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

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•	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.

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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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•	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.

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(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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(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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(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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•	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.

•	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;

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•	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.

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•	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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•	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.

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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.

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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.

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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.

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•	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.

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•	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.

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•	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.

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(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.

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(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.

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◦	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.

◦	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.

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◦	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.

◦	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.

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

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◦	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.

◦	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.

(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.

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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.

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◦	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.

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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.

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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.

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•	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.

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•	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.

(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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•	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.

•	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.

•	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.

•	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.

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•	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.

•	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.

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•	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.

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(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.

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•	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.

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

(b)	Excludes unamortized discounts and debt issuance costs.

(c)	As of December 31, 2019 and 2018, we had an interest rate swap associated with $36 million and $40 million, respectively, of our floating rate debt resulting in an effective interest rate of 3.85 percent as of each of those reporting dates. The fair value of the swap was immaterial for all periods presented.

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

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

•	Inspecting settlements with applicable taxing authorities; and

•	Assessing the expiration of applicable statutes of limitations.

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

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•	turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, ethanol plants, and renewable diesel plant, are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs;

•	fixed-bed catalyst costs, representing the cost of catalyst that is changed out at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function, are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst;

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

•	investments in unconsolidated joint ventures;

•	income taxes receivable;

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

•	goodwill.

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2.	MERGER AND ACQUISITIONS

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3.	RECEIVABLES

4.	INVENTORIES

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5.	LEASES

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

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

•	Rail Transportation includes railcars and related storage facilities;

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

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

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

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

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6.	PROPERTY, PLANT, AND EQUIPMENT

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7.	DEFERRED CHARGES AND OTHER ASSETS

8.	ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES

(a)	The current portion of repatriation tax liability is included in income taxes payable. As of December 31, 2019, the current portion of repatriation tax liability was $54 million. There was no current portion of repatriation tax liability as of December 31, 2018.

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9.	DEBT AND FINANCE LEASE OBLIGATIONS

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

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

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

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We issued $1.0 billion of 4.00 percent Senior Notes due April 1, 2029 (4.00 percent Senior Notes). Proceeds from this debt issuance totaled $992 million before deducting the underwriting discount and other debt issuance costs. The proceeds were used to redeem our 6.125 percent Senior Notes due February 1, 2020 (6.125 percent Senior Notes) for $871 million, or 102.48 percent of stated value, which includes an early redemption fee of $21 million that is reflected in “other income, net” in our statement of income for the year ended December 31, 2019.

•	In connection with the completion of the Merger Transaction as described in Note 2, Valero entered into a guarantee agreement to fully and unconditionally guarantee the prompt payment, when due, of any amount owed to the holders of VLP’s 4.375 percent Senior Notes due December 15, 2026 and 4.5 percent Senior Notes due March 15, 2028. See Note 21 for condensed consolidating financial statements.

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•

We issued $750 million of 4.35 percent Senior Notes due June 1, 2028. Proceeds from this debt issuance totaled $749 million before deducting the underwriting discount and other debt issuance costs. The proceeds were used to redeem our 9.375 percent Senior Notes due March 15, 2019 for $787 million, or 104.9 percent of stated value, which includes an early redemption fee of $37 million that is reflected in “other income, net” in our statement of income for the year ended December 31, 2018.

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VLP issued $500 million of 4.5 percent Senior Notes due March 15, 2028. Proceeds from this debt issuance totaled $498 million before deducting the underwriting discount and other debt issuance costs. The proceeds were available only to the operations of VLP and were used to repay the outstanding balance of $410 million on the VLP Revolver and $85 million on its notes payable to us, which is eliminated in consolidation.

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

10.	COMMITMENTS AND CONTINGENCIES

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11.	EQUITY

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(a)	These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost (credit), as discussed in Note 13.

12.	VARIABLE INTEREST ENTITIES

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

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•

Central Mexico Terminals is a collective group of three subsidiaries of Infraestructura Energetica Nova, S.A.B. de C.V. (IEnova), a Mexican company and subsidiary of Sempra Energy, a U.S. public company. We have terminaling agreements with Central Mexico Terminals that represent variable interests because we have determined them to be finance leases due to our exclusive use of the terminals. Although we do not have an ownership interest in the entities that own each of the three terminals, the finance leases convey to us (i) the power to direct the activities that most significantly impact the economic performance of all three terminals and (ii) the ability to influence the benefits received or the losses incurred by the terminals because of our use of the terminals. As a result, we determined each of the entities was a VIE and that we are the primary beneficiary of each. Substantially all of Central Mexico Terminals’ revenues will be derived from us; therefore, there is limited risk to us associated with Central Mexico Terminals’ operations.

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We also have financial interests in other entities that have been determined to be VIEs because the entities’ contractual arrangements transfer the power to us to direct the activities that most significantly impact their economic performance or reduce the exposure to operational variability and risk of loss created by the entity that otherwise would be held exclusively by the equity owners. Furthermore, we determined that we are the primary beneficiary of these VIEs because (i) certain contractual arrangements (exclusive of our ownership rights) provide us with the power to direct the activities that most significantly impact the economic performance of these entities and/or (ii) our 50 percent ownership interests provide us with significant economic rights and obligations.

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(a)

Prior to the completion of the Merger Transaction with VLP on January 10, 2019 as discussed in Note 2, VLP was a publicly traded master limited partnership that we had determined was a VIE. VLP was formed by us to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. As of December 31, 2018, we owned a 66.2 percent limited partner interest and a 2.0 percent general partner interest in VLP, and public unitholders owned a 31.8 percent limited partner interest. Upon completion of the Merger Transaction, VLP became our indirect wholly owned subsidiary and, as a result, was no longer a VIE.

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13.	EMPLOYEE BENEFIT PLANS

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(a)

Plan assets include only the assets associated with pension plans subject to legal minimum funding standards. Plan assets associated with U.S. nonqualified pension plans are not included here because they are not protected from our creditors and therefore cannot be reflected as a reduction from our obligations under the pension plans. As a result, the reconciliation of funded status does not reflect the effect of plan assets that exist for all of our defined benefit plans. See Note 19 for the assets associated with certain U.S. nonqualified pension plans.

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

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

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14.	STOCK-BASED COMPENSATION

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15.	INCOME TAXES

(a)	See note on page 112.

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

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(a)	Current income tax expense includes a $21 million benefit and a $781 million expense related to our Tax Reform adjustment for the years ended December 31, 2018 and 2017, respectively, as described in “Tax Reform” below.

(b)	Deferred income tax expense (benefit) includes a $9 million expense and a $2.6 billion benefit related to our Tax Reform adjustment for the years ended December 31, 2018 and 2017, respectively, as described in “Tax Reform” below.

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

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

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

•	shift from a worldwide system of taxation to a hybrid territorial system of taxation, resulting in a minimum tax on the income of international subsidiaries (the GILTI tax) rather than a tax deferral on such earnings in certain circumstances;

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

•	repeal of the manufacturing deduction;

•	We remeasured our U.S. deferred tax assets and liabilities using the 21 percent rate, which resulted in a tax benefit and a reduction to our net deferred tax liabilities of $2.6 billion.

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We recognized a one-time transition tax of $734 million on the deemed repatriation of previously undistributed accumulated earnings and profits of our international subsidiaries based on approximately $4.7 billion of the combined earnings and profits of our international subsidiaries that had not been distributed to us. This transition tax will be remitted to the Internal Revenue Service (IRS) over the eight-year period provided in the Code, with the first annual remittance paid in 2018.

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

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16.	EARNINGS PER COMMON SHARE

17.	REVENUES AND SEGMENT INFORMATION

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•	The refining segment includes the operations of our 15 petroleum refineries, the associated marketing activities, and logistics assets that support our refining operations. The principal products manufactured by our refineries and sold by this segment include gasolines and blendstocks, distillates, and other products.

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The ethanol segment includes the operations of our 14 ethanol plants, the associated marketing activities, and logistics assets that support our ethanol operations. The principal products manufactured by our ethanol plants are ethanol and distillers grains. This segment sells some ethanol to the refining segment for blending into gasoline, which is sold to that segment’s customers as a finished gasoline product.

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

(a)	See note on page 123.

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(a)	Total expenditures for long-lived assets includes amounts related to capital expenditures; deferred turnaround and catalyst costs; and property, plant, and equipment for acquisitions.

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18.	SUPPLEMENTAL CASH FLOW INFORMATION

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

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19.	FAIR VALUE MEASUREMENTS

•	Level 1 - Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.

•	Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

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Level 3 - Unobservable inputs for the asset or liability. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.

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•	Commodity derivative contracts consist primarily of exchange-traded futures, which are used to reduce the impact of price volatility on our results of operations and cash flows as discussed in Note 20. These contracts are measured at fair value using a market approach based on quoted prices from the commodity exchange and are categorized in Level 1 of the fair value hierarchy.

•	Physical purchase contracts represent the fair value of fixed-price corn purchase contracts. The fair values of these purchase contracts are measured using a market approach based on quoted prices from the commodity exchange or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.

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Investments of certain benefit plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The plan assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quoted prices from national securities exchanges. The plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.

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Foreign currency contracts consist of foreign currency exchange and purchase contracts and foreign currency swap agreements related to our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of our operations. These contracts are valued based on quoted foreign currency exchange rates and are categorized in Level 1 of the fair value hierarchy.

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Environmental credit obligations represent our liability for the purchase of (i) biofuel credits (primarily RINs in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce and (ii) emission credits under the California Global Warming Solutions Act (the California cap-and-trade system, also known as AB 32) and similar programs, (collectively, the cap-and-trade systems). To the degree we are unable to blend biofuels (such as ethanol and biodiesel) at percentages required under the biofuel programs, we must purchase biofuel credits to comply with these programs. Under the cap-and-trade systems, we must purchase emission credits to comply with these systems. These programs are described in Note 20 under “Environmental Compliance Program Price Risk.” The liability for environmental credits is based on our deficit for such credits as of the balance sheet date, if any, after considering any credits acquired or under contract, and is equal to the product of the credits deficit and the market price of these credits as of the balance sheet date. The environmental credit obligations are categorized in Level 2 of the fair value hierarchy and are measured at fair value using the market approach based on quoted prices from an independent pricing service.

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20.	PRICE RISK MANAGEMENT ACTIVITIES

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

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

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21.	CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

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22.	QUARTERLY FINANCIAL DATA (Unaudited)

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

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*	Filed herewith.

**	Furnished herewith.

***	Submitted electronically herewith.

+	Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto.

++	Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant agrees to furnish supplementally a copy of any such omitted schedule to the SEC upon request.

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