Valero Energy (VLO) 10-K 2019 FY Annual report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission file number 001-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	74-1828067
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

One Valero Way

San Antonio, Texas 78249

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (210) 345-2000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock	VLO	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer		☑	Accelerated filer			☐	Non-accelerated filer		☐
	Smaller reporting company			☐	Emerging growth company			☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $35.5 billion based on the last sales price quoted as of June 28, 2019 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2020, 409,337,126 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We intend to file with the Securities and Exchange Commission a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for April 30, 2020, at which directors will be elected. Portions of the 2020 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.

CROSS-REFERENCE SHEET

The following table indicates the headings in the 2020 Proxy Statement where certain information required in Part III of this Form 10-K may be found.

Form 10-K Item No. and Caption		Heading in 2020 Proxy Statement
10.	Directors, Executive Officers and Corporate Governance	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, and Governance Documents and Codes of Ethics
11.	Executive Compensation	Compensation Committee, Compensation Discussion and Analysis, Executive Compensation, Director Compensation, Pay Ratio Disclosure, and Certain Relationships and Related Transactions
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	Beneficial Ownership of Valero Securities and Equity Compensation Plan Information
13.	Certain Relationships and Related Transactions, and Director Independence	Certain Relationships and Related Transactions and Independent Directors
14.	Principal Accountant Fees and Services	KPMG LLP Fees and Audit Committee Pre-Approval Policy

Copies of all documents incorporated by reference, other than exhibits to such documents, will be provided without charge to each person who receives a copy of this Form 10-K upon written request to Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

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CONTENTS

		PAGE
PART I		1
Items 1. & 2.	Business and Properties	1
	Overview	1
	Available Information	1
	Valero’s Operations	2
	Environmental Matters	9
	Properties	9
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	18
Item 3.	Legal Proceedings	18
Item 4.	Mine Safety Disclosures	19
PART II		20
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	57
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	146
Item 9A.	Controls and Procedures	146
Item 9B.	Other Information	146
PART III		146
Item 10.	Directors, Executive Officers and Corporate Governance	146
Item 11.	Executive Compensation	146
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	146
Item 13.	Certain Relationships and Related Transactions, and Director Independence	146
Item 14.	Principal Accountant Fees and Services	146
PART IV		147
Item 15.	Exhibits and Financial Statement Schedules	147
Signature		151

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The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, to one or more of its consolidated subsidiaries, or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures beginning on page 23 of this report under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”

PART I

ITEMS 1. and 2. BUSINESS AND PROPERTIES

OVERVIEW

We are a Fortune 500 company based in San Antonio, Texas. Our corporate offices are at One Valero Way, San Antonio, Texas, 78249, and our telephone number is (210) 345-2000. We were incorporated in Delaware in 1981 under the name Valero Refining and Marketing Company. We changed our name to Valero Energy Corporation on August 1, 1997. Our common stock trades on the New York Stock Exchange (NYSE) under the trading symbol “VLO.” On January 31, 2020, we had 10,222 employees.

We own 15 petroleum refineries located in the United States (U.S.), Canada, and the United Kingdom (U.K.) with a combined throughput capacity of approximately 3.15 million barrels per day (BPD). Our refineries produce conventional gasolines, premium gasolines, gasoline meeting the specifications of the California Air Resources Board (CARB), diesel, low-sulfur diesel, ultra-low-sulfur diesel, CARB diesel, other distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined petroleum products. We also own 14 ethanol plants located in the Mid-Continent region of the U.S. with a combined production capacity of approximately 1.73 billion gallons per year. We are also a joint venture partner in Diamond Green Diesel Holdings LLC (DGD), which owns and operates a renewable diesel plant in Norco, Louisiana. We sell our products in the wholesale rack or bulk markets in the U.S., Canada, the U.K., Ireland, and Latin America. Approximately 7,000 outlets carry our brand names.

On January 10, 2019, we completed our acquisition of all of the outstanding publicly held common units of Valero Energy Partners LP (VLP) as described in Note 2 of Notes to Consolidated Financial Statements, which is incorporated herein by reference.

AVAILABLE INFORMATION

Our website address is www.valero.com. Information on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other reports, as well as any amendments to those reports, filed with (or furnished to) the U.S. Securities and Exchange Commission (SEC) are available on our website (under About Valero > Investor Relations > Financial Information > SEC Filings) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines and other governance policies, codes of ethics, and the charters of the committees of our board of directors. These documents are available in print to any stockholder that makes a written request to Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

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VALERO’S OPERATIONS

Effective January 1, 2019, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, we created a new reportable segment — renewable diesel — because of the growing importance of renewable fuels in the market and the growth of our investments in renewable fuels production. The renewable diesel segment includes the operations of DGD, which were transferred from the refining segment on January 1, 2019. Also effective January 1, 2019, we no longer have a VLP segment, and we include the operations of VLP in our refining segment. This change was made because of the Merger Transaction with VLP, as defined and discussed in Note 2 of Notes to Consolidated Financial Statements, which is incorporated herein by reference, and the resulting change in how we manage VLP’s operations. We no longer manage VLP as a business but as logistics assets that support the operations of our refining segment.

As a result, as of December 31, 2019, we had three reportable segments as follows:

• Refining segment includes our refining operations, the associated marketing activities, and logistics assets that support our refining operations;

• Ethanol segment includes our ethanol operations, the associated marketing activities, and logistics assets that support our ethanol operations; and

• Renewable diesel segment includes the operations of DGD, our consolidated joint venture, as discussed in Note 12 of Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Financial information about these segments is presented in Note 17 of Notes to Consolidated Financial Statements, which is incorporated herein by reference.

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REFINING

Refining Operations

As of December 31, 2019, our refining operations included 15 petroleum refineries in the U.S., Canada, and the U.K., with a combined total throughput capacity of approximately 3.15 million BPD. The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2019.

Refinery	Location	Throughput Capacity (a) (BPD)
U.S.
Benicia	California	170,000
Wilmington	California	135,000
Meraux	Louisiana	135,000
St. Charles	Louisiana	340,000
Ardmore	Oklahoma	90,000
Memphis	Tennessee	195,000
Corpus Christi (b)	Texas	370,000
Houston	Texas	255,000
McKee	Texas	200,000
Port Arthur	Texas	395,000
Texas City	Texas	260,000
Three Rivers	Texas	100,000
Canada
Quebec City	Quebec, Canada	235,000
U.K.
Pembroke	Wales, U.K.	270,000
Total		3,150,000

________________________

(a) “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.

(b) Represents the combined capacities of two refineries – the Corpus Christi East and Corpus Christi West Refineries.

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The following table presents the percentages of principal charges and yields (on a combined basis) for all of our refineries for 2019, during which period our total combined throughput volumes averaged approximately 3.0 million BPD.

Combined Total Refining System Charges and Yields
Charges
	sour crude oil	23	%
	sweet crude oil	54	%
	residual fuel oil	7	%
	other feedstocks	5	%
	blendstocks	11	%
Yields
	gasolines and blendstocks	48	%
	distillates	38	%
	other products (primarily includes petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur and asphalt)	14	%

California

Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It processes sour crude oils into gasoline, diesel, jet fuel, and asphalt. Gasoline production is primarily California Reformulated Blendstock Gasoline for Oxygenate Blending (CARBOB), which meets CARB specifications when blended with ethanol. The refinery receives crude oil feedstocks via a marine dock and crude oil pipelines connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via pipeline and truck rack into northern California markets.

Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles. The refinery processes a blend of heavy and high-sulfur crude oils. The refinery produces CARBOB gasoline, diesel, CARB diesel, jet fuel, and asphalt. The refinery is connected by pipeline to marine terminals and associated dock facilities that move and store crude oil and other feedstocks. Refined petroleum products are distributed via pipeline systems to various third-party terminals in southern California, Nevada, and Arizona.

Louisiana

Meraux Refinery. Our Meraux Refinery is located approximately 15 miles southeast of New Orleans along the Mississippi River. The refinery processes sour and sweet crude oils into gasoline, diesel, jet fuel, and high sulfur fuel oil. The refinery receives crude oil at its dock and has access to the Louisiana Offshore Oil Port. Finished products are shipped from the refinery’s dock and through the Colonial pipeline. The refinery is located about 40 miles from our St. Charles Refinery, allowing for integration of feedstocks and refined petroleum product blending.

St. Charles Refinery. Our St. Charles Refinery is located approximately 25 miles west of New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline and diesel. The refinery receives crude oil over docks and has access to the Louisiana Offshore Oil Port. Finished products are shipped over these docks and through our Parkway pipeline and the Bengal pipeline, which ultimately provide access to the Plantation and Colonial pipeline networks.

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Oklahoma

Ardmore Refinery. Our Ardmore Refinery is located in Oklahoma, approximately 100 miles south of Oklahoma City. It processes sweet and sour crude oils into gasoline, diesel, and asphalt. The refinery predominantly receives Permian Basin and Cushing-sourced crude oil via third-party pipelines. Refined petroleum products are transported via rail, trucks, and the Magellan pipeline system.

Tennessee

Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River. It processes primarily sweet crude oils. Most of its production is gasoline, diesel, and jet fuels. Crude oil supply is primarily from Cushing, Oklahoma over the Diamond Pipeline. Crude oil can also be received, along with other feedstocks, via barge. Most of the refinery’s products are distributed via truck rack and barges.

Texas

Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located on the Texas Gulf Coast along the Corpus Christi Ship Channel. The East Refinery processes sour crude oil, and the West Refinery processes sweet crude oil, sour crude oil, and residual fuel oil. The feedstocks are delivered by tanker and barge via deepwater docking facilities along the Corpus Christi Ship Channel, and West Texas or South Texas crude oil is delivered via pipelines. The refineries’ physical locations allow for the transfer of various feedstocks and blending components between them. The refineries produce gasoline, aromatics, jet fuel, diesel, and asphalt. Truck racks service local markets for gasoline, diesel, jet fuels, liquefied petroleum gases, and asphalt. These and other finished products are also distributed by ship and barge across docks and third-party pipelines.

Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes sweet crude and intermediate oils into gasoline, jet fuel, and diesel. The refinery successfully commissioned a new alkylation unit in 2019. The refinery receives its feedstocks primarily by various interconnecting pipelines and also has waterborne-receiving capability at deepwater docking facilities along the Houston Ship Channel. The majority of its finished products are delivered to local, mid-continent U.S., and northeastern U.S. markets through various pipelines, including the Colonial and Explorer pipelines.

McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils into gasoline, diesel, jet fuels, and asphalt. The refinery has access to local and Permian Basin crude oil sources via third-party pipelines. Refined petroleum products are transported primarily via third-party pipelines and rail to markets in Texas, New Mexico, Arizona, Colorado, Oklahoma, and Mexico.

Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes heavy sour crude oils and other feedstocks into gasoline, diesel, and jet fuel. The refinery receives crude oil by rail, marine docks, and pipelines. Finished products are distributed into the Colonial, Explorer, and other pipelines, and across the refinery docks into ships and barges.

Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Houston Ship Channel. The refinery processes crude oils into gasoline, diesel, and jet fuel. The refinery receives its feedstocks by pipeline and by ship or barge via deepwater docking facilities along the Houston Ship Channel. The refinery uses ships and barges, as well as the Colonial, Explorer, and other pipelines for distribution of its products.

Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It primarily processes sweet crude oils into gasoline, distillates, and aromatics. The refinery has access to crude oil from West Texas and South Texas through third-party pipelines and trucks. The refinery distributes its refined petroleum products primarily through third-party pipelines.

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Canada

Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet crude oils into gasoline, diesel, jet fuel, heating oil, and low-sulfur fuel oil. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River and by pipeline and ship from western Canada. The refinery transports its products through our pipeline from Quebec City to our terminal in Montreal and to various other terminals throughout eastern Canada by rail, ships, trucks, and third-party pipelines.

U.K.

Pembroke Refinery. Our Pembroke Refinery is located in the County of Pembrokeshire in southwest Wales, U.K. The refinery processes primarily sweet crude oils into gasoline, diesel, jet fuel, heating oil, and low-sulfur fuel oil. The refinery receives all of its feedstocks and delivers some of its products by ship and barge via deepwater docking facilities along the Milford Haven Waterway, with its remaining products being delivered through our Mainline pipeline system and by trucks.

Feedstock Supply

Our crude oil feedstocks are purchased through a combination of term and spot contracts. Our term supply agreements are at market-related prices and are purchased directly or indirectly from various national oil companies as well as international and U.S. oil companies. The contracts generally permit the parties to amend the contracts (or terminate them), effective as of the next scheduled renewal date, by giving the other party proper notice within a prescribed period of time (e.g., 60 days, 6 months) before expiration of the current term. The majority of the crude oil purchased under our term contracts is purchased at the producer’s official stated price (i.e., the “market” price established by the seller for all purchasers) and not at a negotiated price specific to us.

Marketing

Overview

We sell refined petroleum products in both the wholesale rack and bulk markets. These sales include refined petroleum products that are manufactured in our refining operations, as well as refined petroleum products purchased or received on exchange from third parties. Most of our refineries have access to marine transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in the U.S., Canada, the U.K., and other countries.

Wholesale Rack Sales

We sell our gasoline and distillate products, as well as other products, such as asphalt, lube oils, and natural gas liquids (NGLs), on a wholesale basis through an extensive rack marketing network. The principal purchasers of our refined petroleum products from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the U.S., Canada, the U.K., Ireland, and Latin America.

The majority of our rack volume is sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate 5,158 branded sites in the U.S., 874 branded sites in the U.K. and Ireland, and 795 branded sites in Canada as of December 31, 2019. These sites are independently owned and are supplied by us under multi-year contracts. For branded sites, products are sold under the Valero^®, Beacon^®, Diamond Shamrock^®, and Shamrock^® brands in the U.S., the Texaco^® brand in the U.K. and Ireland, and the Ultramar^® brand in Canada.

Bulk Sales

We also sell our gasoline and distillate products, as well as other products, such as asphalt, petrochemicals, and NGLs, through bulk sales channels in the U.S. and international markets. Our bulk sales are made to

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various oil companies, traders, and bulk end-users, such as railroads, airlines, and utilities. Our bulk sales are transported primarily by pipeline, barges, and tankers to major tank farms and trading hubs.

We also enter into refined petroleum product exchange and purchase agreements. These agreements help minimize transportation costs, optimize refinery utilization, balance refined petroleum product availability, broaden geographic distribution, and provide access to markets not connected to our refined product pipeline systems. Exchange agreements provide for the delivery of refined petroleum products by us to unaffiliated companies at our and third-parties’ terminals in exchange for delivery of a similar amount of refined petroleum products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined petroleum products from third parties with delivery occurring at specified locations.

Logistics

We own logistics assets (crude oil pipelines, refined petroleum product pipelines, terminals, tanks, marine docks, truck rack bays, and other assets) that support our refining operations.

ETHANOL

We own 14 ethanol plants with a combined ethanol production capacity of 1.73 billion gallons per year. Our ethanol plants are dry mill facilities that process corn to produce ethanol, distillers grains, and corn oil. We source our corn supply from local farmers and commercial elevators. Our facilities receive corn primarily by rail and truck. We publish on our website a corn bid for local farmers and cooperative dealers to facilitate corn supply transactions.

We sell our ethanol primarily to refiners and gasoline blenders under term and spot contracts in bulk markets such as New York, Chicago, the U.S. Gulf Coast, Florida, and the U.S. West Coast. We also export our ethanol into the global markets. We ship our dry distillers grains (DDGs) by truck or rail primarily to animal feed customers in the U.S. and Mexico. We also sell modified distillers grains locally at our plant sites, and corn oil by truck and rail. We distribute our ethanol through logistics assets, which include railcars owned by us.

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The following table presents the locations of our ethanol plants, their approximate annual production capacities for ethanol (in millions of gallons) and DDGs (in tons), and their approximate annual corn processing capacities (in millions of bushels).

State	City	Ethanol Production Capacity	Production of DDGs	Corn Processed
Indiana	Bluffton	115	302,000	40
	Linden	135	355,000	47
	Mount Vernon	100	263,000	35
Iowa	Albert City	135	355,000	47
	Charles City	140	368,000	49
	Fort Dodge	140	368,000	49
	Hartley	140	368,000	49
	Lakota	110	289,000	38
Michigan	Riga	55	145,000	19
Minnesota	Welcome	140	368,000	49
Nebraska	Albion	135	355,000	47
Ohio	Bloomingburg	135	355,000	47
South Dakota	Aurora	140	368,000	49
Wisconsin	Jefferson	110	352,000	41
Total		1,730	4,611,000	606

The combined production of ethanol from our plants averaged 4.3 million gallons per day for 2019.

RENEWABLE DIESEL

Our renewable segment includes the operations of DGD, which owns and operates a biomass-based diesel plant (the DGD Plant) that processes animal fats, used cooking oils, and other vegetable oils into renewable diesel. The DGD Plant is located next to our St. Charles Refinery in Norco, Louisiana. During 2019, the DGD Plant’s capacity was approximately 18,000 BPD. The DGD Plant is capable of annually converting approximately 2.3 billion pounds of rendered and recycled material into more than 275 million gallons of renewable diesel. In 2019, we began an expansion of the DGD Plant that is expected to increase production up to 675 million gallons of renewable diesel annually. DGD is in the advanced engineering review phase for a potential new renewable diesel plant to be located in Port Arthur, Texas.

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ENVIRONMENTAL MATTERS

We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:

• 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 (EPA) Renewable Fuel Standard (RFS) 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.

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2019, our capital expenditures attributable to compliance with environmental regulations were $235 million, and they are currently estimated to be $14 million for 2020 and $20 million for 2021. The estimates for 2020 and 2021 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments. These amounts could materially change as a result of governmental and regulatory actions.

PROPERTIES

Our principal properties are described above under the caption “VALERO’S OPERATIONS,” and that information is incorporated herein by reference. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2019, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed in Note 5 of Notes to Consolidated Financial Statements, which is incorporated herein by reference. Financial information about our properties is presented in Note 6 of Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Our patents relating to our refining operations are not material to us as a whole. The trademarks and tradenames under which we conduct our branded wholesale business — Valero^®, Diamond Shamrock^®, Shamrock^®, Ultramar^®, Beacon^®, and Texaco^®— and other trademarks employed in the marketing of refined petroleum products are integral to our wholesale rack marketing operations.

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ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results, and/or financial condition, as well as adversely affect the value of an investment in our common stock.

Our financial results are affected by volatile refining margins, which are dependent upon factors beyond our control, including the price of crude oil and the market price at which we can sell refined petroleum products.

Our financial results are primarily affected by the relationship, or margin, between refined petroleum product prices and the prices for crude oil and other feedstocks. Historically, refining margins have been volatile, and we believe they will continue to be volatile in the future. Our cost to acquire feedstocks and the price at which we can ultimately sell refined petroleum products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined petroleum products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of U.S. and international suppliers, levels of refined petroleum product inventories, productivity and growth (or the lack thereof) of U.S. and global economies, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation.

Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refining and marketing margins are uncertain. We do not produce crude oil and must purchase all of the crude oil we refine. We may purchase our crude oil and other refinery feedstocks long before we refine them and sell the refined petroleum products. Price level changes during the period between purchasing feedstocks and selling the refined petroleum products from these feedstocks could have a significant effect on our financial results. A decline in market prices may negatively impact the carrying value of our inventories.

Economic turmoil and political unrest or hostilities, including the threat of future terrorist attacks, could affect the economies of the U.S. and other countries. Lower levels of economic activity could result in declines in energy consumption, including declines in the demand for and consumption of our refined petroleum products, which could cause our revenues and margins to decline and limit our future growth prospects.

Refining margins are also significantly impacted by additional refinery conversion capacity through the expansion of existing refineries or the construction of new refineries. Worldwide refining capacity expansions may result in refining production capability exceeding refined petroleum product demand, which would have an adverse effect on refining margins.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been cheaper than benchmark crude oils, such as Louisiana Light Sweet (LLS) and Brent crude oils. These crude oil feedstock differentials vary significantly depending on overall economic conditions and trends and conditions within the markets for crude oil and refined petroleum products, and they could decline in the future, which would have a negative impact on our results of operations.

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Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance.

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas (GHG) emissions, and characteristics and composition of fuels, including gasoline and diesel. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities as well as at formerly owned properties or third-party sites where we have taken wastes for disposal or where our wastes have migrated. Environmental laws and regulations also may impose liability on us for the conduct of third parties, or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned.

Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to GHG emissions and climate change, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we sell, and decreased demand for our products that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations, discontinue use of certain process units, or install pollution control equipment that could materially and adversely affect our business, financial condition, results of operations, and liquidity.

For example, in 2015, the U.S., Canada, and the U.K. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (which set GHG emission reduction goals) every five years beginning in 2020. In November 2019, the current U.S. administration served notice on the United Nations that the U.S. would withdraw from the Paris Agreement in 2020. There are no guarantees that the Paris Agreement will not be re-implemented in the U.S. or re-implemented in part by specific U.S. states or local governments. Regardless, the Paris Agreement could still affect our operations in Canada, the U.K., Ireland, and Latin America. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various U.S. states, at the U.S. federal level, or in other countries could adversely affect the oil and gas industry.

Investor sentiment towards climate change, fossil fuels, and sustainability could adversely affect our business and our stock price.

There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. If these efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.

Members of the investment community are also increasing their focus on sustainability practices, including practices related to GHGs and climate change, in the energy industry. As a result, we may face increasing pressure regarding our sustainability disclosures and practices. Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our stock.

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If we are unable to meet the sustainability standards set by these investors, we may lose investors, our stock price may be negatively impacted and our reputation may be negatively affected.

Severe weather events may have an adverse effect on our assets and operations.

Severe weather events, such as storms, droughts, or floods, could have an adverse effect on our operations. Members within the scientific community believe that an increasing concentration of GHG emissions in the Earth’s atmosphere may contribute to climate changes that can have significant physical effects, including an increased frequency and severity of these types of events.

Compliance with the U.S. Environmental Protection Agency (EPA) Renewable Fuel Standard (RFS) could adversely affect our performance.

The U.S. EPA has implemented the RFS pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas for the quantity of renewable fuels (such as ethanol and diesel) that must be blended into transportation fuels consumed in the U.S. A Renewable Identification Number (RIN) is assigned to each gallon of renewable fuel produced in or imported into the U.S. As a producer of petroleum-based transportation fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at least commensurate to the U.S. EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program.

We are exposed to the volatility in the market price of RINs. We cannot predict the future prices of RINs. RINs prices are dependent upon a variety of factors, including U.S. EPA regulations, the availability of RINs for purchase, and levels of transportation fuels produced, which can vary significantly from quarter to quarter. If sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the U.S. EPA’s RFS mandates, our results of operations and cash flows could be adversely affected.

Disruption of our ability to obtain crude oil could adversely affect our operations.

A significant portion of our feedstock requirements is satisfied through supplies originating in the Middle East, Africa, Asia, North America, and South America. We are, therefore, subject to the political, geographic, and economic risks attendant to doing business with suppliers located in, and supplies originating from, these areas. If one or more of our supply contracts were terminated, or if political events disrupt our traditional crude oil supply, we believe that adequate alternative supplies of crude oil would be available, but it is possible that we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our results of operations could be materially adversely affected, including reduced sales volumes of refined petroleum products or reduced margins as a result of higher crude oil costs.

In addition, the U.S. government can prevent or restrict us from doing business in or with other countries. These restrictions, and those of other governments, could limit our ability to gain access to business opportunities in various countries. Actions by both the U.S. and other countries have affected our operations in the past and will continue to do so in the future.

Any attempt by the U.S. government to withdraw from or materially modify existing international trade agreements could adversely affect our business, financial condition, and results of operations.

The current U.S. administration has questioned certain existing and proposed trade agreements. For example, the administration withdrew the U.S. from the Trans-Pacific Partnership. In addition, the administration has

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implemented and proposed various trade tariffs, which have resulted in foreign governments responding with tariffs on U.S. goods.

Changes in U.S. social, political, regulatory, and economic conditions or in laws and policies governing foreign trade, manufacturing, development and investment could adversely affect our business. For example, the imposition of tariffs or other trade barriers with other countries could affect our ability to obtain feedstocks from international sources, increase our costs and reduce the competitiveness of our products.

While there is currently a lack of certainty around the likelihood, timing, and details of any such policies and reforms, if the current U.S. administration takes action to withdraw from, or materially modify, existing international trade agreements, our business, financial condition, and results of operations could be adversely affected.

We are subject to interruptions and increased costs as a result of our reliance on third-party transportation of crude oil and the products that we manufacture.

We use the services of third parties to transport feedstocks to our facilities and to transport the products we manufacture to market. If we experience prolonged interruptions of supply or increases in costs to deliver our products to market, or if the ability of the pipelines, vessels, or railroads to transport feedstocks or products is disrupted because of weather events, accidents, derailment, collision, fire, explosion, governmental regulations, or third-party actions, it could have a material adverse effect on our financial position, results of operations, and liquidity.

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.

We currently use rail cars for the transportation of some feedstocks to certain of our facilities and for the transportation of some of the products we manufacture to their markets. We own and lease rail cars for our operations. Rail transportation is subject to a variety of federal, state, and local regulations, as well as industry practices and customs. New laws and regulations, and changes in existing laws and regulations, are frequently enacted or proposed, and could result in increased expenditures for compliance, either directly through costs for our owned and leased rail assets, or as passed along to us by rail carriers and operators. For example, in the past several years, the Department of Transportation and various agencies within the Department of Transportation, including the Surface Transportation Board, the Pipeline and Hazardous Materials Safety Administration, and the Federal Railroad Administration, have issued orders and rules pursuant to the Federal Railroad Safety Act of 1970, the Interstate Commerce Commission Termination Act of 1995, the Rail Safety Improvement Act of 2008, Fixing America’s Surface Transportation Act of 2015 and other statutory authorities concerning such matters as enhanced tank car standards, positive train control and other operational controls, safety training programs, and notification requirements. The general trend has been toward greater regulation of rail transportation over recent years. We do not believe these orders and rules will have a material impact on our financial position, results of operations, and liquidity, although further changes in law, regulations, or industry practices could require us to incur additional costs to the extent they are applicable to us.

Competitors that produce their own supply of feedstocks, own their own retail sites, have greater financial resources, or provide alternative energy sources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined petroleum product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for sites for our refined petroleum products. We do not produce any of our crude oil feedstocks and, following the separation of our retail business in 2013, we do not have a company-owned retail network.

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Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have extensive retail sites. Such competitors are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial, and individual consumers.

Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms, and can adversely affect the financial strength of our business partners.

Our ability to obtain credit and capital depends in large measure on capital markets and liquidity factors that we do not control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, causing them to fail to meet their obligations to us. In addition, decreased returns on pension fund assets may also materially increase our pension funding requirements.

Our access to credit and capital markets also depends on the credit ratings assigned to our debt by independent credit rating agencies. We currently maintain investment-grade ratings by Standard & Poor’s Ratings Services, Moody’s Investors Service, and Fitch Ratings on our senior unsecured debt. Ratings from credit agencies are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Specifically, if ratings agencies were to downgrade our long-term rating, particularly below investment grade, our borrowing costs may increase, which could adversely affect our ability to attract potential investors and our funding sources could decrease. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security, which would increase our operating costs. As a result, a downgrade below investment grade in our credit ratings could have a material adverse impact on our financial position, results of operations, and liquidity.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. We have existing revolving credit facilities, committed letter of credit facilities, and an accounts receivable sales facility to provide us with available financing to meet our ongoing cash needs. In addition, we rely on the counterparties to our derivative instruments to fund their obligations under such arrangements. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions and other counterparties to fund their commitments to us under our various financing facilities or our derivative instruments, which could have a material adverse effect on our financial position, results of operations, and liquidity.

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A significant interruption in one or more of our refineries could adversely affect our business.

Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. Significant interruptions in our refining system could also lead to increased volatility in prices for crude oil feedstocks and refined petroleum products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

A significant interruption related to our information technology systems could adversely affect our business.

Our information technology systems and network infrastructure may be subject to unauthorized access or attack, which could result in (i) a loss of intellectual property, proprietary information, or employee, customer or vendor data; (ii) public disclosure of sensitive information; (iii) increased costs to prevent, respond to, or mitigate cybersecurity events, such as deploying additional personnel and protection technologies, training employees, and engaging third-party experts and consultants; (iv) systems interruption; (v) disruption of our business operations; (vi) remediation costs for repairs of system damage; (vii) reputational damage that adversely affects customer or investor confidence; and (viii) damage to our competitiveness, stock price, and long-term stockholder value. A breach could also originate from, or compromise, our customers’ and vendors’ or other third-party networks outside of our control. A breach may also result in legal claims or proceedings against us by our shareholders, employees, customers, vendors, and governmental authorities (U.S. and non-U.S.). There can be no assurance that our infrastructure protection technologies and disaster recovery plans can prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations. Furthermore, the continuing and evolving threat of cyberattacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

Increasing regulatory focus on privacy and security issues and expanding laws could expose us to increased liability, subject us to lawsuits, investigations and other liabilities and restrictions on our operations that could significantly and adversely affect our business.

Along with our own data and information in the normal course of our business, we and our partners collect and retain certain data that is subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. This data is subject to governmental regulation at the federal, state, international, national, provincial and local levels in many areas of our business, including data privacy and security laws such as the European Union (EU) General Data Protection Regulation (GDPR) and the California Consumer Privacy Act (CCPA).

The GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the EU. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur additional costs. Failure to comply could result in significant penalties of up to a maximum of 4 percent of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows.

The CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security

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incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.

The GDPR and CCPA, as well as other data privacy laws that may become applicable to our business, pose increasingly complex compliance challenges and potentially elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

Our business may be negatively affected by work stoppages, slowdowns or strikes by our employees, as well as new labor legislation issued by regulators.

Workers at some of our refineries are covered by collective bargaining or similar agreements. To the extent we are in negotiations for labor agreements expiring in the future, there is no assurance an agreement will be reached without a strike, work stoppage, or other labor action. Any prolonged strike, work stoppage, or other labor action could have an adverse effect on our financial condition or results of operations. In addition, future federal, state, or foreign labor legislation could result in labor shortages and higher costs, especially during critical maintenance periods.

We are subject to operational risks and our insurance may not be sufficient to cover all potential losses arising from operating hazards. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our financial position, results of operations, and liquidity.

Our operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and natural catastrophes. As protection against these hazards, we maintain insurance coverage against some, but not all, potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage is very limited, and coverage for terrorism risks includes very broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations, and liquidity.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies. We can make no assurances that we will be able to obtain the full amount of our insurance coverage for insured events.

Large capital projects can take many years to complete, and market conditions could deteriorate over time, negatively impacting project returns.

We may engage in capital projects based on the forecasted project economics and level of return on the capital to be employed in the project. Large-scale projects take many years to complete, and market conditions can change from our forecast. As a result, we may be unable to fully realize our expected returns, which could negatively impact our financial condition, results of operations, and cash flows.

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Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use, gross receipts, and value-added taxes), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

On December 22, 2017, tax legislation commonly known as the Tax Cuts and Jobs Act of 2017 (Tax Reform) was enacted. Among other things, Tax Reform reduced the U.S. corporate income tax rate from 35 percent to 21 percent and implemented a new system of taxation for non-U.S. earnings, including by imposing a one-time tax on the deemed repatriation of undistributed earnings of non-U.S. subsidiaries. Tax Reform also generally (i) repealed the manufacturing deduction we previously were able to claim, (ii) resulted in a 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, (iii) limits our annual deductions for interest expense to no more than 30 percent of our “adjusted taxable income” (plus 100 percent of our business interest income) for the year and (iv) permits us to offset only 80 percent (rather than 100 percent) of our taxable income with any net operating losses we generate after 2017. We have evaluated the effects of Tax Reform, including the one-time deemed repatriation tax and the re-measurement of our deferred tax assets and liabilities, and the provisions of Tax Reform, taken as a whole, did not have an adverse impact on our cash tax liabilities, results of operations, or financial condition. We have used reasonable interpretations and assumptions in applying Tax Reform, but it is possible that the Internal Revenue Service (IRS) could issue subsequent guidance or take positions on audit that differ from our prior interpretations and assumptions, which could adversely impact our cash tax liabilities, results of operations, and financial condition.

Our investments in joint ventures and other entities decrease our ability to manage risk.

We conduct some of our operations through joint ventures in which we may share control over certain economic and business interests with our joint venture partners and in some entities in which we have no ownership or control. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their obligations. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on our, or our joint ventures’, financial position, results of operations, and liquidity.

We may incur losses and additional costs as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we use to hedge our exposure to various types of risk are not effective, we may incur losses. In addition, we may be required to incur additional costs in connection with future regulation of derivative instruments to the extent it is applicable to us.

Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates.

On July 27, 2017, the Financial Conduct Authority in the U.K. announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021, or whether different benchmark rates used to price indebtedness

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will develop. In the future, we may need to renegotiate our financial agreements, including, but not limited to, our revolving credit facility (the Valero Revolver), or incur other indebtedness, and the phase-out of LIBOR may negatively impact the terms of such indebtedness. In addition, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR. Disruption in the financial market could have a material adverse effect on our financial position, results of operations, and liquidity.

Changes in the U.K.’s economic and other relationships with the EU could adversely affect us.

In June 2016, the U.K. elected to withdraw from the EU in a national referendum (Brexit). The U.K. withdrew from the EU on January 31, 2020, consistent with the terms of the EU-U.K. Withdrawal Agreement. The terms of that agreement provide for a transition period, from January 31, 2020 to December 31, 2020, during which the trading relationship between the U.K. and the EU will remain the same while the U.K. and the EU try to negotiate an agreement regarding their future trading relationship. The ultimate effects of Brexit will depend on whether an agreement is reached, or on the specific terms of any such agreement that is reached, either of which outcomes could adversely impact the ability to trade freely between the U.K. and the EU at the end of the transition period and could negatively impact our competitive position, supplier and customer relationships, and financial performance.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

LITIGATION

We incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 1 of Notes to Consolidated Financial Statements under the caption “Legal Contingencies.”

ENVIRONMENTAL ENFORCEMENT MATTERS

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

U.S. EPA (Fuels). In our annual report on Form 10-K for the year ended December 31, 2018, we reported that we had an outstanding Notice of Violation (NOV) from the U.S. EPA related to violations from a 2015 Mobile Source Inspection. In the fourth quarter of 2019, we received a draft Consent Order from the U.S. EPA proposing penalties of $3.4 million. We are working with the U.S. EPA to resolve this matter.

Attorney General of the State of Texas (Texas AG) (Corpus Christi Asphalt Plant). In our quarterly report on Form 10-Q for the quarter ended March 31, 2019, we reported that we had received a letter and draft Agreed Final Judgment from the Texas AG related to a contaminated water backflow incident that occurred at the Valero Corpus Christi Asphalt Plant. The draft Agreed Final Judgment assesses proposed penalties in the amount of $1.3 million. We are working with the Texas AG to resolve this matter.

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Texas AG (Port Arthur Refinery). In our quarterly report on Form 10-Q for the quarter ended June 30, 2019, we reported that the Texas AG had filed suit against our Port Arthur Refinery in the 419th Judicial District Court of Travis County, Texas, Cause No. D-1-GN-19-004121, for alleged violations of the Clean Air Act seeking injunctive relief and penalties. We are working with the Texas AG to resolve this matter.

Texas AG (Houston Terminal). In our annual report on Form 10-K for the year ended December 31, 2018, we reported that we had an outstanding Notice of Enforcement (NOE) from the Texas Commission on Environmental Quality (TCEQ), and an outstanding Violation Notice (VN) from the Harris County Pollution Control Services Department, both alleging excess emissions from Tank 003 that occurred during Hurricane Harvey. On January 27, 2020, the Texas AG filed suit related to this incident against our Houston Terminal in the 419th Judicial District Court of Travis County, Texas, Cause No. D-1-GN-20-000516 seeking injunctive relief and penalties. We are working with the Texas AG to resolve this matter.

Bay Area Air Quality Management District (BAAQMD) and Solano County Department of Resource Management Certified Unified Program Agency (Solano County) (Benicia Refinery). In our quarterly report on Form 10-Q for the quarter ended March 31, 2019, we reported that we had received multiple VNs issued by the BAAQMD related to an upset of the Flue Gas Scrubber (FGS) at our Benicia Refinery, and a draft Consent from Solano County related to the FGS incident proposing penalties of $242,840. In our quarterly report on Form 10-Q for the quarter ended September 30, 2019, we reported that we had resolved the matter with Solano County. We continue to work with the BAAQMD on a final resolution of the remaining VNs.

BAAQMD (Benicia Refinery). In our annual report on Form 10-K for the year ended December 31, 2018, we reported that we had multiple outstanding VNs issued by the BAAQMD. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. We continue to work with the BAAQMD to resolve these VNs.

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our annual report on Form 10-K for the year ended December 31, 2018, we reported that we had outstanding Notices of Violation (NOVs) issued by the SCAQMD. These NOVs are for alleged reporting violations and excess emissions at our Wilmington Refinery. We are working with the SCAQMD to resolve these NOVs.

TCEQ (Port Arthur). In our annual report on Form 10-K for the year ended December 31, 2018, we reported that we had an outstanding NOE from the TCEQ alleging unauthorized emissions associated with a November 18, 2017 release of crude oil from the 24-inch fill pipe of Tank T-285. We are working with the TCEQ to resolve this matter.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock trades on the NYSE under the trading symbol “VLO.”

As of January 31, 2020, there were 5,082 holders of record of our common stock.

Dividends are considered quarterly by the board of directors, may be paid only when approved by the board, and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, and other factors and restrictions our board deems relevant. There can be no assurance that we will pay a dividend at the rates we have paid historically, or at all, in the future.

The following table discloses purchases of shares of our common stock made by us or on our behalf during the fourth quarter of 2019.

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 2019	332,704	$	88.06	98,396	234,308	$1.6 billion
November 2019	1,565,500	$	99.21	107,914	1,457,586	$1.5 billion
December 2019	393,694	$	94.61	6,984	386,710	$1.5 billion
Total	2,291,898	$	96.80	213,294	2,078,604	$1.5 billion

____________________________________

(a) The shares reported in this column represent purchases settled in the fourth quarter of 2019 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. As of December 31, 2019, we had $1.5 billion remaining available for purchase under the 2018 Program.

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The following performance graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of Valero’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.

This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return^(a) on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the five-year period commencing December 31, 2014 and ending December 31, 2019. Our peer group comprises the following eight companies: BP plc; CVR Energy, Inc.; Delek US Holdings, Inc.; HollyFrontier Corporation; Marathon Petroleum Corporation; PBF Energy Inc.; Phillips 66; and Royal Dutch Shell plc.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN^(a) 

Among Valero Energy Corporation, the S&P 500 Index,

and Peer Group

	As of December 31,
	2014		2015		2016		2017		2018		2019
Valero Common Stock	$	100.00	$	146.79	$	147.94	$	207.10	$	174.54	$	227.53
S&P 500	100.00		101.38		113.51		138.29		132.23		173.86
Peer Group	100.00		88.46		106.16		134.53		125.35		137.49

____________________________________

(a) Assumes that an investment in Valero common stock and each index was $100 on December 31, 2014. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2014 through December 31, 2019.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2019 was derived from our audited financial statements. The following table should be read together with Item 7, “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” and with the historical financial statements and accompanying notes included in Item 8, “FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.”

The following summaries are in millions of dollars, except for per share amounts:

	Year Ended December 31,
	2019		2018		2017 (a)		2016 (b)		2015 (c)
Revenues	$	108,324	$	117,033	$	93,980	$	75,659	$	87,804
Net income	2,784		3,353		4,156		2,417		4,101
Earnings per common share – assuming dilution	5.84		7.29		9.16		4.94		7.99
Dividends per common share	3.60		3.20		2.80		2.40		1.70
Total assets	53,864		50,155		50,158		46,173		44,227
Debt and finance lease obligations, less current portion	9,178		8,871		8,750		7,886		7,208

_________________________________________________

(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.

(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.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Item 1A, “RISK FACTORS,” and Item 8, “FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA,” included in this report.

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report, including without limitation our disclosures below under the heading “OVERVIEW AND OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “scheduled,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “would,” “should,” “will,” “may,” and similar expressions.

These forward-looking statements include, among other things, statements regarding:

• future refining segment margins, including gasoline and distillate margins;

• future ethanol segment margins;

• future renewable diesel 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 turnaround and catalyst cost expenditures, 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 renewable diesel industry fundamentals.

We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:

• 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, and petrochemicals), ethanol, and renewable diesel;

• demand for, and supplies of, crude oil and other feedstocks;

23

• 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, refined petroleum products, ethanol, and renewable diesel;

• 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 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.

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

24

NON-GAAP FINANCIAL MEASURES

The discussions in “OVERVIEW AND OUTLOOK” and “RESULTS OF OPERATIONS” below include references to financial measures that are not defined under U.S. generally accepted accounting principles (GAAP). These non-GAAP financial measures include adjusted operating income (including adjusted operating income for each of our reportable segments) and refining, ethanol, and renewable diesel segment margin. We have included these non-GAAP financial measures to help facilitate the comparison of operating results between years. See the tables in note (f) beginning on page 39 for reconciliations of these non-GAAP financial measures to their most directly comparable U.S. GAAP financial measures. Also in note (f), we disclose the reasons why we believe our use of the non-GAAP financial measures provides useful information.

OVERVIEW AND OUTLOOK

Overview

For 2019, we reported net income attributable to Valero stockholders of $2.4 billion compared to $3.1 billion for 2018, which represents a decrease of $700 million. This decrease is the result of a $569 million decrease in net income and a $131 million increase in net income attributable to noncontrolling interests. The increase in net income attributable to noncontrolling interests is primarily due to a $279 million pre-tax increase in blender’s tax credits recognized in 2019 compared to 2018, of which 50 percent is attributable to the holder of the noncontrolling interest, as described in note (a) on page 38. The decrease in net income is primarily due to a decrease of $736 million in operating income between the periods, net of the resulting $177 million decrease in income tax expense.

While operating income decreased by $736 million in 2019 compared to 2018, adjusted operating income decreased by $1.0 billion. Adjusted operating income excludes adjustments reflected in the table in note (f) on page 42.

The $1.0 billion decrease in adjusted operating income is primarily due to the following:

• Refining segment. Refining segment adjusted operating income decreased by $1.1 billion primarily due to weaker discounts on crude oils and other feedstocks and lower throughput volumes, partially offset by improved distillate margins. This is more fully described on pages 31 and 32.

• Ethanol segment. Ethanol segment adjusted operating income decreased by $78 million primarily due to higher corn prices and higher operating expenses (excluding depreciation and amortization expense), partially offset by higher ethanol prices. This is more fully described on page 33.

• Renewable diesel segment. Renewable diesel segment adjusted operating income increased by $259 million primarily due to an increase in renewable diesel sales volumes and an increase in the benefit from the blender’s tax credit resulting from an increase in the volume of renewable diesel blended with petroleum-based diesel in 2019 compared to 2018. This is more fully described on pages 34 and 35.

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Outlook

Below are several factors that have impacted or may impact our results of operations during the first quarter of 2020:

• Distillate margins are expected to begin improving due to an anticipated increase in global demand as trade war tensions ease and markets comply with the International Maritime Organization’s lower bunker fuel sulfur specifications, which were effective January 1, 2020. Gasoline margins are expected to remain near current levels.

• Discounts for medium and heavy sour crude oils are expected to remain near current levels as compliance with the new bunker fuel sulfur specifications noted above is expected to reduce demand for high sulfur fuel oils, which compete with sour crude oils as a refining feedstock.

• Ethanol margins are expected to decline as domestic inventory levels rise.

• Renewable diesel segment margins are expected to remain near current levels.

• Our refining operations in the U.K. could be adversely affected by Brexit, which formally occurred on January 31, 2020. Although the legal relationship between the U.K. and the EU has changed, their ongoing relationship will continue to follow the EU’s rules during a transition period that is set to expire on December 31, 2020. During the transition period, the U.K. and the EU are expected to negotiate a new free trade agreement, which could negatively impact the operations of our Pembroke Refinery and our marketing operations in the U.K. and Ireland, as could the failure to reach any agreement. The ultimate effect of Brexit will depend on whether an agreement is reached, or on the specific terms of any agreement that is reached by the U.K. and the EU. See Item 1A “RISK FACTORS”—Changes in the U.K.’s economic and other relationships with the EU could adversely affect us.

• Global concern about the coronavirus outbreak could result in lower demand for and consumption of transportation fuels, which would have a negative impact on our results of operations.

RESULTS OF OPERATIONS

The following tables, including the reconciliations of non-GAAP financial measures to their most directly comparable U.S. GAAP financial measures in note (f) beginning on page 39, highlight our results of operations, our operating performance, and market reference prices that directly impact our operations.

Effective January 1, 2019, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, we created a new reportable segment — renewable diesel — because of the growing importance of renewable fuels in the market and the growth of our investments in renewable fuels production. The renewable diesel segment includes the operations of DGD, which were transferred from the refining segment on January 1, 2019. Also effective January 1, 2019, we no longer have a VLP segment, and we include the operations of VLP in our refining segment. This change was made because of the Merger Transaction with VLP, as described in Note 2 of Notes to Consolidated Financial Statements, and the resulting change in how we manage VLP’s operations. We no longer manage VLP as a business but as logistics assets that support the operations of our refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation.

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2019 Compared to 2018

Financial Highlights by Segment and Total Company

(millions of dollars)

	Year Ended December 31, 2019
	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Revenues:
Revenues from external customers	$	103,746	$	3,606	$	970	$	2		$	108,324
Intersegment revenues	18		231		247		(496		)	—
Total revenues	103,764		3,837		1,217		(494		)	108,324
Cost of sales:
Cost of materials and other (a)	93,371		3,239		360		(494		)	96,476
Operating expenses (excluding depreciation and amortization expense reflected below)	4,289		504		75		—			4,868
Depreciation and amortization expense	2,062		90		50		—			2,202
Total cost of sales	99,722		3,833		485		(494		)	103,546
Other operating expenses (b)	20		1		—		—			21
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		868			868
Depreciation and amortization expense	—		—		—		53			53
Operating income by segment	$	4,022	$	3	$	732	$	(921	)	3,836
Other income, net (d)										104
Interest and debt expense, net of capitalized interest										(454		)
Income before income tax expense										3,486
Income tax expense										702
Net income										2,784
Less: Net income attributable to noncontrolling interests (a)										362
Net income attributable to Valero Energy Corporation stockholders										$	2,422

________________

See note references on pages 38 through 42.

27

Financial Highlights by Segment and Total Company (continued)

(millions of dollars)

	Year Ended December 31, 2018
	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Revenues:
Revenues from external customers	$	113,093	$	3,428	$	508	$	4		$	117,033
Intersegment revenues	25		210		170		(405		)	—
Total revenues	113,118		3,638		678		(401		)	117,033
Cost of sales:
Cost of materials and other (a)	101,866		3,008		262		(404		)	104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154		470		66		—			4,690
Depreciation and amortization expense	1,910		78		29		—			2,017
Total cost of sales	107,930		3,556		357		(404		)	111,439
Other operating expenses (b)	45		—		—		—			45
General and administrative expenses (excluding depreciation and amortization expense reflected below) (c)	—		—		—		925			925
Depreciation and amortization expense	—		—		—		52			52
Operating income by segment	$	5,143	$	82	$	321	$	(974	)	4,572
Other income, net (d)										130
Interest and debt expense, net of capitalized interest										(470		)
Income before income tax expense										4,232
Income tax expense (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

________________

See note references on pages 38 through 42.

28

Average Market Reference Prices and Differentials

	Year Ended December 31,
	2019			2018			Change
Refining
Feedstocks (dollars per barrel)
Brent crude oil	$	64.18		$	71.62		$	(7.44	)
Brent less West Texas Intermediate (WTI) crude oil	7.15			6.71			0.44
Brent less Alaska North Slope (ANS) crude oil	(0.86		)	0.31			(1.17		)
Brent less LLS crude oil	1.47			1.72			(0.25		)
Brent less Argus Sour Crude Index (ASCI) crude oil	3.56			5.20			(1.64		)
Brent less Maya crude oil	6.57			9.22			(2.65		)
LLS crude oil	62.71			69.90			(7.19		)
LLS less ASCI crude oil	2.09			3.48			(1.39		)
LLS less Maya crude oil	5.10			7.50			(2.40		)
WTI crude oil	57.03			64.91			(7.88		)
Natural gas (dollars per million British Thermal Units (MMBtu))	2.47			3.23			(0.76		)
Products (dollars per barrel)
U.S. Gulf Coast:
Conventional Blendstock of Oxygenate Blending (CBOB) gasoline less Brent	4.37			4.81			(0.44		)
Ultra-low-sulfur (ULS) diesel less Brent	14.90			14.02			0.88
Propylene less Brent	(22.31		)	(2.86		)	(19.45		)
CBOB gasoline less LLS	5.84			6.53			(0.69		)
ULS diesel less LLS	16.37			15.74			0.63
Propylene less LLS	(20.84		)	(1.14		)	(19.70		)
U.S. Mid-Continent:
CBOB gasoline less WTI	13.62			13.70			(0.08		)
ULS diesel less WTI	22.77			22.82			(0.05		)
North Atlantic:
CBOB gasoline less Brent	7.20			7.59			(0.39		)
ULS diesel less Brent	17.22			16.29			0.93
U.S. West Coast:
CARBOB 87 gasoline less ANS	16.28			13.05			3.23
CARB diesel less ANS	19.30			18.13			1.17
CARBOB 87 gasoline less WTI	24.29			19.45			4.84
CARB diesel less WTI	27.31			24.53			2.78

29

Average Market Reference Prices and Differentials, (continued)

	Year Ended December 31,
	2019		2018		Change
Ethanol
Chicago Board of Trade (CBOT) corn (dollars per bushel)	$	3.84	$	3.68	$	0.16
New York Harbor (NYH) ethanol (dollars per gallon)	1.53		1.48		0.05
Renewable diesel
New York Mercantile Exchange ULS diesel (dollars per gallon)	1.94		2.09		(0.15		)
Biodiesel RIN (dollars per RIN)	0.48		0.53		(0.05		)
California Low-Carbon Fuel Standard (dollars per metric ton)	196.82		168.24		28.58
CBOT soybean oil (dollars per pound)	0.29		0.30		(0.01		)

Total Company, Corporate, and Other

The following table includes selected financial data for the total company, corporate, and other for 2019 and 2018. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 27 and 28, unless otherwise noted.

	Year Ended December 31,
	2019		2018		Change
Revenues	$	108,324	$	117,033	$	(8,709	)
Cost of sales	103,546		111,439		(7,893		)
General and administrative expenses (excluding depreciation and amortization expense)	868		925		(57		)
Operating income	3,836		4,572		(736		)
Adjusted operating income (see note (f) on page 42)	3,699		4,713		(1,014		)
Other income, net	104		130		(26		)
Income tax expense	702		879		(177		)
Net income attributable to noncontrolling interests	362		231		131

Revenues decreased by $8.7 billion in 2019 compared to 2018 primarily due to decreases in refined petroleum product prices associated with sales made by our refining segment. This decline in revenues was partially offset by lower cost of sales of $7.9 billion primarily due to decreases in crude oil and other feedstock costs and a decrease of $57 million in general and administrative expenses (excluding depreciation and amortization expense), resulting in a decrease in operating income of $736 million in 2019 compared to 2018.

General and administrative expenses (excluding depreciation and amortization expense) decreased by $57 million in 2019 compared to 2018. This decrease was primarily due to environmental reserve adjustments of $108 million associated with certain non-operating sites in 2018, partially offset by increases in legal and other environmental reserves of $24 million and $12 million, respectively, as well as higher taxes other than income taxes of $8 million and expenses associated with the Merger Transaction with VLP of $7 million.

30

Adjusted operating income was $3.7 billion in 2019 compared to $4.7 billion in 2018. Details regarding the $1.0 billion decrease in adjusted operating income between the years are discussed by segment below.

“Other income, net” decreased by $26 million in 2019 compared to 2018. This decrease was primarily due to lower interest income of $30 million and higher foreign currency transaction losses of $14 million, partially offset by the favorable effect of a $16 million lower charge for the early redemption of debt between the periods. As described in note (d) on page 39, we redeemed debt in both 2019 and 2018 and incurred early redemption charges of $22 million and $38 million, respectively.

Income tax expense decreased by $177 million in 2019 compared to 2018 primarily as a result of lower income before income tax expense. Our effective tax rate was 20 percent for 2019 compared to 21 percent for 2018.

Net income attributable to noncontrolling interests increased by $131 million in 2019 compared to 2018 primarily due to a $279 million increase in blender’s tax credits recognized in 2019 compared to 2018, of which 50 percent is attributable to the holder of the noncontrolling interest, as described in note (a) on page 38.

Refining Segment Results

The following table includes selected financial and operating data of our refining segment for 2019 and 2018. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 27 and 28, respectively, unless otherwise noted.

	Year Ended December 31,
	2019		2018		Change
Revenues	$	103,764	$	113,118	$	(9,354	)
Cost of sales	99,722		107,930		(8,208		)
Operating income	4,022		5,143		(1,121		)
Adjusted operating income (see note (f) on page 41)	4,040		5,180		(1,140		)
Margin (see note (f) on page 40)	10,391		11,244		(853		)
Operating expenses (excluding depreciation and amortization expense reflected below)	4,289		4,154		135
Depreciation and amortization expense	2,062		1,910		152
Throughput volumes (thousand BPD) (see note (g) on page 42)	2,952		2,986		(34		)

Refining segment revenues decreased by $9.3 billion in 2019 compared to 2018 primarily due to decreases in refined petroleum product prices. This decline in refining segment revenues was partially offset by lower cost of sales of $8.2 billion primarily due to decreases in crude oil and other feedstock costs, resulting in a decrease in refining segment operating income of $1.1 billion in 2019 compared to 2018.

31

Refining segment adjusted operating income also decreased by $1.1 billion in 2019 compared to 2018. The components of this decrease, along with the reasons for the changes in these components, are outlined below.

• Refining segment margin is primarily affected by refined petroleum product prices and the cost of crude oil and other feedstocks. The market prices for refined petroleum products generally track the price of benchmark crude oils, such as Brent, WTI, and ANS. An increase in the differential between the market price of the refined petroleum products that we sell and the cost of the reference benchmark crude oil has a favorable impact on our refining segment margin, while a decline in this differential has a negative impact on our refining segment margin. Additionally, our refining segment margin is affected by our ability to purchase and process crude oils and other feedstocks that are priced at a discount to Brent and other benchmark crude oils. While we benefit when we process these types of crude oils and other feedstocks, that benefit will vary as the discount widens or narrows. Improvement in these discounts has a favorable impact on our refining segment margin as it lowers our cost of materials; whereas lower discounts result in higher cost of materials, which has a negative impact on our refining segment margin. The table on page 29 reflects market reference prices and differentials that we believe had a material impact on the change in our refining segment margin in 2019 compared to 2018. Refining segment margin decreased by $853 million in 2019 compared to 2018 primarily due to the following:

◦ Lower discounts on crude oils had an unfavorable impact to our refining segment margin of approximately $628 million.

◦ Lower discounts on feedstocks other than crude oils, such as natural gas and residuals, had an unfavorable impact to our refining segment margin of approximately $360 million.

◦ A decrease in throughput volumes of 34,000 BPD had an unfavorable impact to our refining segment margin of approximately $128 million.

◦ A decrease in the cost of biofuel credits (primarily RINs in the U.S.) had a favorable impact on our refining segment margin of $218 million. See Note 20 of Notes to Consolidated Financial Statements for additional information on our government and regulatory compliance programs.

◦ An increase in distillate margins throughout most of our regions had a favorable impact to our refining segment margin of approximately $202 million.

• Refining segment operating expenses (excluding depreciation and amortization expense) increased by $135 million primarily due to higher maintenance costs of $86 million, along with the effect of favorable property tax settlements of $20 million and sales and use tax refunds of $17 million received in 2018 that did not recur in 2019.

• Refining segment depreciation and amortization expense associated with our cost of sales increased by $152 million primarily due to higher refinery turnaround and catalyst amortization expense of $82 million and an increase in depreciation expense of $79 million associated with capital projects that were completed and finance leases that commenced in the latter part of 2018 and early 2019, partially offset by the write-off of assets that were idled or demolished in 2018 of $15 million.

32

Ethanol Segment Results

The following table includes selected financial and operating data of our ethanol segment for 2019 and 2018. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 27 and 28, respectively, unless otherwise noted.

	Year Ended December 31,
	2019		2018		Change
Revenues	$	3,837	$	3,638	$	199
Cost of sales	3,833		3,556		277
Operating income	3		82		(79		)
Adjusted operating income (see note (f) on page 41)	4		82		(78		)
Margin (see note (f) on page 40)	598		630		(32		)
Operating expenses (excluding depreciation and amortization expense reflected below)	504		470		34
Depreciation and amortization expense	90		78		12
Production volumes (thousand gallons per day) (see note (g) on page 42)	4,269		4,109		160

Ethanol segment revenues increased by $199 million in 2019 compared to 2018 primarily due to an increase in ethanol prices. This improvement in ethanol segment revenue was outweighed by higher cost of sales of $277 million, resulting in a decrease in ethanol segment operating income of $79 million in 2019 compared to 2018.

Ethanol segment adjusted operating income decreased by $78 million. The components of this decrease, along with the reasons for the changes in these components, are outlined below.

• Ethanol segment margin is primarily affected by ethanol and corn related co-product prices and the cost of corn. The table on page 30 reflects market reference prices that we believe had a material impact on the change in our ethanol segment margin in 2019 compared to 2018. Ethanol segment margin decreased by $32 million in 2019 compared to 2018 primarily due to the following:

◦ Higher corn prices had an unfavorable impact to our ethanol segment margin of approximately $166 million.

◦ Higher ethanol prices had a favorable impact to our ethanol segment margin of approximately $123 million.

• Ethanol segment operating expenses (excluding depreciation and amortization expense) increased by $34 million primarily due to costs to operate the three plants acquired from Green Plains, Inc. (Green Plains) in November 2018 of $79 million, partially offset by lower energy costs of $29 million and lower chemicals and catalyst costs of $12 million incurred by our other ethanol plants.

• Ethanol segment depreciation and amortization expense associated with our cost of sales increased by $12 million primarily due to depreciation expense associated with the three plants acquired from Green Plains in November 2018.

33

Renewable Diesel Segment Results

The following table includes selected financial and operating data of our renewable diesel segment for 2019 and 2018. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 27 and 28, respectively, unless otherwise noted.

	Year Ended December 31,
	2019		2018		Change
Revenues	$	1,217	$	678	$	539
Cost of sales	485		357		128
Operating income	732		321		411
Adjusted operating income (see note (f) on page 42)	576		317		259
Margin (see note (f) on page 41)	701		412		289
Operating expenses (excluding depreciation and amortization expense reflected below)	75		66		9
Depreciation and amortization expense	50		29		21
Sales volumes (thousand gallons per day) (see note (g) on page 42)	760		431		329

Renewable diesel segment revenues increased by $539 million in 2019 compared to 2018 primarily due to an increase in renewable diesel sales volumes. This improvement in renewable diesel segment revenues was partially offset by higher cost of sales of $128 million, resulting in an increase in renewable diesel segment operating income of $411 million.

Renewable diesel segment adjusted operating income increased by $259 million in 2019 compared to 2018. The components of this increase, along with the reasons for the changes in these components, are outlined below.

• Renewable diesel segment margin increased by $289 million in 2019 compared to 2018 primarily due to the following:

◦ An increase in sales volumes of 329,000 gallons per day, which is primarily due to the additional production capacity resulting from the expansion of the DGD Plant completed in the third quarter of 2018, had a favorable impact to our renewable diesel segment margin of $162 million.

◦ An increase in the benefit for the blender’s tax credit attributable to volumes blended during 2019 compared to 2018 had a favorable impact to our renewable diesel segment margin of $119 million. As more fully described in note (a) on page 38, blender’s tax credits of $275 million and $156 million were attributable to volumes blended during 2019 and 2018, respectively.

• Renewable diesel segment operating expenses (excluding depreciation and amortization expense) increased by $9 million, which is primarily attributable to increased costs resulting from the expansion of the DGD Plant completed in the third quarter of 2018.

34

• Renewable diesel segment depreciation and amortization expense associated with our cost of sales increased by $21 million primarily due to higher turnaround and catalyst amortization expense of $13 million and depreciation expense associated with the expansion of the DGD Plant completed in the third quarter of 2018 of $5 million.

2018 Compared to 2017

Financial Highlights by Segment and Total Company

(millions of dollars)

	Year Ended December 31, 2018
	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Revenues:
Revenues from external customers	$	113,093	$	3,428	$	508	$	4		$	117,033
Intersegment revenues	25		210		170		(405		)	—
Total revenues	113,118		3,638		678		(401		)	117,033
Cost of sales:
Cost of materials and other (a)	101,866		3,008		262		(404		)	104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154		470		66		—			4,690
Depreciation and amortization expense	1,910		78		29		—			2,017
Total cost of sales	107,930		3,556		357		(404		)	111,439
Other operating expenses (b)	45		—		—		—			45
General and administrative expenses (excluding depreciation and amortization expense reflected below) (c)	—		—		—		925			925
Depreciation and amortization expense	—		—		—		52			52
Operating income by segment	$	5,143	$	82	$	321	$	(974	)	4,572
Other income, net (d)										130
Interest and debt expense, net of capitalized interest										(470		)
Income before income tax expense										4,232
Income tax expense (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

________________

See note references on pages 38 through 42.

35

Financial Highlights by Segment and Total Company (continued)

(millions of dollars)

	Year Ended December 31, 2017
	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Revenues:
Revenues from external customers	$	90,258	$	3,324	$	393	$	5		$	93,980
Intersegment revenues	8		176		241		(425		)	—
Total revenues	90,266		3,500		634		(420		)	93,980
Cost of sales:
Cost of materials and other	80,160		2,804		498		(425		)	83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	4,014		443		47		—			4,504
Depreciation and amortization expense	1,824		81		29		—			1,934
Total cost of sales	85,998		3,328		574		(425		)	89,475
Other operating expenses (b)	61		—		—		—			61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		829			829
Depreciation and amortization expense	—		—		—		52			52
Operating income by segment	$	4,207	$	172	$	60	$	(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 (e)										(949		)
Net income										4,156
Less: Net income attributable to noncontrolling interests										91
Net income attributable to Valero Energy Corporation stockholders										$	4,065

________________

See note references on pages 38 through 42.

36

Average Market Reference Prices and Differentials

	Year Ended December 31,
	2018			2017		Change
Refining
Feedstocks (dollars per barrel)
Brent crude oil	$	71.62		$	54.82	$	16.80
Brent less WTI crude oil	6.71			3.92		2.79
Brent less ANS crude oil	0.31			0.26		0.05
Brent less LLS crude oil	1.72			0.69		1.03
Brent less 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 MMBtu)	3.23			2.98		0.25
Products (dollars per barrel)
U.S. Gulf Coast:
CBOB gasoline less Brent	4.81			10.50		(5.69		)
ULS 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		)
ULS 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		)
ULS diesel less WTI	22.82			18.50		4.32
North Atlantic:
CBOB gasoline less Brent	7.59			12.57		(4.98		)
ULS 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

37

Average Market Reference Prices and Differentials, (continued)

	Year Ended December 31,
	2018		2017		Change
Ethanol
CBOT corn (dollars per bushel)	$	3.68	$	3.59	$	0.09
NYH ethanol (dollars per gallon)	1.48		1.56		(0.08		)
Renewable diesel
New York Mercantile Exchange ULS diesel (dollars per gallon)	2.09		1.66		0.43
Biodiesel RIN (dollars per RIN)	0.53		1.01		(0.48		)
California Low-Carbon Fuel Standard (dollars per metric ton)	168.24		89.26		78.98
CBOT soybean oil (dollars per pound)	0.30		0.33		(0.03		)

________________

The following notes relate to references on pages 25 through 36 and pages 43 through 46.

(a) Cost of materials and other for the years ended December 31, 2019 and 2018 includes a benefit of $449 million and $170 million, respectively, for the blender’s tax credit. The benefit recognized in 2019 is attributable to volumes blended during 2019 and 2018 and was recognized in December 2019 because the U.S legislation authorizing the credit was passed and signed into law in that month. The benefit recognized in 2018 is attributable to volumes blended during 2017 and was recognized in February 2018 because the U.S. legislation authorizing the credit was passed and signed into law in that month.

The $449 million and $170 million pre-tax benefits are attributable to volumes blended during the three years and are reflected in our reportable segments as follows (in millions):

	Refining		Renewable Diesel		Total
Periods to which blender’s tax credit is attributable
2019 blender’s tax credit	$	16	$	275	$	291
2018 blender���s tax credit	2		156		158
Total recognized in 2019	$	18	$	431	$	449
2017 blender’s tax credit	$	10	$	160	$	170
Total recognized in 2018	$	10	$	160	$	170

38

Adjustments to reflect the blender’s tax credits in the period during which the volumes were blended are as follows (in millions):

	Year Ended December 31,
	2019		2018		2017
Refining segment
Total blender’s tax credit recognized in period presented	$	18	$	10	$	—
Less: Amount properly reflected in the period associated with volumes blended	16		2		10
Adjustment to reflect blender’s tax credit in proper period for the refining segment (see note (f))	2		8		(10		)
Renewable diesel segment
Total blender’s tax credit recognized in period presented	431		160		—
Less: Amount properly reflected in the period associated with volumes blended	275		156		160
Adjustment to reflect blender’s tax credit in proper period for the renewable diesel segment (see note (f))	156		4		(160		)
Total adjustment to reflect blender’s tax credit in proper period (see note (f))	$	158	$	12	$	(170	)

Of the $449 million pre-tax benefit recognized in 2019, $215 million is attributable to noncontrolling interest and $234 million is attributable to Valero stockholders. Of the $170 million pre-tax benefit recognized in 2018, $80 million is attributable to noncontrolling interest and $90 million is attributable to Valero stockholders.

(b) Other operating expenses reflects expenses that are not associated with our cost of sales and primarily includes costs to repair, remediate, and restore our facilities to normal operations following a non-operating event, such as a natural disaster or a major unplanned outage.

(c) General and administrative expenses (excluding depreciation and amortization expense) for the year ended December 31, 2018 includes a charge of $108 million for environmental reserve adjustments associated with certain non-operating sites.

(d) “Other income, net” for the years ended December 31, 2019 and 2018 includes a $22 million charge from the early redemption of $850 million of our 6.125 percent senior notes due February 1, 2020 and a $38 million charge from the early redemption of $750 million of our 9.375 percent senior notes due March 15, 2019, respectively.

(e) On December 22, 2017, Tax Reform was enacted, and we recognized an income tax benefit of $1.9 billion in December 2017 that represented our initial estimate of the impact of Tax Reform. We finalized our estimates during the year ended December 31, 2018 and recorded an income tax benefit of $12 million during the period.

(f) We use certain financial measures (as noted below) that are not defined under U.S. GAAP and are considered to be non-GAAP financial measures.

We have defined these non-GAAP measures and believe they are useful to the external users of our financial statements, including industry analysts, investors, lenders, and rating agencies. We believe these measures are useful to assess our ongoing financial performance because, when reconciled to their most comparable U.S. GAAP measures, they provide improved comparability between periods through the exclusion of certain items that we believe are not indicative of our core operating performance and that may obscure our underlying business results and trends. These non-GAAP measures should not be considered as alternatives to their most comparable U.S. GAAP measures nor should they be considered in isolation or as a substitute for an analysis of our results of operations as reported under U.S. GAAP. In addition, these non-GAAP measures may not be comparable to similarly titled measures used by other companies because we may define them differently, which diminishes their utility.

39

Non-GAAP financial measures are as follows:

◦ Refining margin is defined as refining operating income adjusted to reflect the blender’s tax credit in the proper period, and excluding operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense, and other operating expenses, as reflected in the table below.

	Year Ended December 31,
	2019			2018			2017
Reconciliation of refining operating income to refining margin
Refining operating income	$	4,022		$	5,143		$	4,207
Exclude:
Blender’s tax credit (see note (a))	2			8			(10		)
Operating expenses (excluding depreciation and amortization expense)	(4,289		)	(4,154		)	(4,014		)
Depreciation and amortization expense	(2,062		)	(1,910		)	(1,824		)
Other operating expenses (see note (b))	(20		)	(45		)	(61		)
Refining margin	$	10,391		$	11,244		$	10,116

◦ Ethanol margin is defined as ethanol operating income excluding operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense, and other operating expenses, as reflected in the table below.

	Year Ended December 31,
	2019			2018			2017
Reconciliation of ethanol operating income to ethanol margin
Ethanol operating income	$	3		$	82		$	172
Exclude:
Operating expenses (excluding depreciation and amortization expense)	(504		)	(470		)	(443		)
Depreciation and amortization expense	(90		)	(78		)	(81		)
Other operating expenses (see note (b))	(1		)	—			—
Ethanol margin	$	598		$	630		$	696

40

◦ Renewable diesel margin is defined as renewable diesel operating income adjusted to reflect the blender’s tax credit in the proper period, and excluding operating expenses (excluding depreciation and amortization expense) and depreciation and amortization expense, as reflected in the table below.

	Year Ended December 31,
	2019			2018			2017
Reconciliation of renewable diesel operating income to renewable diesel margin
Renewable diesel operating income	$	732		$	321		$	60
Exclude:
Blender’s tax credit (see note (a))	156			4			(160		)
Operating expenses (excluding depreciation and amortization expense)	(75		)	(66		)	(47		)
Depreciation and amortization expense	(50		)	(29		)	(29		)
Renewable diesel margin	$	701		$	412		$	296

◦ Adjusted refining operating income is defined as refining segment operating income adjusted to reflect the blender’s tax credit in the proper period and excluding other operating expenses, as reflected in the table below.

	Year Ended December 31,
	2019			2018			2017
Reconciliation of refining operating income to adjusted refining operating income
Refining operating income	$	4,022		$	5,143		$	4,207
Exclude:
Blender’s tax credit (see note (a))	2			8			(10		)
Other operating expenses (see note (b))	(20		)	(45		)	(61		)
Adjusted refining operating income	$	4,040		$	5,180		$	4,278

◦ Adjusted ethanol operating income is defined as ethanol segment operating income excluding other operating expenses as reflected in the table below.

	Year Ended December 31,
	2019			2018		2017
Reconciliation of ethanol operating income to adjusted ethanol operating income
Ethanol operating income	$	3		$	82	$	172
Exclude:
Other operating expenses (see note (b))	(1		)	—		—
Adjusted ethanol operating income	$	4		$	82	$	172

41

◦ Adjusted renewable diesel operating income is defined as renewable diesel segment operating income adjusted to reflect the blender’s tax credit in the proper period, as reflected in the table below.

	Year Ended December 31,
	2019		2018		2017
Reconciliation of renewable diesel operating income to adjusted renewable diesel operating income
Renewable diesel operating income	$	732	$	321	$	60
Exclude:
Blender’s tax credit (see note (a))	156		4		(160		)
Adjusted renewable diesel operating income	$	576	$	317	$	220

◦ Adjusted operating income is defined as total company operating income adjusted to reflect the blender’s tax credit in the proper period, and excluding other operating expenses and environmental reserve adjustments associated with certain non-operating sites, as reflected in the table below.

	Year Ended December 31,
	2019			2018			2017
Reconciliation of total company operating income to adjusted operating income
Total company operating income	$	3,836		$	4,572		$	3,563
Exclude:
Blender’s tax credit (see note (a))	158			12			(170		)
Other operating expenses (see note (b))	(21		)	(45		)	(61		)
Environmental reserve adjustments (see note (c))	—			(108		)	—
Adjusted operating income	$	3,699		$	4,713		$	3,794

(g) We use throughput volumes, production volumes, and sales volumes for the refining segment, ethanol segment, and renewable diesel segment, respectively, due to their general use by others who operate facilities similar to those included in our segments.

42

Total Company, Corporate, and Other

The following table includes selected financial data for the total company, corporate, and other for 2018 and 2017. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 35 and 36, unless otherwise noted.

	Year Ended December 31,
	2018		2017			Change
Revenues	$	117,033	$	93,980		$	23,053
Cost of sales	111,439		89,475			21,964
General and administrative expenses (excluding depreciation and amortization expense)	925		829			96
Operating income	4,572		3,563			1,009
Adjusted operating income (see note (f) on page 42)	4,713		3,794			919
Other income, net	130		112			18
Income tax expense (benefit)	879		(949		)	1,828
Net income attributable to noncontrolling interests	231		91			140

Revenues increased by $23.1 billion in 2018 compared to 2017 primarily due to increases in refined petroleum product prices associated with sales made by our refining segment. This improvement in revenues was partially offset by higher cost of sales of $22.0 billion primarily due to increases in crude oil and other feedstock costs, and an increase of $96 million in general and administrative expenses (excluding depreciation and amortization expense), resulting in an increase in operating income of $1.0 billion in 2018 compared to 2017.

General and administrative expenses (excluding depreciation and amortization expense) increased by $96 million in 2018 compared to 2017. This increase was primarily due to environmental reserve adjustments of $108 million associated with certain non-operating sites in 2018, partially offset by expenses incurred in 2017 associated with the termination of the acquisition of certain assets from Plains All American Pipeline, L.P. of $16 million.

Adjusted operating income was $4.7 billion in 2018 compared to $3.8 billion in 2017. Details regarding the $919 million increase in adjusted operating income between the years are discussed by segment below.

“Other income, net” increased by $18 million in 2018 compared to 2017. This increase was primarily due to higher equity in earnings associated with our Diamond pipeline joint venture of $39 million and higher interest income of $29 million, partially offset by a $38 million charge for the early redemption of debt as described in note (d) on page 39.

Income tax expense increased by $1.8 billion in 2018 compared to 2017 primarily due to the effect from a $1.9 billion income tax benefit in 2017 resulting from Tax Reform, as described in note (e) on page 39. Excluding the effect of Tax Reform from 2017, the effective tax rate for 2017 was 28 percent compared to 21 percent for 2018. The decrease in our effective tax rate is primarily due to the reduction in the U.S. statutory income tax rate from 35 percent to 21 percent effective January 1, 2018 as a result of Tax Reform.

Net income attributable to noncontrolling interests increased by $140 million in 2018 compared to 2017 primarily due to higher earnings associated with DGD, which includes a benefit for the blender’s tax credit

43

of which $80 million is attributable to the holder of the noncontrolling interest, as described in note (a) on page 38.

Refining Segment Results

The following table includes selected financial and operating data of our refining segment for 2018 and 2017. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 35 and 36, respectively, unless otherwise noted.

	Year Ended December 31,
	2018		2017		Change
Revenues	$	113,118	$	90,266	$	22,852
Cost of sales	107,930		85,998		21,932
Operating income	5,143		4,207		936
Adjusted operating income (see note (f) on page 41)	5,180		4,278		902
Margin (see note (f) on page 40)	11,244		10,116		1,128
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154		4,014		140
Depreciation and amortization expense	1,910		1,824		86
Throughput volumes (thousand BPD) (see note (g) on page 42)	2,986		2,940		46

Refining segment revenues increased by $22.9 billion in 2018 compared to 2017 primarily due to increases in refined petroleum product prices. This improvement in refining segment revenues was partially offset by higher cost of sales of $21.9 billion primarily due to increases in crude oil and other feedstock costs, resulting in an increase in refining segment operating income of $936 million in 2018 compared to 2017.

Refining segment adjusted operating income increased by $902 million in 2018 compared to 2017. The components of this increase, along with the reasons for the changes in these components, are outlined below.

• Refining segment margin is primarily affected by refined petroleum product prices and the cost of crude oil and other feedstocks. The market prices for refined petroleum products generally track the price of benchmark crude oils, such as Brent, WTI, and ANS. An increase in the differential between the market price of the refined petroleum products that we sell and the cost of the reference benchmark crude oil has a favorable impact on our refining segment margin, while a decline in this differential has a negative impact on our refining segment margin. Additionally, our refining segment margin is affected by our ability to purchase and process crude oils and other feedstocks that are priced at a discount to Brent and other benchmark crude oils. While we benefit when we process these types of crude oils and other feedstocks, that benefit will vary as the discount widens or narrows. Improvement in these discounts has a favorable impact on our refining segment margin as it lowers our cost of materials; whereas lower discounts result in higher cost of materials, which has a negative impact on our refining segment margin. The table on page 37 reflects market reference prices and differentials that we believe had a material impact on the change in our refining segment margin in 2018 compared to 2017. Refining segment margin increased by $1.1 billion in 2018 compared to 2017, primarily due to the following:

◦ An increase in distillate margins throughout all of our regions had a favorable impact to our refining segment margin of approximately $1.3 billion.

44

◦ Higher discounts on crude oils had a favorable impact to our refining segment margin of approximately $561 million.

◦ A decrease in the cost of biofuel credits (primarily RINs in the U.S.) had a favorable impact to our refining segment margin of $406 million. See Note 20 of Notes to Consolidated Financial Statements for additional information on our government and regulatory compliance programs.

◦ An increase in throughput volumes of 46,000 BPD had a favorable impact to our refining segment margin of approximately $153 million.

◦ A decrease in gasoline margins throughout all of our regions had an unfavorable impact to our refining segment margin of approximately $1.3 billion.

• Refining segment operating expenses (excluding depreciation and amortization expense) increased by $140 million primarily due to higher employee-related expenses of $33 million, an increase in energy costs of $28 million, the effect of a favorable insurance settlement of $20 million in 2017 for our McKee Refinery, higher maintenance expense of $17 million, and higher chemicals and catalyst costs of $15 million.

• Refining segment depreciation and amortization expense associated with our cost of sales increased by $86 million primarily due to an increase in depreciation expense of $44 million associated with capital projects that were completed in the latter part of 2017 and early 2018 and higher refinery turnaround and catalyst amortization expense of $35 million, along with the write-off of assets that were idled or demolished in 2018 of $15 million.

Ethanol Segment Results

The following table includes selected financial and operating data of our ethanol segment for 2018 and 2017. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 35 and 36, respectively, unless otherwise noted.

	Year Ended December 31,
	2018		2017		Change
Revenues	$	3,638	$	3,500	$	138
Cost of sales	3,556		3,328		228
Operating income	82		172		(90		)
Margin (see note (f) on page 40)	630		696		(66		)
Operating expenses (excluding depreciation and amortization expense reflected below)	470		443		27
Depreciation and amortization expense	78		81		(3		)
Production volumes (thousand gallons per day) (see note (g) on page 42)	4,109		3,972		137

Ethanol segment revenues increased by $138 million in 2018 compared to 2017 primarily due to an increase in ethanol sales volumes. This improvement in ethanol segment revenue was outweighed by higher cost of sales of $228 million, resulting in a decrease in ethanol segment operating income of $90 million in 2018

45

compared to 2017. The components of this decrease, along with the reasons for the changes in these components, are outlined below.

• Ethanol segment margin is primarily affected by ethanol and corn related co-product prices and the cost of corn. The table on page 38 reflects market reference prices that we believe had a material impact on the change in our ethanol segment margin in 2018 compared to 2017. Ethanol segment margin decreased by $66 million in 2018 compared to 2017 primarily due to the following:

◦ Lower ethanol prices had an unfavorable impact to our ethanol segment margin of approximately $159 million.

◦ Higher corn prices had an unfavorable impact to our ethanol segment margin of approximately $36 million.

◦ Higher prices of the corn related co-products that we produced had a favorable impact to our ethanol segment margin of approximately $101 million.

◦ Higher production volumes of 137,000 gallons per day had a favorable impact to our ethanol segment margin of approximately $26 million.

• Ethanol segment operating expenses (excluding depreciation and amortization expense) increased by $27 million primarily due to costs to operate the three plants acquired from Green Plains in November 2018 of $14 million and higher chemicals and catalysts costs of $8 million incurred by our other ethanol plants.

Renewable Diesel Segment Results

The following table includes selected financial and operating data of our renewable diesel segment for 2018 and 2017. The selected financial data is derived from the Financial Highlights by Segment and Total Company tables on pages 35 and 36, respectively, unless otherwise noted.

	Year Ended December 31,
	2018		2017		Change
Revenues	$	678	$	634	$	44
Cost of sales	357		574		(217		)
Operating income	321		60		261
Adjusted operating income (see note (f) on page 42)	317		220		97
Margin (see note (f) on page 41)	412		296		116
Operating expenses (excluding depreciation and amortization expense reflected below)	66		47		19
Depreciation and amortization expense	29		29		—
Sales volumes (thousand gallons per day) (see note (g) on page 42)	431		440		(9		)

Renewable diesel segment revenues increased by $44 million in 2018 compared to 2017 primarily due to higher renewable diesel sales prices. This improvement in renewable diesel segment revenues, along with

46

a decrease in total cost of sales of $217 million, resulted in an increase in renewable diesel segment operating income of $261 million.

Renewable diesel segment adjusted operating income increased by $97 million in 2018 compared to 2017. The components of this increase, along with the reasons for the changes in these components are outlined below.

• Renewable diesel segment margin increased by $116 million in 2018 compared to 2017 primarily due to the following:

◦ An increase in renewable diesel prices in 2018 had a favorable impact to our renewable diesel segment margin of $60 million.

◦ Price risk management activities had a favorable impact to our renewable diesel segment margin of $40 million. We recognized a hedge gain of $29 million in 2018 from commodity derivative instruments associated with our price risk management activities compared to a loss of $11 million in 2017.

• Renewable diesel segment operating expenses (excluding depreciation and amortization expense) increased by $19 million primarily attributable to higher chemical and catalyst costs of $10 million and increased costs resulting from the expansion of the DGD Plant completed in the third quarter of 2018 of $3 million.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We believe that we have sufficient funds from operations and from borrowings under our credit facilities to fund our ongoing operating requirements and other commitments. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.

Our liquidity consisted of the following as of December 31, 2019 (in millions):

Available borrowing capacity from committed facilities:
Valero Revolver	$	3,966
Canadian Revolver	112
Accounts receivable sales facility	1,200
Letter of credit facility	50
Total available borrowing capacity	5,328
Cash and cash equivalents(a)	2,473
Total liquidity	$	7,801

___________________

(a) Excludes $110 million of cash and cash equivalents related to our variable interest entities (VIEs) that is available for use only by our VIEs.

47

Information about our outstanding borrowings, letters of credit issued, and availability under our credit facilities is reflected in Note 9 of Notes to Consolidated Financial Statements.

Cash Flows

Components of our cash flows are set forth below (in millions):

	Year Ended December 31,
	2019			2018			2017
Cash flows provided by (used in):
Operating activities	$	5,531		$	4,371		$	5,482
Investing activities	(3,001		)	(3,928		)	(2,382		)
Financing activities	(2,997		)	(3,168		)	(2,272		)
Effect of foreign exchange rate changes on cash	68			(143		)	206
Net increase (decrease) in cash and cash equivalents	$	(399	)	$	(2,868	)	$	1,034

Cash Flows for the Year Ended December 31, 2019

Our operations generated $5.5 billion of cash in 2019, driven primarily by net income of $2.8 billion, noncash charges to income of $2.5 billion, and a positive change in working capital of $294 million. Noncash charges included $2.3 billion of depreciation and amortization expense and $234 million of deferred income tax expense. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is detailed in Note 18 of Notes to Consolidated Financial Statements. The source of cash resulting from the $294 million change in working capital was mainly due to:

• an increase of $1.5 billion in accounts payable due to an increase in commodity prices in December 2019 compared to December 2018 combined with an increase in crude oil volumes purchased and the timing of payments of invoices;

• a decrease of $427 million in prepaid expenses and other mainly due to a decrease in income taxes receivable resulting from a refund of $348 million, including interest, associated with the settlement of the combined audit related to our U.S. federal income tax returns for 2010 and 2011;

• an increase of $153 million in income taxes payable primarily resulting from higher pre-tax income in the fourth quarter of 2019; partially offset by

• an increase of $1.5 billion in receivables resulting from (i) an increase in commodity prices in December 2019 compared to December 2018 combined with an increase in sales volumes, and (ii) a receivable of $449 million for the blender’s tax credit attributable to volumes blended during 2019 and 2018; and

• an increase of $385 million in inventories due to an increase in commodity prices in December 2019 compared to December 2018 combined with higher inventory levels.

The $5.5 billion of cash generated by our operations, along with (i) $992 million of proceeds from debt issuances related to our 4.00 percent Senior Notes, (ii) $239 million of proceeds from borrowings of VIEs, and (iii) $399 million from available cash on hand, were used mainly to:

• fund $2.7 billion in capital investments, as defined in “Capital Investments” on page 50, of which $160 million related to self-funded capital investments by DGD;

• fund $225 million of capital expenditures of VIEs other than DGD;

• acquire undivided interests in pipeline and terminal assets for $72 million;

• redeem our 6.125 percent Senior Notes for $871 million (or 102.48 percent of stated value);

• purchase common stock for treasury of $777 million;

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• pay common stock dividends of $1.5 billion;

• acquire all of the outstanding publicly held common units of VLP for $950 million; and

• pay distributions to noncontrolling interests of $70 million.

In addition, during the year ended December 31, 2019, we sold and repaid $900 million of eligible receivables under our accounts receivable sales facility.

Cash Flows for the Year Ended December 31, 2018

Our operations generated $4.4 billion of cash in 2018, driven primarily by net income of $3.4 billion and noncash charges to income of $2.3 billion, partially offset by a negative change in working capital of $1.3 billion. Noncash charges included $2.1 billion of depreciation and amortization expense and $203 million of deferred income tax expense. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is detailed in Note 18 of Notes to Consolidated Financial Statements. The use of cash resulting from the $1.3 billion change in working capital was mainly due to:

• an increase of $457 million in receivables resulting from an increase in sales volumes, partially offset by a decrease in commodity prices;

• an increase of $197 million in inventory primarily due to higher inventory levels;

• a decrease of $684 million 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 of $113 million in accrued expenses mainly due to the timing of payments on our environmental compliance program obligations; partially offset by

• an increase of $304 million in accounts payable due to an increase in crude oil and other feedstock volumes purchased, partially offset by a decrease in commodity prices.

The $4.4 billion of cash generated by our operations, along with (i) $1.3 billion of proceeds from debt issuances and borrowings, (ii) $109 million of proceeds from borrowings of VIEs, and (iii) $2.9 billion from available cash on hand, were used mainly to:

• fund $2.7 billion in capital investments, of which $192 million related to self-funded capital investments by DGD;

• fund $124 million of capital expenditures of VIEs other than DGD;

• 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;

• acquire undivided interests in pipeline and terminal assets for $212 million;

• redeem our 9.375 percent Senior Notes for $787 million (or 104.9 percent of stated value);

• make payments on debt and finance 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.

Cash Flows for the Year Ended December 31, 2017

Our operations generated $5.5 billion of cash in 2017. Net income of $4.2 billion, net of the $1.9 billion noncash benefit from Tax Reform and other noncash charges of $2.1 billion, and a positive change in working

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capital of $1.3 billion were the primary drivers of the cash generated by our operations in 2017. Other noncash charges included $2.0 billion of depreciation and amortization expense. See “RESULTS OF OPERATIONS” for further discussion of our operations. The Tax Reform benefit and the change in our working capital are detailed in Notes 15 and 18, respectively, of Notes to Consolidated Financial Statements. The source of cash resulting from the $1.3 billion change in working capital was mainly due to:

• an increase of $1.8 billion in accounts payable primarily as a result of an increase in commodity prices;

• an increase of $489 million 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 of $870 million in receivables primarily as a result of an increase in commodity prices; and

• an increase of $516 million in inventory due to higher volumes held combined with an increase in commodity prices.

The $5.5 billion of cash generated by our operations, along with borrowings of $380 million under the VLP Revolver, were used mainly to:

• fund $2.3 billion in capital investments, of which $88 million related to self-funded capital investments by DGD;

• fund $26 million of capital expenditures of VIEs other than DGD;

• 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.

Capital Investments

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are improved continuously. The cost of improvements, which consist of the addition of new Units and betterments of existing Units, can be significant. We have historically acquired our refineries at amounts significantly below their replacement costs, whereas our improvements are made at full replacement value. As such, the costs for improving our refinery assets increase over time and are significant in relation to the amounts we paid to acquire our refineries. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

We make improvements to our refineries in order to maintain and enhance their operating reliability, to meet environmental obligations with respect to reducing emissions and removing prohibited elements from the products we produce, or to enhance their profitability. Reliability and environmental improvements generally do not increase the throughput capacities of our refineries. Improvements that enhance refinery profitability may increase throughput capacity, but many of these improvements allow our refineries to process different types of crude oil and to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

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We consider capital investments to include the following:

• Capital expenditures for purchases of, additions to, and improvements in our property, plant, and equipment, including those made by DGD but excluding other VIEs;

• Deferred turnaround and catalyst cost expenditures, including those made by DGD; and

• Investments in unconsolidated joint ventures.

We include DGD’s capital expenditures and deferred turnaround and catalyst cost expenditures in capital investments because we, as operator of DGD, manage its capital projects and expenditures. We do not include the capital expenditures of our other consolidated VIEs in capital investments because we do not operate those VIEs. In addition, we do not include expenditures for acquisitions and acquisitions of undivided interests in capital investments.

We expect to make capital investments of approximately $2.5 billion in 2020. Approximately 60 percent of those investments are for sustaining the business and 40 percent are for growth strategies. However, we continuously evaluate our capital budget and make changes as conditions warrant. This capital investment estimate excludes potential strategic acquisitions, including acquisitions of undivided interests.

Other Matters Impacting Liquidity and Capital Resources

Stock Purchase Program

On January 23, 2018, our board of directors authorized the 2018 Program for the purchase of our outstanding common stock. As of December 31, 2019, we had $1.5 billion remaining available for purchase under the 2018 Program with no expiration date. We have no obligation to make purchases under this program.

Pension Plan Funding

We plan to contribute approximately $140 million to our pension plans and $21 million to our other postretirement benefit plans during 2020. See Note 13 of Notes to Consolidated Financial Statements for a discussion of our employee benefit plans.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, GHG emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 8 of Notes to Consolidated Financial Statements for disclosure of our environmental liabilities.

Tax Matters

We take tax positions in our tax returns from time to time that may not be ultimately allowed by the relevant taxing authority. When we take such positions, we evaluate the likelihood of sustaining those positions and determine the amount of tax benefit arising from such positions, if any, that should be recognized in our financial statements. Tax benefits not recognized by us are recorded as a liability for unrecognized tax benefits, which represents our potential future obligation to various taxing authorities if the tax positions are not sustained.

As of December 31, 2019, our liability for unrecognized tax benefits, excluding related interest and penalties, was $868 million. Of this amount, $525 million is associated with refund claims associated with taxes paid

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on incentive payments received from the U.S. federal government for blending biofuels into refined petroleum products. We recorded a tax refund receivable of $525 million in connection with our refund claims, but we also recorded a liability for unrecognized tax benefits of $525 million due to the complexity of this matter and uncertainties with respect to sustaining these refund claims. Therefore, our financial position, results of operations, and liquidity will not be negatively impacted if we are unsuccessful in sustaining these refund claims. The remaining liability for unrecognized tax benefits, excluding related interest and penalties, of $343 million represents our potential future obligations to various taxing authorities if the tax positions associated with that liability are not sustained.

Details about our liability for unrecognized tax benefits, along with other information about our unrecognized tax benefits, are included in Note 15 of Notes to Consolidated Financial Statements.

Cash Held by Our International Subsidiaries

As of December 31, 2019, $1.5 billion of our cash and cash equivalents was held by our international subsidiaries. Cash held by our international subsidiaries can be repatriated to us without any U.S. federal income tax consequences as a result of the deemed repatriation provisions of Tax Reform, but certain other taxes may apply, including, but not limited to, withholding taxes imposed by certain international jurisdictions and U.S. state income taxes. Therefore, there is a cost to repatriate cash held by certain of our international subsidiaries to us, but we believe that such amount is not material to our financial position or liquidity.

Concentration of Customers

Our operations have a concentration of customers in the refining industry and customers who are refined petroleum product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

OFF-BALANCE SHEET ARRANGEMENTS

We have not entered into any transactions, agreements, or other contractual arrangements that would result in off-balance sheet liabilities.

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CONTRACTUAL OBLIGATIONS

Our contractual obligations as of December 31, 2019 are summarized below (in millions).

	Payments Due by Year
	2020		2021		2022		2023		2024		Thereafter		Total
Debt and finance lease obligations (a)	$	541	$	103	$	93	$	110	$	82	$	9,485	$	10,414
Debt obligations – interest payments	464		462		455		449		449		3,947		6,226
Operating lease liabilities (b)	376		250		194		160		125		498		1,603
Purchase obligations	14,284		1,906		1,644		1,565		1,519		3,558		24,476
Other long-term liabilities (c)	—		160		168		200		215		2,185		2,928
Total	$	15,665	$	2,881	$	2,554	$	2,484	$	2,390	$	19,673	$	45,647

______________________________

(a) Debt obligations exclude amounts related to unamortized discounts and debt issuance costs. Finance lease obligations include related interest expense. Debt obligations due in 2020 include $348 million associated with borrowings under the IEnova Revolver (as defined and described in Note 9 of Notes to Consolidated Financial Statements) for the construction of terminals in Mexico by Central Mexico Terminals (as defined and described in Note 12 of Notes to Consolidated Financial Statements). The IEnova Revolver is only available to the operations of Central Mexico Terminals, and its creditors do not have recourse against us.

(b) Operating lease liabilities include related interest expense.

(c) Other long-term liabilities exclude amounts related to the long-term portion of operating lease liabilities that are separately presented above.

Debt and Finance Lease Obligations

Our debt and finance lease obligations are described in Notes 9 and 5, respectively, of Notes to Consolidated Financial Statements.

Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements may increase. As of December 31, 2019, all of our ratings on our senior unsecured debt, including debt guaranteed by us, are at or above investment grade level as follows:

Rating Agency	Rating
Moody’s Investors Service	Baa2 (stable outlook)
Standard & Poor’s Ratings Services	BBB (stable outlook)
Fitch Ratings	BBB (stable outlook)

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.

Debt Obligations – Interest Payments

Interest payments for our debt obligations as described in Note 9 of Notes to Consolidated Financial Statements are the expected payments based on information available as of December 31, 2019.

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Operating Lease Liabilities

Our operating lease liabilities arise from leasing arrangements for the right to use various classes of underlying assets as described in Note 5 of Notes to Consolidated Financial Statements. Operating lease liabilities are recognized for leasing arrangements with terms greater than one year and are not reduced by minimum lease payments to be received by us under subleases.

Purchase Obligations

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations under certain crude oil and other feedstock supply arrangements, industrial gas supply arrangements (such as hydrogen supply arrangements), natural gas supply arrangements, and various throughput, transportation and terminaling agreements. We enter into these contracts to ensure an adequate supply of feedstock and utilities and adequate storage capacity to operate our refineries and ethanol plants. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligation amounts shown in the preceding table include both short- and long-term obligations and are based on (i) fixed or minimum quantities to be purchased and (ii) fixed or estimated prices to be paid based on current market conditions.

Other Long-Term Liabilities

Our other long-term liabilities are described in Note 8 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the preceding table, we made our best estimate of expected payments for each type of liability based on information available as of December 31, 2019.

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements became effective January 1, 2020, or will become effective in the future. The effect on our financial statements upon adoption of these pronouncements is discussed in the above-referenced note.

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies that involve critical accounting estimates, and should be read in conjunction with Note 1 of Notes to Consolidated Financial Statements, which summarizes our significant accounting policies. The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes.

Unrecognized Tax Benefits

We take tax positions in our tax returns from time to time that may not be ultimately allowed by the relevant taxing authority. When we take such positions, we evaluate the likelihood of sustaining those positions and determine the amount of tax benefit arising from such positions, if any, that should be recognized in our financial statements. Tax benefits not recognized by us are recorded as a liability for unrecognized tax

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benefits, which represents our potential future obligation to various taxing authorities if the tax positions are not sustained.

The evaluation of tax positions and the determination of the benefit arising from such positions that are recognized in our financial statements requires us to make significant judgments and estimates based on an analysis of complex tax laws and regulations and related interpretations. These judgments and estimates are subject to change due to many factors, including the progress of ongoing tax audits, case law, and changes in legislation.

Details of our liability for unrecognized tax benefits, along with other information about our unrecognized tax benefits, are included in Note 15 of Notes to Consolidated Financial Statements.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating primarily to the discharge of materials into the environment, waste management, and pollution prevention measures. Future legislative action and regulatory initiatives could result in changes to required operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.

Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies.

The amount of our accruals for environmental matters are included in Note 8 of Notes to Consolidated Financial Statements.

Pension and Other Postretirement Benefit Obligations

We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. These assumptions are disclosed and described in Note 13 of Notes to Consolidated Financial Statements. Changes in these assumptions are primarily influenced by factors outside of our control. For example, the discount rate assumption represents a yield curve comprised of various long-term bonds that have an average rating of double-A when averaging all available ratings by the recognized rating agencies, while the expected return on plan assets is based on a compounded return calculated assuming an asset allocation that is representative of the asset mix in our pension plans. To determine the expected return on plan assets, we utilized a forward-looking model of asset returns. The historical geometric average return over the 10 years prior to December 31, 2019 was 9.41 percent. The actual return on assets for the years ended December 31, 2019, 2018, and 2017 was 23.44 percent, (5.53) percent, and 19.31 percent, respectively. These assumptions can have a significant effect on the amounts reported in our financial statements.

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The following sensitivity analysis shows the effects on the projected benefit obligation as of December 31, 2019 and net periodic benefit cost for the year ending December 31, 2020 (in millions):

	Pension Benefits		Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease of 0.25%	$	134	$	10
Compensation rate increase of 0.25%	17		n/a
Increase in expense resulting from:
Discount rate decrease of 0.25%	12		—
Expected return on plan assets decrease of 0.25%	6		n/a
Compensation rate increase of 0.25%	4		n/a

Our net periodic benefit cost is determined using the spot-rate approach. Under this approach, our net periodic benefit cost is impacted by the spot rates of the corporate bond yield curve used to calculate our liability discount rate. If the yield curve were to flatten entirely and our liability discount rate remained unchanged, our net periodic benefit cost would increase by $16 million for pension benefits and $2 million for other postretirement benefits in 2020.

See Note 13 of Notes to Consolidated Financial Statements for a discussion of our pension and other postretirement benefit obligations.

Inventory Valuation

The cost of our inventories is principally determined under the last-in, first-out (LIFO) method using the dollar-value LIFO approach. Our LIFO inventories are carried at the lower of cost or market value and our non-LIFO inventories are carried at the lower of cost or net realizable value. The market value of our LIFO inventories is determined based on the net realizable value of the inventories.

We compare the market value of inventories to their cost on an aggregate basis, excluding materials and supplies. In determining the market value of our inventories, we assume that feedstocks are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined products. We also estimate the usual and customary transportation costs required to move the inventory from our plants to the appropriate points of sale. We then apply an estimated selling price to our inventories. If the aggregate market value is less than cost, we recognize a loss for the difference in our statements of income.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE RISK

We are exposed to market risks related to the volatility in the price of crude oil, refined petroleum products (primarily gasoline and distillate), renewable diesel, grain (primarily corn), renewable diesel feedstocks, and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including futures and options to manage the volatility of:

• 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, renewable diesel sales, or natural gas purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

Our positions in commodity derivative instruments are monitored and managed on a daily basis by our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

The following sensitivity analysis includes all of our derivative instruments entered into for purposes other than trading with which we have market risk (in millions):

	December 31,
	2019			2018
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(39	)	$	2
10% decrease in underlying commodity prices	38			(6		)

See Note 20 of Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of December 31, 2019.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory environmental compliance programs. To manage this risk, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. As of December 31, 2019 and 2018, the amount of gain or loss in the fair value of derivative instruments that would have resulted from a 10 percent increase or decrease in the underlying price of the contracts was not material. See Note 20 of Notes to Consolidated Financial Statements for a discussion about these compliance programs.

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INTEREST RATE RISK

The following table provides information about our debt instruments (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented.

	December 31, 2019
	Expected Maturity Dates
	2020 (a)			2021			2022			2023			2024			There- after			Total (b)			Fair Value
Fixed rate	$	—		$	11		$	—		$	—		$	—		$	8,474		$	8,485		$	10,099
Average interest rate	—		%	5.0		%	—		%	—		%	—		%	5.2		%	5.2		%
Floating rate (c)	$	453		$	6		$	6		$	19		$	—		$	—		$	484		$	484
Average interest rate	5.0		%	4.5		%	4.5		%	4.5		%	—		%	—		%	5.0		%

	December 31, 2018
	Expected Maturity Dates
	2019 (a)			2020			2021			2022			2023			There- after			Total (b)			Fair Value
Fixed rate	$	—		$	850		$	10		$	—		$	—		$	7,474		$	8,334		$	8,737
Average interest rate	—		%	6.1		%	5.0		%	—		%	—		%	5.4		%	5.5		%
Floating rate (c)	$	214		$	5		$	5		$	5		$	20		$	—		$	249		$	249
Average interest rate	4.6		%	4.7		%	4.7		%	4.7		%	4.7		%	—		%	4.6		%

________________________

(a) As of December 31, 2019 and 2018, our floating rate debt due in 2020 and 2019 includes $348 million and $109 million, respectively, associated with borrowings under the IEnova Revolver for the construction of terminals in Mexico by Central Mexico Terminals. The IEnova Revolver is only available to the operations of Central Mexico Terminals, and its creditors do not have recourse against us.

(b) Excludes unamortized discounts and debt issuance costs.

(c) As of December 31, 2019 and 2018, we had an interest rate swap associated with $36 million and $40 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.

FOREIGN CURRENCY RISK

As of December 31, 2019, we had foreign currency contracts to purchase $739 million of U.S. dollars and $2.3 billion of U.S. dollar equivalent Canadian dollars. Our market risk was minimal on these contracts, as all of them matured on or before February 15, 2020.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Valero Energy Corporation. Our management evaluated the effectiveness of Valero’s internal control over financial reporting as of December 31, 2019. In its evaluation, management used the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management believes that as of December 31, 2019, our internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on the effectiveness of our internal control over financial reporting, which begins on page 62 of this report.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Valero Energy Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Valero Energy Corporation and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

60

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Assessment of gross unrecognized tax benefits

As discussed in Note 15 to the consolidated financial statements, as of December 31, 2019, the Company has gross unrecognized tax benefits, excluding related interest and penalties, of $897 million. The Company’s tax positions are subject to examination by local taxing authorities and the resolution of such examinations may span multiple years. Due to the complexities inherent in the interpretation of income tax laws in domestic and international jurisdictions, it is uncertain whether some of the Company’s income tax positions will be sustained upon examination.

We identified the assessment of the Company’s gross unrecognized tax benefits as a critical audit matter because complex auditor judgment was required in evaluating the Company’s interpretation of income tax laws and assessing the Company’s estimate of the ultimate resolution of its income tax positions.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s income tax process, including controls to evaluate which of the Company’s income tax positions may not be sustained upon examination and estimate the gross unrecognized tax benefits.

We involved domestic and international income tax professionals with specialized skills and knowledge, who assisted in:

• Obtaining an understanding and evaluating the Company’s income tax positions as filed or intended to be filed;

• Evaluating the Company’s interpretation of income tax laws by developing an independent assessment of the Company’s income tax positions and comparing the results to the Company’s assessment;

• Inspecting settlements with applicable taxing authorities; and

• Assessing the expiration of applicable statutes of limitations.

In addition, we evaluated the Company’s ability to estimate its gross unrecognized tax benefits by comparing historical uncertain income tax positions, including the gross unrecognized tax benefits, to actual results upon conclusion of tax examinations.

/s/ KPMG LLP

We have served as the Company’s auditor since 2004.

San Antonio, Texas

February 26, 2020

61

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Valero Energy Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited Valero Energy Corporation’s and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2020 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial

62

statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

San Antonio, Texas

February 26, 2020

63

VALERO ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(millions of dollars, except par value)

	December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	2,583		$	2,982
Receivables, net	8,904			7,345
Inventories	7,013			6,532
Prepaid expenses and other	469			816
Total current assets	18,969			17,675
Property, plant, and equipment, at cost	44,294			42,473
Accumulated depreciation	(15,030		)	(13,625		)
Property, plant, and equipment, net	29,264			28,848
Deferred charges and other assets, net	5,631			3,632
Total assets	$	53,864		$	50,155
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and finance lease obligations	$	494		$	238
Accounts payable	10,205			8,594
Accrued expenses	949			630
Taxes other than income taxes payable	1,304			1,213
Income taxes payable	208			49
Total current liabilities	13,160			10,724
Debt and finance lease obligations, less current portion	9,178			8,871
Deferred income tax liabilities	5,103			4,962
Other long-term liabilities	3,887			2,867
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	6,821			7,048
Treasury stock, at cost; 264,209,742 and 255,905,051 common shares	(15,648		)	(14,925		)
Retained earnings	31,974			31,044
Accumulated other comprehensive loss	(1,351		)	(1,507		)
Total Valero Energy Corporation stockholders’ equity	21,803			21,667
Noncontrolling interests	733			1,064
Total equity	22,536			22,731
Total liabilities and equity	$	53,864		$	50,155

See Notes to Consolidated Financial Statements.

64

VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2019			2018			2017
Revenues (a)	$	108,324		$	117,033		$	93,980
Cost of sales:
Cost of materials and other	96,476			104,732			83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	4,868			4,690			4,504
Depreciation and amortization expense	2,202			2,017			1,934
Total cost of sales	103,546			111,439			89,475
Other operating expenses	21			45			61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	868			925			829
Depreciation and amortization expense	53			52			52
Operating income	3,836			4,572			3,563
Other income, net	104			130			112
Interest and debt expense, net of capitalized interest	(454		)	(470		)	(468		)
Income before income tax expense (benefit)	3,486			4,232			3,207
Income tax expense (benefit)	702			879			(949		)
Net income	2,784			3,353			4,156
Less: Net income attributable to noncontrolling interests	362			231			91
Net income attributable to Valero Energy Corporation stockholders	$	2,422		$	3,122		$	4,065
Earnings per common share	$	5.84		$	7.30		$	9.17
Weighted-average common shares outstanding (in millions)	413			426			442
Earnings per common share – assuming dilution	$	5.84		$	7.29		$	9.16
Weighted-average common shares outstanding – assuming dilution (in millions)	414			428			444
_______________________________________________
Supplemental information:
(a)    Includes excise taxes on sales by certain of our international operations	$	5,595		$	5,626		$	5,573

See Notes to Consolidated Financial Statements.

65

VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(millions of dollars)

	Year Ended December 31,
	2019			2018			2017
Net income	$	2,784		$	3,353		$	4,156
Other comprehensive income (loss):
Foreign currency translation adjustment	349			(517		)	514
Net gain (loss) on pension and other postretirement benefits	(234		)	49			(65		)
Net loss on cash flow hedges	(8		)	—			—
Other comprehensive income (loss) before income tax expense (benefit)	107			(468		)	449
Income tax expense (benefit) related to items of other comprehensive income (loss)	(48		)	10			(21		)
Other comprehensive income (loss)	155			(478		)	470
Comprehensive income	2,939			2,875			4,626
Less: Comprehensive income attributable to noncontrolling interests	361			229			91
Comprehensive income attributable to Valero Energy Corporation stockholders	$	2,578		$	2,646		$	4,535

See Notes to Consolidated Financial Statements.

66

VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(millions of dollars)

	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, 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	—		—			—			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
Net income	—		—			—			2,422			—			2,422			362			2,784
Dividends on common stock ($3.60 per share)	—		—			—			(1,492		)	—			(1,492		)	—			(1,492		)
Stock-based compensation expense	—		77			—			—			—			77			—			77
Transactions in connection with stock-based compensation plans	—		(50		)	30			—			—			(20		)	—			(20		)
Stock purchases under purchase program	—		—			(753		)	—			—			(753		)	—			(753		)
Acquisition of Valero Energy Partners LP publicly held common units	—		(328		)	—			—			—			(328		)	(622		)	(950		)
Distributions to noncontrolling interests	—		—			—			—			—			—			(70		)	(70		)
Other	—		74			—			—			—			74			—			74
Other comprehensive income (loss)	—		—			—			—			156			156			(1		)	155
Balance as of December 31, 2019	$	7	$	6,821		$	(15,648	)	$	31,974		$	(1,351	)	$	21,803		$	733		$	22,536

See Notes to Consolidated Financial Statements.

67

VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(millions of dollars)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities:
Net income	$	2,784		$	3,353		$	4,156
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	2,255			2,069			1,986
Deferred income tax expense (benefit)	234			203			(2,543		)
Changes in current assets and current liabilities	294			(1,297		)	1,289
Changes in deferred charges and credits and other operating activities, net	(36		)	43			594
Net cash provided by operating activities	5,531			4,371			5,482
Cash flows from investing activities:
Capital expenditures (excluding variable interest entities (VIEs))	(1,627		)	(1,463		)	(1,269		)
Capital expenditures of VIEs:
Diamond Green Diesel Holdings LLC (DGD)	(142		)	(165		)	(84		)
Other VIEs	(225		)	(124		)	(26		)
Deferred turnaround and catalyst cost expenditures (excluding VIEs)	(762		)	(888		)	(519		)
Deferred turnaround and catalyst cost expenditures of DGD	(18		)	(27		)	(4		)
Investments in unconsolidated joint ventures	(164		)	(181		)	(406		)
Peru Acquisition, net of cash acquired	—			(468		)	—
Acquisition of ethanol plants	(3		)	(320		)	—
Acquisitions of undivided interests	(72		)	(212		)	(72		)
Minor acquisitions	—			(88		)	—
Other investing activities, net	12			8			(2		)
Net cash used in investing activities	(3,001		)	(3,928		)	(2,382		)
Cash flows from financing activities:
Proceeds from debt issuances and borrowings (excluding VIEs)	1,892			1,258			380
Proceeds from borrowings of VIEs	239			109			—
Repayments of debt and finance lease obligations (excluding VIEs)	(1,805		)	(1,353		)	(15		)
Repayments of debt of VIEs	(6		)	(6		)	(6		)
Purchases of common stock for treasury	(777		)	(1,708		)	(1,372		)
Common stock dividends	(1,492		)	(1,369		)	(1,242		)
Acquisition of Valero Energy Partners LP publicly held common units	(950		)	—			—
Contributions from noncontrolling interests	—			32			30
Distributions to noncontrolling interests	(70		)	(116		)	(67		)
Other financing activities, net	(28		)	(15		)	20
Net cash used in financing activities	(2,997		)	(3,168		)	(2,272		)
Effect of foreign exchange rate changes on cash	68			(143		)	206
Net increase (decrease) in cash and cash equivalents	(399		)	(2,868		)	1,034
Cash and cash equivalents at beginning of year	2,982			5,850			4,816
Cash and cash equivalents at end of year	$	2,583		$	2,982		$	5,850

See Notes to Consolidated Financial Statements.

68

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS, BASIS OF PRESENTATION, AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.

We are an international manufacturer and marketer of transportation fuels and petrochemical products. We own and operate 15 petroleum refineries with a combined throughput capacity of approximately 3.15 million barrels per day and 14 ethanol plants with a combined production capacity of approximately 1.73 billion gallons per year as of December 31, 2019. The petroleum refineries are located in the United States (U.S.), Canada, and the United Kingdom (U.K.), and the ethanol plants are located in the Mid-Continent region of the U.S. We are also a joint venture partner in DGD, which owns and operates a renewable diesel plant in Norco, Louisiana. We sell our products in the wholesale rack or bulk markets in the U.S., Canada, the U.K., Ireland, and Latin America. Approximately 7,000 outlets carry our brand names.

Basis of Presentation

General

These consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and with the rules and regulations of the U.S. Securities and Exchange Commission (SEC).

Reclassifications

Effective January 1, 2019, we revised our reportable segments to reflect a new reportable segment — renewable diesel. The renewable diesel segment includes the operations of DGD, our consolidated joint venture as discussed in Note 12, that were transferred from the refining segment. Also effective January 1, 2019, we no longer have a VLP segment, and we now include the operations of Valero Energy Partners LP and its consolidated subsidiaries (VLP) in our refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation. See Note 2 regarding our merger with VLP, which occurred on January 10, 2019, and Note 17 for segment information.

Prior year amounts for capital expenditures and deferred turnaround and catalyst cost expenditures in the consolidated statements of cash flows have been reclassified to conform to the 2019 presentation to separately provide these expenditures for us and our consolidated VIEs.

Significant Accounting Policies

Principles of Consolidation

These financial statements include those of Valero, our wholly owned subsidiaries, and VIEs in which we have a controlling financial interest. Our VIEs are described in Note 12. The ownership interests held by others in the VIEs are recorded as noncontrolling interests. Intercompany items and transactions have been eliminated in consolidation. Investments in less than wholly owned entities where we have significant influence are accounted for using the equity method.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual

69

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Cash Equivalents

Our cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash and have a maturity of three months or less when acquired.

Receivables

Trade receivables are carried at original invoice amount. We maintain an allowance for doubtful accounts, which is adjusted based on management’s assessment of our customers’ historical collection experience, known credit risks, and industry and economic conditions.

Inventories

The cost of refinery feedstocks and refined petroleum products, grain and ethanol, and renewable diesel feedstocks (animal fats, used cooking oils, and other vegetable oils) and renewable diesel is determined under the last-in, first-out (LIFO) method using the dollar-value LIFO approach, with any increments valued based on average purchase prices during the year. Our LIFO inventories are carried at the lower of cost or market. The cost of products purchased for resale and the cost of materials and supplies are determined principally under the weighted-average cost method. Our non-LIFO inventories are carried at the lower of cost or net realizable value. If the aggregate market value of our LIFO inventories or the aggregate net realizable value of our non-LIFO inventories is less than the related aggregate cost, we recognize a loss for the difference in our statements of income.

Property, Plant, and Equipment

The cost of property, plant, and equipment (property assets) purchased or constructed, including betterments of property assets, is capitalized. However, the cost of repairs to and normal maintenance of property assets is expensed as incurred. Betterments of property assets are those that extend the useful life, increase the capacity or improve the operating efficiency of the asset, or improve the safety of our operations. The cost of property assets constructed includes interest and certain overhead costs allocable to the construction activities.

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are continuously improved. Improvements consist of the addition of new Units and betterments of existing Units. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

Depreciation of property assets used in our refining and renewable diesel segments is recorded on a straight-line basis over the estimated useful lives of these assets primarily using the composite method of depreciation. We maintain a separate composite group of property assets for each of our refineries and our renewable diesel plant. We estimate the useful life of each group based on an evaluation of the property assets comprising the group, and such evaluations consist of, but are not limited to, the physical inspection of the assets to determine their condition, consideration of the manner in which the assets are maintained, assessment of the

70

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

need to replace assets, and evaluation of the manner in which improvements impact the useful life of the group. The estimated useful lives of our composite groups range primarily from 20 to 30 years.

Under the composite method of depreciation, the cost of an improvement is added to the composite group to which it relates and is depreciated over that group’s estimated useful life. We design improvements to our refineries and renewable diesel plant in accordance with engineering specifications, design standards, and practices accepted in our industry, and these improvements have design lives consistent with our estimated useful lives. Therefore, we believe the use of the group life to depreciate the cost of improvements made to the group is reasonable because the estimated useful life of each improvement is consistent with that of the group.

Also under the composite method of depreciation, the historical cost of a minor property asset (net of salvage value) that is retired or replaced is charged to accumulated depreciation and no gain or loss is recognized in income. However, a gain or loss is recognized in income for a major property asset that is retired, replaced, sold, or for an abnormal disposition of a property asset (primarily involuntary conversions). Gains and losses are reflected in depreciation and amortization expense, unless such amounts are reported separately due to materiality.

Depreciation of property assets used in our ethanol segment is recorded on a straight-line basis over the estimated useful lives of the related assets. The estimated useful life of our grain processing equipment is 20 years.

Leasehold improvements are amortized on a straight-line basis over the shorter of the lease term or the estimated useful life of the related asset. Finance lease ROU (defined below) assets are amortized as discussed in “Leases” below.

Deferred Charges and Other Assets

“Deferred charges and other assets, net” primarily include the following:

• turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, ethanol plants, and renewable diesel plant, 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, are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst;

• operating lease ROU (defined below) assets, which are amortized as discussed in “Leases” below;

• investments in unconsolidated joint ventures;

• income taxes receivable;

• intangible assets, which are amortized over their estimated useful lives; and

• goodwill.

71

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Leases

We evaluate if a contract is or contains a lease at inception of the contract. If we determine that a contract is or contains a lease, we recognize a right-of-use (ROU) asset and lease liability at the commencement date of the lease based on the present value of lease payments over the lease term. The present value of the lease payments is determined by using the implicit rate when readily determinable. If not determinable, our centrally managed treasury group provides an incremental borrowing rate based on quoted interest rates obtained from financial institutions. The rate used is for a term similar to the duration of the lease based on information available at the commencement date. Lease terms include options to extend or terminate the lease when it is reasonably certain that we will exercise those options.

We recognize ROU assets and lease liabilities for leasing arrangements with terms greater than one year. Except for the marine transportation asset class, we account for lease and non-lease components in a contract as a single lease component for all classes of underlying assets. Our marine transportation contracts include non-lease components, such as maintenance and crew costs. We allocate the consideration in these contracts based on pricing information provided by the third-party broker.

Expense for an operating lease is recognized as a single lease cost on a straight-line basis over the lease term and is reflected in the appropriate income statement line item based on the leased asset’s function. Amortization expense of a finance lease ROU asset is recognized on a straight-line basis over the lesser of the useful life of the leased asset or the lease term. However, if the lease transfers ownership of the finance lease ROU asset to us at the end of the lease term, the finance lease ROU asset is amortized over the useful life of the leased asset. Amortization expense is reflected in “depreciation and amortization expense.” Interest expense is incurred based on the carrying value of the lease liability and is reflected in “interest and debt expense, net of capitalized interest.”

Impairment of Assets

Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized for the amount by which the carrying amount of the long-lived asset exceeds its fair value, with fair value determined based on discounted estimated net cash flows or other appropriate methods.

We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in income based on the difference between the estimated current fair value of the investment and its carrying amount.

Asset Retirement Obligations

We record a liability, which is referred to as an asset retirement obligation, at fair value for the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed, or leased. We record the liability when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable

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estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the liability’s fair value.

We have obligations with respect to certain of our assets related to our refining and ethanol segments to clean and/or dispose of various component parts of the assets at the time they are retired. However, these component parts can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain all our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets related to our refining and ethanol segments have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire such assets cannot reasonably be estimated at this time. We will recognize a liability at such time when sufficient information exists to estimate a date or range of potential settlement dates that is needed to employ a present value technique to estimate fair value.

Environmental Matters

Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Amounts recorded for environmental liabilities have not been reduced by possible recoveries from third parties and have not been measured on a discounted basis.

Legal Contingencies

We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred.

Foreign Currency Translation

Generally, our international subsidiaries use their local currency as their functional currency. Balance sheet amounts are translated into U.S. dollars using exchange rates in effect as of the balance sheet date. Income statement amounts are translated into U.S. dollars using the exchange rates in effect at the time the underlying transactions occur. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive loss.

Revenue Recognition

Our revenues are primarily generated from contracts with customers. We generate revenue from contracts with customers from the sale of products by our refining, ethanol, and renewable diesel segments. Revenues are recognized when we satisfy our performance obligation to transfer products to our customers, which typically occurs at a point in time upon shipment or delivery of the products, and for an amount that reflects the transaction price that is allocated to the performance obligation.

The customer is able to direct the use of, and obtain substantially all of the benefits from, the products at the point of shipment or delivery. As a result, we consider control to have transferred upon shipment or delivery

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because we have a present right to payment at that time, the customer has legal title to the asset, we have transferred physical possession of the asset, and the customer has significant risks and rewards of ownership of the asset.

Our contracts with customers state the final terms of the sale, including the description, quantity, and price for goods sold. Payment is typically due in full within two to ten days of delivery. In the normal course of business, we generally do not accept product returns.

The transaction price is the consideration that we expect to be entitled to in exchange for our products. The transaction price for substantially all of our contracts is generally based on commodity market pricing (i.e., variable consideration). As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. Some of our contracts also contain variable consideration in the form of sales incentives to our customers, such as discounts and rebates. For contracts that include variable consideration, we estimate the factors that determine the variable consideration in order to establish the transaction price.

We have elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by us from a customer (e.g., sales tax, use tax, value-added tax, etc.). We continue to include in the transaction price excise taxes that are imposed on certain inventories in our international operations. The amount of such taxes is provided in supplemental information in a footnote on the statements of income.

There are instances where we provide shipping services in relation to the goods sold to our customer. Shipping and handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are included in cost of materials and other. We have elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities rather than as a promised service and we have included these activities in cost of materials and other.

We enter into certain purchase and sale arrangements with the same counterparty that are deemed to be made in contemplation of one another. We combine these transactions and present the net effect in cost of materials and other. We also enter into refined petroleum product exchange transactions to fulfill sales contracts with our customers by accessing refined petroleum products in markets where we do not operate our own refineries. These refined petroleum product exchanges are accounted for as exchanges of nonmonetary assets, and no revenues are recorded on these transactions.

Cost Classifications

“Cost of materials and other” primarily includes the cost of materials that are a component of our products sold. These costs include (i) the direct cost of materials (such as crude oil and other refinery feedstocks, refined petroleum products and blendstocks, and ethanol feedstocks and products) that are a component of our products sold; (ii) costs related to the delivery (such as shipping and handling costs) of products sold; (iii) costs related to our environmental credit obligations to comply with various governmental and regulatory programs (such as the cost of Renewable Identification Numbers (RINs) as required by the U.S. Environmental Protection Agency’s (EPA) Renewable Fuel Standard, emission credits under various cap-and-trade systems, as defined in Note 19); (iv) the blender’s tax credit recognized on qualified biodiesel mixtures; (v) gains and losses on our commodity derivative instruments; and (vi) certain excise taxes.

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“Operating expenses (excluding depreciation and amortization expense)” include costs to operate our refineries, ethanol plants, and logistics assets, except for depreciation and amortization expense. These costs primarily include employee-related expenses, energy and utility costs, catalysts and chemical costs, and repair and maintenance expenses.

“Depreciation and amortization expense” associated with our operations is separately presented in our statement of income as a component of cost of sales and general and administrative expenses and is disclosed by reportable segment in Note 17.

“Other operating expenses” include costs, if any, incurred by our reportable segments that are not associated with our cost of sales.

Environmental Compliance Program Costs

We purchase credits in the open market to meet our obligations under various environmental compliance programs. We purchase biofuel credits (primarily RINs in the U.S.) to comply with government regulations that require us to blend a certain percentage of biofuels into the products we produce. To the degree that we are unable to blend biofuels at the required percentage, we must purchase biofuel credits to meet our obligation. We purchase greenhouse gas (GHG) emission credits to comply with government regulations concerning various GHG emission programs, including cap-and-trade systems. These programs are described in Note 20 under “Environmental Compliance Program Price Risk.”

The costs of purchased biofuel credits and GHG emission credits are charged to cost of materials and other as such credits are needed to satisfy our obligation. To the extent we have not purchased enough credits to satisfy our obligation as of the balance sheet date, we charge cost of materials and other for such deficiency based on the market price of the credits as of the balance sheet date, and we record a liability for our obligation to purchase those credits. See Note 19 for disclosure of our fair value liability.

Stock-Based Compensation

Compensation expense for our share-based compensation plans is based on the fair value of the awards granted and is recognized in income on a straight-line basis over the shorter of (i) the requisite service period of each award or (ii) the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the vesting period established in the award.

Income Taxes

Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by unrecognized tax benefits, if such items may be available to offset the unrecognized tax benefit. Stranded income tax effects are released from accumulated other comprehensive loss to retained earnings on an individual item basis as those items are reclassified into income.

We have elected to classify any interest expense and penalties related to the underpayment of income taxes in income tax expense.

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We have elected to treat the global intangible low-taxed income (GILTI) tax as a period expense.

Earnings per Common Share

Earnings per common share is computed by dividing net income attributable to Valero stockholders by the weighted-average number of common shares outstanding for the year. Participating securities are included in the computation of basic earnings per share using the two-class method. Earnings per common share – assuming dilution is computed by dividing net income attributable to Valero stockholders by the weighted-average number of common shares outstanding for the year increased by the effect of dilutive securities. Potentially dilutive securities are excluded from the computation of earnings per common share – assuming dilution when the effect of including such shares would be antidilutive.

Financial Instruments

Our financial instruments include cash and cash equivalents, receivables, payables, debt, operating and finance lease obligations, commodity derivative contracts, and foreign currency derivative contracts. The estimated fair values of these financial instruments approximate their carrying amounts, except for certain debt as discussed in Note 19.

Derivatives and Hedging

All derivative instruments, not designated as normal purchases or sales, are recorded in the balance sheet as either assets or liabilities measured at their fair values with changes in fair value recognized currently in income. To manage commodity price risk, we primarily use cash flow hedges and economic hedges, and we also use fair value hedges from time to time. The cash flow effects of all of our derivative instruments are reflected in operating activities in the consolidated statements of cash flows.

Accounting Pronouncements Adopted During 2019

Topic 842

We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 842, “Leases,” (Topic 842) on January 1, 2019. Topic 842 increases the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Topic 842 supersedes previous lease accounting requirements under FASB ASC Topic 840, “Leases,” (Topic 840). We adopted Topic 842 using the optional transition method that permits us to record a cumulative-effect adjustment and apply the new disclosure requirements beginning in 2019 and continue to present comparative period information as required under Topic 840; however, we did not have a cumulative-effect adjustment to the opening balance of retained earnings at the date of adoption.

In addition, we elected the transition practical expedient package 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. See “Leases” above for a discussion of our revised accounting policy and also see Note 5 for information on our leases.

In preparation for the adoption of Topic 842, we enhanced our contracting and lease evaluation systems and related processes, and we developed a new lease accounting system to capture our leases and support the

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required disclosures. We integrated our lease accounting system with our general ledger and modified our related procurement and payment processes.

Adoption of this standard resulted in (i) the recognition of ROU assets and lease liabilities for our operating leases of $1.3 billion, (ii) the derecognition of existing assets under construction of $539 million related to a build-to-suit lease arrangement with respect to the MVP Terminal (see Note 10 under “Contractual Capital Commitments—MVP Terminal”), and (iii) the presentation of new disclosures about our leasing activities beginning in the first quarter of 2019. Adoption of this standard did not impact our results of operations or liquidity, and our accounting for finance leases is substantially unchanged.

Other

In addition to the adoption of Topic 842 discussed above, we adopted the following Accounting Standards Update (ASU) on January 1, 2019. Our adoption of this ASU did not affect our financial statements or related disclosures.

ASU		Basis of Adoption
2017-12	Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities	Cumulative effect

Accounting Pronouncements Adopted on January 1, 2020

The following ASUs were adopted on January 1, 2020, and our adoption did not have a material impact on our financial statements or related disclosures.

ASU		Basis of Adoption
2016-13	Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (including codification improvements in ASUs 2018-19 and 2019-11 and ASU 2020-02— Financial Instruments—Credit Losses (Topic 326): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 119)	Cumulative effect
2018-15	Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	Prospectively
2019-12	Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes	Prospectively

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2. MERGER AND ACQUISITIONS

Merger with VLP

On January 10, 2019, we completed our acquisition of all of the outstanding publicly held common units of VLP pursuant to a definitive Agreement and Plan of Merger (Merger Agreement, and together with the transactions contemplated thereby, the Merger Transaction) with VLP. Upon completion of the Merger Transaction, each outstanding publicly held common unit was converted into the right to receive $42.25 per common unit in cash without any interest thereon, and all such publicly traded common units were automatically canceled and ceased to exist. Upon completion of the Merger Transaction, we paid aggregate merger consideration of $950 million, which was funded with available cash on hand.

Prior to the completion of the Merger Transaction, we consolidated the financial statements of VLP (see Note 12) and reflected noncontrolling interests on our balance sheet for the portion of VLP’s partners’ capital held by VLP’s public common unitholders. Upon completion of the Merger Transaction, VLP became our indirect wholly owned subsidiary and, as a result, we no longer reflect noncontrolling interests on our balance sheet with respect to VLP. In addition, we no longer attribute a portion of VLP’s net income to noncontrolling interests. Because we had a controlling financial interest in VLP before the Merger Transaction and retained our controlling financial interest in VLP after the Merger Transaction, the change in our ownership interest in VLP as a result of the merger was accounted for as an equity transaction. Accordingly, we did not recognize a gain or loss on the Merger Transaction.

Acquisition of Ethanol Plants

On November 15, 2018, we acquired 3 ethanol plants from two subsidiaries of Green Plains Inc. for total cash consideration of $320 million including working capital of $20 million. The ethanol plants are located in Bluffton, Indiana; Lakota, Iowa; and Riga, Michigan with a combined ethanol production capacity of 280 million gallons per year. This acquisition was accounted for as an asset acquisition.

Peru Acquisition

On May 14, 2018, we acquired 100 percent of the issued and outstanding equity interests in Pure Biofuels del Peru S.A.C. (now known as Valero Peru S.A.C.) (Valero Peru) from Pegasus Capital Advisors L.P. and various minority equity holders. Valero Peru markets refined petroleum products through its logistics assets in Peru. Valero Peru owns a terminal at the Port of Callao, near Lima, with approximately 1 million barrels of storage capacity for refined petroleum and renewable products. Through one of its subsidiaries, Valero Peru also owns a 180,000-barrel storage terminal in Paita, in northern Peru, which is scheduled to commence operations in the second quarter of 2020, pending regulatory approvals. This acquisition, which is referred to as the Peru Acquisition, was consistent with our general business strategy and broadens the geographic diversity of our refining segment. This acquisition was accounted for as a business combination.

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The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date, based on an independent appraisal that was completed in the fourth quarter of 2018 (in millions). We paid $468 million from available cash on hand, of which $132 million was for working capital. During the third and fourth quarters of 2018, we recognized immaterial adjustments to the preliminary amounts recorded for the Peru Acquisition with a corresponding adjustment to goodwill due to the completion of the independent appraisal. These adjustments did not have a material effect on our results of operations for the year ended December 31, 2018.

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

Deferred charges and other assets primarily include identifiable intangible assets of $200 million and goodwill of $260 million. Identifiable intangible assets, which consist of customer contracts and relationships, are amortized on a straight-line basis over ten years. Goodwill is calculated as the excess of the consideration transferred over the estimated fair values of the underlying tangible and identifiable intangible assets acquired and liabilities assumed. Goodwill represents the future economic benefits expected to be recognized from our expansion into the Latin American refined petroleum products markets arising from other assets acquired that were not individually identified and separately recognized. We determined that the entire balance of goodwill is related to the refining segment. NaN of the goodwill is deductible for tax purposes.

Our statements of income include the results of operations of Valero Peru since the date of acquisition, and such results are reflected in the refining segment. Results of operations since the date of acquisition, supplemental pro forma financial information, and acquisition-related costs have not been presented for the Peru Acquisition as such information is not material to our results of operations.

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3. RECEIVABLES

Receivables consisted of the following (in millions):

	December 31,
	2019			2018
Receivables from contracts with customers	$	5,610		$	4,673
Receivables from certain purchase and sale arrangements	2,484			2,311
Commodity derivative and foreign currency contract receivables	116			229
Other receivables	730			166
Total receivables	8,940			7,379
Allowance for doubtful accounts	(36		)	(34		)
Receivables, net	$	8,904		$	7,345

There were no significant changes in our allowance for doubtful accounts during the years ended December 31, 2019, 2018, and 2017.

4. INVENTORIES

Inventories consisted of the following (in millions):

	December 31,
	2019		2018
Refinery feedstocks	$	2,399	$	2,265
Refined petroleum products and blendstocks	4,034		3,653
Ethanol feedstocks and products	260		298
Renewable diesel feedstocks and products	46		52
Materials and supplies	274		264
Inventories	$	7,013	$	6,532

As of December 31, 2019 and 2018, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by $2.5 billion and $1.5 billion, respectively. Our non-LIFO inventories accounted for $1.4 billion and $1.1 billion of our total inventories as of December 31, 2019 and 2018, respectively.

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5. LEASES

General

We have entered into long-term leasing arrangements for the right to use various classes of underlying assets as follows:

• Pipelines, Terminals, and Tanks includes facilities and equipment used in the storage, transportation, production, and sale of refinery feedstock, refined petroleum product, and corn inventories;

• Marine Transportation includes time charters for ocean-going tankers and coastal vessels;

• Rail Transportation includes railcars and related storage facilities;

• Feedstock Processing Equipment includes machinery, equipment, and various facilities used in our refining, ethanol, and renewable diesel operations;

• Energy and Gases includes facilities and equipment related to industrial gases and power used in our operations;

• Real Estate includes land and rights-of-way associated with our refineries and pipelines, as well as office facilities; and

• Other includes equipment primarily used at our corporate offices, such as printers and copiers.

In addition to fixed lease payments, some arrangements contain provisions for variable lease payments. Certain leases for pipelines, terminals, and tanks provide for variable lease payments based on, among other things, throughput volumes in excess of a base amount. Certain marine transportation leases contain provisions for payments that are contingent on usage. Additionally, if the rental increases are not scheduled in the lease, such as an increase based on subsequent changes in the index or rate, those rents are considered variable lease payments. In all instances, variable lease payments are recognized in the period in which the obligation for those payments is incurred.

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Lease Costs and Other Supplemental Information

In accordance with Topic 842, our total lease cost comprises costs that are included in our income statement, as well as costs capitalized as part of an item of property, plant, and equipment or inventory. Total lease cost by class of underlying asset was as follows (in millions):

	Year Ended December 31, 2019
	Pipelines, Terminals, and Tanks		Transportation					Feedstock Processing Equipment		Energy and Gases		Real Estate			Other		Total
			Marine			Rail
Finance lease cost:
Amortization of ROU assets	$	44	$	—		$	—	$	7	$	3	$	—		$	—	$	54
Interest on lease liabilities	47		—			—		1		2		—			—		50
Operating lease cost	182		145			52		20		9		27			4		439
Variable lease cost	66		35			—		1		—		1			—		103
Short-term lease cost	9		53			—		29		—		—			—		91
Sublease income	—		(27		)	—		—		—		(3		)	—		(30		)
Total lease cost	$	348	$	206		$	52	$	58	$	14	$	25		$	4	$	707

In accordance with Topic 840, “rental expense, net of sublease rental income” was as follows (in millions):

	Year Ended December 31,
	2018		2017
Minimum rental expense	$	515	$	691
Contingent rental expense	19		21
Total rental expense	534		712
Less: Sublease rental income	31		54
Rental expense, net of sublease rental income	$	503	$	658

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The following table presents additional information related to our operating and finance leases (in millions, except for lease terms and discount rates):

	December 31, 2019
	Operating Leases			Finance Leases
Supplemental balance sheet information
ROU assets, net reflected in the following balance sheet line items:
Property, plant, and equipment, net	$	—		$	790
Deferred charges and other assets, net	1,329			—
Total ROU assets, net	$	1,329		$	790
Current lease liabilities reflected in the following balance sheet line items:
Current portion of debt and finance lease obligations	$	—		$	41
Accrued expenses	331			—
Noncurrent lease liabilities reflected in the following balance sheet line items:
Debt and finance lease obligations, less current portion	—			750
Other long-term liabilities	959			—
Total lease liabilities	$	1,290		$	791
Other supplemental information
Weighted-average remaining lease term	7.7 years			19.7 years
Weighted-average discount rate	4.9		%	5.2		%

Supplemental cash flow information related to our operating and finance leases is presented in Note 18.

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Maturity Analysis

The remaining minimum lease payments due under our long-term leases were as follows (in millions):

	December 31, 2019				December 31, 2018
	Operating Leases		Finance Leases		Operating Leases		Capital Leases
2019	n/a		n/a		$	359	$	69
2020	$	376	$	88	245		65
2021	250		86		178		62
2022	194		87		146		64
2023	160		91		123		65
2024	125		82		n/a		n/a
Thereafter	498		1,011		514		957
Total undiscounted lease payments	1,603		1,445		$	1,565	1,282
Less: Amount associated with discounting	313		654				676
Total lease liabilities	$	1,290	$	791			$	606

Future Lease Commencement

As described and defined in Note 10, we have a terminaling agreement with MVP to utilize certain assets at the MVP Terminal upon completion of construction, which is expected to occur during the first quarter of 2020. We expect to recognize a finance lease ROU asset and related liability of approximately $1.5 billion in 2020 in connection with this agreement.

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6. PROPERTY, PLANT, AND EQUIPMENT

Major classes of property, plant, and equipment, including assets held under finance leases, consisted of the following (in millions):

	December 31,
	2019			2018
Land	$	476		$	416
Crude oil processing facilities	32,047			30,721
Transportation and terminaling facilities	5,179			4,935
Grain processing equipment	1,201			1,212
Administrative buildings	1,015			953
Finance lease ROU assets (see Note 5)	944			711
Other	1,701			1,565
Construction in progress	1,731			1,960
Property, plant, and equipment, at cost	44,294			42,473
Accumulated depreciation	(15,030		)	(13,625		)
Property, plant, and equipment, net	$	29,264		$	28,848

Capital lease assets, as determined in accordance with Topic 840, are presented as “Finance lease ROU assets” as of December 31, 2018. Effective January 1, 2019, in connection with our adoption of Topic 842, these assets are considered finance lease ROU assets and are presented as “Finance lease ROU assets.” As further described in Note 5, our finance lease ROU assets arise from leasing arrangements for the right to use various classes of underlying assets including (i) pipelines, terminals, and tanks, (ii) marine and rail transportation, and (iii) feedstock processing equipment.

Accumulated amortization on the assets presented as “Finance lease ROU assets” was $155 million and $106 million as of December 31, 2019 and 2018, respectively.

Depreciation expense for the years ended December 31, 2019, 2018, and 2017 was $1.5 billion, $1.4 billion, and $1.3 billion, respectively.

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7. DEFERRED CHARGES AND OTHER ASSETS

“Deferred charges and other assets, net” consisted of the following (in millions):

	December 31,
	2019		2018
Deferred turnaround and catalyst costs, net	$	1,778	$	1,749
Operating lease ROU assets, net (see Note 5)	1,329		—
Investments in unconsolidated joint ventures	942		542
Income taxes receivable	525		343
Intangible assets, net	283		307
Goodwill	260		260
Other	514		431
Deferred charges and other assets, net	$	5,631	$	3,632

Amortization expense for deferred turnaround and catalyst costs and intangible assets was $759 million, $668 million, and $650 million for the years ended December 31, 2019, 2018, and 2017, respectively.

8. ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES

Accrued expenses and other long-term liabilities consisted of the following (in millions):

	Accrued Expenses				Other Long-Term Liabilities
	December 31,				December 31,
	2019		2018		2019		2018
Operating lease liabilities (see Note 5)	$	331	$	—	$	959	$	—
Liability for unrecognized tax benefits (see Note 15)	—		—		954		721
Defined benefit plan liabilities (see Note 13)	37		43		834		654
Repatriation tax liability (see Note 15) (a)	—		—		508		603
Environmental liabilities	27		29		319		327
Wage and other employee-related liabilities	292		302		121		109
Accrued interest expense	83		93		—		—
Contract liabilities from contracts with customers (see Note 17)	55		31		—		—
Environmental credit obligations (see Note 19)	31		34		—		—
Other accrued liabilities	93		98		192		453
Accrued expenses and other long-term liabilities	$	949	$	630	$	3,887	$	2,867

^{__________________________} 

(a) The current portion of repatriation tax liability is included in income taxes payable. As of December 31, 2019, the current portion of repatriation tax liability was $54 million. There was 0 current portion of repatriation tax liability as of December 31, 2018.

86

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. DEBT AND FINANCE LEASE OBLIGATIONS

Debt, at stated values, and finance lease obligations consisted of the following (in millions):

	Final Maturity	December 31,
		2019			2018
Credit facilities:
Valero Revolver	2024	$	—		$	—
IEnova Revolver	2028	348			109
Canadian Revolver	2020	—			—
Accounts receivable sales facility	2020	100			100
Public debt:
Valero Senior Notes
6.625%	2037	1,500			1,500
3.4%	2026	1,250			1,250
4.0%	2029	1,000			—
6.125%	2020	—			850
4.35%	2028	750			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			500
Gulf Opportunity Zone Revenue Bonds, Series 2010, 4.0%	2040	300			300
Debenture, 7.65%	2026	100			100
Other debt	Various	47			50
Net unamortized debt issuance costs and other		(88		)	(80		)
Total debt		8,881			8,503
Finance lease obligations (see Note 5)		791			606
Total debt and finance lease obligations		9,672			9,109
Less: Current portion		494			238
Debt and finance lease obligations, less current portion		$	9,178		$	8,871

87

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Credit Facilities

Valero Revolver

In March 2019, we amended our revolving credit facility (the Valero Revolver) to increase the borrowing capacity from $3 billion to $4 billion and to extend the maturity date from November 2020 to March 2024. The Valero Revolver also provides for the issuance of letters of credit of up to $2.4 billion.

Outstanding borrowings under the Valero Revolver bear interest, at our option, at either (i) the adjusted LIBO rate (as defined in the Valero Revolver) for the applicable interest period in effect from time to time plus the applicable margin or (ii) the alternate base rate (as defined in the Valero Revolver) plus the applicable margin. The Valero Revolver also requires payments for customary fees, including facility fees, letter of credit participation fees, and administrative agent fees. The interest rate and facility fees under the Valero Revolver are subject to adjustment based upon the credit ratings assigned to our senior unsecured debt.

We had 0 borrowings or repayments under the Valero Revolver during the years ended December 31, 2019, 2018, and 2017.

VLP Revolver

As of December 31, 2018, VLP had a $750 million senior unsecured revolving credit facility (the VLP Revolver) with a group of lenders that was scheduled to mature in November 2020. However, on January 10, 2019, in connection with the completion of the Merger Transaction as described in Note 2, the VLP Revolver was terminated.

During the year ended December 31, 2018, VLP repaid the outstanding balance of $410 million on the VLP Revolver using proceeds from its public offering of $500 million 4.5 percent Senior Notes as described in “Public Debt” below. During the year ended December 31, 2017, VLP borrowed $380 million under the revolver and made 0 repayments.

IEnova Revolver

In February 2018, Central Mexico Terminals (as described in Note 12) entered into a combined $340 million unsecured revolving credit facility (IEnova Revolver) with IEnova (defined in Note 12) that matures in February 2028. In November 2019, the IEnova Revolver was increased to $491 million. IEnova may terminate this revolver at any time and demand repayment of all outstanding amounts; therefore, all outstanding borrowings are reflected in current portion of debt. The IEnova Revolver is available only to the operations of Central Mexico Terminals, and the creditors of Central Mexico Terminals do not have recourse against us.

Outstanding borrowings under this revolver bear interest at the three-month LIBO rate for the applicable interest period in effect from time to time plus the applicable margin. The interest rate under this revolver is subject to adjustment, with agreement by both parties, based upon changes in market conditions. As of December 31, 2019 and 2018, the variable rate was 5.749 percent and 6.046 percent, respectively.

During the year ended December 31, 2019 and 2018, Central Mexico Terminals borrowed $239 million and $109 million, respectively, and had 0 repayments under this revolver.

88

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Canadian Revolver

In November 2019, one of our Canadian subsidiaries amended its committed revolving credit facility (the Canadian Revolver) of C$150 million, under which it may borrow and obtain letters of credit, to extend the maturity date from November 2019 to November 2020.

We had 0 borrowings or repayments under this revolver during the years ended December 31, 2019, 2018, and 2017.

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell up to $1.3 billion of eligible trade receivables on a revolving basis. In July 2019, we amended our agreement to extend the maturity date to July 2020. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

As of December 31, 2019 and 2018, $2.2 billion and $1.8 billion, respectively, of our accounts receivable composed the designated pool of accounts receivable included in the program. All amounts outstanding under the accounts receivable sales facility are reflected as debt on our balance sheets and proceeds and repayments are reflected as cash flows from financing activities on the statements of cash flows. As of December 31, 2019 and 2018, the variable interest rate on the accounts receivable sales facility was 2.3866 percent and 3.0618 percent, respectively. During the year ended December 31, 2019, we sold and repaid $900 million of eligible receivables under the accounts receivable sales facility. During the years ended December 31, 2018 and 2017, we had 0 proceeds from or repayments under the accounts receivable sales facility.

89

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Summary of Credit Facilities

We had outstanding borrowings, letters of credit issued, and availability under our credit facilities as follows (amounts in millions and currency in U.S. dollars, except as noted):

				December 31, 2019
	Facility Amount		Maturity Date	Outstanding Borrowings		Letters of Credit Issued (a)		Availability
Committed facilities:
Valero Revolver	$	4,000	March 2024	$	—	$	34	$	3,966
Canadian Revolver	C$	150	November 2020	C$	—	C$	5	C$	145
Accounts receivable sales facility	$	1,300	July 2020	$	100	n/a		$	1,200
Letter of credit facility (b)	$	50	November 2020	n/a		$	—	$	50
Committed facility of VIE (c):
IEnova Revolver	$	491	February 2028	$	348	n/a		$	143
Uncommitted facilities:
Letter of credit facilities	n/a		n/a	n/a		$	121	n/a

^{__________________________} 

(a) Letters of credit issued as of December 31, 2019 expire at various times in 2020 through 2021.

(b) The letter of credit facility was amended to reduce the facility from $100 million to $50 million and to extend the maturity date from November 2019 to November 2020.

(c) Creditors of our VIE do not have recourse against us.

We are charged letter of credit issuance fees under our various uncommitted short-term bank credit facilities. These uncommitted credit facilities have no commitment fees or compensating balance requirements.

Public Debt

During the year ended December 31, 2019, the following activity occurred:

• We issued $1.0 billion of 4.00 percent Senior Notes due April 1, 2029 (4.00 percent Senior Notes). Proceeds from this debt issuance totaled $992 million before deducting the underwriting discount and other debt issuance costs. The proceeds were used to redeem our 6.125 percent Senior Notes due February 1, 2020 (6.125 percent Senior Notes) for $871 million, or 102.48 percent of stated value, which includes an early redemption fee of $21 million that is reflected in “other income, net” in our statement of income for the year ended December 31, 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 VLP’s 4.375 percent Senior Notes due December 15, 2026 and 4.5 percent Senior Notes due March 15, 2028. See Note 21 for condensed consolidating financial statements.

90

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During the year ended December 31, 2018, the following activity occurred:

• 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” in our statement of income for the year ended December 31, 2018.

• 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 us, which is eliminated in consolidation.

During the year ended December 31, 2017, there was no issuance or redemption activity related to our public debt.

Other Debt

During the year ended December 31, 2018, we retired $137 million of debt assumed in connection with the Peru Acquisition with available cash on hand.

Other Disclosures

“Interest and debt expense, net of capitalized interest” is comprised as follows (in millions):

	Year Ended December 31,
	2019		2018		2017
Interest and debt expense	$	544	$	557	$	539
Less: Capitalized interest	90		87		71
Interest and debt expense, net of capitalized interest	$	454	$	470	$	468

Our credit facilities and other debt arrangements contain various customary restrictive covenants, including cross-default and cross-acceleration clauses.

91

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Principal maturities for our debt obligations as of December 31, 2019 were as follows (in millions):

2020 (a)	$	453
2021	17
2022	6
2023	19
2024	—
Thereafter	8,474
Net unamortized debt issuance costs and other	(88		)
Total debt	$	8,881

^{__________________________} 

(a) As of December 31, 2019, our debt obligations due in 2020 include $348 million associated with borrowings under the IEnova Revolver.

10. COMMITMENTS AND CONTINGENCIES

Purchase Obligations

We have various purchase obligations under certain crude oil and other feedstock supply arrangements, industrial gas supply arrangements (such as hydrogen supply arrangements), natural gas supply arrangements, and various throughput, transportation and terminaling agreements. We enter into these contracts to ensure an adequate supply of feedstock and utilities and adequate storage capacity to operate our refineries and ethanol plants. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. None of these obligations is associated with suppliers’ financing arrangements. These purchase obligations are not reflected as liabilities.

Contractual Capital Commitments

MVP Terminal

We have a 50 percent membership interest in MVP Terminalling, LLC (MVP), a Delaware limited liability company formed in September 2017 with a subsidiary of Magellan Midstream Partners LP (Magellan), to construct, own, and operate the Magellan Valero Pasadena marine terminal (MVP Terminal) located adjacent to the Houston Ship Channel in Pasadena, Texas. The MVP Terminal contains (i) approximately 5 million barrels of storage capacity, (ii) a dock with two ship berths, and (iii) a three-bay truck rack facility. In connection with our terminaling agreement with MVP, described below, we will have dedicated use of (i) approximately 4 million barrels of storage, (ii) one ship berth, and (iii) the three-bay truck rack facility. Construction of phases one and two of the project began in 2017 with a total cost of $840 million, of which we have committed to contribute 50 percent ($420 million). The project could expand up to four phases with a total project cost of approximately $1.4 billion if warranted by additional demand and agreed to by Magellan and us. Since inception, we have contributed $404 million to MVP, of which $157 million was contributed during the year ended December 31, 2019.

Concurrent with the formation of MVP, we entered into a terminaling agreement with MVP to utilize the MVP Terminal upon completion of the majority of phase two, which is expected to occur in the first quarter

92

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

of 2020. The terminaling agreement has an initial term of 12 years with 2 five-year automatic renewals, and year-to-year renewals thereafter.

Prior to our adoption of Topic 842 as described in Note 1, we were considered the accounting owner of the MVP Terminal during the construction period due to our membership interest in MVP and because we determined that the terminaling agreement was a capital lease. Accordingly, as of December 31, 2018, we had recorded an asset of $539 million in property, plant, and equipment representing 100 percent of the construction costs incurred by MVP, as well as capitalized interest incurred by us, and a long-term liability of $292 million payable to Magellan. The amounts recorded for the portion of the construction costs associated with the payable to Magellan were noncash investing and financing items, respectively.

On January 1, 2019, as a result of our adoption of Topic 842, we derecognized the asset and liability related to MVP discussed above and recorded our equity investment in MVP of $247 million, which is included in “deferred charges and other assets, net.” The amounts derecognized are noncash investing and financing items, respectively. As of December 31, 2019, the carrying value of our equity investment in MVP was $401 million.

Central Texas Pipeline

We committed to a 40 percent undivided interest in a project with a subsidiary of Magellan to jointly build a 135-mile, 20-inch refined petroleum products pipeline with a capacity of up to 150,000 barrels per day from Houston to Hearne, Texas. The pipeline was placed in service in the third quarter of 2019. The cost of our 40 percent undivided interest in the pipeline was $160 million, of which $80 million was spent during the year ended December 31, 2019.

Self-Insurance

We are self-insured for certain medical and dental, workers’ compensation, automobile liability, general liability, and property liability claims up to applicable retention limits. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss. These liabilities are included in accrued expenses and other long-term liabilities.

93

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. EQUITY

Share Activity

Activity in the number of shares of common stock and treasury stock was as follows (in millions):

	Common Stock	Treasury Stock
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	)
Transactions in connection with stock-based compensation plans	—	1
Stock purchases under purchase program	—	(9	)
Balance as of December 31, 2019	673	(264	)

Preferred Stock

We have 20 million shares of preferred stock authorized with a par value of $0.01 per share. NaN shares of preferred stock were outstanding as of December 31, 2019 or 2018.

Treasury Stock

We purchase shares of our common stock as authorized under our common stock purchase program (described below) and to meet our obligations under employee stock-based compensation plans.

On July 13, 2015, our board of directors authorized us to purchase $2.5 billion of our outstanding common stock with no expiration date, and we completed that program during 2017. On September 21, 2016, our board of directors authorized our purchase of up to an additional $2.5 billion with no expiration date, and we completed that program during 2018. On January 23, 2018, our board of directors authorized our purchase of up to an additional $2.5 billion (the 2018 Program) with no expiration date. During the years ended December 31, 2019, 2018, and 2017, we purchased $752 million, $1.5 billion, and $1.3 billion, respectively, of our common stock under our programs. As of December 31, 2019, we have approval under the 2018 Program to purchase approximately $1.5 billion of our common stock.

Common Stock Dividends

On January 23, 2020, our board of directors declared a quarterly cash dividend of $0.98 per common share payable on March 4, 2020 to holders of record at the close of business on February 12, 2020.

94

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Tax Effects Related to Components of Other Comprehensive Income (Loss)

The tax effects allocated to each component of other comprehensive income (loss) were as follows (in millions):

	Before-Tax Amount			Tax Expense (Benefit)			Net Amount
Year ended December 31, 2019
Foreign currency translation adjustment	$	349		$	—		$	349
Pension and other postretirement benefits:
Loss arising during the year related to:
Net actuarial loss	(245		)	(54		)	(191		)
Prior service cost	(3		)	(1		)	(2		)
Miscellaneous loss	—			4			(4		)
Amounts reclassified into income related to:
Net actuarial loss	38			9			29
Prior service credit	(28		)	(6		)	(22		)
Curtailment and settlement loss	4			1			3
Net loss on pension and other postretirement benefits	(234		)	(47		)	(187		)
Derivative instruments designated and qualifying as cash flow hedges:
Net loss arising during the year	(6		)	(1		)	(5		)
Net gain reclassified into income	(2		)	—			(2		)
Net loss on cash flow hedges	(8		)	(1		)	(7		)
Other comprehensive income	$	107		$	(48	)	$	155

95

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	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	)
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

96

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accumulated Other Comprehensive Loss

Changes in accumulated other comprehensive loss by component, net of tax, were as follows (in millions):

	Foreign Currency Translation Adjustment			Defined Benefit Plans Items			Losses on Cash Flow Hedges			Total
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	—			(91		)	—			(91		)
Balance as of December 31, 2018	(1,022		)	(485		)	—			(1,507		)
Other comprehensive income (loss) before reclassifications	346			(197		)	(2		)	147
Amounts reclassified from accumulated other comprehensive  loss	—			10			(1		)	9
Other comprehensive income (loss)	346			(187		)	(3		)	156
Balance as of December 31, 2019	$	(676	)	$	(672	)	$	(3	)	$	(1,351	)

97

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Gains (losses) reclassified out of accumulated other comprehensive loss and into net income were as follows (in millions):

Details about Accumulated Other Comprehensive Loss Components										Affected Line Item in the Statement of Income
	Year Ended December 31,
	2019			2018			2017
Amortization of items related to defined benefit pension plans:
Net actuarial loss	$	(38	)	$	(63	)	$	(50	)	(a) Other income, net
Prior service credit	28			29			36			(a) Other income, net
Curtailment and settlement	(4		)	(7		)	(4		)	(a) Other income, net
	(14		)	(41		)	(18		)	Total before tax
	4			9			6			Tax benefit
	$	(10	)	$	(32	)	$	(12	)	Net of tax
Gains on cash flow hedges:
Commodity contracts	$	2		$	—		$	—		Revenues
	$	2		$	—		$	—		Net of tax
Total reclassifications for the year	$	(8	)	$	(32	)	$	(12	)	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

Consolidated VIEs

In the normal course of business, we have financial interests in certain entities that have been determined to be VIEs. We consolidate a VIE when we have a variable interest in an entity for which we are the primary beneficiary such that we have (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to make this determination, we evaluated our contractual arrangements with the VIEs, including arrangements for the use of assets, purchases of products and services, debt, equity, or management of operating activities.

The following discussion summarizes our involvement with our VIEs:

• DGD is a joint venture with a subsidiary of Darling Ingredients Inc. that owns and operates a plant that processes animal fats, used cooking oils, and other vegetable oils into renewable diesel. The plant is located in Norco, Louisiana next to our St. Charles Refinery. Our significant agreements with DGD include an operations agreement that outlines our responsibilities as operator of the plant and a marketing agreement.

98

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As operator, we operate the plant and perform certain day-to-day operating and management functions for DGD as an independent contractor. The operations agreement provides us (as operator) with certain power to direct the activities that most significantly impact DGD’s economic performance. Because this agreement conveys such power to us and is separate from our ownership rights, we determined that DGD was a VIE. For this reason and because we hold a 50 percent ownership interest that provides us with significant economic rights and obligations, we determined that we are the primary beneficiary of DGD. DGD has risk associated with its operations because it generates revenues from third-party customers.

• Central Mexico Terminals is a collective group of 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. We have terminaling agreements with Central Mexico Terminals that represent variable interests because we have determined them to be finance 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 finance 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 50 percent ownership interests provide us with significant economic rights and obligations.

The VIEs’ assets can only be used to settle their own obligations and the VIEs’ creditors have no recourse to our assets. We do not provide financial guarantees to our VIEs. Although we have provided credit facilities to some of our VIEs in support of their construction or acquisition activities, these transactions are eliminated in consolidation. Our financial position, results of operations, and cash flows are impacted by our consolidated VIEs’ performance, net of intercompany eliminations, to the extent of our ownership interest in each VIE.

99

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables present summarized balance sheet information for the significant assets and liabilities of our VIEs, which are included in our balance sheets (in millions).

	December 31, 2019
	DGD		Central Mexico Terminals		Other		Total
Assets
Cash and cash equivalents	$	85	$	—	$	25	$	110
Other current assets	567		33		89		689
Property, plant, and equipment, net	706		381		105		1,192
Liabilities
Current liabilities, including current portion of debt and finance lease obligations	$	66	$	409	$	8	$	483
Debt and finance lease obligations, less current portion	—		—		31		31

	December 31, 2018
	VLP (a)		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 finance lease obligations	$	27	$	28	$	118	$	9	$	182
Debt and finance lease obligations, less current portion	990		—		—		34		1,024

____________________

(a) 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 that we had determined was a VIE. 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. 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. Upon completion of the Merger Transaction, VLP became our indirect wholly owned subsidiary and, as a result, was no longer a VIE.

Non-Consolidated VIEs

We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations and are accounted for as equity investments.

100

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. EMPLOYEE BENEFIT PLANS

Defined Benefit Plans

We have defined benefit pension plans, some of which are subject to collective bargaining agreements, that cover most of our employees. These plans provide eligible employees with retirement income based primarily on years of service and compensation during specific periods under final average pay and cash balance formulas. We fund our pension plans as required by local regulations. In the U.S., all qualified pension plans are subject to the Employee Retirement Income Security Act’s minimum funding standard. We typically do not fund or fully fund U.S. nonqualified and certain international pension plans that are not subject to funding requirements because contributions to these pension plans may be less economic and investment returns may be less attractive than our other investment alternatives.

We also provide health care and life insurance benefits for certain retired employees through our postretirement benefit plans. Most of our employees become eligible for these benefits if, while still working for us, they reach normal retirement age or take early retirement. These plans are unfunded, and retired employees share the cost with us. Individuals who became our employees as a result of an acquisition became eligible for postretirement benefits under our plans as determined by the terms of the relevant acquisition agreement.

101

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in benefit obligation related to all of our defined benefit plans, the changes in fair value of plan assets^(a), and the funded status of our defined benefit plans as of and for the years ended were as follows (in millions):

	Pension Plans						Other Postretirement Benefit Plans
	December 31,						December 31,
	2019			2018			2019			2018
Changes in benefit obligation
Benefit obligation as of beginning of year	$	2,639		$	2,926		$	292		$	306
Service cost	119			133			5			6
Interest cost	98			91			11			10
Participant contributions	—			—			11			10
Benefits paid	(154		)	(207		)	(29		)	(28		)
Actuarial (gain) loss	528			(285		)	41			(9		)
Other	9			(19		)	5			(3		)
Benefit obligation as of end of year	$	3,239		$	2,639		$	336		$	292
Changes in plan assets (a)
Fair value of plan assets as of beginning of year	$	2,236		$	2,428		$	—		$	—
Actual return on plan assets	490			(130		)	—			—
Valero contributions	128			156			18			18
Participant contributions	—			—			11			10
Benefits paid	(154		)	(207		)	(29		)	(28		)
Other	9			(11		)	—			—
Fair value of plan assets as of end of year	$	2,709		$	2,236		$	—		$	—
Reconciliation of funded status (a)
Fair value of plan assets as of end of year	$	2,709		$	2,236		$	—		$	—
Less: Benefit obligation as of end of year	3,239			2,639			336			292
Funded status as of end of year	$	(530	)	$	(403	)	$	(336	)	$	(292	)
Accumulated benefit obligation	$	3,039		$	2,492		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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The actuarial loss for the year ended December 31, 2019 primarily resulted from a decrease in the discount rates used to determine our benefit obligations for our pension plans from 4.25 percent in 2018 to 3.14 percent in 2019. The actuarial gain for the year ended December 31, 2018 primarily resulted from an increase in the discount rates used to determine our benefit obligations for our pension plans from 3.58 percent in 2017 to 4.25 percent in 2018.

The fair value of our plan assets as of December 31, 2019 was favorably impacted by the return on plan assets resulting primarily from an improvement in equity market prices for the year. The fair value of our plan assets as of December 31, 2018 was unfavorably impacted by the negative return on plan assets resulting primarily from a significant decline in equity market prices for the year.

Amounts recognized in our balance sheet for our pension and other postretirement benefits plans include (in millions):

	Pension Plans						Other Postretirement Benefit Plans
	December 31,						December 31,
	2019			2018			2019			2018
Deferred charges and other assets, net	$	5		$	2		$	—		$	—
Accrued expenses	(17		)	(22		)	(20		)	(21		)
Other long-term liabilities	(518		)	(383		)	(316		)	(271		)
	$	(530	)	$	(403	)	$	(336	)	$	(292	)

The following table presents information for our pension plans with projected benefit obligations in excess of plan assets (in millions).

	December 31,
	2019		2018
Projected benefit obligation	$	3,182	$	2,564
Fair value of plan assets	2,647		2,160

The following table presents information for our pension plans with accumulated benefit obligations in excess of plan assets (in millions).

	December 31,
	2019		2018
Accumulated benefit obligation	$	2,760	$	2,253
Fair value of plan assets	2,402		1,974

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VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Benefit payments that we expect to pay, including amounts related to expected future services that we expect to receive, are as follows for the years ending December 31 (in millions):

	Pension Benefits		Other Postretirement Benefits
2020	$	179	$	21
2021	219		20
2022	190		20
2023	204		19
2024	205		19
2025-2029	1,105		88

We plan to contribute approximately $140 million to our pension plans and $21 million to our other postretirement benefit plans during 2020.

The components of net periodic benefit cost (credit) related to our defined benefit plans were as follows (in millions):

	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018			2017
Service cost	$	119		$	133		$	123		$	5		$	6		$	6
Interest cost	98			91			86			11			10			10
Expected return on plan assets	(166		)	(163		)	(150		)	—			—			—
Amortization of:
Net actuarial (gain) loss	41			65			53			(3		)	(2		)	(3		)
Prior service credit	(19		)	(18		)	(20		)	(9		)	(11		)	(16		)
Special charges	4			7			4			1			—			—
Net periodic benefit cost (credit)	$	77		$	115		$	96		$	5		$	3		$	(3	)

The components of net periodic benefit cost (credit) other than the service cost component (i.e., the non-service cost components) are included in “other income, net” in the statements of income.

Amortization of prior service credit shown in the preceding table was based on a straight-line amortization of the cost over the average remaining service period of employees expected to receive benefits under each respective plan. Amortization of the net actuarial (gain) loss shown in the preceding table was based on the straight-line amortization of the excess of the unrecognized (gain) loss over 10 percent of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under each respective plan.

104

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Pre-tax amounts recognized in other comprehensive income (loss) were as follows (in millions):

	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018			2017
Net gain (loss) arising during the year:
Net actuarial gain (loss)	$	(204	)	$	(8	)	$	(73	)	$	(41	)	$	9		$	(6	)
Prior service (cost) credit	—			7			(4		)	(3		)	—			—
Net (gain) loss reclassified into income:
Net actuarial (gain) loss	41			65			53			(3		)	(2		)	(3		)
Prior service credit	(19		)	(18		)	(20		)	(9		)	(11		)	(16		)
Curtailment and settlement loss	4			7			4			—			—			—
Total changes in other comprehensive income (loss)	$	(178	)	$	53		$	(40	)	$	(56	)	$	(4	)	$	(25	)

The pre-tax amounts in accumulated other comprehensive loss that have not yet been recognized as components of net periodic benefit cost (credit) were as follows (in millions):

	Pension Plans						Other Postretirement Benefit Plans
	December 31,						December 31,
	2019			2018			2019			2018
Net actuarial (gain) loss	$	988		$	828		$	(20	)	$	(64	)
Prior service credit	(90		)	(108		)	(19		)	(31		)
Total	$	898		$	720		$	(39	)	$	(95	)

The weighted-average assumptions used to determine the benefit obligations were as follows:

	Pension Plans				Other Postretirement Benefit Plans
	December 31,				December 31,
	2019		2018		2019		2018
Discount rate	3.14	%	4.25	%	3.32	%	4.40	%
Rate of compensation increase	3.75	%	3.78	%	n/a		n/a
Interest crediting rate for cash balance plans	3.03	%	3.04	%	n/a		n/a

The discount rate assumption used to determine the benefit obligations as of December 31, 2019 and 2018 for the majority of our pension plans and other postretirement benefit plans was based on the Aon AA Only Above Median yield curve and considered the timing of the projected cash outflows under our plans. This curve was designed by Aon to provide a means for plan sponsors to value the liabilities of their pension plans

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

or postretirement benefit plans. It is a hypothetical double-A yield curve represented by a series of annualized individual discount rates with maturities from one-half year to 99 years. Each bond issue underlying the curve is required to have an average rating of double-A when averaging all available ratings by Moody’s Investors Service, Standard & Poor’s Ratings Services, and Fitch Ratings. Only the bonds representing the 50 percent highest yielding issuances among those with average ratings of double-A are included in this yield curve.

We based our discount rate assumption on the Aon AA Only Above Median yield curve because we believe it is representative of the types of bonds we would use to settle our pension and other postretirement benefit plan liabilities as of those dates. We believe that the yields associated with the bonds used to develop this yield curve reflect the current level of interest rates.

The weighted-average assumptions used to determine the net periodic benefit cost were as follows:

	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2019		2018		2017		2019		2018		2017
Discount rate	4.24	%	3.59	%	4.08	%	4.40	%	3.72	%	4.26	%
Expected long-term rate of return on plan assets	7.22	%	7.24	%	7.29	%	n/a		n/a		n/a
Rate of compensation increase	3.78	%	3.86	%	3.81	%	n/a		n/a		n/a
Interest crediting rate for cash balance plans	3.04	%	3.04	%	3.04	%	n/a		n/a		n/a

The assumed health care cost trend rates were as follows:

	December 31,
	2019		2018
Health care cost trend rate assumed for the next year	7.32	%	7.29	%
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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables present the fair values of the assets of our pension plans (in millions) as of December 31, 2019 and 2018 by level of the fair value hierarchy. Assets categorized in Level 1 of the hierarchy are measured at fair value using a market approach based on unadjusted quoted prices from national securities exchanges. Assets categorized in Level 2 of the hierarchy are measured at net asset value in a market that is not active. As previously noted, we do not fund or fully fund U.S. nonqualified and certain international pension plans that are not subject to funding requirements, and we do not fund our other postretirement benefit plans.

	Fair Value Hierarchy							Total as of December 31, 2019
	Level 1			Level 2		Level 3
Equity securities:
U.S. companies (a)	$	622		$	—	$	—	$	622
International companies	205			1		—		206
Preferred stock	4			—		—		4
Mutual funds:
International growth	123			—		—		123
Index funds	90			—		—		90
Corporate debt instruments (a)	—			293		—		293
Government securities:
U.S. Treasury securities	53			—		—		53
Other government securities	—			148		—		148
Common collective trusts (b)	—			751		—		751
Pooled separate accounts	—			250		—		250
Private funds	—			104		—		104
Insurance contract	—			17		—		17
Interest and dividends receivable	5			—		—		5
Cash and cash equivalents	59			—		—		59
Securities transactions payable, net	(16		)	—		—		(16		)
Total pension plan assets	$	1,145		$	1,564	$	—	$	2,709

^{___________________________} 

See notes on page 108.

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VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	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	76			—		—		76
Corporate debt instruments (a)	—			284		—		284
Government securities:
U.S. Treasury securities	45			—		—		45
Other government securities	—			138		—		138
Common collective trusts (b)	—			609		—		609
Pooled separate accounts	—			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

^{__________________________________} 

(a) This class of securities is held in a wide range of industrial sectors.

(b) This class includes primarily investments in approximately 75 percent equities and 25 percent bonds as of December 31, 2019. As of December 31, 2018, this class included primarily investments in approximately 70 percent equities and 30 percent bonds.

The investment policies and strategies for the assets of our pension plans incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk and the market value of the pension plans’ assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the pension plans’ mix of assets includes a diversified portfolio of equity and fixed-income investments. Equity securities include international stocks and a blend of U.S. growth and value stocks of various sizes of capitalization. Fixed income securities include bonds and notes issued by the U.S. government and its agencies, corporate bonds, and mortgage-backed securities. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2019, the target allocations for plan assets under our primary pension plan are 70 percent equity securities and 30 percent fixed income investments.

The expected long-term rate of return on plan assets is based on a forward-looking expected asset return model. This model derives an expected rate of return based on the target asset allocation of a plan’s assets.

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The underlying assumptions regarding expected rates of return for each asset class reflect Aon’s best expectations for these asset classes. The model reflects the positive effect of periodic rebalancing among diversified asset classes. We select an expected asset return that is supported by this model.

Defined Contribution Plans

We have defined contribution plans that cover most of our employees. Our contributions to these plans are based on employees’ compensation and/or a partial match of employee contributions to the plans. Our contributions to these defined contribution plans were $77 million, $74 million, and $70 million for the years ended December 31, 2019, 2018, and 2017, respectively.

14. STOCK-BASED COMPENSATION

Overview

Under our 2011 Omnibus Stock Incentive Plan (the OSIP), various stock and stock-based awards may be granted to employees and non-employee directors. Awards available under the OSIP include, but are not limited to, (i) restricted stock that vests over a period determined by our compensation committee, (ii) performance awards that vest upon the achievement of an objective performance goal, (iii) options to purchase shares of common stock, (iv) dividend equivalent rights, and (v) stock unit awards. The OSIP was approved by our stockholders on April 28, 2011 and re-approved by our stockholders on May 12, 2016. As of December 31, 2019, 7,740,665 shares of our common stock remained available to be awarded under the OSIP.

We also maintain another stock-based compensation plan under which previously granted equity awards remain outstanding. NaN additional grants may be awarded under this plan.

The following table reflects activity related to our stock-based compensation arrangements (in millions):

	Year Ended December 31,
	2019		2018		2017
Stock-based compensation expense:
Restricted stock	$	64	$	63	$	58
Performance awards	23		22		19
Stock options and other awards	2		1		—
Total stock-based compensation expense	$	89	$	86	$	77
Tax benefit recognized on stock-based compensation expense	$	19	$	18	$	27
Tax benefit realized for tax deductions resulting from exercises and vestings	17		32		44
Effect of tax deductions in excess of recognized stock-based compensation expense	7		20		24

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a discussion of our significant stock-based compensation arrangement.

Restricted Stock

Restricted stock is granted to employees and non-employee directors. Restricted stock granted to employees vests in accordance with individual written agreements between the participants and us, usually in equal annual installments over a period of three years beginning one year after the date of grant. Restricted stock granted to our non-employee directors vests in equal annual installments over a period of three years beginning one year after the date of grant. The fair value of each restricted stock per share is equal to the market price of our common stock. A summary of the status of our restricted stock awards is presented in the following table.

	Number of Shares		Weighted- Average Grant-Date Fair Value Per Share
Nonvested shares as of January 1, 2019	1,176,578		$	80.70
Granted	677,482		98.75
Vested	(757,217	)	78.54
Forfeited	(4,989	)	83.18
Nonvested shares as of December 31, 2019	1,091,854		93.38

As of December 31, 2019, there was $59 million of unrecognized compensation cost related to outstanding unvested restricted stock awards, which is expected to be recognized over a weighted-average period of approximately two years.

The following table reflects activity related to our restricted stock:

	Year Ended December 31,
	2019		2018		2017
Weighted-average grant-date fair value per share of restricted stock granted	$	98.75	$	92.12	$	79.32
Fair value of restricted stock vested (in millions)	74		80		71

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VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. INCOME TAXES

Income Statement Components

Income before income tax expense (benefit) was as follows (in millions):

	Year Ended December 31,
	2019		2018		2017
U.S. operations	$	2,496	$	3,168	$	2,283
International operations	990		1,064		924
Income before income tax expense (benefit)	$	3,486	$	4,232	$	3,207

Statutory income tax rates applicable to the countries in which we operate were as follows:

	Year Ended December 31,
	2019		2018		2017
U.S.	21	%	21	%	35	%
Canada	15	%	15	%	15	%
U.K.	19	%	19	%	19	%
Ireland	13	%	13	%	13	%
Peru	30	%	30	%	n/a
Mexico	30	%	30	%	n/a

The following is a reconciliation of income tax expense (benefit) computed by applying statutory income tax rates as reflected in the preceding table to actual income tax expense (benefit) (in millions):

	U.S.					International					Total
	Amount			Percent		Amount			Percent		Amount			Percent
Year ended December 31, 2019
Income tax expense at statutory rates	$	524		21.0	%	$	147		14.8	%	$	671		19.2	%
U.S. state and Canadian provincial tax expense, net of federal income tax effect	16			0.7	%	88			8.9	%	104			3.0	%
Permanent differences	(36		)	(1.5	)%	10			1.0	%	(26		)	(0.7	)%
GILTI tax (a)	115			4.6	%	—			—		115			3.3	%
Foreign tax credits	(95		)	(3.8	)%	—			—		(95		)	(2.7	)%
Repatriation withholding tax	45			1.8	%	—			—		45			1.3	%
Tax effects of income associated with noncontrolling interests	(77		)	(3.1	)%	2			0.2	%	(75		)	(2.2	)%
Other, net	(36		)	(1.4	)%	(1		)	(0.1	)%	(37		)	(1.1	)%
Income tax expense	$	456		18.3	%	$	246		24.8	%	$	702		20.1	%

^{__________________________} 

(a) See note on page 112.

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VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	U.S.					International				Total
	Amount			Percent		Amount		Percent		Amount			Percent
Year ended December 31, 2018
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 (a)	67			2.1	%	—		—		67			1.6	%
Foreign tax credits	(50		)	(1.6	)%	—		—		(50		)	(1.2	)%
Effects of Tax Reform (a)	(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
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 (a)	(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	)%

^{__________________________} 

(a) See “Tax Reform” below for a discussion of the changes in tax law in the U.S. that were enacted in December 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Components of income tax expense (benefit) were as follows (in millions):

	U.S.				International			Total
Year ended December 31, 2019
Current:
Country	$	145			$	186		$	331
U.S. state / Canadian provincial	37				100			137
Total current	182				286			468
Deferred:
Country	290				(28		)	262
U.S. state / Canadian provincial	(16		)		(12		)	(28		)
Total deferred	274				(40		)	234
Income tax expense	$	456			$	246		$	702
Year ended December 31, 2018
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
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” below.

(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” below.

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Income Taxes Paid (Refunded)

Income taxes paid to (received from) U.S. and international taxing authorities were as follows (in millions):

	Year Ended December 31,
	2019				2018		2017
U.S.	$	(298	)	(a)	$	1,016	$	239
International	182				345		171
Income taxes paid (refunded), net	$	(116	)		$	1,361	$	410

^{__________________________} 

(a) This amount includes a refund of $348 million, including interest, that we received related to the settlement of the combined audit of our U.S. federal income tax returns for 2010 and 2011. See “Tax Returns Under Audit – U.S. Federal” below.

Deferred Income Tax Assets and Liabilities

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows (in millions):

	December 31,
	2019			2018
Deferred income tax assets:
Tax credit carryforwards	$	683		$	644
Net operating losses (NOLs)	582			523
Inventories	141			101
Compensation and employee benefit liabilities	213			175
Environmental liabilities	69			71
Other	156			141
Total deferred income tax assets	1,844			1,655
Valuation allowance	(1,200		)	(1,111		)
Net deferred income tax assets	644			544
Deferred income tax liabilities:
Property, plant, and equipment	4,924			4,589
Deferred turnaround costs	331			316
Inventories	217			287
Investments	122			142
Other	153			172
Total deferred income tax liabilities	5,747			5,506
Net deferred income tax liabilities	$	5,103		$	4,962

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We had the following income tax credit and loss carryforwards as of December 31, 2019 (in millions):

	Amount		Expiration
U.S. state income tax credits (gross amount)	$	89	2020 through 2033
U.S. state income tax credits (gross amount)	17		Unlimited
U.S. foreign tax credits	598		2027
U.S. state NOLs (gross amount)	10,913		2020 through 2039

We have recorded a valuation allowance as of December 31, 2019 and 2018 due to uncertainties related to our ability to utilize some of our deferred income tax assets associated with our U.S. foreign tax credits and certain U.S. state income tax credits and NOLs before they expire. The valuation allowance is based on our estimates of future taxable income in the various jurisdictions in which we operate and the period over which deferred income tax assets will be recoverable. The valuation allowance increased by $89 million in 2019 primarily due to an increase in excess U.S. foreign tax credits as well as U.S. state income tax NOLs.

As a part of completing our accounting for Tax Reform in 2018 as described in “Tax Reform” below, we assessed our ability to use our foreign tax credits to offset the tax on the deemed repatriation of the accumulated earnings and profits of our international subsidiaries and concluded that our foreign tax credit carryforwards were not more likely than not to be realized, and we recorded a full valuation allowance against the deferred income tax asset associated with those carryforwards.

As described in “Tax Reform” below, one of the most significant changes in Tax Reform was the shift from a worldwide system of taxation to a hybrid territorial system. The shift to a hybrid territorial system allows us to distribute cash via a dividend from our international subsidiaries with a full dividend received deduction in the U.S. As a result, we will not recognize U.S. federal deferred taxes for the future tax consequences attributable to undistributed earnings of our international subsidiaries. However, there may be a cost to repatriate the undistributed earnings of certain of our international subsidiaries to us, including, but not limited to, withholding taxes imposed by certain international jurisdictions and U.S. state income taxes. As of December 31, 2019, the cumulative undistributed earnings of these subsidiaries that is considered permanently reinvested in those countries were approximately $4.2 billion. It is not practicable to estimate the amount of additional tax that would be payable on those earnings, if distributed.

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Unrecognized Tax Benefits

Change in Unrecognized Tax Benefits

The following is a reconciliation of the change in unrecognized tax benefits, excluding related interest and penalties, (in millions):

	Year Ended December 31,
	2019			2018			2017
Balance as of beginning of year	$	970		$	941		$	936
Additions for tax positions related to the current year	19			23			33
Additions for tax positions related to prior years	30			28			15
Reductions for tax positions related to prior years	(101		)	(19		)	(42		)
Reductions for tax positions related to the lapse of applicable statute of limitations	(14		)	(1		)	(1		)
Settlements	(7		)	(2		)	—
Balance as of end of year	$	897		$	970		$	941

Liability for Unrecognized Tax Benefits

The following is a reconciliation of unrecognized tax benefits to our liability for unrecognized tax benefits presented in our balance sheets (in millions).

	December 31,
	2019			2018
Unrecognized tax benefits	$	897		$	970
Tax refund claims not yet filed but that we intend to file	(29		)	(277		)
Interest and penalties	100			88
Liability for unrecognized tax benefits presented in our balance sheets	$	968		$	781

Our liability for unrecognized tax benefits is reflected in the following balance sheet line items (in millions):

	December 31,
	2019		2018
Income taxes payable	$	—	$	42
Other long-term liabilities	954		721
Deferred tax liabilities	14		18
Liability for unrecognized tax benefits presented in our balance sheets	$	968	$	781

As of December 31, 2019, our liability for unrecognized tax benefits includes $525 million of refund claims associated with taxes paid on incentive payments received from the U.S. federal government for blending biofuels into refined petroleum products. We recorded a tax refund receivable of $525 million in connection with our refund claims, but we also recorded a liability for unrecognized tax benefits of $525 million due to the complexity of this matter and uncertainties with respect to sustaining these refund claims. Therefore, our

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financial position, results of operations, and liquidity will not be negatively impacted if we are unsuccessful in sustaining these refund claims.

Other Disclosures

As of December 31, 2019 and 2018, there was $762 million and $807 million, respectively, of unrecognized tax benefits that if recognized would reduce our annual effective tax rate.

Interest and penalties incurred during the years ended December 31, 2019, 2018, and 2017 was immaterial.

Although reasonably possible, we do not anticipate that any of our tax audits will be resolved in 2020 that would result in a reduction in our liability for unrecognized tax benefits due to the tax positions being sustained or due to our agreement of their disallowance. Should any reductions occur, we do not expect they would have a significant impact on our financial statements because such reductions would not significantly affect our annual effective tax rate.

Tax Returns Under Audit

U.S. Federal

In 2019, we settled the combined audit related to our U.S. federal income tax returns for 2010 and 2011 and received a refund of $348 million, including interest. We did not have a significant change to our liability for unrecognized tax benefits upon settlement of the audit. As of December 31, 2019, our U.S. federal income tax returns for 2012 through 2015 were under audit by the IRS. The IRS has proposed adjustments and we are working with the IRS to resolve these matters. We believe that these matters will be resolved for amounts consistent with our liability for unrecognized tax benefits associated with these matters.

We have amended our U.S federal income tax returns for 2005 through 2011 to exclude from taxable income incentive payments received from the U.S. federal government for blending biofuels into refined petroleum products, and we have claimed $525 million in refunds. The 2005 through 2009 amended return refund claims have been disallowed by the IRS and we are currently evaluating our options to contest the disallowance of these adjustments. As noted above in the discussion of our liability for unrecognized tax benefits, an ultimate disallowance of these refund claims would not negatively impact our financial position, results of operations, and liquidity.

U.S. State

As of December 31, 2019, our California tax returns for 2004 through 2008 and 2011 through 2016 were under audit by the state of California. We do not expect the ultimate disposition of these audits will result in a material change to our financial position, results of operations, or liquidity. We believe these audits will be resolved for amounts consistent with the liability for unrecognized tax benefits associated with these audits.

International

As of December 31, 2019, our Canadian subsidiary’s federal tax returns for 2013 through 2016 were under audit by the Canada Revenue Agency (CRA) and our Quebec provincial tax returns for 2013 through 2016 were under audit by Revenue Quebec. We are currently protesting the proposed adjustments by the CRA for 2013 and 2014 and we do not expect the ultimate disposition of these adjustments will result in a material change to our financial position, results of operations, or liquidity.

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Tax Reform

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (Tax Reform) was enacted, which resulted in significant changes to the Code and was effective beginning on January 1, 2018. The most significant changes affecting us are as follows:

• reduction in the statutory income tax rate from 35 percent to 21 percent;

• assessment of a one-time transition tax on deemed repatriated earnings and profits from our international subsidiaries;

• shift from a worldwide system of taxation to a hybrid 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;

• deduction for all of the costs to acquire or construct certain business assets in the year they are placed in service through 2022; and

• repeal of the manufacturing deduction;

The following narrative describes the activity that occurred with respect to Tax Reform for the years ended December 31, 2017 and 2018.

We reflected an overall income tax benefit of $1.9 billion for the year ended December 31, 2017 with respect to Tax Reform as a result of the following:

• 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 paid in 2018.

• We accrued withholding tax of $47 million on a portion of the earnings of one of our international subsidiaries that we have deemed to not be permanently reinvested in our operations in that country.

Because of the significant and complex changes to the Code from Tax Reform, including the need for regulatory guidance from the IRS to properly account for many of the provisions, the SEC issued Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” which required that the effects of Tax Reform be recorded for items where the accounting was complete, as well as for items where a reasonable estimate could be made (referred to as provisional amounts). For items where reasonable estimates could not be made, provisional amounts were not recorded and those items continued to be accounted for under the Code prior to changes from Tax Reform until a reasonable estimate could be made.

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The following table summarizes the components of our adjustment (in millions) to reflect the effects of Tax Reform for the years ended December 31, 2018 and 2017, including whether such amounts were complete, provisional, or incomplete. The amounts presented for 2018 were completed during the fourth quarter of 2018.

	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	)

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16. EARNINGS PER COMMON SHARE

Earnings per common share were computed as follows (dollars and shares in millions, except per share amounts):

	Year Ended December 31,
	2019		2018		2017
Earnings per common share
Net income attributable to Valero stockholders	$	2,422	$	3,122	$	4,065
Less: Income allocated to participating securities	7		9		14
Net income available to common shareholders	$	2,415	$	3,113	$	4,051
Weighted-average common shares outstanding	413		426		442
Earnings per common share	$	5.84	$	7.30	$	9.17
Earnings per common share – assuming dilution
Net income attributable to Valero stockholders	$	2,422	$	3,122	$	4,065
Weighted-average common shares outstanding	413		426		442
Effect of dilutive securities	1		2		2
Weighted-average common shares outstanding – assuming dilution	414		428		444
Earnings per common share – assuming dilution	$	5.84	$	7.29	$	9.16

Participating securities include restricted stock and performance awards granted under our 2011 Omnibus Stock Incentive Plan. Dilutive securities include participating securities as well as outstanding stock options granted under our 2011 Omnibus Stock Incentive Plan.

17. REVENUES AND SEGMENT INFORMATION

Revenue from Contracts with Customers

Disaggregation of Revenue

Revenue is presented in the table below under “Segment Information” disaggregated by product because this is the level of disaggregation that management has determined to be beneficial to users of our financial statements.

Receivables from Contracts with Customers

Our receivables from contracts with customers are included in “receivables, net” as presented in Note 3.

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Contract Liabilities from Contracts with Customers

Our contract liabilities from contracts with customers are included in accrued expenses as presented in Note 8. Substantially all of the contract liabilities as of December 31, 2018 were recognized into revenue during the year ended December 31, 2019.

Remaining Performance Obligations

We have spot and term contracts with customers, the majority of which are spot contracts with no remaining performance obligations. We do not disclose remaining performance obligations for contracts that have terms of one year or less. The transaction price for our remaining term contracts includes a fixed component and variable consideration (i.e., a commodity price), both of which are allocated entirely to a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation. The fixed component is not material and the variable consideration is highly uncertain. Therefore, as of December 31, 2019, we have not disclosed the aggregate amount of the transaction price allocated to our remaining performance obligations.

Segment Information

Effective January 1, 2019, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, we created a new reportable segment — renewable diesel — because of the growing importance of renewable fuels in the market and the growth of our investments in renewable fuels production. The renewable diesel segment includes the operations of DGD, which were transferred from the refining segment on January 1, 2019. Also effective January 1, 2019, we no longer have a VLP segment, and we include the operations of VLP in our refining segment. This change was made because of the Merger Transaction with VLP, as described in Note 2, and the resulting change in how we manage VLP’s operations. We no longer manage VLP as a business but as logistics assets that support the operations of our refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation.

We have 3 reportable segments — refining, ethanol, and renewable diesel. Each segment is a strategic business unit that offers different products and services by employing unique technologies and marketing strategies and whose operations and operating performance are managed and evaluated separately. Operating performance is measured based on the operating income generated by the segment, which includes revenues and expenses that are directly attributable to the management of the respective segment. Intersegment sales are generally derived from transactions made at prevailing market rates. The following is a description of each segment’s business operations.

• The refining segment includes the operations of our 15 petroleum refineries, the associated marketing activities, and logistics assets that support our refining operations. The principal products manufactured by our refineries and sold by this segment include gasolines and blendstocks, distillates, and other 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. This segment sells some ethanol to the refining segment for blending into gasoline, which is sold to that segment’s customers as a finished gasoline product.

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• The renewable diesel segment includes the operations of DGD, our consolidated joint venture as discussed in Note 12. The principal product manufactured by DGD and sold by this segment is renewable diesel. This segment sells some renewable diesel to the refining segment, which is then sold to that segment’s customers.

Operations that are not included in any of the reportable segments are included in the corporate category.

The following tables reflect information about our operating income and total expenditures for long-lived assets by reportable segment (in millions):

	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Year ended December 31, 2019
Revenues:
Revenues from external customers	$	103,746	$	3,606	$	970	$	2		$	108,324
Intersegment revenues	18		231		247		(496		)	—
Total revenues	103,764		3,837		1,217		(494		)	108,324
Cost of sales:
Cost of materials and other	93,371		3,239		360		(494		)	96,476
Operating expenses (excluding depreciation and amortization expense reflected below)	4,289		504		75		—			4,868
Depreciation and amortization expense	2,062		90		50		—			2,202
Total cost of sales	99,722		3,833		485		(494		)	103,546
Other operating expenses	20		1		—		—			21
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		868			868
Depreciation and amortization expense	—		—		—		53			53
Operating income by segment	$	4,022	$	3	$	732	$	(921	)	$	3,836
Total expenditures for long-lived assets (a)	$	2,581	$	47	$	160	$	58		$	2,846

^{__________________________} 

(a) See note on page 123.

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	Refining		Ethanol		Renewable Diesel		Corporate and Eliminations			Total
Year ended December 31, 2018
Revenues:
Revenues from external customers	$	113,093	$	3,428	$	508	$	4		$	117,033
Intersegment revenues	25		210		170		(405		)	—
Total revenues	113,118		3,638		678		(401		)	117,033
Cost of sales:
Cost of materials and other	101,866		3,008		262		(404		)	104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154		470		66		—			4,690
Depreciation and amortization expense	1,910		78		29		—			2,017
Total cost of sales	107,930		3,556		357		(404		)	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	$	5,143	$	82	$	321	$	(974	)	$	4,572
Total expenditures for long-lived assets (a)	$	2,767	$	373	$	192	$	44		$	3,376

Year ended December 31, 2017
Revenues:
Revenues from external customers	$	90,258	$	3,324	$	393	$	5		$	93,980
Intersegment revenues	8		176		241		(425		)	—
Total revenues	90,266		3,500		634		(420		)	93,980
Cost of sales:
Cost of materials and other	80,160		2,804		498		(425		)	83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	4,014		443		47		—			4,504
Depreciation and amortization expense	1,824		81		29		—			1,934
Total cost of sales	85,998		3,328		574		(425		)	89,475
Other operating expenses	61		—		—		—			61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		829			829
Depreciation and amortization expense	—		—		—		52			52
Operating income by segment	$	4,207	$	172	$	60	$	(876	)	$	3,563
Total expenditures for long-lived assets (a)	$	1,732	$	84	$	88	$	44		$	1,948

^{__________________________} 

(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.

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The following table provides a disaggregation of revenues from external customers for our principal products by reportable segment (in millions).

	Year Ended December 31,
	2019		2018		2017
Refining:
Gasolines and blendstocks	$	42,798	$	46,596	$	40,347
Distillates	51,942		55,037		41,680
Other product revenues	9,006		11,460		8,231
Total refining revenues	103,746		113,093		90,258
Ethanol:
Ethanol	2,889		2,713		2,764
Distillers grains	717		715		560
Total ethanol revenues	3,606		3,428		3,324
Renewable diesel:
Renewable diesel	970		508		393
Corporate – other revenues	2		4		5
Revenues	$	108,324	$	117,033	$	93,980

Revenues by geographic area are shown in the following table (in millions). The geographic area is based on location of customer and no customer accounted for 10 percent or more of our revenues.

	Year Ended December 31,
	2019		2018		2017
U.S.	$	77,173	$	82,992	$	66,614
Canada	7,915		9,211		7,039
U.K. and Ireland	13,584		15,208		11,556
Other countries	9,652		9,622		8,771
Revenues	$	108,324	$	117,033	$	93,980

Long-lived assets include property, plant, and equipment and certain long-lived assets included in “deferred charges and other assets, net.” Long-lived assets by geographic area consisted of the following (in millions):

	December 31,
	2019		2018
U.S.	$	27,485	$	27,475
Canada	1,886		1,798
U.K. and Ireland	1,232		1,113
Other countries	497		266
Total long-lived assets	$	31,100	$	30,652

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Total assets by reportable segment were as follows (in millions):

	December 31,
	2019		2018
Refining	$	47,067	$	43,488
Ethanol	1,615		1,691
Renewable diesel	1,412		787
Corporate and eliminations	3,770		4,189
Total assets	$	53,864	$	50,155

As of December 31, 2019 and 2018, our investments in unconsolidated joint ventures accounted for under the equity method were $942 million and $542 million, respectively, all of which related to the refining segment and are reflected in “deferred charges and other assets, net” as presented in Note 7.

18. SUPPLEMENTAL CASH FLOW INFORMATION

In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):

	Year Ended December 31,
	2019			2018			2017
Decrease (increase) in current assets:
Receivables, net	$	(1,468	)	$	(457	)	$	(870	)
Inventories	(385		)	(197		)	(516		)
Prepaid expenses and other	427			(77		)	151
Increase (decrease) in current liabilities:
Accounts payable	1,534			304			1,842
Accrued expenses	(27		)	(113		)	21
Taxes other than income taxes payable	60			(73		)	172
Income taxes payable	153			(684		)	489
Changes in current assets and current liabilities	$	294		$	(1,297	)	$	1,289

Cash flows related to interest and income taxes were as follows (in millions):

	Year Ended December 31,
	2019			2018		2017
Interest paid in excess of amount capitalized, including interest on finance leases	$	452		$	463	$	457
Income taxes paid (refunded), net (see Note 15)	(116		)	1,361		410

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplemental cash flow information related to our operating and finance leases was as follows (in millions):

	Year Ended December 31, 2019
	Operating Leases		Finance Leases
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows	$	441	$	50
Investing cash flows	1		—
Financing cash flows	—		34
Changes in lease balances resulting from new and modified leases (a)	1,756		239

___________________

(a) Includes noncash activity of $1.3 billion for operating lease ROU assets recorded on January 1, 2019 upon adoption of Topic 842.

Noncash investing and financing activities for the year ended December 31, 2019 also included the derecognition of the property, plant, and equipment and the related long-term liability associated with a build-to-suit lease arrangement with respect to the MVP Terminal, and the subsequent recognition of our investment in MVP, which is the unconsolidated joint venture that owns the MVP Terminal, as described in Note 10.

Noncash investing and financing activities for the years ended December 31, 2018 and 2017 included the recognition of (i) finance lease assets and related obligations primarily for the lease of storage tanks and (ii) terminal assets and related obligations under owner accounting as described in Note 10.

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19. FAIR VALUE MEASUREMENTS

General

U.S. GAAP requires or permits certain assets and liabilities to be measured at fair value on a recurring or nonrecurring basis in our balance sheets, and those assets and liabilities are presented below under “Recurring Fair Value Measurements” and “Nonrecurring Fair Value Measurements.” Assets and liabilities measured at fair value on a recurring basis, such as derivative financial instruments, are measured at fair value at the end of each reporting period. Assets and liabilities measured at fair value on a nonrecurring basis, such as the impairment of property, plant and equipment, are measured at fair value in particular circumstances.

U.S. GAAP also requires the disclosure of the fair values of financial instruments when an option to elect fair value accounting has been provided, but such election has not been made. A debt obligation is an example of such a financial instrument. The disclosure of the fair values of financial instruments not recognized at fair value in our balance sheet is presented below under “Other Financial Instruments.”

U.S. GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.

• 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.

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Recurring Fair Value Measurements

The following tables present information (in millions) about our assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of December 31, 2019 and 2018.

We have elected to offset the fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty, including any related cash collateral assets or obligations as shown below; however, fair value amounts by hierarchy level are presented in the following tables on a gross basis. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

	December 31, 2019
							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	$	617	$	—	$	—	$	617	$	(612	)	$	—		$	5	$	—
Foreign currency contracts	27		—		—		27		n/a			n/a			27		n/a
Investments of certain benefit plans	65		—		9		74		n/a			n/a			74		n/a
Total	$	709	$	—	$	9	$	718	$	(612	)	$	—		$	106
Liabilities
Commodity derivative contracts	$	668	$	—	$	—	$	668	$	(612	)	$	(56	)	$	—	$	(84	)
Environmental credit obligations	—		2		—		2		n/a			n/a			2		n/a
Physical purchase contracts	—		3		—		3		n/a			n/a			3		n/a
Foreign currency contracts	10		—		—		10		n/a			n/a			10		n/a
Total	$	678	$	5	$	—	$	683	$	(612	)	$	(56	)	$	15

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	December 31, 2018
							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	$	2,792	$	—	$	—	$	2,792	$	(2,669	)	$	(34	)	$	89	$	—
Foreign currency contracts	4		—		—		4		n/a			n/a			4		n/a
Investments of certain benefit plans	60		—		9		69		n/a			n/a			69		n/a
Total	$	2,856	$	—	$	9	$	2,865	$	(2,669	)	$	(34	)	$	162
Liabilities
Commodity derivative contracts	$	2,681	$	—	$	—	$	2,681	$	(2,669	)	$	(12	)	$	—	$	(136	)
Environmental credit obligations	—		13		—		13		n/a			n/a			13		n/a
Physical purchase contracts	—		5		—		5		n/a			n/a			5		n/a
Foreign currency contracts	1		—		—		1		n/a			n/a			1		n/a
Total	$	2,682	$	18	$	—	$	2,700	$	(2,669	)	$	(12	)	$	19

A description of our assets and liabilities recognized at fair value along with the valuation methods and inputs we used to develop their fair value measurements are as follows:

• 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 a market approach 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.

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• Foreign currency contracts consist of foreign currency exchange and purchase contracts and foreign currency swap agreements related to our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of our operations. These contracts are valued based on quoted foreign currency exchange rates 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.

There were no transfers into or out of Level 3 for assets and liabilities held as of December 31, 2019 and 2018 that were measured at fair value on a recurring basis.

There was no significant activity during the years ended December 31, 2019, 2018, and 2017 related to the fair value amounts categorized in Level 3 as of December 31, 2019 and 2018.

Nonrecurring Fair Value Measurements

There were 0 assets or liabilities that were measured at fair value on a nonrecurring basis as of December 31, 2019 and 2018.

Other Financial Instruments

Financial instruments that we recognize in our balance sheets at their carrying amounts are shown in the following table along with their associated fair values (in millions):

		December 31, 2019				December 31, 2018
	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets
Cash and cash equivalents	Level 1	$	2,583	$	2,583	$	2,982	$	2,982
Financial liabilities
Debt (excluding finance leases)	Level 2	8,881		10,583		8,503		8,986

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20. PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks primarily related to the volatility in the price of commodities, foreign currency exchange rates, and the price of credits needed to comply with various government and regulatory programs. We enter into derivative instruments to manage some of these risks, including derivative instruments related to the various commodities we purchase or produce, and foreign currency exchange and purchase contracts, as described below under “Risk Management Activities by Type of Risk.” These derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 19), as summarized below under “Fair Values of Derivative Instruments.” The effect of these derivative instruments on our income is summarized below under “Effect of Derivative Instruments on Income.”

Risk Management Activities by Type of Risk

Commodity Price Risk

We are exposed to market risks related to the volatility in the price of crude oil, refined petroleum products (primarily gasoline and distillate), renewable diesel, grain (primarily corn), renewable diesel feedstocks, and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, such as futures and options. Our positions in commodity derivative instruments are monitored and managed on a daily basis by our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

We primarily use commodity derivative instruments as cash flow hedges and economic hedges. Our objectives for entering into each type of hedge is described below.

• Cash flow hedges – The objective of our cash flow hedges is to lock in the price of forecasted (i) feedstock, refined petroleum product, or natural gas purchases, or (ii) refined petroleum product or renewable diesel sales at existing market prices that we deem favorable.

• Economic hedges – Our objectives for holding economic hedges are to (i) manage price volatility in certain feedstock and refined petroleum product inventories and fixed-price purchase contracts, and (ii) lock in the price of forecasted feedstock, refined petroleum product, or natural gas purchases or refined petroleum product or renewable diesel sales at existing market prices that we deem favorable.

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As of December 31, 2019, we had the following outstanding commodity derivative instruments that were used as cash flow hedges and economic hedges, as well as commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except corn contracts that are presented in thousands of bushels).

	Notional Contract Volumes by Year of Maturity
	2020	2021
Derivatives designated as cash flow hedges
Renewable diesel:
Futures – long	995	—
Futures – short	2,492	—
Derivatives designated as economic hedges
Crude oil and refined petroleum products:
Futures – long	73,348	2
Futures – short	76,045	—
Options – long	1,550	—
Options – short	1,550	—
Corn:
Futures – long	50,120	—
Futures – short	66,575	295
Physical contracts – long	22,055	306

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions related to our international operations that are denominated in currencies other than the local (functional) currencies of our operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency contracts. These contracts are not designated as hedging instruments for accounting purposes and therefore are classified as economic hedges. As of December 31, 2019, we had foreign currency contracts to purchase $739 million of U.S. dollars and $2.3 billion of U.S. dollar equivalent Canadian dollars. All of these commitments matured on or before February 15, 2020.

Environmental Compliance Program Price Risk

We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory environmental compliance programs. To manage this risk, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. Certain of these programs require us to blend biofuels into the products we produce, and we are subject to such programs in most of the countries in which we operate. These countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at

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a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate, we must purchase biofuel credits (primarily RINs in the U.S.). We are exposed to the volatility in the market price of these credits, and we manage that risk by purchasing biofuel credits when prices are deemed favorable. For the years ended December 31, 2019, 2018, and 2017, the cost of meeting our obligations under these compliance programs was $318 million, $536 million, and $942 million, respectively. These amounts are reflected in cost of materials and other.

We are subject to additional requirements under GHG emission programs, including the cap-and-trade systems, as discussed in Note 19. Under these cap-and-trade systems, we purchase various GHG emission credits available on the open market. Therefore, we are exposed to the volatility in the market price of these credits. The cost to implement certain provisions of the cap-and-trade systems are significant; however, we recovered the majority of these costs from our customers for the years ended December 31, 2019, 2018, and 2017 and expect to continue to recover the majority of these costs in the future. For the years ended December 31, 2019, 2018, and 2017, the net cost of meeting our obligations under these compliance programs was immaterial.

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of December 31, 2019 and 2018 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 19 for additional information related to the fair values of our derivative instruments.

As indicated in Note 19, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The following tables, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts.

	Balance Sheet Location	December 31, 2019				December 31, 2018
		Asset Derivatives		Liability Derivatives		Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts	Receivables, net	$	9	$	20	$	—	$	—
Derivatives not designated as hedging instruments
Commodity contracts	Receivables, net	$	608	$	648	$	2,792	$	2,681
Physical purchase contracts	Inventories	—		3		—		5
Foreign currency contracts	Receivables, net	27		—		4		—
Foreign currency contracts	Accrued expenses	—		10		—		1
Total		$	635	$	661	$	2,796	$	2,687

Market Risk

Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions

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may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by our risk control group to ensure compliance with our stated risk management policy. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.

Effect of Derivative Instruments on Income

The following table provides information about the gain (loss) recognized in income on our derivative instruments and the line items in the statements of income in which such gains (losses) are reflected (in millions).

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Year Ended December 31,
		2019			2018			2017
Commodity contracts	Revenues	$	5		$	—		$	—
Commodity contracts	Cost of materials and other	(68		)	(165		)	(278		)
Commodity contracts	Operating expenses (excluding depreciation and amortization expense)	—			7			—
Foreign currency contracts	Cost of materials and other	(21		)	56			(40		)
Foreign currency contracts	Other income, net	75			(43		)	—

21. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

In connection with the completion of the Merger Transaction as described in Note 2, Valero Energy Corporation, the parent company, entered into a guarantee agreement to fully and unconditionally guarantee the prompt payment, when due, of the following debt issued by Valero Energy Partners LP, an indirect wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of December 31, 2019:

•4.375 percent Senior Notes due December 15, 2026, and

•4.5 percent Senior Notes due March 15, 2028.

The following condensed consolidating financial information is provided as an alternative to providing separate financial statements for Valero Energy Partners LP, which has no independent assets or operations. The financial position, results of operations, and cash flows of Valero Energy Partners LP’s wholly owned subsidiaries are included in “Other Non-Guarantor Subsidiaries.” The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.

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Condensed Consolidating Balance Sheet

December 31, 2019

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP		Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	912		$	—	$	1,671		$	—		$	2,583
Receivables, net	—			—		8,904			—			8,904
Receivables from affiliates	4,336			—		13,806			(18,142		)	—
Inventories	—			—		7,013			—			7,013
Prepaid expenses and other	63			—		406			—			469
Total current assets	5,311			—		31,800			(18,142		)	18,969
Property, plant and equipment, at cost	—			—		44,294			—			44,294
Accumulated depreciation	—			—		(15,030		)	—			(15,030		)
Property, plant and equipment, net	—			—		29,264			—			29,264
Investment in affiliates	37,902			2,673		382			(40,957		)	—
Deferred charges and other assets, net	771			—		4,860			—			5,631
Total assets	$	43,984		$	2,673	$	66,306		$	(59,099	)	$	53,864
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and finance lease obligations	$	—		$	—	$	494		$	—		$	494
Accounts payable	—			—		10,205			—			10,205
Accounts payable to affiliates	12,515			1,291		4,336			(18,142		)	—
Accrued expenses	120			7		822			—			949
Taxes other than income taxes payable	—			—		1,304			—			1,304
Income taxes payable	108			—		100			—			208
Total current liabilities	12,743			1,298		17,261			(18,142		)	13,160
Debt and finance lease obligations, less current portion	7,095			991		1,092			—			9,178
Deferred income tax liabilities	—			2		5,101			—			5,103
Other long-term liabilities	2,343			—		1,544			—			3,887
Equity:
Stockholders’ equity:
Common stock	7			—		1			(1		)	7
Additional paid-in capital	6,821			—		9,771			(9,771		)	6,821
Treasury stock, at cost	(15,648		)	—		—			—			(15,648		)
Retained earnings	31,974			—		31,636			(31,636		)	31,974
Partners’ equity	—			382		—			(382		)	—
Accumulated other comprehensive loss	(1,351		)	—		(833		)	833			(1,351		)
Total stockholders’ equity	21,803			382		40,575			(40,957		)	21,803
Noncontrolling interests	—			—		733			—			733
Total equity	21,803			382		41,308			(40,957		)	22,536
Total liabilities and equity	$	43,984		$	2,673	$	66,306		$	(59,099	)	$	53,864

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Condensed Consolidating Balance Sheet

December 31, 2018

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP		Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	291		$	152	$	2,539		$	—		$	2,982
Receivables, net	—			—		7,345			—			7,345
Receivables from affiliates	4,369			2		10,684			(15,055		)	—
Inventories	—			—		6,532			—			6,532
Prepaid expenses and other	466			—		355			(5		)	816
Total current assets	5,126			154		27,455			(15,060		)	17,675
Property, plant and equipment, at cost	—			—		42,473			—			42,473
Accumulated depreciation	—			—		(13,625		)	—			(13,625		)
Property, plant and equipment, net	—			—		28,848			—			28,848
Investment in affiliates	34,696			2,267		(321		)	(36,642		)	—
Long-term notes receivable from affiliates	285			—		—			(285		)	—
Deferred charges and other assets, net	572			1		3,059			—			3,632
Total assets	$	40,679		$	2,422	$	59,041		$	(51,987	)	$	50,155
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and finance lease obligations	$	—		$	—	$	238		$	—		$	238
Accounts payable	14			—		8,580			—			8,594
Accounts payable to affiliates	9,847			837		4,370			(15,054		)	—
Accrued expenses	155			7		468			—			630
Accrued expenses to affiliates	—			1		—			(1		)	—
Taxes other than income taxes payable	—			—		1,213			—			1,213
Income taxes payable	53			1		—			(5		)	49
Total current liabilities	10,069			846		14,869			(15,060		)	10,724
Debt and finance lease obligations, less current portion	6,955			990		926			—			8,871
Long-term notes payable to affiliates	—			285		—			(285		)	—
Deferred income tax liabilities	—			2		4,960			—			4,962
Other long-term liabilities	1,988			—		879			—			2,867
Equity:
Stockholders’ equity:
Common stock	7			—		1			(1		)	7
Additional paid-in capital	7,048			—		9,754			(9,754		)	7,048
Treasury stock, at cost	(14,925		)	—		—			—			(14,925		)
Retained earnings	31,044			—		28,305			(28,305		)	31,044
Partners’ equity	—			299		—			(299		)	—
Accumulated other comprehensive loss	(1,507		)	—		(1,097		)	1,097			(1,507		)
Total stockholders’ equity	21,667			299		36,963			(37,262		)	21,667
Noncontrolling interests	—			—		444			620			1,064
Total equity	21,667			299		37,407			(36,642		)	22,731
Total liabilities and equity	$	40,679		$	2,422	$	59,041		$	(51,987	)	$	50,155

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Condensed Consolidating Statement of Income

Year Ended December 31, 2019

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	108,324		$	—		$	108,324
Cost of sales:
Cost of materials and other	—			—			96,476			—			96,476
Operating expenses (excluding depreciation and amortization expense reflected below)	—			—			4,868			—			4,868
Depreciation and amortization expense	—			—			2,202			—			2,202
Total cost of sales	—			—			103,546			—			103,546
Other operating expenses	—			—			21			—			21
General and administrative expenses (excluding depreciation and amortization expense reflected below)	6			—			862			—			868
Depreciation and amortization expense	—			—			53			—			53
Operating income (loss)	(6		)	—			3,842			—			3,836
Equity in earnings of subsidiaries	3,006			406			357			(3,769		)	—
Other income, net	193			—			625			(714		)	104
Interest and debt expense, net of capitalized interest	(927		)	(47		)	(194		)	714			(454		)
Income before income tax expense (benefit)	2,266			359			4,630			(3,769		)	3,486
Income tax expense (benefit)	(156		)	—			858			—			702
Net income	2,422			359			3,772			(3,769		)	2,784
Less: Net income attributable to noncontrolling interests	—			—			360			2			362
Net income attributable to stockholders	$	2,422		$	359		$	3,412		$	(3,771	)	$	2,422

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Condensed Consolidating Statement of Income

Year Ended December 31, 2018

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	117,033		$	—		$	117,033
Cost of sales:
Cost of materials and other	—			—			104,732			—			104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	—			—			4,690			—			4,690
Depreciation and amortization expense	—			—			2,017			—			2,017
Total cost of sales	—			—			111,439			—			111,439
Other operating expenses	—			—			45			—			45
General and administrative expenses (excluding depreciation and amortization expense reflected below)	2			—			923			—			925
Depreciation and amortization expense	—			—			52			—			52
Operating income (loss)	(2		)	—			4,574			—			4,572
Equity in earnings of subsidiaries	3,724			319			196			(4,239		)	—
Other income, net	220			2			621			(713		)	130
Interest and debt expense, net of capitalized interest	(913		)	(55		)	(215		)	713			(470		)
Income before income tax expense (benefit)	3,029			266			5,176			(4,239		)	4,232
Income tax expense (benefit)	(93		)	2			970			—			879
Net income	3,122			264			4,206			(4,239		)	3,353
Less: Net income attributable to noncontrolling interests	—			—			163			68			231
Net income attributable to stockholders	$	3,122		$	264		$	4,043		$	(4,307	)	$	3,122

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Income

Year Ended December 31, 2017

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	93,980		$	—		$	93,980
Cost of sales:
Cost of materials and other	—			���			83,037			—			83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	—			—			4,504			—			4,504
Depreciation and amortization expense	—			—			1,934			—			1,934
Total cost of sales	—			—			89,475			—			89,475
Other operating expenses	—			—			61			—			61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	6			—			823			—			829
Depreciation and amortization expense	—			—			52			—			52
Operating income (loss)	(6		)	—			3,569			—			3,563
Equity in earnings of subsidiaries	5,236			275			176			(5,687		)	—
Other income, net	290			1			415			(594		)	112
Interest and debt expense, net of capitalized interest	(780		)	(36		)	(246		)	594			(468		)
Income before income tax expense (benefit)	4,740			240			3,914			(5,687		)	3,207
Income tax expense (benefit)	675			2			(1,626		)	—			(949		)
Net income	4,065			238			5,540			(5,687		)	4,156
Less: Net income attributable to noncontrolling interests	—			—			29			62			91
Net income attributable to stockholders	$	4,065		$	238		$	5,511		$	(5,749	)	$	4,065

139

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2019

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP		Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income	$	2,422		$	359	$	3,772		$	(3,769	)	$	2,784
Other comprehensive income:
Foreign currency translation adjustment	346			—		286			(283		)	349
Net loss on pension and other postretirement benefits	(234		)	—		(19		)	19			(234		)
Net loss on cash flow hedges	(4		)	—		(8		)	4			(8		)
Other comprehensive income before income tax benefit	108			—		259			(260		)	107
Income tax benefit related to items of other comprehensive income	(48		)	—		(4		)	4			(48		)
Other comprehensive income	156			—		263			(264		)	155
Comprehensive income	2,578			359		4,035			(4,033		)	2,939
Less: Comprehensive income attributable to noncontrolling interests	—			—		359			2			361
Comprehensive income attributable to stockholders	$	2,578		$	359	$	3,676		$	(4,035	)	$	2,578

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2018

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP		Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income	$	3,122		$	264	$	4,206		$	(4,239	)	$	3,353
Other comprehensive loss:
Foreign currency translation adjustment	(515		)	—		(419		)	417			(517		)
Net gain on pension and other postretirement benefits	49			—		18			(18		)	49
Other comprehensive loss before income tax expense	(466		)	—		(401		)	399			(468		)
Income tax expense related to items of other comprehensive loss	10			—		3			(3		)	10
Other comprehensive loss	(476		)	—		(404		)	402			(478		)
Comprehensive income	2,646			264		3,802			(3,837		)	2,875
Less: Comprehensive income attributable to noncontrolling interests	—			—		161			68			229
Comprehensive income attributable to stockholders	$	2,646		$	264	$	3,641		$	(3,905	)	$	2,646

140

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Comprehensive Income

Year Ended December 31, 2017

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP		Other Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net income	$	4,065		$	238	$	5,540	$	(5,687	)	$	4,156
Other comprehensive income:
Foreign currency translation adjustment	514			—		434		(434		)	514
Net gain (loss) on pension and other postretirement benefits	(65		)	—		4		(4		)	(65		)
Other comprehensive income before income tax expense (benefit)	449			—		438		(438		)	449
Income tax expense (benefit) related to items of other comprehensive income	(21		)	—		1		(1		)	(21		)
Other comprehensive income	470			—		437		(437		)	470
Comprehensive income	4,535			238		5,977		(6,124		)	4,626
Less: Comprehensive income attributable to noncontrolling interests	—			—		29		62			91
Comprehensive income attributable to stockholders	$	4,535		$	238	$	5,948	$	(6,186	)	$	4,535

141

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2019

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(131	)	$	(46	)	$	6,165		$	(457	)	$	5,531
Cash flows from investing activities:
Capital expenditures (excluding VIEs)	—			—			(1,627		)	—			(1,627		)
Capital expenditures of VIEs:
DGD	—			—			(142		)	—			(142		)
Other VIEs	—			—			(225		)	—			(225		)
Deferred turnaround and catalyst cost expenditures (excluding VIEs)	—			—			(762		)	—			(762		)
Deferred turnaround and catalyst cost expenditures of DGD	—			—			(18		)	—			(18		)
Investments in unconsolidated joint ventures	—			—			(164		)	—			(164		)
Acquisitions of ethanol plants	—			—			(3		)	—			(3		)
Acquisitions of undivided interests	—			—			(72		)	—			(72		)
Intercompany investing activities	395			2			(2,973		)	2,576			—
Other investing activities, net	—			—			12			—			12
Net cash provided by (used in) investing activities	395			2			(5,974		)	2,576			(3,001		)
Cash flows from financing activities:
Proceeds from debt issuances and borrowings (excluding VIEs)	992			—			900			—			1,892
Proceeds from borrowings of VIEs	—			—			239			—			239
Repayments of debt and finance lease obligations (excluding VIEs)	(871		)	—			(934		)	—			(1,805		)
Repayments of debt of VIEs	—			—			(6		)	—			(6		)
Intercompany financing activities	2,520			268			(212		)	(2,576		)	—
Purchases of common stock for treasury	(777		)	—			—			—			(777		)
Common stock dividends	(1,492		)	—			(81		)	81			(1,492		)
Acquisition of VLP publicly held common units	—			—			(950		)	—			(950		)
Distributions to noncontrolling interests and unitholders of VLP	—			(376		)	(70		)	376			(70		)
Other financing activities, net	(15		)	—			(13		)	—			(28		)
Net cash provided by (used in) financing activities	357			(108		)	(1,127		)	(2,119		)	(2,997		)
Effect of foreign exchange rate changes on cash	—			—			68			—			68
Net increase (decrease) in cash and cash equivalents	621			(152		)	(868		)	—			(399		)
Cash and cash equivalents at beginning of year	291			152			2,539			—			2,982
Cash and cash equivalents at end of year	$	912		$	—		$	1,671		$	—		$	2,583

142

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2018

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(1,207	)	$	(51	)	$	5,828		$	(199	)	$	4,371
Cash flows from investing activities:
Capital expenditures (excluding VIEs)	—			—			(1,463		)	—			(1,463		)
Capital expenditures of VIEs:
DGD	—			—			(165		)	—			(165		)
Other VIEs	—			—			(124		)	—			(124		)
Deferred turnaround and catalyst cost expenditures (excluding VIEs)	—			—			(888		)	—			(888		)
Deferred turnaround and catalyst cost expenditures of DGD	—			—			(27		)	—			(27		)
Investments in unconsolidated joint ventures	—			—			(181		)	—			(181		)
Peru Acquisition, net of cash acquired	—			—			(468		)	—			(468		)
Acquisitions of ethanol plants	—			—			(320		)	—			(320		)
Acquisitions of undivided interests	—			—			(212		)	—			(212		)
Minor acquisitions	—			—			(88		)	—			(88		)
Intercompany investing activities	758			102			(2,381		)	1,521			—
Other investing activities, net	—			—			8			—			8
Net cash provided by (used in) investing activities	758			102			(6,309		)	1,521			(3,928		)
Cash flows from financing activities:
Proceeds from debt issuances and borrowings (excluding VIEs)	750			498			10			—			1,258
Proceeds from borrowings of VIEs	—			—			109			—			109
Repayments of debt and finance lease obligations (excluding VIEs)	(787		)	(410		)	(156		)	—			(1,353		)
Repayments of debt of VIEs	—			—			(6		)	—			(6		)
Intercompany financing activities	2,106			190			(775		)	(1,521		)	—
Purchases of common stock for treasury	(1,708		)	—			—			—			(1,708		)
Common stock dividends	(1,369		)	—			(32		)	32			(1,369		)
Contributions to noncontrolling interests	—			—			32			—			32
Distributions to noncontrolling interests and unitholders of VLP	—			(215		)	(68		)	167			(116		)
Other financing activities, net	2			(4		)	(13		)	—			(15		)
Net cash provided by (used in) financing activities	(1,006		)	59			(899		)	(1,322		)	(3,168		)
Effect of foreign exchange rate changes on cash	—			—			(143		)	—			(143		)
Net increase (decrease) in cash and cash equivalents	(1,455		)	110			(1,523		)	—			(2,868		)
Cash and cash equivalents at beginning of year	1,746			42			4,062			—			5,850
Cash and cash equivalents at end of year	$	291		$	152		$	2,539		$	—		$	2,982

143

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2017

(in millions)

	Valero Energy Corporation			Valero Energy Partners LP			Other Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(73	)	$	(34	)	$	5,720		$	(131	)	$	5,482
Cash flows from investing activities:
Capital expenditures (excluding VIEs)	—			—			(1,269		)	—			(1,269		)
Capital expenditures of VIEs:
DGD	—			—			(84		)	—			(84		)
Other VIEs	—			—			(26		)	—			(26		)
Deferred turnaround and catalyst cost expenditures (excluding VIEs)	—			—			(519		)	—			(519		)
Deferred turnaround and catalyst cost expenditures of DGD	—			—			(4		)	—			(4		)
Investments in unconsolidated joint ventures	—			—			(406		)	—			(406		)
Acquisitions of undivided interests	—			—			(72		)	—			(72		)
Intercompany investing activities	(4,002		)	(187		)	(6,696		)	10,885			—
Other investing activities, net	—			—			(2		)	—			(2		)
Net cash used in investing activities	(4,002		)	(187		)	(9,078		)	10,885			(2,382		)
Cash flows from financing activities:
Proceeds from debt issuances and borrowings (excluding VIEs)	—			380			—			—			380
Repayments of debt and finance lease obligations (excluding VIEs)	—			—			(15		)	—			(15		)
Repayments of debt of VIEs	—			—			(6		)	—			(6		)
Intercompany financing activities	6,704			(63		)	4,244			(10,885		)	—
Purchases of common stock for treasury	(1,372		)	—			—			—			(1,372		)
Common stock dividends	(1,242		)	—			(10		)	10			(1,242		)
Contributions from noncontrolling interests	—			—			30			—			30
Distributions to noncontrolling interests and unitholders of VLP	—			(161		)	(27		)	121			(67		)
Other financing activities, net	10			36			(26		)	—			20
Net cash provided by financing activities	4,100			192			4,190			(10,754		)	(2,272		)
Effect of foreign exchange rate changes on cash	—			—			206			—			206
Net increase (decrease) in cash and cash equivalents	25			(29		)	1,038			—			1,034
Cash and cash equivalents at beginning of year	1,721			71			3,024			—			4,816
Cash and cash equivalents at end of year	$	1,746		$	42		$	4,062		$	—		$	5,850

144

VALERO ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. QUARTERLY FINANCIAL DATA (Unaudited)

The following tables summarize quarterly financial data for the years ended December 31, 2019 and 2018 (in millions, except per share amounts).

	2019 Quarter Ended
	March 31		June 30		September 30		December 31
Revenues	$	24,263	$	28,933	$	27,249	$	27,879
Gross profit (a)	533		1,123		1,119		2,003
Operating income	308		908		881		1,739
Net income	167		648		639		1,330
Net income attributable to Valero Energy Corporation stockholders	141		612		609		1,060
Earnings per common share	0.34		1.47		1.48		2.58
Earnings per common share – assuming dilution	0.34		1.47		1.48		2.58
	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

^{___________________________} 

(a) Gross profit is calculated as revenues less total cost of sales.

145

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2019.

Internal Control over Financial Reporting.

(a) Management’s Report on Internal Control over Financial Reporting.

The management report on Valero’s internal control over financial reporting required by Item 9A appears in Item 8 on page 59 of this report, and is incorporated herein by reference.

(b) Attestation Report of the Independent Registered Public Accounting Firm.

KPMG LLP’s report on Valero’s internal control over financial reporting appears in Item 8 beginning on page 62 of this report, and is incorporated herein by reference.

(c) Changes in Internal Control over Financial Reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEMS 10-14.

The information required by Items 10 through 14 of Form 10-K is incorporated herein by reference to the definitive proxy statement for our 2020 annual meeting of stockholders. We expect to file the proxy statement with the SEC on or before March 31, 2020.

146

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    1. Financial Statements. The following consolidated financial statements of Valero Energy Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:

	Page
Management’s report on internal control over financial reporting	59
Reports of independent registered public accounting firm	60
Consolidated balance sheets as of December 31, 2019 and 2018	64
Consolidated statements of income for the years ended December 31, 2019, 2018, and 2017	65
Consolidated statements of comprehensive income for the years ended December 31, 2019, 2018, and 2017	66
Consolidated statements of equity for the years ended December 31, 2019, 2018, and 2017	67
Consolidated statements of cash flows for the years ended December 31, 2019, 2018, and 2017	68
Notes to consolidated financial statements	69

2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits. Filed as part of this Form 10-K are the following exhibits:

++2.01	—	Agreement and Plan of Merger, dated as of October 18, 2018, by and among Valero Energy Corporation; Forest Merger Sub, LLC; Valero Energy Partners LP; and Valero Energy Partners GP LLC–incorporated by reference to Exhibit 2.1 to Valero’s Current Report on Form 8-K dated and filed October 18, 2018 (SEC File No. 1-13175).
3.01	—	Amended and Restated Certificate of Incorporation of Valero Energy Corporation, formerly known as Valero Refining and Marketing Company–incorporated by reference to Exhibit 3.1 to Valero’s Registration Statement on Form S-1 (SEC File No. 333-27013) filed May 13, 1997.
3.02	—	Certificate of Amendment (July 31, 1997) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 3.02 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
3.03	—	Certificate of Merger of Ultramar Diamond Shamrock Corporation with and into Valero Energy Corporation dated December 31, 2001–incorporated by reference to Exhibit 3.03 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
3.04	—	Amendment (effective December 31, 2001) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 3.1 to Valero’s Current Report on Form 8-K dated December 31, 2001, and filed January 11, 2002 (SEC File No. 1-13175).
3.05	—	Second Certificate of Amendment (effective September 17, 2004) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 3.04 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (SEC File No. 1-13175).
3.06	—	Certificate of Merger of Premcor Inc. with and into Valero Energy Corporation effective September 1, 2005–incorporated by reference to Exhibit 2.01 to Valero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (SEC File No. 1-13175).
3.07	—	Third Certificate of Amendment (effective December 2, 2005) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 3.07 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 1-13175).

147

3.08	—	Fourth Certificate of Amendment (effective May 24, 2011) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 4.8 to Valero’s Current Report on Form 8-K dated and filed May 24, 2011 (SEC File No. 1-13175).
3.09	—	Fifth Certificate of Amendment (effective May 13, 2016) to Restated Certificate of Incorporation of Valero Energy Corporation–incorporated by reference to Exhibit 3.02 to Valero’s Current Report on Form 8-K dated May 12, 2016, and filed May 18, 2016 (SEC File No. 1-13175).
3.10	—	Amended and Restated Bylaws of Valero Energy Corporation–incorporated by reference to Exhibit 3.01 to Valero’s Current Report on Form 8-K dated September 20, 2017 and filed September 21, 2017 (SEC File No. 1-13175).
4.01	—	Indenture dated as of December 12, 1997 between Valero Energy Corporation and The Bank of New York–incorporated by reference to Exhibit 3.4 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-56599) filed June 11, 1998.
4.02	—	First Supplemental Indenture dated as of June 28, 2000 between Valero Energy Corporation and The Bank of New York (including Form of 7 3/4% Senior Deferrable Note due 2005)–incorporated by reference to Exhibit 4.6 to Valero’s Current Report on Form 8-K dated June 28, 2000, and filed June 30, 2000 (SEC File No. 1-13175).
4.03	—	Indenture (Senior Indenture) dated as of June 18, 2004 between Valero Energy Corporation and Bank of New York–incorporated by reference to Exhibit 4.7 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
4.04	—	Form of Indenture related to subordinated debt securities–incorporated by reference to Exhibit 4.8 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
4.05	—	Indenture dated as of March 10, 2015 between Valero Energy Corporation and U.S. Bank National Association, as trustee-incorporated by reference to Exhibit 4.1 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-202635) filed March 10, 2015.
4.06	—	Indenture, dated as of November 30, 2016, between Valero Energy Partners LP, as issuer, and U.S. Bank National Association, as trustee–incorporated by reference to Exhibit 4.1 to Valero Energy Partners LP’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration File No. 333-208052) filed November 30, 2016.
4.07	—	First Supplemental Indenture (with Parent Guarantee), dated as of January 10, 2019, among Valero Energy Partners LP, as issuer; Valero Energy Corporation, as parent guarantor; and U.S. Bank National Association, as trustee–incorporated by reference to Exhibit 4.2 to Valero’s Current Report on Form 8-K dated and filed January 10, 2019 (SEC File No. 1-13175).
4.08	—	Specimen Certificate of Common Stock–incorporated by reference to Exhibit 4.1 to Valero’s Registration Statement on Form S-3 (SEC File No. 333-116668) filed June 21, 2004.
*4.09	—	Description of Valero Energy Corporation common stock, $0.01 par value.
+10.01	—	Valero Energy Corporation Annual Bonus Plan, amended and restated as of February 28, 2018–incorporated by reference to Exhibit 10.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2017 (SEC File No. 1-13175).
+10.02	—	Valero Energy Corporation 2005 Omnibus Stock Incentive Plan, amended and restated as of October 1, 2005–incorporated by reference to Exhibit 10.02 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2009 (SEC File No. 1-13175).
+10.03	—	Valero Energy Corporation 2011 Omnibus Stock Incentive Plan, amended and restated February 25, 2016–incorporated by reference to Exhibit 10.04 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2015 (SEC File No. 1-13175).
+10.04	—	Valero Energy Corporation Deferred Compensation Plan, amended and restated as of January 1, 2008–incorporated by reference to Exhibit 10.04 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).
+10.05	—	Valero Energy Corporation Amended and Restated Supplemental Executive Retirement Plan, amended and restated as of November 10, 2008–incorporated by reference to Exhibit 10.08 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2008 (SEC File No. 1-13175).

148

+10.06	—	Valero Energy Corporation Excess Pension Plan, as amended and restated effective December 31, 2011–incorporated by reference to Exhibit 10.10 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
+10.07	—	Form of Change of Control Severance Agreement (Tier I) between Valero Energy Corporation and executive officer–incorporated by reference to Exhibit 10.15 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
+10.08	—	Form of Change of Control Severance Agreement (Tier II) between Valero Energy Corporation and executive officer–incorporated by reference to Exhibit 10.16 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2013 (SEC File No. 1-13175).
+10.09	—	Form of Amendment (dated January 7, 2013) to Change of Control Severance Agreements (to eliminate excise tax gross-up benefit)–incorporated by reference to Exhibit 10.17 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
+10.10	—	Form of Change of Control Severance Agreement (Tier II-A) between Valero Energy Corporation and executive officer–incorporated by reference to Exhibit 10.02 to Valero’s Current Report on Form 8-K dated November 2, 2016, and filed November 7, 2016 (SEC File No. 1-13175).
+10.11	—	Schedule of Tier II-A Change of Control Agreements–incorporated by reference to Exhibit 10.11 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2018 (SEC File No. 1-13175).
+10.12	—	Form of Amendment (dated January 17, 2017) to Change of Control Severance Agreements, amending Section 9 thereof–incorporated by reference to Exhibit 10.01 to Valero’s Current Report on Form 8-K dated and filed January 17, 2017 (SEC File No. 1-13175).
*+10.13	—	Form of Performance Share Award Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan.
+10.14	—	Form of Stock Option Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan–incorporated by reference to Exhibit 10.21 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2011 (SEC File No. 1-13175).
+10.15	—	Form of Performance Stock Option Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan–incorporated by reference to Exhibit 10.21 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
+10.16	—	Form of Restricted Stock Agreement pursuant to the Valero Energy Corporation 2011 Omnibus Stock Incentive Plan–incorporated by reference to Exhibit 10.25 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2012 (SEC File No. 1-13175).
*+10.17	—	Long-Term Incentive Agreement dated as of December 18, 2019, between Valero Energy Corporation and R. Lane Riggs.
+10.18	—	Form of Stock Unit Award Agreement for Non-Employee Directors (standard)-incorporated by reference to Exhibit 10.01 to Valero’s Current Report on Form 8-K dated April 30, 2019, and filed May 1, 2019 (SEC File No. 1-13175).
+10.19	—	Form of Stock Unit Award Agreement for Non-Employee Directors (with one-year hold provision)-incorporated by reference to Exhibit 10.02 to Valero’s Current Report on Form 8-K dated April 30, 2019, and filed May 1, 2019 (SEC File No. 1-13175).
10.20	—	Fourth Amended and Restated Revolving Credit Agreement, dated as of March 19, 2019, among Valero Energy Corporation, as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent; and the lenders named therein–incorporated by reference to Exhibit 10.1 to Valero’s Current Report on Form 8-K dated March 19, 2019, and filed March 19, 2019 (SEC File No. 1-13175).
14.01	—	Code of Ethics for Senior Financial Officers–incorporated by reference to Exhibit 14.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File No. 1-13175).
*21.01	—	Valero Energy Corporation subsidiaries.
*23.01	—	Consent of KPMG LLP dated February 26, 2020.

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*24.01	—	Power of Attorney dated February 26, 2020 (on the signature page of this Form 10-K).
*31.01	—	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
*31.02	—	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
**32.01	—	Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002).
99.01	—	Audit Committee Pre-Approval Policy–incorporated by reference to Exhibit 99.01 to Valero’s Annual Report on Form 10-K for the year ended December 31, 2017 (SEC File No. 1-13175).
***101.INS	—	Inline XBRL Instance Document–the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
***101.SCH	—	Inline XBRL Taxonomy Extension Schema Document.
***101.CAL	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
***101.DEF	—	Inline XBRL Taxonomy Extension Definition Linkbase Document.
***101.LAB	—	Inline XBRL Taxonomy Extension Label Linkbase Document.
***101.PRE	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
***104	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________

* 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.

Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S-K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the SEC upon its request, copies of certain instruments, each relating to debt not exceeding 10 percent of the total assets of the registrant and its subsidiaries on a consolidated basis.

150

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VALERO ENERGY CORPORATION (Registrant)
By:	/s/ Joseph W. Gorder
	(Joseph W. Gorder)
	Chairman of the Board and Chief Executive Officer

Date: February 26, 2020

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POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Joseph W. Gorder, Donna M. Titzman, and Jason W. Fraser, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Joseph W. Gorder	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	February 26, 2020
(Joseph W. Gorder)
/s/ Donna M. Titzman	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 26, 2020
(Donna M. Titzman)
/s/ H. Paulett Eberhart	Director	February 26, 2020
(H. Paulett Eberhart)
/s/ Kimberly S. Greene	Director	February 26, 2020
(Kimberly S. Greene)
/s/ Deborah P. Majoras	Director	February 26, 2020
(Deborah P. Majoras)
/s/ Donald L. Nickles	Director	February 26, 2020
(Donald L. Nickles)
/s/ Philip J. Pfeiffer	Director	February 26, 2020
(Philip J. Pfeiffer)
/s/ Robert A. Profusek	Director	February 26, 2020
(Robert A. Profusek)
/s/ Stephen M. Waters	Director	February 26, 2020
(Stephen M. Waters)
/s/ Randall J. Weisenburger	Director	February 26, 2020
(Randall J. Weisenburger)
/s/ Rayford Wilkins, Jr.	Director	February 26, 2020
(Rayford Wilkins, Jr.)

152