beginning January 1, 2018. Under U.S. GAAP we are required to recognize the effect of Tax Reform in the period of enactment. As a result, we recognized a $1.9 billion income tax benefit in December 2017, which represented our initial estimate of the impact of Tax Reform in accordance with Staff Accounting Bulletin No. 118 (SAB 118). We finalized our estimates in December 2018 and have recorded an additional benefit of $12 million for the year ended December 31, 2018.
|
(e)
|
Excluding the income tax benefits discussed in note (d) from both years and the other adjustments to income tax reflected in the table on page
31
from 2018, the effective tax rates for the years ended December 31, 2018 and 2017 were 22 percent and 28 percent, respectively. The decrease in the effective rate is primarily due to the decline in the U.S. statutory income tax rate from 35 percent to 21 percent as a result of Tax Reform (see note (d)).
|
(f)
|
In accordance with U.S. GAAP, we are required to state our inventories at the lower of cost or market. When the market price of our inventory falls below cost, we record a lower of cost or market inventory valuation adjustment to write down the value to market. In subsequent periods, the value of our inventory is reassessed and a lower of cost or market inventory valuation adjustment is recorded to reflect the net change in the lower of cost or market inventory valuation reserve between the periods. As of December 31, 2018 and December 31, 2017, the market price of our inventory was above cost; therefore we did not have a lower of cost or market inventory valuation reserve as of those dates. During the year ended December 31, 2016, we recorded a change in our inventory valuation reserve that was established on December 31, 2015, resulting in a noncash benefit of $747 million, of which $697 million and $50 million were attributable to our refining segment and ethanol segment, respectively.
|
(g)
|
Effective October 1, 2016 we (i) transferred ownership of all our assets in Aruba, other than certain hydrocarbon inventories and working capital, to Refineria di Aruba N.V. (RDA), an entity wholly-owned by the Government of Aruba (GOA), (ii) settled our obligations under various agreements with the GOA, including agreements that required us to dismantle our leasehold improvements under certain conditions, and (iii) sold the working capital of our Aruba operations, including hydrocarbon inventories, to the GOA, CITGO Aruba Refining N.V. (CAR), and CITGO Petroleum Corporation (together with CAR and certain other affiliates, collectively, CITGO). We refer to this transaction as the “Aruba Disposition.”
|
(h)
|
We use certain financial measures (as noted below) that are not defined under U.S. GAAP and are considered to be non-GAAP measures.
|
◦
|
Adjusted net income attributable to Valero Energy Corporation stockholders
is defined as net income attributable to Valero Energy Corporation stockholders excluding the items noted below, along with their related income tax effect. We have excluded these items because we believe that they are not indicative of our core operating performance and that their exclusion results in an important measure of our ongoing financial performance to better assess our underlying business results and trends. The basis for our belief with respect to each excluded item is provided below.
|
–
|
Blender’s tax credit attributable to Valero Energy Corporation stockholders
- The blender’s tax credit is attributable to volumes blended during 2017 and is not related to 2018 activities, as described in note (a).
|
–
|
Lower of cost or market inventory valuation adjustment -
The noncash benefit recorded during 2016 to adjust our inventory valuation reserve, as described in note (f).
|
–
|
Asset impairment loss -
The impairment loss of $56 million in 2016 associated with the Aruba Disposition, as described in note (g).
|
–
|
Texas City Refinery fire expenses
- The costs incurred to respond to and assess the damage caused by the fire that occurred at the Texas City Refinery on April 19, 2018 are specific to that event and are not ongoing costs incurred in our operations.
|
–
|
Environmental reserve adjustments
- The environmental reserve adjustments are attributable to sites that were shut down by prior owners and subsequently acquired by us (referred to by us as non-operating sites), as described in note (b).
|
–
|
Loss on early redemption of debt
- The penalty and other expenses incurred in connection with the early redemption of our 9.375 percent senior notes due March 15, 2019 (see note (c)) are not associated with the ongoing costs of our borrowing and financing activities.
|
–
|
Income tax benefit from Tax Reform
- Income tax benefit from Tax Reform (see note (d)) is associated with changes in U.S. tax legislation and is not indicative of our core performance.
|
–
|
Income tax benefit from Aruba Disposition -
The income tax benefit in 2016 resulting from the cancellation of outstanding debt obligations associated with the Aruba Disposition, as described in note (g).
|
◦
|
Refining margin
is defined as refining operating income excluding the blender’s tax credit, the lower of cost or market inventory valuation adjustment, the asset impairment loss, operating expenses (excluding depreciation and amortization expense), other operating expenses, and depreciation and amortization expense, as reflected in the table below.
|
◦
|
Ethanol margin
is defined as ethanol operating income excluding the lower of cost or market inventory valuation adjustment, operating expenses (excluding depreciation and amortization expense), and depreciation and amortization expense, as reflected in the table below.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Reconciliation of refining segment operating income
to refining margin
|
|
|
|
|
|
||||||
Operating income
|
$
|
5,119
|
|
|
$
|
3,975
|
|
|
$
|
3,730
|
|
Add back:
|
|
|
|
|
|
||||||
Blender’s tax credit (a)
|
(170
|
)
|
|
—
|
|
|
—
|
|
|||
Lower of cost or market inventory valuation
adjustment (f)
|
—
|
|
|
—
|
|
|
(697
|
)
|
|||
Asset impairment loss (g)
|
—
|
|
|
—
|
|
|
56
|
|
|||
Operating expenses (excluding depreciation and
amortization expense)
|
4,099
|
|
|
3,959
|
|
|
3,740
|
|
|||
Depreciation and amortization expense
|
1,863
|
|
|
1,800
|
|
|
1,734
|
|
|||
Other operating expenses
|
45
|
|
|
58
|
|
|
—
|
|
|||
Refining margin
|
$
|
10,956
|
|
|
$
|
9,792
|
|
|
$
|
8,563
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Reconciliation of ethanol segment operating income
to ethanol margin
|
|
|
|
|
|
||||||
Operating income
|
$
|
82
|
|
|
$
|
172
|
|
|
$
|
340
|
|
Add back:
|
|
|
|
|
|
||||||
Lower of cost or market inventory valuation
adjustment (f)
|
—
|
|
|
—
|
|
|
(50
|
)
|
|||
Operating expenses (excluding depreciation and
amortization expense)
|
470
|
|
|
443
|
|
|
415
|
|
|||
Depreciation and amortization expense
|
78
|
|
|
81
|
|
|
66
|
|
|||
Ethanol margin
|
$
|
630
|
|
|
$
|
696
|
|
|
$
|
771
|
|
◦
|
Adjusted refining operating income
is defined as refining segment operating income excluding the blender’s tax credit, lower of cost or market inventory valuation adjustment, asset impairment loss, and other operating expenses.
|
◦
|
Adjusted ethanol operating income
is defined as ethanol segment operating income excluding the lower of cost or market inventory valuation adjustment.
|
◦
|
Adjusted VLP operating income
is defined as VLP segment operating income excluding other operating expenses.
|
◦
|
Adjusted corporate and eliminations
is defined as corporate and eliminations excluding the environmental reserve adjustments associated with certain non-operating sites (see note (b)).
|
(i)
|
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.
|
(j)
|
Valero uses certain operating statistics (as noted below) to evaluate performance between comparable periods. Different companies may calculate them in different ways.
|
•
|
Increase in distillate margins.
We experienced improved distillate margins throughout all our regions in 2017 compared to 2016. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was
$13.26
per barrel for 2017 compared to
$10.21
per barrel for 2016, representing a favorable increase of $3.05 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was
$18.50
per barrel for 2017 compared to
$13.03
per barrel for 2016, representing a favorable increase of $5.47 per barrel. We estimate that the increase in distillate margins per barrel in 2017 compared to 2016 had a favorable impact to our refining segment margin of approximately $1.2 billion.
|
•
|
Increase in gasoline margins.
We also experienced improved gasoline margins throughout all our regions in 2017 compared to 2016. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was
$15.65
per barrel for 2017 compared to
$11.82
per barrel for 2016, representing a favorable increase of $3.83 per barrel. Another example is the Brent-based reference margin for U.S. Gulf Coast CBOB gasoline, which was
$10.50
per barrel for 2017 compared to
$9.17
per barrel for 2016, representing a favorable increase of $1.33 per barrel. We estimate that the increase in gasoline margins per barrel in 2017 compared to 2016 had a favorable impact to our refining segment margin of approximately $577 million.
|
•
|
Higher throughput volumes
. Refining segment throughput volumes increased by 85,000 BPD in 2017. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $283 million.
|
•
|
Lower discounts on sour crude oils.
The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process sour crude oils that are priced at a discount to Brent crude oil. While we benefitted from processing these sour crude oils in 2017, that benefit declined compared to 2016. For example, ASCI crude oil processed in our U.S. Gulf Coast region sold at a discount to Brent of $4.18 per barrel for 2017 compared to a discount of $5.18 per barrel for 2016, representing an unfavorable decrease of $1.00 per barrel. Another example is Maya crude oil which sold at a discount to Brent of $7.74 per barrel for 2017 compared to $8.63 per barrel for 2016, representing an unfavorable decrease of $0.89 per barrel. We estimate that the reduction in discounts for sour crude oils that we processed in 2017 had an unfavorable impact to our refining segment margin of approximately $305 million.
|
•
|
Lower discounts on other feedstocks
. In addition to crude oil, we utilize other feedstocks such as residuals, in certain of our refining processes. We benefit when we process these other feedstocks that are priced at a discount to Brent crude oil. While we benefitted from processing these types of feedstocks in 2017, that benefit declined compared to 2016. We estimate that the reduction in the discounts for the other feedstocks that we processed in 2017 had an unfavorable impact to our refining segment margin of approximately $203 million.
|
•
|
Higher costs of biofuel credits.
As described in
Note 20
of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs. The cost of these credits (primarily RINs in the U.S.) was $942 million in 2017 compared to $749 million in 2016, an increase of $193 million.
|
•
|
Increase in charges from VLP.
Charges from the VLP segment for transportation and terminaling services increased $89 million in 2017 compared to 2016 primarily due to additional services provided by terminals and a product pipeline system acquired by VLP in 2017 and 2016 that were formerly a part of the refining segment, as well as an undivided interest in crude system assets acquired by VLP in 2017. Details regarding the increase in charges from VLP are discussed in the VLP segment analysis below.
|
•
|
Lower ethanol prices.
Ethanol prices were lower in 2017 compared to 2016 primarily due to higher industry production, which resulted in higher domestic inventories. For example, the New York Harbor ethanol price was $1.56 per gallon for 2017 compared to $1.60 per gallon for 2016. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $73 million.
|
•
|
Lower co-product prices
. A decrease in export demand for corn related co-products, primarily distiller’s grains, had an unfavorable effect on the prices we received. We estimate that the decrease in the price for corn related co-products had an unfavorable impact to our ethanol segment margin of approximately $52 million.
|
•
|
Lower corn prices.
Despite a slight increase in the CBOT corn price from $3.58 per bushel for 2016 to $3.59 per bushel for 2017, we acquired corn at lower prices due to favorable location differentials, resulting in a decrease in the price we paid for corn in 2017 compared to 2016. We estimate that the decrease in the price we paid for corn had a favorable impact to our ethanol segment margin of approximately $25 million.
|
•
|
Higher production volumes.
Ethanol segment margin was favorably impacted by increased production volumes of 130,000 gallons per day in 2017 compared to 2016 primarily due to reliability improvements. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of approximately $25 million.
|
(a)
|
Excludes
$235 million
of cash and cash equivalents related to our variable interest entities (VIEs) that is available for use only by our VIEs.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
$
|
4,371
|
|
|
$
|
5,482
|
|
|
$
|
4,820
|
|
Investing activities
|
(3,928
|
)
|
|
(2,382
|
)
|
|
(2,006
|
)
|
|||
Financing activities
|
(3,168
|
)
|
|
(2,272
|
)
|
|
(2,012
|
)
|
|||
Effect of foreign exchange rate changes on cash
|
(143
|
)
|
|
206
|
|
|
(100
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
$
|
(2,868
|
)
|
|
$
|
1,034
|
|
|
$
|
702
|
|
•
|
an increase in receivables resulting from an increase in sales volumes, partially offset by a decrease in commodity prices;
|
•
|
an increase in inventory primarily due to higher inventory levels;
|
•
|
a decrease in income taxes payable primarily resulting from (i) $527 million of payments in early 2018 related to 2017 tax liabilities and (ii) $181 million of payments in late 2018 that will be applied to 2019 tax liabilities;
|
•
|
a decrease in accrued expenses mainly due to the timing of payments on our environmental compliance program obligations; partially offset by
|
•
|
an increase in accounts payable due to an increase in crude oil and other feedstock volumes purchased, partially offset by a decrease in commodity prices.
|
•
|
fund
$2.7 billion
in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
|
•
|
fund (i)
$468 million
for the Peru Acquisition (as defined and discussed in
Note 2
of Notes to Consolidated Financial Statements) in May 2018; (ii)
$320 million
for the acquisition of three ethanol plants in November 2018; and (iii)
$88 million
for other minor acquisitions;
|
•
|
fund
$124 million
of capital expenditures of certain VIEs;
|
•
|
acquire undivided interests in pipeline and terminal assets for
$212 million
;
|
•
|
redeem our
9.375
percent Senior Notes due March 15, 2019 for
$787 million
(or
104.9
percent of stated value);
|
•
|
make payments on debt and capital lease obligations of $435 million, of which
$410 million
related to the repayment of all outstanding borrowings under VLP’s
$750 million
senior unsecured revolving credit facility (the VLP Revolver);
|
•
|
retire
$137 million
of debt assumed in connection with the Peru Acquisition;
|
•
|
purchase common stock for treasury of
$1.7 billion
;
|
•
|
pay common stock dividends of
$1.4 billion
; and
|
•
|
pay distributions to noncontrolling interests of
$116 million
.
|
•
|
an increase in accounts payable primarily as a result of an increase in commodity prices; and
|
•
|
an increase in income taxes payable resulting from deferring the payment of our fourth quarter 2017 estimated taxes to January 2018, as allowed by tax relief authorization from the IRS; partially offset by
|
•
|
an increase in receivables primarily as a result of an increase in commodity prices; and
|
•
|
an increase in inventory due to higher volumes held combined with an increase in commodity prices.
|
•
|
fund
$2.3 billion
in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
|
•
|
acquire an undivided interest in crude system assets for
$72 million
;
|
•
|
purchase common stock for treasury of
$1.4 billion
;
|
•
|
pay common stock dividends of
$1.2 billion
;
|
•
|
pay distributions to noncontrolling interests of
$67 million
; and
|
•
|
increase available cash on hand by
$1.0 billion
.
|
•
|
an increase in accounts payable primarily as a result of higher commodity prices;
|
•
|
a reduction of our inventories; and
|
•
|
a reduction in prepaid expenses and other related to income taxes receivable due to utilization in 2016 of our 2015 overpayment of taxes; partially offset by
|
•
|
an increase in receivables primarily as a result of higher commodity prices.
|
•
|
fund
$2.0 billion
in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
|
•
|
redeem our
6.125
percent Senior Notes due June 15, 2017 for
$778 million
(or
103.70
percent of stated value) and our
7.2
percent Senior Notes due October 15, 2017 for
$213 million
(or
106.27
percent of stated value);
|
•
|
make payments on debt and capital lease obligations of $525 million, of which
$494 million
related to borrowings under the VLP Revolver, $9 million related to capital lease obligations, and $22 million related to other debt;
|
•
|
pay off a long-term liability of
$137 million
owed to a joint venture partner for an owner-method joint venture investment;
|
•
|
purchase common stock for treasury of
$1.3 billion
;
|
•
|
pay common stock dividends of
$1.1 billion
;
|
•
|
pay distributions to noncontrolling interests of
$65 million
; and
|
•
|
increase available cash on hand by
$702 million
.
|
|
Payments Due by Year
|
|
|
||||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Debt and capital
lease obligations (a)
|
$
|
283
|
|
|
$
|
920
|
|
|
$
|
77
|
|
|
$
|
69
|
|
|
$
|
85
|
|
|
$
|
8,431
|
|
|
$
|
9,865
|
|
Operating lease obligations
|
359
|
|
|
245
|
|
|
178
|
|
|
146
|
|
|
123
|
|
|
514
|
|
|
1,565
|
|
|||||||
Purchase obligations
|
14,853
|
|
|
2,309
|
|
|
1,630
|
|
|
1,407
|
|
|
1,320
|
|
|
4,333
|
|
|
25,852
|
|
|||||||
Other long-term liabilities
|
—
|
|
|
249
|
|
|
232
|
|
|
235
|
|
|
261
|
|
|
1,890
|
|
|
2,867
|
|
|||||||
Total
|
$
|
15,495
|
|
|
$
|
3,723
|
|
|
$
|
2,117
|
|
|
$
|
1,857
|
|
|
$
|
1,789
|
|
|
$
|
15,168
|
|
|
$
|
40,149
|
|
(a)
|
Debt obligations exclude amounts related to unamortized discounts and debt issuance costs. Capital lease obligations include related interest expense.
|
|
|
Rating
|
||
Rating Agency
|
|
Valero
|
|
VLP
|
Moody’s Investors Service
|
|
Baa2 (stable outlook)
|
|
Baa3 (no outlook)
|
Standard & Poor’s Ratings Services
|
|
BBB (stable outlook)
|
|
BBB- (no outlook)
|
Fitch Ratings
|
|
BBB (stable outlook)
|
|
BBB- (no outlook)
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
Increase in projected benefit obligation resulting from:
|
|
|
|
||||
Discount rate decrease of 0.25%
|
$
|
104
|
|
|
$
|
8
|
|
Compensation rate increase of 0.25%
|
12
|
|
|
n/a
|
|
||
Increase in expense resulting from:
|
|
|
|
||||
Discount rate decrease of 0.25%
|
9
|
|
|
1
|
|
||
Expected return on plan assets decrease of 0.25%
|
6
|
|
|
n/a
|
|
||
Compensation rate increase of 0.25%
|
3
|
|
|
n/a
|
|
•
|
inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a LIFO basis) differ from our previous year-end LIFO inventory levels; and
|
•
|
forecasted feedstock and refined petroleum product purchases, refined petroleum 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.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Gain (loss) in fair value resulting from:
|
|
|
|
||||
10% increase in underlying commodity prices
|
$
|
2
|
|
|
$
|
(43
|
)
|
10% decrease in underlying commodity prices
|
(6
|
)
|
|
45
|
|
|
December 31, 2018
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
There-
after
|
|
Total (a)
|
|
Fair
Value
|
||||||||||||||||
Fixed rate
|
$
|
—
|
|
|
$
|
850
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,474
|
|
|
$
|
8,334
|
|
|
$
|
8,737
|
|
Average interest rate
|
—
|
%
|
|
6.1
|
%
|
|
5
|
%
|
|
—
|
%
|
|
—
|
%
|
|
5.4
|
%
|
|
5.5
|
%
|
|
|
|||||||||
Floating rate (b)
|
$
|
214
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
20
|
|
|
$
|
—
|
|
|
$
|
249
|
|
|
$
|
249
|
|
Average interest rate
|
4.6
|
%
|
|
4.7
|
%
|
|
4.7
|
%
|
|
4.7
|
%
|
|
4.7
|
%
|
|
—
|
%
|
|
4.6
|
%
|
|
|
|
December 31, 2017
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-
after
|
|
Total (a)
|
|
Fair
Value
|
||||||||||||||||
Fixed rate
|
$
|
—
|
|
|
$
|
750
|
|
|
$
|
850
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,224
|
|
|
$
|
7,824
|
|
|
$
|
9,236
|
|
Average interest rate
|
—
|
%
|
|
9.4
|
%
|
|
6.1
|
%
|
|
—
|
%
|
|
—
|
%
|
|
5.6
|
%
|
|
6.0
|
%
|
|
|
|||||||||
Floating rate (b)
|
$
|
106
|
|
|
$
|
6
|
|
|
$
|
416
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
19
|
|
|
$
|
559
|
|
|
$
|
559
|
|
Average interest rate
|
2.1
|
%
|
|
3.8
|
%
|
|
2.9
|
%
|
|
3.8
|
%
|
|
3.8
|
%
|
|
3.8
|
%
|
|
2.8
|
%
|
|
|
(a)
|
Excludes unamortized discounts and debt issuance costs.
|
(b)
|
As of
December 31, 2018
and
2017
, we had an interest rate swap associated with $40 million and $49 million, respectively, of our floating rate debt resulting in an effective interest rate of 3.85 percent as of each of those reporting dates. The fair value of the swap was immaterial for all periods presented.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
2,982
|
|
|
$
|
5,850
|
|
Receivables, net
|
7,345
|
|
|
6,922
|
|
||
Inventories
|
6,532
|
|
|
6,384
|
|
||
Prepaid expenses and other
|
816
|
|
|
156
|
|
||
Total current assets
|
17,675
|
|
|
19,312
|
|
||
Property, plant, and equipment, at cost
|
42,473
|
|
|
40,010
|
|
||
Accumulated depreciation
|
(13,625
|
)
|
|
(12,530
|
)
|
||
Property, plant, and equipment, net
|
28,848
|
|
|
27,480
|
|
||
Deferred charges and other assets, net
|
3,632
|
|
|
3,366
|
|
||
Total assets
|
$
|
50,155
|
|
|
$
|
50,158
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Current portion of debt and capital lease obligations
|
$
|
238
|
|
|
$
|
122
|
|
Accounts payable
|
8,594
|
|
|
8,348
|
|
||
Accrued expenses
|
630
|
|
|
712
|
|
||
Taxes other than income taxes payable
|
1,213
|
|
|
1,321
|
|
||
Income taxes payable
|
49
|
|
|
568
|
|
||
Total current liabilities
|
10,724
|
|
|
11,071
|
|
||
Debt and capital lease obligations, less current portion
|
8,871
|
|
|
8,750
|
|
||
Deferred income tax liabilities
|
4,962
|
|
|
4,708
|
|
||
Other long-term liabilities
|
2,867
|
|
|
2,729
|
|
||
Commitments and contingencies
|
|
|
|
||||
Equity:
|
|
|
|
||||
Valero Energy Corporation stockholders’ equity:
|
|
|
|
||||
Common stock, $0.01 par value; 1,200,000,000 shares authorized;
673,501,593 and 673,501,593 shares issued
|
7
|
|
|
7
|
|
||
Additional paid-in capital
|
7,048
|
|
|
7,039
|
|
||
Treasury stock, at cost;
255,905,051
and 239,603,534 common shares
|
(14,925
|
)
|
|
(13,315
|
)
|
||
Retained earnings
|
31,044
|
|
|
29,200
|
|
||
Accumulated other comprehensive loss
|
(1,507
|
)
|
|
(940
|
)
|
||
Total Valero Energy Corporation stockholders’ equity
|
21,667
|
|
|
21,991
|
|
||
Noncontrolling interests
|
1,064
|
|
|
909
|
|
||
Total equity
|
22,731
|
|
|
22,900
|
|
||
Total liabilities and equity
|
$
|
50,155
|
|
|
$
|
50,158
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues (a)
|
$
|
117,033
|
|
|
$
|
93,980
|
|
|
$
|
75,659
|
|
Cost of sales:
|
|
|
|
|
|
||||||
Cost of materials and other
|
104,732
|
|
|
83,037
|
|
|
65,962
|
|
|||
Operating expenses (excluding depreciation and amortization
expense reflected below)
|
4,690
|
|
|
4,504
|
|
|
4,251
|
|
|||
Depreciation and amortization expense
|
2,017
|
|
|
1,934
|
|
|
1,846
|
|
|||
Lower of cost or market inventory valuation adjustment
|
—
|
|
|
—
|
|
|
(747
|
)
|
|||
Total cost of sales
|
111,439
|
|
|
89,475
|
|
|
71,312
|
|
|||
Other operating expenses
|
45
|
|
|
61
|
|
|
—
|
|
|||
General and administrative expenses (excluding depreciation and
amortization expense reflected below)
|
925
|
|
|
829
|
|
|
709
|
|
|||
Depreciation and amortization expense
|
52
|
|
|
52
|
|
|
48
|
|
|||
Asset impairment loss
|
—
|
|
|
—
|
|
|
56
|
|
|||
Operating income
|
4,572
|
|
|
3,563
|
|
|
3,534
|
|
|||
Other income, net
|
130
|
|
|
112
|
|
|
94
|
|
|||
Interest and debt expense, net of capitalized interest
|
(470
|
)
|
|
(468
|
)
|
|
(446
|
)
|
|||
Income before income tax expense (benefit)
|
4,232
|
|
|
3,207
|
|
|
3,182
|
|
|||
Income tax expense (benefit)
|
879
|
|
|
(949
|
)
|
|
765
|
|
|||
Net income
|
3,353
|
|
|
4,156
|
|
|
2,417
|
|
|||
Less: Net income attributable to noncontrolling interests
|
231
|
|
|
91
|
|
|
128
|
|
|||
Net income attributable to Valero Energy Corporation stockholders
|
$
|
3,122
|
|
|
$
|
4,065
|
|
|
$
|
2,289
|
|
|
|
|
|
|
|
||||||
Earnings per common share
|
$
|
7.30
|
|
|
$
|
9.17
|
|
|
$
|
4.94
|
|
Weighted-average common shares outstanding (in millions)
|
426
|
|
|
442
|
|
|
461
|
|
|||
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution
|
$
|
7.29
|
|
|
$
|
9.16
|
|
|
$
|
4.94
|
|
Weighted-average common shares outstanding –
assuming dilution (in millions)
|
428
|
|
|
444
|
|
|
464
|
|
|||
_______________________________________________
|
|
|
|
|
|
||||||
Supplemental information:
|
|
|
|
|
|
||||||
(a) Includes excise taxes on sales by certain of our international
operations
|
$
|
5,626
|
|
|
$
|
5,573
|
|
|
$
|
5,493
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net income
|
$
|
3,353
|
|
|
$
|
4,156
|
|
|
$
|
2,417
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
(517
|
)
|
|
514
|
|
|
(415
|
)
|
|||
Net gain
(loss) on pension
and other postretirement benefits
|
49
|
|
|
(65
|
)
|
|
(98
|
)
|
|||
Other comprehensive income (loss) before
income tax expense (benefit)
|
(468
|
)
|
|
449
|
|
|
(513
|
)
|
|||
Income tax expense (benefit) related to
items of other comprehensive income (loss)
|
10
|
|
|
(21
|
)
|
|
(37
|
)
|
|||
Other comprehensive income (loss)
|
(478
|
)
|
|
470
|
|
|
(476
|
)
|
|||
Comprehensive income
|
2,875
|
|
|
4,626
|
|
|
1,941
|
|
|||
Less: Comprehensive income attributable
to noncontrolling interests
|
229
|
|
|
91
|
|
|
129
|
|
|||
Comprehensive income attributable to
Valero Energy Corporation stockholders
|
$
|
2,646
|
|
|
$
|
4,535
|
|
|
$
|
1,812
|
|
|
Valero Energy Corporation Stockholders’ Equity
|
|
|
|
|
||||||||||||||||||||||||||
|
Common
Stock
|
|
Additional
Paid-in
Capital
|
|
Treasury
Stock
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Total
|
|
Non-
controlling
Interests
|
|
Total
Equity
|
||||||||||||||||
Balance as of December 31, 2015
|
$
|
7
|
|
|
$
|
7,064
|
|
|
$
|
(10,799
|
)
|
|
$
|
25,188
|
|
|
$
|
(933
|
)
|
|
$
|
20,527
|
|
|
$
|
827
|
|
|
$
|
21,354
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
2,289
|
|
|
—
|
|
|
2,289
|
|
|
128
|
|
|
2,417
|
|
||||||||
Dividends on common stock
($2.40 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,111
|
)
|
|
—
|
|
|
(1,111
|
)
|
|
—
|
|
|
(1,111
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
||||||||
Transactions in connection with
stock-based compensation plans
|
—
|
|
|
(89
|
)
|
|
34
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
(55
|
)
|
||||||||
Stock purchases under purchase program
|
—
|
|
|
—
|
|
|
(1,262
|
)
|
|
—
|
|
|
—
|
|
|
(1,262
|
)
|
|
—
|
|
|
(1,262
|
)
|
||||||||
Issuance of Valero Energy Partners LP
common units |
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
||||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(65
|
)
|
|
(65
|
)
|
||||||||
Other
|
—
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
(72
|
)
|
|
(27
|
)
|
||||||||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(477
|
)
|
|
(477
|
)
|
|
1
|
|
|
(476
|
)
|
||||||||
Balance as of December 31, 2016
|
7
|
|
|
7,088
|
|
|
(12,027
|
)
|
|
26,366
|
|
|
(1,410
|
)
|
|
20,024
|
|
|
830
|
|
|
20,854
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
4,065
|
|
|
—
|
|
|
4,065
|
|
|
91
|
|
|
4,156
|
|
||||||||
Dividends on common stock
($2.80 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,242
|
)
|
|
—
|
|
|
(1,242
|
)
|
|
—
|
|
|
(1,242
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
||||||||
Transactions in connection with
stock-based compensation plans
|
—
|
|
|
(82
|
)
|
|
19
|
|
|
—
|
|
|
—
|
|
|
(63
|
)
|
|
—
|
|
|
(63
|
)
|
||||||||
Stock purchases under purchase programs
|
—
|
|
|
—
|
|
|
(1,307
|
)
|
|
—
|
|
|
—
|
|
|
(1,307
|
)
|
|
—
|
|
|
(1,307
|
)
|
||||||||
Issuance of Valero Energy Partners LP
common units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
33
|
|
||||||||
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30
|
|
|
30
|
|
||||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(67
|
)
|
|
(67
|
)
|
||||||||
Other
|
—
|
|
|
(35
|
)
|
|
—
|
|
|
11
|
|
|
—
|
|
|
(24
|
)
|
|
(8
|
)
|
|
(32
|
)
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
470
|
|
|
470
|
|
|
—
|
|
|
470
|
|
||||||||
Balance as of December 31, 2017
|
7
|
|
|
7,039
|
|
|
(13,315
|
)
|
|
29,200
|
|
|
(940
|
)
|
|
21,991
|
|
|
909
|
|
|
22,900
|
|
||||||||
Reclassification of stranded income tax
effects of Tax Reform per ASU 2018-02
(see Note 1)
|
—
|
|
|
—
|
|
|
—
|
|
|
91
|
|
|
(91
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
3,122
|
|
|
—
|
|
|
3,122
|
|
|
231
|
|
|
3,353
|
|
||||||||
Dividends on common stock
($3.20 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,369
|
)
|
|
—
|
|
|
(1,369
|
)
|
|
—
|
|
|
(1,369
|
)
|
||||||||
Stock-based compensation expense
|
—
|
|
|
82
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
—
|
|
|
82
|
|
||||||||
Transactions in connection with
stock-based compensation plans
|
—
|
|
|
(70
|
)
|
|
(99
|
)
|
|
—
|
|
|
—
|
|
|
(169
|
)
|
|
—
|
|
|
(169
|
)
|
||||||||
Stock purchases under purchase programs
|
—
|
|
|
—
|
|
|
(1,511
|
)
|
|
—
|
|
|
—
|
|
|
(1,511
|
)
|
|
—
|
|
|
(1,511
|
)
|
||||||||
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32
|
|
|
32
|
|
||||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(116
|
)
|
|
(116
|
)
|
||||||||
Other
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
10
|
|
|
7
|
|
||||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(476
|
)
|
|
(476
|
)
|
|
(2
|
)
|
|
(478
|
)
|
||||||||
Balance as of December 31, 2018
|
$
|
7
|
|
|
$
|
7,048
|
|
|
$
|
(14,925
|
)
|
|
$
|
31,044
|
|
|
$
|
(1,507
|
)
|
|
$
|
21,667
|
|
|
$
|
1,064
|
|
|
$
|
22,731
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
3,353
|
|
|
$
|
4,156
|
|
|
$
|
2,417
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
2,069
|
|
|
1,986
|
|
|
1,894
|
|
|||
Lower of cost or market inventory valuation adjustment
|
—
|
|
|
—
|
|
|
(747
|
)
|
|||
Asset impairment loss
|
—
|
|
|
—
|
|
|
56
|
|
|||
Deferred income tax expense (benefit)
|
203
|
|
|
(2,543
|
)
|
|
230
|
|
|||
Changes in current assets and current liabilities
|
(1,297
|
)
|
|
1,289
|
|
|
976
|
|
|||
Changes in deferred charges and credits and
other operating activities, net
|
43
|
|
|
594
|
|
|
(6
|
)
|
|||
Net cash provided by operating activities
|
4,371
|
|
|
5,482
|
|
|
4,820
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(1,628
|
)
|
|
(1,353
|
)
|
|
(1,278
|
)
|
|||
Deferred turnaround and catalyst costs
|
(915
|
)
|
|
(523
|
)
|
|
(718
|
)
|
|||
Investments in joint ventures
|
(181
|
)
|
|
(406
|
)
|
|
(4
|
)
|
|||
Capital expenditures of certain variable interest entities (VIEs)
|
(124
|
)
|
|
(26
|
)
|
|
—
|
|
|||
Peru Acquisition, net of cash acquired
|
(468
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisition of ethanol plants
|
(320
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisitions of undivided interests
|
(212
|
)
|
|
(72
|
)
|
|
—
|
|
|||
Minor acquisitions
|
(88
|
)
|
|
—
|
|
|
—
|
|
|||
Other investing activities, net
|
8
|
|
|
(2
|
)
|
|
(6
|
)
|
|||
Net cash used in investing activities
|
(3,928
|
)
|
|
(2,382
|
)
|
|
(2,006
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from debt issuances and borrowings (excluding
borrowings of certain VIEs)
|
1,258
|
|
|
380
|
|
|
2,153
|
|
|||
Proceeds from borrowings of certain VIEs
|
109
|
|
|
—
|
|
|
—
|
|
|||
Repayments of debt and capital lease obligations
|
(1,359
|
)
|
|
(21
|
)
|
|
(1,475
|
)
|
|||
Purchases of common stock for treasury
|
(1,708
|
)
|
|
(1,372
|
)
|
|
(1,336
|
)
|
|||
Common stock dividends
|
(1,369
|
)
|
|
(1,242
|
)
|
|
(1,111
|
)
|
|||
Contributions from noncontrolling interests
|
32
|
|
|
30
|
|
|
—
|
|
|||
Distributions to noncontrolling interests
|
(116
|
)
|
|
(67
|
)
|
|
(65
|
)
|
|||
Other financing activities, net
|
(15
|
)
|
|
20
|
|
|
(178
|
)
|
|||
Net cash used in financing activities
|
(3,168
|
)
|
|
(2,272
|
)
|
|
(2,012
|
)
|
|||
Effect of foreign exchange rate changes on cash
|
(143
|
)
|
|
206
|
|
|
(100
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
(2,868
|
)
|
|
1,034
|
|
|
702
|
|
|||
Cash and cash equivalents at beginning of year
|
5,850
|
|
|
4,816
|
|
|
4,114
|
|
|||
Cash and cash equivalents at end of year
|
$
|
2,982
|
|
|
$
|
5,850
|
|
|
$
|
4,816
|
|
1.
|
DESCRIPTION OF BUSINESS, BASIS OF PRESENTATION, AND SIGNIFICANT ACCOUNTING POLICIES
|
•
|
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;
|
•
|
income taxes receivable;
|
•
|
investments in joint ventures accounted for under the equity method;
|
•
|
intangible assets; and
|
•
|
goodwill.
|
•
|
Transition Elections
. We elected the package of practical expedients that permits us to not reassess our prior conclusions about lease identification, lease classification, and initial direct costs under the new standard, as well as the practical expedient that permits us to not assess existing land easements under the new standard.
|
•
|
Lessee Accounting Policy Elections.
We elected the short-term lease recognition exemption whereby right-of-use (ROU) assets and lease liabilities are not recognized for leasing arrangements with terms less than one year, and the practical expedient to not separate lease and non-lease components for all classes of underlying assets other than the marine transportation asset class.
|
2.
|
ACQUISITIONS AND MERGER
|
Current assets, net of cash acquired
|
$
|
158
|
|
Property, plant, and equipment
|
102
|
|
|
Deferred charges and other assets
|
466
|
|
|
Current liabilities, excluding current portion of debt
|
(26
|
)
|
|
Debt assumed, including current portion
|
(137
|
)
|
|
Deferred income tax liabilities
|
(62
|
)
|
|
Other long-term liabilities
|
(27
|
)
|
|
Noncontrolling interest
|
(6
|
)
|
|
Total consideration, net of cash acquired
|
$
|
468
|
|
3.
|
ARUBA DISPOSITION
|
4.
|
RECEIVABLES
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Receivables from contracts with customers
|
$
|
4,673
|
|
|
$
|
5,686
|
|
Receivables from certain purchase and sale arrangements
|
2,311
|
|
|
1,098
|
|
||
Commodity derivative and foreign currency
contract receivables
|
229
|
|
|
102
|
|
||
Other receivables
|
166
|
|
|
69
|
|
||
Total receivables
|
7,379
|
|
|
6,955
|
|
||
Allowance for doubtful accounts
|
(34
|
)
|
|
(33
|
)
|
||
Receivables, net
|
$
|
7,345
|
|
|
$
|
6,922
|
|
|
|
|
|
|
|
5.
|
INVENTORIES
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Refinery feedstocks
|
$
|
2,292
|
|
|
$
|
2,427
|
|
Refined petroleum products and blendstocks
|
3,678
|
|
|
3,459
|
|
||
Ethanol feedstocks and products
|
298
|
|
|
242
|
|
||
Materials and supplies
|
264
|
|
|
256
|
|
||
Inventories
|
$
|
6,532
|
|
|
$
|
6,384
|
|
6.
|
PROPERTY, PLANT, AND EQUIPMENT
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Land
|
|
$
|
416
|
|
|
$
|
411
|
|
Crude oil processing facilities
|
|
30,721
|
|
|
30,109
|
|
||
Transportation and terminaling facilities
|
|
4,935
|
|
|
4,335
|
|
||
Grain processing equipment
|
|
1,212
|
|
|
903
|
|
||
Administrative buildings
|
|
953
|
|
|
910
|
|
||
Other
|
|
2,276
|
|
|
2,068
|
|
||
Construction in progress
|
|
1,960
|
|
|
1,274
|
|
||
Property, plant, and equipment, at cost
|
|
42,473
|
|
|
40,010
|
|
||
Accumulated depreciation
|
|
(13,625
|
)
|
|
(12,530
|
)
|
||
Property, plant, and equipment, net
|
|
$
|
28,848
|
|
|
$
|
27,480
|
|
7.
|
DEFERRED CHARGES AND OTHER ASSETS
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred turnaround and catalyst costs, net
|
$
|
1,749
|
|
|
$
|
1,520
|
|
Income taxes receivable
|
343
|
|
|
673
|
|
||
Investments in joint ventures
|
542
|
|
|
530
|
|
||
Intangible assets, net
|
307
|
|
|
142
|
|
||
Goodwill
|
260
|
|
|
—
|
|
||
Other
|
431
|
|
|
501
|
|
||
Deferred charges and other assets, net
|
$
|
3,632
|
|
|
$
|
3,366
|
|
8.
|
ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES
|
|
Accrued
Expenses
|
|
Other Long-Term
Liabilities
|
||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Defined benefit plan liabilities (see Note 13)
|
$
|
43
|
|
|
$
|
33
|
|
|
$
|
654
|
|
|
$
|
776
|
|
Wage and other employee-related liabilities
|
302
|
|
|
278
|
|
|
109
|
|
|
111
|
|
||||
Uncertain income tax position liabilities (see Note 15)
|
—
|
|
|
—
|
|
|
721
|
|
|
723
|
|
||||
Repatriation tax liability (see Note 15) (a)
|
—
|
|
|
—
|
|
|
603
|
|
|
597
|
|
||||
Environmental liabilities (see Note 10)
|
29
|
|
|
30
|
|
|
327
|
|
|
232
|
|
||||
Environmental credit obligations (see Note 19)
|
34
|
|
|
152
|
|
|
—
|
|
|
—
|
|
||||
Accrued interest expense
|
93
|
|
|
105
|
|
|
—
|
|
|
—
|
|
||||
Other accrued liabilities
|
129
|
|
|
114
|
|
|
453
|
|
|
290
|
|
||||
Accrued expenses and other long-term liabilities
|
$
|
630
|
|
|
$
|
712
|
|
|
$
|
2,867
|
|
|
$
|
2,729
|
|
(a)
|
The current portion of repatriation tax liability is included in income taxes payable. There was
no
current portion of repatriation tax liability as of
December 31, 2018
and
$114 million
as of
December 31, 2017
.
|
9.
|
DEBT AND CAPITAL LEASE OBLIGATIONS
|
|
Final
Maturity
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
|||||
Credit facilities:
|
|
|
|
|
|
||||
Valero Revolver
|
2020
|
|
$
|
—
|
|
|
$
|
—
|
|
VLP Revolver
|
2020
|
|
—
|
|
|
410
|
|
||
IEnova Revolver
|
2028
|
|
109
|
|
|
—
|
|
||
Canadian Revolver
|
2019
|
|
—
|
|
|
—
|
|
||
Accounts receivable sales facility
|
2019
|
|
100
|
|
|
100
|
|
||
Public debt:
|
|
|
|
|
|
||||
Valero Senior Notes
|
|
|
|
|
|
||||
6.625%
|
2037
|
|
1,500
|
|
|
1,500
|
|
||
3.4%
|
2026
|
|
1,250
|
|
|
1,250
|
|
||
6.125%
|
2020
|
|
850
|
|
|
850
|
|
||
4.35 %
|
2028
|
|
750
|
|
|
—
|
|
||
9.375%
|
2019
|
|
—
|
|
|
750
|
|
||
7.5%
|
2032
|
|
750
|
|
|
750
|
|
||
4.9%
|
2045
|
|
650
|
|
|
650
|
|
||
3.65%
|
2025
|
|
600
|
|
|
600
|
|
||
10.5%
|
2039
|
|
250
|
|
|
250
|
|
||
8.75%
|
2030
|
|
200
|
|
|
200
|
|
||
7.45%
|
2097
|
|
100
|
|
|
100
|
|
||
6.75%
|
2037
|
|
24
|
|
|
24
|
|
||
VLP Senior Notes
|
|
|
|
|
|
||||
4.375%
|
2026
|
|
500
|
|
|
500
|
|
||
4.5%
|
2028
|
|
500
|
|
|
—
|
|
||
Gulf Opportunity Zone Revenue Bonds, Series 2010, 4.0%
|
2040
|
|
300
|
|
|
300
|
|
||
Debenture, 7.65%
|
2026
|
|
100
|
|
|
100
|
|
||
Other debt
|
Various
|
|
50
|
|
|
49
|
|
||
Net unamortized debt issuance costs and other
|
|
|
(80
|
)
|
|
(73
|
)
|
||
Total debt
|
|
|
8,503
|
|
|
8,310
|
|
||
Capital lease obligations
|
|
|
606
|
|
|
562
|
|
||
Total debt and capital lease obligations
|
|
|
9,109
|
|
|
8,872
|
|
||
Less current portion
|
|
|
238
|
|
|
122
|
|
||
Debt and capital lease obligations, less current portion
|
|
|
$
|
8,871
|
|
|
$
|
8,750
|
|
|
|
|
|
|
|
December 31, 2018
|
||||||||||||
|
|
Facility
Amount
|
|
Maturity Date
|
|
Outstanding
Borrowings
|
|
Letters of
Credit Issued
|
|
Availability
|
||||||||
|
|
|
|
|
|
|||||||||||||
Committed facilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Valero Revolver
|
|
$
|
3,000
|
|
|
November 2020
|
|
$
|
—
|
|
|
$
|
57
|
|
|
$
|
2,943
|
|
Canadian Revolver
|
|
C$
|
150
|
|
|
November 2019
|
|
C$
|
—
|
|
|
C$
|
5
|
|
|
C$
|
145
|
|
Accounts receivable
sales facility
|
|
$
|
1,300
|
|
|
July 2019
|
|
$
|
100
|
|
|
n/a
|
|
|
$
|
1,200
|
|
|
Letter of credit facility
|
|
$
|
100
|
|
|
November 2019
|
|
n/a
|
|
|
$
|
—
|
|
|
$
|
100
|
|
|
Committed facilities of
VIEs (a):
|
|
|
|
|
|
|
|
|
|
|
||||||||
VLP Revolver (b)
|
|
$
|
750
|
|
|
November 2020
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
750
|
|
IEnova Revolver
|
|
$
|
340
|
|
|
February 2028
|
|
$
|
109
|
|
|
n/a
|
|
|
$
|
231
|
|
|
Uncommitted facilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Letter of credit facilities
|
|
n/a
|
|
|
n/a
|
|
n/a
|
|
|
$
|
229
|
|
|
n/a
|
|
(a)
|
Creditors of our VIEs do not have recourse against us.
|
(b)
|
The VLP Revolver was terminated on
January 10, 2019
. See “VLP Revolver” above.
|
•
|
We issued
$750 million
of
4.35
percent Senior Notes due
June 1, 2028
. Proceeds from this debt issuance totaled
$749 million
before deducting the underwriting discount and other debt issuance costs. The proceeds were used to redeem our
9.375
percent Senior Notes due
March 15, 2019
for
$787 million
, or
104.9
percent of stated value, which includes an early redemption fee of
$37 million
that is reflected in other income, net.
|
•
|
VLP issued
$500 million
of
4.5
percent Senior Notes due
March 15, 2028
. Proceeds from this debt issuance totaled
$498 million
before deducting the underwriting discount and other debt issuance costs. The proceeds were available only to the operations of VLP and were used to repay the outstanding balance of
$410 million
on the VLP Revolver and
$85 million
on its notes payable to
|
•
|
We issued
$1.25 billion
of
3.4
percent Senior Notes due
September 15, 2026
. Proceeds from this debt issuance totaled
$1.246 billion
before deducting the underwriting discount and other debt issuance costs.
|
•
|
We redeemed our
6.125
percent Senior Notes due
June 15, 2017
for
$778 million
, or
103.70
percent of stated value.
|
•
|
We redeemed our
7.2
percent Senior Notes due
October 15, 2017
for
$213 million
, or
106.27
percent of stated value.
|
•
|
VLP issued
$500 million
of
4.375
percent Senior Notes due
December 15, 2026
. Proceeds from this debt issuance totaled
$500 million
before deducting the underwriting discount and other debt issuance costs. The proceeds were available only to the operations of VLP and were used to repay
$494 million
on the VLP Revolver. On
January 10, 2019
, in connection with the completion of the Merger Transaction as described in
Note 2
, Valero entered into a guarantee agreement to fully and unconditionally guarantee the prompt payment, when due, of any amount owed to the holders of these notes.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Interest and debt expense
|
$
|
557
|
|
|
$
|
539
|
|
|
$
|
511
|
|
Less capitalized interest
|
87
|
|
|
71
|
|
|
65
|
|
|||
Interest and debt expense, net of
capitalized interest
|
$
|
470
|
|
|
$
|
468
|
|
|
$
|
446
|
|
|
Debt
|
|
Capital
Lease
Obligations
|
||||
2019
|
$
|
214
|
|
|
$
|
69
|
|
2020
|
855
|
|
|
65
|
|
||
2021
|
15
|
|
|
62
|
|
||
2022
|
5
|
|
|
64
|
|
||
2023
|
20
|
|
|
65
|
|
||
Thereafter
|
7,474
|
|
|
957
|
|
||
Net unamortized debt issuance
costs and other
|
(80
|
)
|
|
n/a
|
|
||
Total minimum lease payments
|
n/a
|
|
|
1,282
|
|
||
Less amount representing interest
|
n/a
|
|
|
676
|
|
||
Total
|
$
|
8,503
|
|
|
$
|
606
|
|
10.
|
COMMITMENTS AND CONTINGENCIES
|
2019
|
$
|
359
|
|
2020
|
245
|
|
|
2021
|
178
|
|
|
2022
|
146
|
|
|
2023
|
123
|
|
|
Thereafter
|
514
|
|
|
Total minimum rental payments
|
$
|
1,565
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Minimum rental expense
|
$
|
515
|
|
|
$
|
691
|
|
|
$
|
739
|
|
Contingent rental expense
|
19
|
|
|
21
|
|
|
70
|
|
|||
Total rental expense
|
534
|
|
|
712
|
|
|
809
|
|
|||
Less sublease rental income
|
31
|
|
|
54
|
|
|
31
|
|
|||
Rental expense, net of
sublease rental income
|
$
|
503
|
|
|
$
|
658
|
|
|
$
|
778
|
|
11.
|
EQUITY
|
|
Common
Stock
|
|
Treasury
Stock
|
||
Balance as of December 31, 2015
|
673
|
|
|
(200
|
)
|
Transactions in connection with
stock-based compensation plans
|
—
|
|
|
1
|
|
Stock purchases under purchase program
|
—
|
|
|
(23
|
)
|
Balance as of December 31, 2016
|
673
|
|
|
(222
|
)
|
Transactions in connection with
stock-based compensation plans
|
—
|
|
|
1
|
|
Stock purchases under purchase programs
|
—
|
|
|
(19
|
)
|
Balance as of December 31, 2017
|
673
|
|
|
(240
|
)
|
Stock purchases under purchase programs
|
—
|
|
|
(16
|
)
|
Balance as of December 31, 2018
|
673
|
|
|
(256
|
)
|
|
Before-Tax
Amount
|
|
Tax Expense
(Benefit)
|
|
Net Amount
|
||||||
Year Ended December 31, 2018:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
(517
|
)
|
|
$
|
—
|
|
|
$
|
(517
|
)
|
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Gain arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial gain
|
1
|
|
|
—
|
|
|
1
|
|
|||
Prior service credit
|
7
|
|
|
1
|
|
|
6
|
|
|||
Amounts reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
63
|
|
|
14
|
|
|
49
|
|
|||
Prior service credit
|
(29
|
)
|
|
(7
|
)
|
|
(22
|
)
|
|||
Curtailment and settlement loss
|
7
|
|
|
2
|
|
|
5
|
|
|||
Net gain on pension and other
postretirement benefits
|
49
|
|
|
10
|
|
|
39
|
|
|||
Other comprehensive loss
|
$
|
(468
|
)
|
|
$
|
10
|
|
|
$
|
(478
|
)
|
|
Before-Tax
Amount
|
|
Tax Expense
(Benefit)
|
|
Net Amount
|
||||||
Year Ended December 31, 2017:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
514
|
|
|
$
|
—
|
|
|
$
|
514
|
|
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Loss arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
(79
|
)
|
|
(29
|
)
|
|
(50
|
)
|
|||
Prior service cost
|
(4
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
Miscellaneous loss
|
—
|
|
|
3
|
|
|
(3
|
)
|
|||
Amounts reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
50
|
|
|
18
|
|
|
32
|
|
|||
Prior service credit
|
(36
|
)
|
|
(13
|
)
|
|
(23
|
)
|
|||
Curtailment and settlement loss
|
4
|
|
|
1
|
|
|
3
|
|
|||
Net loss on pension and other
postretirement benefits
|
(65
|
)
|
|
(21
|
)
|
|
(44
|
)
|
|||
Other comprehensive income
|
$
|
449
|
|
|
$
|
(21
|
)
|
|
$
|
470
|
|
Year Ended December 31, 2016:
|
|
|
|
|
|
||||||
Foreign currency translation adjustment
|
$
|
(415
|
)
|
|
$
|
—
|
|
|
$
|
(415
|
)
|
Pension and other postretirement benefits:
|
|
|
|
|
|
||||||
Loss arising during the year related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
(110
|
)
|
|
(34
|
)
|
|
(76
|
)
|
|||
Miscellaneous gain
|
—
|
|
|
(8
|
)
|
|
8
|
|
|||
Amounts reclassified into income related to:
|
|
|
|
|
|
||||||
Net actuarial loss
|
48
|
|
|
18
|
|
|
30
|
|
|||
Prior service credit
|
(36
|
)
|
|
(13
|
)
|
|
(23
|
)
|
|||
Net loss on pension and other
postretirement benefits
|
(98
|
)
|
|
(37
|
)
|
|
(61
|
)
|
|||
Other comprehensive loss
|
$
|
(513
|
)
|
|
$
|
(37
|
)
|
|
$
|
(476
|
)
|
|
Foreign
Currency
Translation
Adjustment
|
|
Defined
Benefit
Plan
Items
|
|
Total
|
||||||
Balance as of December 31, 2015
|
$
|
(605
|
)
|
|
$
|
(328
|
)
|
|
$
|
(933
|
)
|
Other comprehensive loss
before reclassifications
|
(416
|
)
|
|
(68
|
)
|
|
(484
|
)
|
|||
Amounts reclassified from
accumulated other comprehensive
loss
|
—
|
|
|
7
|
|
|
7
|
|
|||
Other comprehensive loss
|
(416
|
)
|
|
(61
|
)
|
|
(477
|
)
|
|||
Balance as of December 31, 2016
|
(1,021
|
)
|
|
(389
|
)
|
|
(1,410
|
)
|
|||
Other comprehensive income (loss)
before reclassifications
|
514
|
|
|
(56
|
)
|
|
458
|
|
|||
Amounts reclassified from
accumulated other comprehensive
loss
|
—
|
|
|
12
|
|
|
12
|
|
|||
Other comprehensive income (loss)
|
514
|
|
|
(44
|
)
|
|
470
|
|
|||
Balance as of December 31, 2017
|
(507
|
)
|
|
(433
|
)
|
|
(940
|
)
|
|||
Other comprehensive income (loss)
before reclassifications
|
(515
|
)
|
|
7
|
|
|
(508
|
)
|
|||
Amounts reclassified from
accumulated other comprehensive
loss
|
—
|
|
|
32
|
|
|
32
|
|
|||
Other comprehensive income (loss)
|
(515
|
)
|
|
39
|
|
|
(476
|
)
|
|||
Reclassification of stranded income
tax effects of Tax Reform
to retained earnings per
ASU 2018-02 (see Note 1)
|
—
|
|
|
(91
|
)
|
|
(91
|
)
|
|||
Balance as of December 31, 2018
|
$
|
(1,022
|
)
|
|
$
|
(485
|
)
|
|
$
|
(1,507
|
)
|
Details about
Accumulated Other
Comprehensive Loss
Components
|
|
|
|
Affected Line
Item in the
Statement of
Income
|
||||||||||
|
Year Ended December 31,
|
|
||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
||||||||
Amortization of items related to
defined benefit pension plans:
|
|
|
|
|
|
|
|
|
||||||
Net actuarial loss
|
|
$
|
(63
|
)
|
|
$
|
(50
|
)
|
|
$
|
(48
|
)
|
|
(a) Other income, net
|
Prior service credit
|
|
29
|
|
|
36
|
|
|
36
|
|
|
(a) Other income, net
|
|||
Curtailment and settlement
|
|
(7
|
)
|
|
(4
|
)
|
|
—
|
|
|
(a) Other income, net
|
|||
|
|
(41
|
)
|
|
(18
|
)
|
|
(12
|
)
|
|
Total before tax
|
|||
|
|
9
|
|
|
6
|
|
|
5
|
|
|
Tax benefit
|
|||
Total reclassifications for the year
|
|
$
|
(32
|
)
|
|
$
|
(12
|
)
|
|
$
|
(7
|
)
|
|
Net of tax
|
(a)
|
These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost (credit), as discussed in
Note 13
.
|
12.
|
VARIABLE INTEREST ENTITIES
|
•
|
Prior to the completion of the Merger Transaction with VLP on January 10, 2019 as discussed in
Note 2
, VLP was a publicly traded master limited partnership whose common limited partner units were traded on the New York Stock Exchange under the trading symbol “VLP.” VLP was formed by us to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. VLP’s assets include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of
ten
of our refineries. As of
December 31, 2018
, we owned a
66.2
percent limited partner interest and a
2.0
percent general partner interest in VLP, and public unitholders owned a
31.8
percent limited partner interest.
|
•
|
Diamond Green Diesel Holdings LLC (DGD) is a joint venture with Darling Green Energy LLC, a subsidiary of Darling Ingredients Inc., that was formed to construct and operate a biodiesel plant that processes animal fats, used cooking oils, and other vegetable oils into renewable green diesel. The plant is located next to our St. Charles Refinery and began operations in June 2013. Our significant agreements with DGD include an operations agreement that outlines our responsibilities as operator of the plant, a debt agreement whereby we financed approximately
60
percent of the construction costs of the plant, and a marketing agreement.
|
•
|
We have terminaling agreements with three subsidiaries of Infraestructura Energetica Nova, S.A.B. de C.V. (IEnova), a Mexican company and subsidiary of Sempra Energy, a U.S. public company. The three subsidiaries are collectively referred to as Central Mexico Terminals and were previously referred to by us as VPM Terminals. The terminaling agreements represent variable interests because we have determined them to be capital leases due to our exclusive use of the terminals. Although we do not have an ownership interest in the entities that own each of the three terminals, the capital leases convey to us (i) the power to direct the activities that most significantly impact the economic performance of all three terminals and (ii) the ability to influence the benefits received or the losses incurred by the terminals because of our use of the terminals. As a result, we determined each of the entities was a VIE and that we are the primary beneficiary of each. Substantially all of Central Mexico Terminals’ revenues will be derived from us; therefore, there is limited risk to us associated with Central Mexico Terminals’ operations.
|
•
|
We also have financial interests in other entities that have been determined to be VIEs because the entities’ contractual arrangements transfer the power to us to direct the activities that most significantly impact their economic performance or reduce the exposure to operational variability and risk of loss created by the entity that otherwise would be held exclusively by the equity owners. Furthermore, we determined that we are the primary beneficiary of these VIEs because (i) certain contractual arrangements (exclusive of our ownership rights) provide us with the power to direct the activities that most significantly impact the economic performance of these entities and/or (ii) our
|
|
December 31, 2018
|
||||||||||||||||||
|
VLP
|
|
DGD
|
|
Central
Mexico
Terminals |
|
Other
|
|
Total
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
152
|
|
|
$
|
65
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
235
|
|
Other current assets
|
2
|
|
|
112
|
|
|
20
|
|
|
64
|
|
|
198
|
|
|||||
Property, plant, and equipment, net
|
1,409
|
|
|
576
|
|
|
156
|
|
|
113
|
|
|
2,254
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities, including current portion
of debt and capital lease obligations
|
$
|
27
|
|
|
$
|
28
|
|
|
$
|
118
|
|
|
$
|
9
|
|
|
$
|
182
|
|
Debt and capital lease obligations,
less current portion
|
990
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
1,024
|
|
|
December 31, 2017
|
||||||||||||||||||
|
VLP
|
|
DGD
|
|
Central
Mexico
Terminals |
|
Other
|
|
Total
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
42
|
|
|
$
|
123
|
|
|
$
|
1
|
|
|
$
|
13
|
|
|
$
|
179
|
|
Other current assets
|
2
|
|
|
66
|
|
|
4
|
|
|
—
|
|
|
72
|
|
|||||
Property, plant, and equipment, net
|
1,416
|
|
|
435
|
|
|
51
|
|
|
127
|
|
|
2,029
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities, including current portion
of debt and capital lease obligations
|
$
|
27
|
|
|
$
|
33
|
|
|
$
|
26
|
|
|
$
|
9
|
|
|
$
|
95
|
|
Debt and capital lease obligations,
less current portion
|
905
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
948
|
|
13.
|
EMPLOYEE BENEFIT PLANS
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Changes in benefit obligation:
|
|
|
|
|
|
|
|
||||||||
Benefit obligation as of beginning of year
|
$
|
2,926
|
|
|
$
|
2,567
|
|
|
$
|
306
|
|
|
$
|
302
|
|
Service cost
|
133
|
|
|
123
|
|
|
6
|
|
|
6
|
|
||||
Interest cost
|
91
|
|
|
86
|
|
|
10
|
|
|
10
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
10
|
|
|
9
|
|
||||
Benefits paid
|
(207
|
)
|
|
(158
|
)
|
|
(28
|
)
|
|
(28
|
)
|
||||
Actuarial (gain) loss
|
(285
|
)
|
|
286
|
|
|
(9
|
)
|
|
6
|
|
||||
Other
|
(19
|
)
|
|
22
|
|
|
(3
|
)
|
|
1
|
|
||||
Benefit obligation as of end of year
|
$
|
2,639
|
|
|
$
|
2,926
|
|
|
$
|
292
|
|
|
$
|
306
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets (a):
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets as of beginning of year
|
$
|
2,428
|
|
|
$
|
2,097
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
(130
|
)
|
|
363
|
|
|
—
|
|
|
—
|
|
||||
Valero contributions
|
156
|
|
|
110
|
|
|
18
|
|
|
19
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
10
|
|
|
9
|
|
||||
Benefits paid
|
(207
|
)
|
|
(158
|
)
|
|
(28
|
)
|
|
(28
|
)
|
||||
Other
|
(11
|
)
|
|
16
|
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets as of end of year
|
$
|
2,236
|
|
|
$
|
2,428
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Reconciliation of funded status
(a)
:
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets as of end of year
|
$
|
2,236
|
|
|
$
|
2,428
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Less benefit obligation as of end of year
|
2,639
|
|
|
2,926
|
|
|
292
|
|
|
306
|
|
||||
Funded status as of end of year
|
$
|
(403
|
)
|
|
$
|
(498
|
)
|
|
$
|
(292
|
)
|
|
$
|
(306
|
)
|
|
|
|
|
|
|
|
|
||||||||
Accumulated benefit obligation
|
$
|
2,492
|
|
|
$
|
2,746
|
|
|
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 19
for the assets associated with certain U.S. nonqualified pension plans.
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Deferred charges and other assets, net
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accrued expenses
|
(22
|
)
|
|
(14
|
)
|
|
(21
|
)
|
|
(19
|
)
|
||||
Other long-term liabilities
|
(383
|
)
|
|
(489
|
)
|
|
(271
|
)
|
|
(287
|
)
|
||||
|
$
|
(403
|
)
|
|
$
|
(498
|
)
|
|
$
|
(292
|
)
|
|
$
|
(306
|
)
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Projected benefit obligation
|
$
|
2,564
|
|
|
$
|
2,872
|
|
Fair value of plan assets
|
2,160
|
|
|
2,369
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Accumulated benefit obligation
|
$
|
2,253
|
|
|
$
|
2,526
|
|
Fair value of plan assets
|
1,974
|
|
|
2,180
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
2019
|
$
|
169
|
|
|
$
|
21
|
|
2020
|
193
|
|
|
21
|
|
||
2021
|
175
|
|
|
21
|
|
||
2022
|
180
|
|
|
20
|
|
||
2023
|
194
|
|
|
20
|
|
||
2024-2028
|
1,043
|
|
|
95
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
Service cost
|
$
|
133
|
|
|
$
|
123
|
|
|
$
|
111
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
7
|
|
Interest cost
|
91
|
|
|
86
|
|
|
84
|
|
|
10
|
|
|
10
|
|
|
12
|
|
||||||
Expected return on plan assets
|
(163
|
)
|
|
(150
|
)
|
|
(139
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial (gain) loss
|
65
|
|
|
53
|
|
|
49
|
|
|
(2
|
)
|
|
(3
|
)
|
|
(1
|
)
|
||||||
Prior service credit
|
(18
|
)
|
|
(20
|
)
|
|
(20
|
)
|
|
(11
|
)
|
|
(16
|
)
|
|
(16
|
)
|
||||||
Special charges (credits)
|
7
|
|
|
4
|
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost (credit)
|
$
|
115
|
|
|
$
|
96
|
|
|
$
|
78
|
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
|
$
|
2
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||||||||
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
Net gain (loss) arising during
the year:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
(8
|
)
|
|
$
|
(73
|
)
|
|
$
|
(145
|
)
|
|
$
|
9
|
|
|
$
|
(6
|
)
|
|
$
|
35
|
|
Prior service (cost) credit
|
7
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net (gain) loss reclassified into
income:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial (gain) loss
|
65
|
|
|
53
|
|
|
49
|
|
|
(2
|
)
|
|
(3
|
)
|
|
(1
|
)
|
||||||
Prior service credit
|
(18
|
)
|
|
(20
|
)
|
|
(20
|
)
|
|
(11
|
)
|
|
(16
|
)
|
|
(16
|
)
|
||||||
Curtailment and settlement loss
|
7
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total changes in other
comprehensive income (loss)
|
$
|
53
|
|
|
$
|
(40
|
)
|
|
$
|
(116
|
)
|
|
$
|
(4
|
)
|
|
$
|
(25
|
)
|
|
$
|
18
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net actuarial (gain) loss
|
$
|
828
|
|
|
$
|
894
|
|
|
$
|
(64
|
)
|
|
$
|
(57
|
)
|
Prior service credit
|
(108
|
)
|
|
(121
|
)
|
|
(31
|
)
|
|
(42
|
)
|
||||
Total
|
$
|
720
|
|
|
$
|
773
|
|
|
$
|
(95
|
)
|
|
$
|
(99
|
)
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||
|
December 31,
|
|
December 31,
|
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Discount rate
|
4.25
|
%
|
|
3.58
|
%
|
|
4.40
|
%
|
|
3.72
|
%
|
Rate of compensation increase
|
3.78
|
%
|
|
3.86
|
%
|
|
n/a
|
|
|
n/a
|
|
Interest crediting rate for
cash balance plans
|
3.04
|
%
|
|
3.04
|
%
|
|
n/a
|
|
|
n/a
|
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||||
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||
Discount rate
|
3.59
|
%
|
|
4.08
|
%
|
|
4.45
|
%
|
|
3.72
|
%
|
|
4.26
|
%
|
|
4.53
|
%
|
Expected long-term rate of return
on plan assets
|
7.24
|
%
|
|
7.29
|
%
|
|
7.28
|
%
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
Rate of compensation increase
|
3.86
|
%
|
|
3.81
|
%
|
|
3.79
|
%
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
Interest crediting rate for
cash balance plans
|
3.04
|
%
|
|
3.04
|
%
|
|
3.10
|
%
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
|
December 31,
|
||||
|
2018
|
|
2017
|
||
Health care cost trend rate assumed for the next year
|
7.29
|
%
|
|
7.30
|
%
|
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
|
2026
|
|
|
2026
|
|
|
Fair Value Hierarchy
|
|
Total as of
December 31, 2018 |
||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
U.S. companies (a)
|
$
|
497
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
497
|
|
International companies
|
159
|
|
|
1
|
|
|
—
|
|
|
160
|
|
||||
Preferred stock
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
97
|
|
|
—
|
|
|
—
|
|
|
97
|
|
||||
Index funds (b)
|
76
|
|
|
—
|
|
|
—
|
|
|
76
|
|
||||
Corporate debt instruments
|
—
|
|
|
284
|
|
|
—
|
|
|
284
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
||||
Other government securities
|
—
|
|
|
138
|
|
|
—
|
|
|
138
|
|
||||
Common collective trusts (c)
|
—
|
|
|
609
|
|
|
—
|
|
|
609
|
|
||||
Pooled separate accounts (d)
|
—
|
|
|
190
|
|
|
—
|
|
|
190
|
|
||||
Private funds
|
—
|
|
|
87
|
|
|
—
|
|
|
87
|
|
||||
Insurance contract
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
||||
Interest and dividends receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
40
|
|
|
—
|
|
|
—
|
|
|
40
|
|
||||
Securities transactions payable, net
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
||||
Total pension plan assets
|
$
|
909
|
|
|
$
|
1,327
|
|
|
$
|
—
|
|
|
$
|
2,236
|
|
|
Fair Value Hierarchy
|
|
Total as of
December 31, 2017 |
||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|||||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
U.S. companies (a)
|
$
|
571
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
571
|
|
International companies
|
187
|
|
|
1
|
|
|
—
|
|
|
188
|
|
||||
Preferred stock
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
||||||||
International growth
|
118
|
|
|
—
|
|
|
—
|
|
|
118
|
|
||||
Index funds (b)
|
85
|
|
|
—
|
|
|
—
|
|
|
85
|
|
||||
Corporate debt instruments
|
—
|
|
|
272
|
|
|
—
|
|
|
272
|
|
||||
Government securities:
|
|
|
|
|
|
|
|
||||||||
U.S. Treasury securities
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
||||
Other government securities
|
—
|
|
|
144
|
|
|
—
|
|
|
144
|
|
||||
Common collective trusts (c)
|
—
|
|
|
621
|
|
|
—
|
|
|
621
|
|
||||
Pooled separate accounts (d)
|
—
|
|
|
192
|
|
|
—
|
|
|
192
|
|
||||
Private funds
|
—
|
|
|
101
|
|
|
—
|
|
|
101
|
|
||||
Insurance contract
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
||||
Interest and dividends receivable
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Cash and cash equivalents
|
85
|
|
|
1
|
|
|
—
|
|
|
86
|
|
||||
Securities transactions payable, net
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
||||
Total pension plan assets
|
$
|
1,078
|
|
|
$
|
1,350
|
|
|
$
|
—
|
|
|
$
|
2,428
|
|
(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 as of
December 31, 2018
. As of
December 31, 2017
, this class included primarily investments in approximately
70
percent equities and
30
percent bonds.
|
(c)
|
This class includes primarily investments in approximately
70
percent equities and
30
percent bonds as of
December 31, 2018
. As of
December 31, 2017
, this class included primarily investments in approximately
80
percent equities and
20
percent bonds.
|
(d)
|
This class includes primarily investments in approximately
50
percent equities and
50
percent bonds as of
December 31, 2018
and
2017
.
|
14.
|
STOCK-BASED COMPENSATION
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Stock-based compensation expense:
|
|
|
|
|
|
||||||
Restricted stock
|
$
|
63
|
|
|
$
|
58
|
|
|
$
|
52
|
|
Performance awards
|
22
|
|
|
19
|
|
|
15
|
|
|||
Stock options and other awards
|
1
|
|
|
—
|
|
|
1
|
|
|||
Total stock-based compensation expense
|
$
|
86
|
|
|
$
|
77
|
|
|
$
|
68
|
|
Tax benefit recognized on stock-based compensation expense
|
$
|
18
|
|
|
$
|
27
|
|
|
$
|
24
|
|
Tax benefit realized for tax deductions resulting from
exercises and vestings
|
32
|
|
|
44
|
|
|
33
|
|
|||
Effect of tax deductions in excess of recognized
stock-based compensation expense
|
20
|
|
|
24
|
|
|
22
|
|
|
Number of
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
Per Share
|
|||
Nonvested shares as of January 1, 2018
|
1,401,040
|
|
|
$
|
69.82
|
|
Granted
|
628,908
|
|
|
92.12
|
|
|
Vested
|
(843,709
|
)
|
|
71.26
|
|
|
Forfeited
|
(9,661
|
)
|
|
69.97
|
|
|
Nonvested shares as of December 31, 2018
|
1,176,578
|
|
|
80.70
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Weighted-average grant-date fair value per share of
restricted stock granted
|
$
|
92.12
|
|
|
$
|
79.32
|
|
|
$
|
59.00
|
|
Fair value of restricted stock vested (in millions)
|
80
|
|
|
71
|
|
|
46
|
|
15.
|
INCOME TAXES
|
•
|
reduction in the statutory income tax rate from
35
percent to
21
percent;
|
•
|
repeal of the manufacturing deduction;
|
•
|
deduction for all of the costs to acquire or construct certain business assets in the year they are placed in service through 2022;
|
•
|
shift from a worldwide system of taxation to a territorial system of taxation, resulting in a minimum tax on the income of international subsidiaries (the GILTI tax) rather than a tax deferral on such earnings in certain circumstances; and
|
•
|
assessment of a one-time transition tax on deemed repatriated earnings and profits from our international subsidiaries.
|
•
|
We remeasured our U.S. deferred tax assets and liabilities using the
21
percent rate, which resulted in a tax benefit and a reduction to our net deferred tax liabilities of
$2.6 billion
.
|
•
|
We recognized a one-time transition tax of
$734 million
on the deemed repatriation of previously undistributed accumulated earnings and profits of our international subsidiaries based on approximately
$4.7 billion
of the combined earnings and profits of our international subsidiaries that had not been distributed to us. This transition tax will be remitted to the Internal Revenue Service (IRS) over the eight-year period provided in the Code, with the first annual remittance being paid in 2018.
|
•
|
We accrued withholding tax of
$47 million
on a portion of the cash held by one of our international subsidiaries that we have deemed to not be permanently reinvested in our operations in that country.
|
|
Year Ended December
31,
|
|
Cumulative
Tax Reform
Adjustment
|
||||||||||||
|
2017
|
|
2018
|
|
|||||||||||
|
Accounting
Status
|
|
Amount
|
|
Accounting
Status
|
|
Amount
|
|
|||||||
Income tax benefit from the remeasurement of
U.S. deferred income tax assets and liabilities
|
Complete
|
|
$
|
(2,643
|
)
|
|
Complete
|
|
$
|
—
|
|
|
$
|
(2,643
|
)
|
Tax on the deemed repatriation of the
accumulated earnings and profits of our
international subsidiaries
|
Provisional
|
|
734
|
|
|
Complete
|
|
6
|
|
|
740
|
|
|||
Recognition of foreign withholding tax, net of
U.S. federal tax benefit
|
Complete
|
|
47
|
|
|
Complete
|
|
—
|
|
|
47
|
|
|||
Deductibility of certain executive compensation
expense
|
Incomplete
|
|
—
|
|
|
Complete
|
|
5
|
|
|
5
|
|
|||
Income tax expense associated with the statutory
income tax rate differential on accrual to
return adjustments that were identified upon
completion of our U.S. federal income
tax return in 2018
|
Incomplete
|
|
—
|
|
|
Complete
|
|
9
|
|
|
9
|
|
|||
Foreign tax credit available to offset the tax on
deemed repatriation of the accumulated
earnings and profits of our international
subsidiaries
|
Incomplete
|
|
—
|
|
|
Complete
|
|
(32
|
)
|
|
(32
|
)
|
|||
Tax Reform benefit
|
|
|
$
|
(1,862
|
)
|
|
|
|
$
|
(12
|
)
|
|
$
|
(1,874
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
U.S. operations
|
$
|
3,168
|
|
|
$
|
2,283
|
|
|
$
|
1,733
|
|
International operations
|
1,064
|
|
|
924
|
|
|
1,449
|
|
|||
Income before income tax expense (benefit)
|
$
|
4,232
|
|
|
$
|
3,207
|
|
|
$
|
3,182
|
|
|
Year Ended December 31, 2018
|
|||||||||||||||||||
|
U.S.
|
|
International
|
|
Total
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Income tax expense at statutory rates
|
$
|
665
|
|
|
21.0
|
%
|
|
$
|
163
|
|
|
15.3
|
%
|
|
$
|
828
|
|
|
19.6
|
%
|
U.S. state and Canadian provincial
tax expense, net of federal
income tax effect
|
44
|
|
|
1.4
|
%
|
|
80
|
|
|
7.5
|
%
|
|
124
|
|
|
2.9
|
%
|
|||
Permanent differences
|
(9
|
)
|
|
(0.3
|
)%
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(0.2
|
)%
|
|||
GILTI tax
|
67
|
|
|
2.1
|
%
|
|
—
|
|
|
—
|
|
|
67
|
|
|
1.6
|
%
|
|||
Foreign tax credits
|
(50
|
)
|
|
(1.6
|
)%
|
|
—
|
|
|
—
|
|
|
(50
|
)
|
|
(1.2
|
)%
|
|||
Effects of Tax Reform
|
(12
|
)
|
|
(0.4
|
)%
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(0.3
|
)%
|
|||
Tax effects of income associated
with noncontrolling interests
|
(49
|
)
|
|
(1.5
|
)%
|
|
—
|
|
|
—
|
|
|
(49
|
)
|
|
(1.2
|
)%
|
|||
Other, net
|
(23
|
)
|
|
(0.7
|
)%
|
|
3
|
|
|
0.3
|
%
|
|
(20
|
)
|
|
(0.5
|
)%
|
|||
Income tax expense
|
$
|
633
|
|
|
20.0
|
%
|
|
$
|
246
|
|
|
23.1
|
%
|
|
$
|
879
|
|
|
20.7
|
%
|
|
Year Ended December 31, 2017
|
|||||||||||||||||||
|
U.S.
|
|
International
|
|
Total
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Income tax expense at statutory rates
|
$
|
799
|
|
|
35.0
|
%
|
|
$
|
158
|
|
|
17.1
|
%
|
|
$
|
957
|
|
|
29.8
|
%
|
U.S. state and Canadian provincial
tax expense, net of federal
income tax effect
|
37
|
|
|
1.6
|
%
|
|
46
|
|
|
5.0
|
%
|
|
83
|
|
|
2.6
|
%
|
|||
Permanent differences:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Manufacturing deduction
|
(42
|
)
|
|
(1.8
|
)%
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
(1.3
|
)%
|
|||
Other
|
(9
|
)
|
|
(0.4
|
)%
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(0.3
|
)%
|
|||
Change in tax law
|
(1,862
|
)
|
|
(81.6
|
)%
|
|
—
|
|
|
—
|
|
|
(1,862
|
)
|
|
(58.1
|
)%
|
|||
Tax effects of income associated
with noncontrolling interests
|
(31
|
)
|
|
(1.4
|
)%
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|
(1.0
|
)%
|
|||
Other, net
|
(52
|
)
|
|
(2.3
|
)%
|
|
7
|
|
|
0.8
|
%
|
|
(45
|
)
|
|
(1.4
|
)%
|
|||
Income tax expense (benefit)
|
$
|
(1,160
|
)
|
|
(50.9
|
)%
|
|
$
|
211
|
|
|
22.9
|
%
|
|
$
|
(949
|
)
|
|
(29.7
|
)%
|
|
Year Ended December 31, 2016
|
|||||||||||||||||||
|
U.S.
|
|
International
|
|
Total
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Income tax expense at statutory rates
|
$
|
606
|
|
|
35.0
|
%
|
|
$
|
256
|
|
|
17.7
|
%
|
|
$
|
862
|
|
|
27.1
|
%
|
U.S. state and Canadian provincial
tax expense, net of federal
income tax effect
|
5
|
|
|
0.3
|
%
|
|
31
|
|
|
2.1
|
%
|
|
36
|
|
|
1.1
|
%
|
|||
Permanent differences:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Manufacturing deduction
|
(22
|
)
|
|
(1.3
|
)%
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(0.7
|
)%
|
|||
Other
|
(3
|
)
|
|
(0.2
|
)%
|
|
(10
|
)
|
|
(0.7
|
)%
|
|
(13
|
)
|
|
(0.4
|
)%
|
|||
Change in tax law
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(0.5
|
)%
|
|
(7
|
)
|
|
(0.2
|
)%
|
|||
Tax effects of income associated
with noncontrolling interests
|
(44
|
)
|
|
(2.5
|
)%
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|
(1.4
|
)%
|
|||
Other, net
|
(37
|
)
|
|
(2.1
|
)%
|
|
(10
|
)
|
|
(0.7
|
)%
|
|
(47
|
)
|
|
(1.5
|
)%
|
|||
Income tax expense
|
$
|
505
|
|
|
29.2
|
%
|
|
$
|
260
|
|
|
17.9
|
%
|
|
$
|
765
|
|
|
24.0
|
%
|
|
Year Ended December 31, 2018
|
||||||||||
|
U.S.
|
|
International
|
|
Total
|
||||||
Current:
|
|
|
|
|
|
||||||
Country
|
$
|
432
|
|
|
$
|
141
|
|
|
$
|
573
|
|
U.S. state / Canadian provincial
|
37
|
|
|
66
|
|
|
103
|
|
|||
Total current
|
469
|
|
(a)
|
207
|
|
|
676
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Country
|
145
|
|
|
25
|
|
|
170
|
|
|||
U.S. state / Canadian provincial
|
19
|
|
|
14
|
|
|
33
|
|
|||
Total deferred
|
164
|
|
(b)
|
39
|
|
|
203
|
|
|||
Income tax expense
|
$
|
633
|
|
|
$
|
246
|
|
|
$
|
879
|
|
|
Year Ended December 31, 2017
|
||||||||||
|
U.S.
|
|
International
|
|
Total
|
||||||
Current:
|
|
|
|
|
|
||||||
Country
|
$
|
1,305
|
|
|
$
|
194
|
|
|
$
|
1,499
|
|
U.S. state / Canadian provincial
|
34
|
|
|
61
|
|
|
95
|
|
|||
Total current
|
1,339
|
|
(a)
|
255
|
|
|
1,594
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Country
|
(2,522
|
)
|
|
(29
|
)
|
|
(2,551
|
)
|
|||
U.S. state / Canadian provincial
|
23
|
|
|
(15
|
)
|
|
8
|
|
|||
Total deferred
|
(2,499
|
)
|
(b)
|
(44
|
)
|
|
(2,543
|
)
|
|||
Income tax expense (benefit)
|
$
|
(1,160
|
)
|
|
$
|
211
|
|
|
$
|
(949
|
)
|
(a)
|
Current income tax expense includes a
$21 million
benefit and a
$781 million
expense related to our Tax Reform adjustment for the years ended
December 31, 2018
and
2017
, respectively, as described in
“Tax Reform”
above.
|
(b)
|
Deferred income tax expense (benefit) includes a
$9 million
expense and a
$2.6 billion
benefit related to our Tax Reform adjustment for the years ended
December 31, 2018
and
2017
, respectively, as described in
“Tax Reform”
above.
|
|
Year Ended December 31, 2016
|
||||||||||
|
U.S.
|
|
International
|
|
Total
|
||||||
Current:
|
|
|
|
|
|
||||||
Country
|
$
|
294
|
|
|
$
|
194
|
|
|
$
|
488
|
|
U.S. state / Canadian provincial
|
12
|
|
|
35
|
|
|
47
|
|
|||
Total current
|
306
|
|
|
229
|
|
|
535
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Country
|
203
|
|
|
35
|
|
|
238
|
|
|||
U.S. state / Canadian provincial
|
(4
|
)
|
|
(4
|
)
|
|
(8
|
)
|
|||
Total deferred
|
199
|
|
|
31
|
|
|
230
|
|
|||
Income tax expense
|
$
|
505
|
|
|
$
|
260
|
|
|
$
|
765
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
U.S.
|
$
|
1,016
|
|
|
$
|
239
|
|
|
$
|
241
|
|
International
|
345
|
|
|
171
|
|
|
203
|
|
|||
Income taxes paid, net
|
$
|
1,361
|
|
|
$
|
410
|
|
|
$
|
444
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred income tax assets:
|
|
|
|
||||
Tax credit carryforwards
|
$
|
644
|
|
|
$
|
69
|
|
Net operating losses (NOLs)
|
523
|
|
|
492
|
|
||
Inventories
|
101
|
|
|
135
|
|
||
Compensation and employee benefit liabilities
|
175
|
|
|
179
|
|
||
Environmental liabilities
|
71
|
|
|
47
|
|
||
Other
|
141
|
|
|
112
|
|
||
Total deferred income tax assets
|
1,655
|
|
|
1,034
|
|
||
Valuation allowance
|
(1,111
|
)
|
|
(498
|
)
|
||
Net deferred income tax assets
|
544
|
|
|
536
|
|
||
|
|
|
|
||||
Deferred income tax liabilities:
|
|
|
|
||||
Property, plant, and equipment
|
4,589
|
|
|
4,545
|
|
||
Deferred turnaround costs
|
316
|
|
|
272
|
|
||
Inventories
|
287
|
|
|
243
|
|
||
Investments
|
142
|
|
|
77
|
|
||
Other
|
172
|
|
|
107
|
|
||
Total deferred income tax liabilities
|
5,506
|
|
|
5,244
|
|
||
Net deferred income tax liabilities
|
$
|
4,962
|
|
|
$
|
4,708
|
|
|
Amount
|
|
Expiration
|
||
U.S. state income tax credits
|
$
|
80
|
|
|
2019 through 2031
|
U.S. state income tax credits
|
6
|
|
|
Unlimited
|
|
U.S. foreign tax credits
|
575
|
|
|
2027
|
|
U.S. state NOLs (gross amount)
|
10,039
|
|
|
2019 through 2038
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Balance as of beginning of year
|
$
|
941
|
|
|
$
|
936
|
|
|
$
|
964
|
|
Additions based on tax positions related to the current year
|
23
|
|
|
33
|
|
|
36
|
|
|||
Additions for tax positions related to prior years
|
28
|
|
|
15
|
|
|
11
|
|
|||
Reductions for tax positions related to prior years
|
(19
|
)
|
|
(42
|
)
|
|
(46
|
)
|
|||
Reductions for tax positions related to the lapse of
applicable statute of limitations
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
Settlements
|
(2
|
)
|
|
—
|
|
|
(237
|
)
|
|||
Reclassification of uncertain tax receivable to long-term
receivable from IRS
|
—
|
|
|
—
|
|
|
211
|
|
|||
Balance as of end of year
|
$
|
970
|
|
|
$
|
941
|
|
|
$
|
936
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Unrecognized tax benefits
|
$
|
970
|
|
|
$
|
941
|
|
Tax refund claim not presented in our balance sheets
|
(277
|
)
|
|
(274
|
)
|
||
Other
|
88
|
|
|
77
|
|
||
Uncertain tax position liabilities presented in our balance sheets
|
$
|
781
|
|
|
$
|
744
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Income taxes payable
|
$
|
42
|
|
|
$
|
—
|
|
Other long-term liabilities
|
721
|
|
|
723
|
|
||
Deferred tax liabilities
|
18
|
|
|
21
|
|
||
Uncertain tax position liabilities presented in our balance sheets
|
$
|
781
|
|
|
$
|
744
|
|
16.
|
EARNINGS PER COMMON SHARE
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Earnings per common share:
|
|
|
|
|
|
||||||
Net income attributable to Valero stockholders
|
$
|
3,122
|
|
|
$
|
4,065
|
|
|
$
|
2,289
|
|
Less income allocated to participating securities
|
9
|
|
|
14
|
|
|
7
|
|
|||
Net income available to common shareholders
|
$
|
3,113
|
|
|
$
|
4,051
|
|
|
$
|
2,282
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding
|
426
|
|
|
442
|
|
|
461
|
|
|||
|
|
|
|
|
|
||||||
Earnings per common share
|
$
|
7.30
|
|
|
$
|
9.17
|
|
|
$
|
4.94
|
|
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution:
|
|
|
|
|
|
||||||
Net income attributable to Valero stockholders
|
$
|
3,122
|
|
|
$
|
4,065
|
|
|
$
|
2,289
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding
|
426
|
|
|
442
|
|
|
461
|
|
|||
Effect of dilutive securities
|
2
|
|
|
2
|
|
|
3
|
|
|||
Weighted-average common shares outstanding –
assuming dilution
|
428
|
|
|
444
|
|
|
464
|
|
|||
|
|
|
|
|
|
||||||
Earnings per common share – assuming dilution
|
$
|
7.29
|
|
|
$
|
9.16
|
|
|
$
|
4.94
|
|
17.
|
REVENUES AND SEGMENT INFORMATION
|
•
|
The
refining segment
includes the operations of our
15
petroleum refineries, the associated marketing activities, and certain logistics assets that support our refining operations that are not owned by VLP. The principal products manufactured by our refineries and sold by this segment include gasolines and blendstocks (e.g., conventional gasolines, premium gasolines, and gasoline meeting the specifications of the California Air Resources Board (CARB)), distillates (e.g., diesel, low-sulfur diesel, ultra-low-sulfur diesel, CARB diesel, jet fuel, and other distillates), and other products (e.g., asphalt, petrochemicals, lubricants, and other refined petroleum products).
|
•
|
The
ethanol segment
includes the operations of our
14
ethanol plants, the associated marketing activities, and logistics assets that support our ethanol operations. The principal products manufactured by our ethanol plants are ethanol and distillers grains. We sell some ethanol to our refining segment for blending into gasoline, which is sold to that segment’s customers as a finished gasoline product.
|
•
|
The
VLP segment
includes the results of VLP. VLP generates revenue from transportation and terminaling activities provided to our refining segment. All of VLP’s revenues are intersegment revenues that are generated under commercial agreements with our refining segment. Revenues generated under these agreements are eliminated in consolidation.
|
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Year ended December 31, 2018:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
113,601
|
|
|
$
|
3,428
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
117,033
|
|
Intersegment revenues
|
14
|
|
|
210
|
|
|
546
|
|
|
(770
|
)
|
|
—
|
|
|||||
Total revenues
|
113,615
|
|
|
3,638
|
|
|
546
|
|
|
(766
|
)
|
|
117,033
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
102,489
|
|
|
3,008
|
|
|
—
|
|
|
(765
|
)
|
|
104,732
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
4,099
|
|
|
470
|
|
|
125
|
|
|
(4
|
)
|
|
4,690
|
|
|||||
Depreciation and amortization expense
|
1,863
|
|
|
78
|
|
|
76
|
|
|
—
|
|
|
2,017
|
|
|||||
Total cost of sales
|
108,451
|
|
|
3,556
|
|
|
201
|
|
|
(769
|
)
|
|
111,439
|
|
|||||
Other operating expenses
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
925
|
|
|
925
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||
Operating income by segment
|
$
|
5,119
|
|
|
$
|
82
|
|
|
$
|
345
|
|
|
$
|
(974
|
)
|
|
$
|
4,572
|
|
Total expenditures for long-lived assets (a)
|
$
|
2,935
|
|
|
$
|
373
|
|
|
$
|
24
|
|
|
$
|
44
|
|
|
$
|
3,376
|
|
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Year ended December 31, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
90,651
|
|
|
$
|
3,324
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
93,980
|
|
Intersegment revenues
|
6
|
|
|
176
|
|
|
452
|
|
|
(634
|
)
|
|
—
|
|
|||||
Total revenues
|
90,657
|
|
|
3,500
|
|
|
452
|
|
|
(629
|
)
|
|
93,980
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
80,865
|
|
|
2,804
|
|
|
—
|
|
|
(632
|
)
|
|
83,037
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
3,959
|
|
|
443
|
|
|
104
|
|
|
(2
|
)
|
|
4,504
|
|
|||||
Depreciation and amortization expense
|
1,800
|
|
|
81
|
|
|
53
|
|
|
—
|
|
|
1,934
|
|
|||||
Total cost of sales
|
86,624
|
|
|
3,328
|
|
|
157
|
|
|
(634
|
)
|
|
89,475
|
|
|||||
Other operating expenses
|
58
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
61
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
829
|
|
|
829
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||
Operating income by segment
|
$
|
3,975
|
|
|
$
|
172
|
|
|
$
|
292
|
|
|
$
|
(876
|
)
|
|
$
|
3,563
|
|
Total expenditures for long-lived assets (a)
|
$
|
1,710
|
|
|
$
|
84
|
|
|
$
|
110
|
|
|
$
|
44
|
|
|
$
|
1,948
|
|
Year Ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
71,968
|
|
|
$
|
3,691
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
75,659
|
|
Intersegment revenues
|
—
|
|
|
210
|
|
|
363
|
|
|
(573
|
)
|
|
—
|
|
|||||
Total revenues
|
71,968
|
|
|
3,901
|
|
|
363
|
|
|
(573
|
)
|
|
75,659
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
63,405
|
|
|
3,130
|
|
|
—
|
|
|
(573
|
)
|
|
65,962
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
3,740
|
|
|
415
|
|
|
96
|
|
|
—
|
|
|
4,251
|
|
|||||
Depreciation and amortization expense
|
1,734
|
|
|
66
|
|
|
46
|
|
|
—
|
|
|
1,846
|
|
|||||
Lower of cost or market inventory
valuation adjustment
|
(697
|
)
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
(747
|
)
|
|||||
Total cost of sales
|
68,182
|
|
|
3,561
|
|
|
142
|
|
|
(573
|
)
|
|
71,312
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
709
|
|
|
709
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
|||||
Asset impairment loss
|
56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|||||
Operating income by segment
|
$
|
3,730
|
|
|
$
|
340
|
|
|
$
|
221
|
|
|
$
|
(757
|
)
|
|
$
|
3,534
|
|
Total expenditures for long-lived assets (a)
|
$
|
1,867
|
|
|
$
|
68
|
|
|
$
|
23
|
|
|
$
|
38
|
|
|
$
|
1,996
|
|
(a)
|
Total expenditures for long-lived assets includes amounts related to capital expenditures, deferred turnaround and catalyst costs, and property, plant, and equipment for acquisitions.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Refining:
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
$
|
46,606
|
|
|
$
|
40,366
|
|
|
$
|
33,450
|
|
Distillates
|
55,546
|
|
|
42,074
|
|
|
32,576
|
|
|||
Other product revenues
|
11,463
|
|
|
8,217
|
|
|
5,942
|
|
|||
Total refining revenues
|
113,615
|
|
|
90,657
|
|
|
71,968
|
|
|||
Ethanol:
|
|
|
|
|
|
||||||
Ethanol
|
2,912
|
|
|
2,940
|
|
|
3,315
|
|
|||
Distillers grains
|
726
|
|
|
560
|
|
|
586
|
|
|||
Total ethanol revenues
|
3,638
|
|
|
3,500
|
|
|
3,901
|
|
|||
VLP:
|
|
|
|
|
|
||||||
Pipeline transportation
|
124
|
|
|
101
|
|
|
78
|
|
|||
Terminaling
|
415
|
|
|
348
|
|
|
284
|
|
|||
Storage and other
|
7
|
|
|
3
|
|
|
1
|
|
|||
Total VLP revenues
|
546
|
|
|
452
|
|
|
363
|
|
|||
Corporate – other revenues
|
4
|
|
|
5
|
|
|
—
|
|
|||
Elimination of intersegment revenues
|
(770
|
)
|
|
(634
|
)
|
|
(573
|
)
|
|||
Revenues
|
$
|
117,033
|
|
|
$
|
93,980
|
|
|
$
|
75,659
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
U.S.
|
$
|
27,475
|
|
|
$
|
26,083
|
|
Canada
|
1,798
|
|
|
1,915
|
|
||
U.K. and Ireland
|
1,113
|
|
|
1,063
|
|
||
Other countries
|
266
|
|
|
—
|
|
||
Total long-lived assets
|
$
|
30,652
|
|
|
$
|
29,061
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Refining
|
$
|
42,673
|
|
|
$
|
40,382
|
|
Ethanol
|
1,691
|
|
|
1,344
|
|
||
VLP
|
1,620
|
|
|
1,517
|
|
||
Corporate and eliminations
|
4,171
|
|
|
6,915
|
|
||
Total assets
|
$
|
50,155
|
|
|
$
|
50,158
|
|
18.
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Decrease (increase) in current assets:
|
|
|
|
|
|
||||||
Receivables, net
|
$
|
(457
|
)
|
|
$
|
(870
|
)
|
|
$
|
(1,531
|
)
|
Inventories
|
(197
|
)
|
|
(516
|
)
|
|
771
|
|
|||
Prepaid expenses and other
|
(77
|
)
|
|
151
|
|
|
47
|
|
|||
Increase (decrease) in current liabilities:
|
|
|
|
|
|
||||||
Accounts payable
|
304
|
|
|
1,842
|
|
|
1,556
|
|
|||
Accrued expenses
|
(113
|
)
|
|
21
|
|
|
117
|
|
|||
Taxes other than income taxes payable
|
(73
|
)
|
|
172
|
|
|
82
|
|
|||
Income taxes payable
|
(684
|
)
|
|
489
|
|
|
(66
|
)
|
|||
Changes in current assets and current liabilities
|
$
|
(1,297
|
)
|
|
$
|
1,289
|
|
|
$
|
976
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Interest paid in excess of amount capitalized
|
$
|
463
|
|
|
$
|
457
|
|
|
$
|
427
|
|
Income taxes paid, net
|
1,361
|
|
|
410
|
|
|
444
|
|
19.
|
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, 2017
|
||||||||||||||||||||||||||||||
|
|
|
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
|
$
|
875
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
894
|
|
|
$
|
(893
|
)
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
Investments of certain
benefit plans
|
65
|
|
|
—
|
|
|
8
|
|
|
73
|
|
|
n/a
|
|
|
n/a
|
|
|
73
|
|
|
n/a
|
|
||||||||
Total
|
$
|
940
|
|
|
$
|
19
|
|
|
$
|
8
|
|
|
$
|
967
|
|
|
$
|
(893
|
)
|
|
$
|
—
|
|
|
$
|
74
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity derivative
contracts
|
$
|
955
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
969
|
|
|
$
|
(893
|
)
|
|
$
|
(76
|
)
|
|
$
|
—
|
|
|
$
|
(102
|
)
|
Environmental credit
obligations
|
—
|
|
|
104
|
|
|
—
|
|
|
104
|
|
|
n/a
|
|
|
n/a
|
|
|
104
|
|
|
n/a
|
|
||||||||
Physical purchase
contracts
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|
n/a
|
|
|
n/a
|
|
|
6
|
|
|
n/a
|
|
||||||||
Foreign currency
contracts
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
n/a
|
|
|
n/a
|
|
|
7
|
|
|
n/a
|
|
||||||||
Total
|
$
|
962
|
|
|
$
|
124
|
|
|
$
|
—
|
|
|
$
|
1,086
|
|
|
$
|
(893
|
)
|
|
$
|
(76
|
)
|
|
$
|
117
|
|
|
|
•
|
Commodity derivative contracts consist primarily of exchange-traded futures, which are used to reduce the impact of price volatility on our results of operations and cash flows as discussed in
Note 20
. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the commodity exchange and are categorized in Level 1 of the fair value hierarchy.
|
•
|
Physical purchase contracts represent the fair value of fixed-price corn purchase contracts. The fair values of these 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 plan 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 plan 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 for 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.
|
•
|
Environmental credit obligations represent our liability for the purchase of (i) biofuel credits (primarily RINs in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce and (ii) emission credits under the
California Global Warming Solutions Act
(the California cap-and-trade system, also known as AB 32) and similar programs, (collectively, the cap-and-trade systems). To the degree we are unable to blend biofuels (such as ethanol and biodiesel) at percentages required under the biofuel programs, we must purchase biofuel credits to comply with these programs. Under the cap-and-trade systems, we must purchase emission credits to comply with these systems. These programs are described in
Note 20
under “Environmental Compliance Program Price Risk.” The liability for environmental credits is based on our deficit for such credits as of the balance sheet date, if any, after considering any credits acquired or under contract, and is equal to the product of the credits deficit and the market price of these credits as of the balance sheet date. The environmental credit obligations are categorized in Level 2 of the fair value hierarchy and are measured at fair value using the market approach based on quoted prices from an independent pricing service.
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
Hierarchy
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Financial assets:
|
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
Level 1
|
|
$
|
2,982
|
|
|
$
|
2,982
|
|
|
$
|
5,850
|
|
|
$
|
5,850
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Debt (excluding capital leases)
|
Level 2
|
|
8,503
|
|
|
8,986
|
|
|
8,310
|
|
|
9,795
|
|
20.
|
PRICE RISK MANAGEMENT ACTIVITIES
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2019
|
|
2020
|
||
Crude oil and refined petroleum products:
|
|
|
|
|
||
Futures – long
|
|
149,470
|
|
|
224
|
|
Futures – short
|
|
143,826
|
|
|
671
|
|
Options – long
|
|
26,500
|
|
|
—
|
|
Options – short
|
|
26,500
|
|
|
—
|
|
Natural gas:
|
|
|
|
|
||
Futures – long
|
|
5,000,000
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
26,025
|
|
|
—
|
|
Futures – short
|
|
55,395
|
|
|
875
|
|
Physical contracts – long
|
|
27,109
|
|
|
875
|
|
Soybean oil:
|
|
|
|
|
||
Futures – long
|
|
137,518
|
|
|
—
|
|
Futures – short
|
|
285,957
|
|
|
—
|
|
|
Balance Sheet
Location
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
|
Asset
Derivatives |
|
Liability
Derivatives |
|
Asset
Derivatives |
|
Liability
Derivatives |
|||||||||
Derivatives not designated
as hedging instruments
|
|
|
|
|
|
|
|
|
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
||||||||
Futures
|
Receivables, net
|
|
$
|
2,787
|
|
|
$
|
2,681
|
|
|
$
|
886
|
|
|
$
|
966
|
|
Options
|
Receivables, net
|
|
5
|
|
|
—
|
|
|
8
|
|
|
3
|
|
||||
Physical purchase contracts
|
Inventories
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
||||
Foreign currency contracts
|
Receivables, net
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Foreign currency contracts
|
Accrued expenses
|
|
—
|
|
|
1
|
|
|
—
|
|
|
7
|
|
||||
Total
|
|
|
$
|
2,796
|
|
|
$
|
2,687
|
|
|
$
|
894
|
|
|
$
|
982
|
|
Derivatives Used as
Economic Hedges
|
|
Location of Gain (Loss)
Recognized in Income
on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||||
Commodity contracts
|
|
Cost of materials and other
|
|
$
|
(165
|
)
|
|
$
|
(278
|
)
|
|
$
|
(86
|
)
|
Commodity contracts
|
|
Operating expenses
(excluding depreciation and
amortization expense)
|
|
7
|
|
|
—
|
|
|
—
|
|
|||
Foreign currency contracts
|
|
Cost of materials and other
|
|
56
|
|
|
(40
|
)
|
|
16
|
|
21.
|
QUARTERLY FINANCIAL DATA (Unaudited)
|
|
2018 Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
Revenues
|
$
|
26,439
|
|
|
$
|
31,015
|
|
|
$
|
30,849
|
|
|
$
|
28,730
|
|
Gross profit (a)
|
1,062
|
|
|
1,535
|
|
|
1,451
|
|
|
1,546
|
|
||||
Operating income
|
801
|
|
|
1,253
|
|
|
1,219
|
|
|
1,299
|
|
||||
Net income
|
582
|
|
|
875
|
|
|
874
|
|
|
1,022
|
|
||||
Net income attributable to
Valero Energy Corporation
stockholders
|
469
|
|
|
845
|
|
|
856
|
|
|
952
|
|
||||
Earnings per common share
|
1.09
|
|
|
1.96
|
|
|
2.01
|
|
|
2.26
|
|
||||
Earnings per common share –
assuming dilution
|
1.09
|
|
|
1.96
|
|
|
2.01
|
|
|
2.24
|
|
||||
|
|
|
|
|
|
|
|
||||||||
|
2017 Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31 (b)
|
||||||||
Revenues
|
$
|
21,772
|
|
|
$
|
22,254
|
|
|
$
|
23,562
|
|
|
$
|
26,392
|
|
Gross profit (a)
|
732
|
|
|
1,049
|
|
|
1,614
|
|
|
1,110
|
|
||||
Operating income
|
528
|
|
|
860
|
|
|
1,332
|
|
|
843
|
|
||||
Net income
|
321
|
|
|
572
|
|
|
863
|
|
|
2,400
|
|
||||
Net income attributable to
Valero Energy Corporation
stockholders
|
305
|
|
|
548
|
|
|
841
|
|
|
2,371
|
|
||||
Earnings per common share
|
0.68
|
|
|
1.23
|
|
|
1.91
|
|
|
5.43
|
|
||||
Earnings per common share –
assuming dilution
|
0.68
|
|
|
1.23
|
|
|
1.91
|
|
|
5.42
|
|
(a)
|
Gross profit is calculated as revenues less total cost of sales.
|
(b)
|
During the quarter ended
December 31, 2017
, we recognized an income tax benefit of
$1.9 billion
related to Tax Reform as described in
Note 15
.
|
|
|
|
—
|
||
|
|
|
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.
|
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
—
|
||
|
|
|
***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.
|
++
|
Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant agrees to furnish supplementally a copy of any such omitted schedule to the SEC upon request.
|
|
VALERO ENERGY CORPORATION
(Registrant)
|
|
|
By:
|
/s/ Joseph W. Gorder
|
|
|
(Joseph W. Gorder)
|
|
|
Chairman of the Board, President,
and Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Joseph W. Gorder
|
|
Chairman of the Board, President,
and Chief Executive Officer
(Principal Executive Officer)
|
|
February 28, 2019
|
(Joseph W. Gorder)
|
|
|
||
|
|
|
|
|
/s/ Donna M. Titzman
|
|
Executive Vice President
and Chief Financial Officer
(Principal Financial and Accounting Officer)
|
|
February 28, 2019
|
(Donna M. Titzman)
|
|
|
||
|
|
|
|
|
/s/ H. Paulett Eberhart
|
|
Director
|
|
February 28, 2019
|
(H. Paulett Eberhart)
|
|
|
||
|
|
|
|
|
/s/ Kimberly S. Greene
|
|
Director
|
|
February 28, 2019
|
(Kimberly S. Greene)
|
|
|
||
|
|
|
|
|
/s/ Deborah P. Majoras
|
|
Director
|
|
February 28, 2019
|
(Deborah P. Majoras)
|
|
|
||
|
|
|
|
|
/s/ Donald L. Nickles
|
|
Director
|
|
February 28, 2019
|
(Donald L. Nickles)
|
|
|
||
|
|
|
|
|
/s/ Philip J. Pfeiffer
|
|
Director
|
|
February 28, 2019
|
(Philip J. Pfeiffer)
|
|
|
||
|
|
|
|
|
/s/ Robert A. Profusek
|
|
Director
|
|
February 28, 2019
|
(Robert A. Profusek)
|
|
|
||
|
|
|
|
|
/s/ Stephen M. Waters
|
|
Director
|
|
February 28, 2019
|
(Stephen M. Waters)
|
|
|
||
|
|
|
|
|
/s/ Randall J. Weisenburger
|
|
Director
|
|
February 28, 2019
|
(Randall J. Weisenburger)
|
|
|
||
|
|
|
|
|
/s/ Rayford Wilkins, Jr.
|
|
Director
|
|
February 28, 2019
|
(Rayford Wilkins, Jr.)
|
|
|
Name of Entity
|
|
State of Incorporation/Organization
|
|
|
|
AIR BP-PBF DEL PERU SAC
|
|
Peru
|
BELFAST STORAGE LTD
|
|
Northern Ireland
|
CANADIAN ULTRAMAR COMPANY
|
|
Nova Scotia
|
COLONNADE TEXAS INSURANCE COMPANY, LLC
|
|
Texas
|
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.
|
ENTERPRISE CLAIMS MANAGEMENT, INC.
|
|
Texas
|
GCP LOGISTICS COMPANY LLC
|
|
Delaware
|
GOLDEN EAGLE ASSURANCE LIMITED
|
|
British Columbia
|
HAMMOND MAINLINE PIPELINE LLC
|
|
Delaware
|
HUNTWAY REFINING COMPANY
|
|
Delaware
|
MAINLINE PIPELINES LIMITED
|
|
England and Wales
|
MAPLE ETHANOL LTD.
|
|
Virgin Islands (U.K.)
|
MICHIGAN REDEVELOPMENT GP, LLC
|
|
Delaware
|
MICHIGAN REDEVELOPMENT, L.P.
|
|
Delaware
|
MRP PROPERTIES COMPANY, LLC
|
|
Michigan
|
NECHES RIVER HOLDING CORP.
|
|
Delaware
|
NORCO METHANOL, LLC
|
|
Delaware
|
OCEANIC TANKERS AGENCY LIMITED
|
|
Quebec
|
PARKWAY PIPELINE LLC
|
|
Delaware
|
PENTA TANKS TERMINALS S.A.
|
|
Peru
|
PICKARD PLACE CONDOMINIUM ASSOCIATION
|
|
Michigan
|
PI DOCK FACILITIES LLC
|
|
Delaware
|
PORT ARTHUR COKER COMPANY L.P.
|
|
Delaware
|
PREMCOR USA INC.
|
|
Delaware
|
PROPERTY RESTORATION, L.P.
|
|
Delaware
|
PURE BIOFUELS DEL PERU S.A.C.
|
|
Peru
|
PURE BIOFUELS HOLDINGS L.P.
|
|
Alberta
|
SABINE RIVER HOLDING CORP.
|
|
Delaware
|
SABINE RIVER LLC
|
|
Delaware
|
SAINT BERNARD PROPERTIES COMPANY 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
|
TRANSPORT MARITIME ST. LAURENT INC.
|
|
Quebec
|
ULTRAMAR ACCEPTANCE INC.
|
|
Canada
|
ULTRAMAR ENERGY INC.
|
|
Delaware
|
ULTRAMAR INC.
|
|
Nevada
|
V-TEX LOGISTICS LLC
|
|
Delaware
|
VALERO ADMINISTRATIVE SERVICES DE MÉXICO, S.A. DE C.V.
|
|
Mexico
|
VALERO ARUBA ACQUISITION COMPANY I, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA FINANCE INTERNATIONAL, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA HOLDING COMPANY N.V.
|
|
Aruba
|
VALERO ARUBA HOLDINGS INTERNATIONAL, LTD.
|
|
Virgin Islands (U.K.)
|
VALERO ARUBA MAINTENANCE/OPERATIONS COMPANY N.V.
|
|
Aruba
|
VALERO (BARBADOS) SRL
|
|
Barbados
|
VALERO BROWNSVILLE TERMINAL LLC
|
|
Texas
|
VALERO CANADA FINANCE, INC.
|
|
Delaware
|
VALERO CANADA L.P.
|
|
Newfoundland
|
VALERO CAPITAL CORPORATION
|
|
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 FOREST CONTRIBUTION LLC
|
|
Delaware
|
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 AND SUPPLY COMPANY
|
|
Delaware
|
VALERO MARKETING AND SUPPLY DE MÉXICO S.A. DE C.V.
|
|
Mexico
|
VALERO MARKETING AND SUPPY INTERNATIONAL LTD.
|
|
Cayman Islands
|
VALERO MARKETING AND SUPPLY (PANAMA) LLC
|
|
Delaware
|
VALERO MARKETING IRELAND LIMITED
|
|
Ireland
|
VALERO MKS LOGISTICS, L.L.C.
|
|
Delaware
|
VALERO NEDERLAND COÖPERATIEF U.A.
|
|
The Netherlands
|
VALERO NEW AMSTERDAM B.V.
|
|
The Netherlands
|
VALERO OMEGA COMPANY, L.L.C.
|
|
Delaware
|
VALERO OPERATIONAL SERVICES DE MÉXICO, S.A. DE C.V.
|
|
Mexico
|
VALERO OPERATIONS SUPPORT, LTD
|
|
England and Wales
|
VALERO PARTNERS CCTS, LLC
|
|
Delaware
|
VALERO PARTNERS CORPUS EAST, LLC
|
|
Delaware
|
VALERO PARTNERS CORPUS WEST, LLC
|
|
Delaware
|
VALERO PARTNERS EP, LLC
|
|
Delaware
|
VALERO PARTNERS HOUSTON, LLC
|
|
Delaware
|
VALERO PARTNERS LOUISIANA, LLC
|
|
Delaware
|
VALERO PARTNERS LUCAS, LLC
|
|
Delaware
|
VALERO PARTNERS MCKEE, LLC
|
|
Delaware
|
VALERO PARTNERS MEMPHIS, LLC
|
|
Delaware
|
VALERO PARTNERS MERAUX, LLC
|
|
Delaware
|
VALERO PARTNERS NORTH TEXAS, LLC
|
|
Delaware
|
VALERO PARTNERS OPERATING CO. LLC
|
|
Delaware
|
VALERO PARTNERS PAPS, LLC
|
|
Delaware
|
VALERO PARTNERS PORT ARTHUR, LLC
|
|
Delaware
|
VALERO PARTNERS SOUTH TEXAS, LLC
|
|
Delaware
|
VALERO PARTNERS TEXAS CITY, LLC
|
|
Delaware
|
VALERO PARTNERS THREE RIVERS, LLC
|
|
Delaware
|
VALERO PARTNERS WEST MEMPHIS, LLC
|
|
Delaware
|
VALERO PARTNERS WEST TEXAS, LLC
|
|
Delaware
|
VALERO PARTNERS WYNNEWOOD, LLC
|
|
Delaware
|
VALERO PAYMENT SERVICES COMPANY
|
|
Virginia
|
VALERO PEMBROKESHIRE LLC
|
|
Delaware
|
VALERO PEMBROKESHIRE OIL TERMINAL LTD
|
|
England and Wales
|
VALERO (PERU) HOLDINGS GP LLC
|
|
Delaware
|
VALERO (PERU) HOLDINGS LIMITED
|
|
British Columbia
|
VALERO PLAINS COMPANY LLC
|
|
Texas
|
VALERO POWER MARKETING LLC
|
|
Delaware
|
VALERO RAIL OPERATIONS DE MÉXICO, S.A. DE C.V.
|
|
Mexico
|
VALERO RAIL PARTNERS, 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
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Texas
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VALERO SECURITY SYSTEMS, INC.
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Delaware
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VALERO SERVICES, INC.
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Delaware
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VALERO SKELLYTOWN PIPELINE, LLC
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Delaware
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VALERO TEJAS COMPANY LLC
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Delaware
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VALERO TERMINAL HOLDCO LTD
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England and Wales
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VALERO TERMINALING AND DISTRIBUTION COMPANY
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Delaware
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VALERO TERMINALING AND DISTRIBUTION DE MEXICO, S.A. DE C.V.
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Mexico
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VALERO TEXAS POWER MARKETING, INC.
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Delaware
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VALERO ULTRAMAR HOLDINGS INC.
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Delaware
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VALERO UNIT INVESTMENTS, L.L.C.
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Delaware
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VALERO WEST WALES LLC
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Delaware
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VRG PROPERTIES COMPANY
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Delaware
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VTD PROPERTIES COMPANY
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Delaware
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WARSHALL COMPANY LLC
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Delaware
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ZELIG COMMERCIAL, INC.
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Panama
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/s/ Joseph W. Gorder
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Joseph W. Gorder
Chief Executive Officer and President
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/s/ Donna M. Titzman
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Donna M. Titzman
Executive Vice President and Chief Financial Officer
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ Joseph W. Gorder
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Joseph W. Gorder
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Chief Executive Officer and President
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February 28, 2019
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ Donna M. Titzman
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Donna M. Titzman
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Executive Vice President and Chief Financial Officer
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February 28, 2019
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