VALERO ENERGY CORP/TX - Annual Report: 2019 (Form 10-K)
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
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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 |
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(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.
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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.
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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 |
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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.
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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.
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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 |
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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 |
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(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. |
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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 | % |