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•	Refining segment includes our refining operations, the associated marketing activities, and certain logistics assets, which are not owned by VLP, that support our refining operations;

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

•	VLP segment includes the operations of VLP, which is a limited partnership that owns logistics assets that provide transportation and terminaling services to our refining segment.

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(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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(a)

Ethanol is commercially produced using either the wet mill or dry mill process. Wet milling involves separating the grain kernel into its component parts (germ, fiber, protein, and starch) prior to fermentation. In the dry mill process, the entire grain kernel is ground into flour. The starch in the flour is converted to ethanol during the fermentation process, creating carbon dioxide and distillers grains.

(b)

During fermentation, nearly all of the starch in the grain is converted into ethanol and carbon dioxide, while the remaining nutrients (proteins, fats, minerals, and vitamins) are concentrated to yield corn oil, modified distillers grains, or, after further drying, dried distillers grains. Distillers grains generally are an economical partial replacement for corn and soybeans in feeds for cattle, swine, and poultry. Corn oil is produced as fuel grade and feed grade (not for human consumption), and is sold primarily as a feedstock for biodiesel or renewable diesel production with a smaller percentage sold into animal feed markets.

(c)	The Bluffton, Lakota, and Riga plants were acquired from two subsidiaries of Green Plains Inc. in November 2018. The annual ethanol, DDG production, and corn processing capacities for these ethanol plants were only applicable for November and December of 2018.

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(a)	Capacity shown represents VLP’s 40 percent undivided interest in the pipeline segment. Total capacity for the pipeline segment is 150,000 BPD.

(b)	Capacity shown represents VLP’s 33⅓ percent undivided interest in the pipeline. Total capacity for the pipeline is 63,000 BPD.

(c)	Capacity shown represents VLP’s 33⅓ percent undivided interest in the pipeline connection. Total capacity for the pipeline connection is 98,400 BPD.

(d)	Portions of VLP’s Memphis logistics system pipelines are owned by Memphis Light, Gas and Water (MLGW), but they are operated and maintained exclusively by VLP under long-term arrangements with MLGW.

(e)	The Diamond pipeline is owned 50 percent by Valero and 50 percent by Plains All American Pipeline, L.P.

(f)	Capacity shown represents VLP’s 33⅓ percent undivided interest in the terminal. Total storage capacity is 499,000 barrels.

(g)	Capacity shown represents VLP’s 33⅓ percent undivided interest in the truck rack. Total capacity is 30,000 BPD.

(h)	Dock throughput is reflected in thousands of barrels per hour.

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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 Renewable Fuel Standard could adversely affect our performance;

•	Item 1A, “Risk Factors”—We may incur additional costs as a result of our use of rail cars for the transportation of crude oil and the products that we manufacture;

•	Item 3, “Legal Proceedings” under the caption “Environmental Enforcement Matters,” and;

•	Item 8, “Financial Statements and Supplementary Data” in Note 8 of Notes to Consolidated Financial Statements and Note 10 of Notes to Consolidated Financial Statements under the caption “Environmental Matters.”

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(a)

The shares reported in this column represent purchases settled in the fourth quarter of 2018 relating to (i) our purchases of shares in open-market transactions to meet our obligations under stock-based compensation plans and (ii) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our stock-based compensation plans.

(b)

On January 23, 2018, we announced that our board of directors authorized our purchase of up to $2.5 billion of our outstanding common stock (the 2018 Program), with no expiration date, which was in addition to the remaining amount available under a $2.5 billion program authorized on September 21, 2016 (the 2016 Program). During the fourth quarter of 2018, we completed our purchases under the 2016 Program. As of December 31, 2018, we had $2.2 billion remaining available for purchase under the 2018 Program.

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(a)	Assumes that an investment in Valero common stock and each index was $100 on December 31, 2013. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2013 through December 31, 2018.

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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 as described in Note 5 of Notes to Consolidated Financial Statements.

(c)	Includes a noncash lower of cost or market inventory valuation reserve adjustment that resulted in a net charge to our results of operations of $790 million.

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

•	future ethanol segment margins;

•	expectations regarding feedstock costs, including crude oil differentials, and operating expenses;

•	anticipated levels of crude oil and refined petroleum product inventories;

•	our anticipated level of capital investments, including deferred costs for refinery turnarounds and catalyst, capital expenditures for environmental and other purposes, and joint venture investments, and the effect of those capital investments on our results of operations;

•	anticipated trends in the supply of and demand for crude oil and other feedstocks and refined petroleum products in the regions where we operate, as well as globally;

•	expectations regarding environmental, tax, and other regulatory initiatives; and

•	the effect of general economic and other conditions on refining, ethanol, and midstream industry fundamentals.

•	acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined petroleum products or receive feedstocks;

•	political and economic conditions in nations that produce crude oil or consume refined petroleum products;

•	demand for, and supplies of, refined petroleum products such as gasoline, diesel, jet fuel, petrochemicals, and ethanol;

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

•	the ability of the members of the Organization of Petroleum Exporting Countries to agree on and to maintain crude oil price and production controls;

•	the level of consumer demand, including seasonal fluctuations;

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•	refinery overcapacity or undercapacity;

•	our ability to successfully integrate any acquired businesses into our operations;

•	the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;

•	the level of competitors’ imports into markets that we supply;

•	accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;

•	changes in the cost or availability of transportation for feedstocks and refined petroleum products;

•	the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;

•	the levels of government subsidies for alternative fuels;

•	the volatility in the market price of biofuel credits (primarily RINs needed to comply with the RFS) and GHG emission credits needed to comply with the requirements of various GHG emission programs;

•	delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;

•	earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined petroleum products and ethanol;

•	rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;

•	legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tariffs and tax and environmental regulations, such as those implemented under the California cap-and-trade system (also known as AB 32) and similar programs, and the U.S. EPA’s regulation of GHGs, which may adversely affect our business or operations;

•	changes in the credit ratings assigned to our debt securities and trade credit;

•	changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, the euro, the Mexican peso, and the Peruvian sol relative to the U.S. dollar;

•	overall economic conditions, including the stability and liquidity of financial markets; and

•	other factors generally described in the “Risk Factors” section included in Item 1A, “Risk Factors” in this report.

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•	Refining segment. Refining segment adjusted operating income increased $961 million primarily due to improved distillate margins, favorable crude oil discounts, and lower costs of biofuel credits, partially offset by lower gasoline margins. This is more fully described on pages 36 through 37.

•	Ethanol segment. Ethanol segment operating income decreased by $90 million primarily due to lower ethanol prices and higher corn prices, partially offset by higher corn related co-products prices. This is more fully described on pages 37 through 38.

•	VLP segment. VLP segment adjusted operating income increased by $50 million primarily due to incremental revenues, partially offset by higher cost of sales, generated from transportation and terminaling services associated with a terminal and a product pipeline system acquired by VLP in November 2017 that were formerly a part of the refining segment. This is more fully described on page 38.

•	Corporate and eliminations. Adjusted corporate and eliminations decreased by $10 million primarily due to expenses in 2017 associated with the termination of the acquisition of certain assets from Plains All American Pipeline, L.P. (Plains). This is more fully described on page 38.

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•	Refining and ethanol margins are expected to remain near current levels.

•	Medium and heavy sour crude oil discounts are expected to remain weaker than their five-year averages as supplies of sour crude oils available in the market remain suppressed.

•	Sweet crude oil discounts are expected to remain near current levels as export demand remains strong and freight costs continue to rise. U.S. inland sweet crude oil discounts are also expected to remain wide with higher production and limited pipeline capacity to transport crude oil out of the Permian Basin and other producing regions in the U.S.

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Our refining operations in the U.K. could be adversely affected by Brexit, which is currently scheduled to occur on March 29, 2019. The U.K. and the European Union have yet to finalize the terms of Brexit, and the U.K.’s exit from the European Union without an agreement on an overall structure for an ongoing relationship with the European Union could result in the imposition of border controls and customs duties on trade that could negatively impact the operations of our Pembroke Refinery. While we do not believe that Brexit will have a material impact on us, we are taking steps to minimize the impact of possible delays on importing certain materials critical to our refining operations. The ultimate effect of Brexit will depend on the specific terms of any agreement reached by the U.K. and the European Union. See Item 1A “Risk Factors”—Changes in the U.K.’s economic and other relationships with the European Union could adversely affect us.

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Increase in distillate margins. We experienced improved distillate margins throughout all of our regions in 2018 compared to 2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $14.02 per barrel for 2018 compared to $13.26 per barrel for 2017, representing a favorable increase of $0.76 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was $22.82 per barrel for 2018 compared to $18.50 per barrel for 2017, representing a favorable increase of $4.32 per barrel. We estimate that the increase in distillate margins per barrel in 2018 compared to 2017 had a favorable impact to our refining segment margin of approximately $1.3 billion.

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Higher discounts on crude oils. The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil. We benefitted from processing these types of crude oils in 2018 and that benefit improved compared to 2017. For example, WTI crude oil, a light sweet crude oil, sold at a discount to Brent of $6.71 per barrel for 2018 compared to a discount of $3.92 per barrel for 2017, representing a favorable increase of $2.79 per barrel. Another example is Maya crude oil, a sour crude oil processed in our U.S. Gulf Coast region, which sold at a discount to Brent of $9.22 per barrel for 2018 compared to $7.74 per barrel for 2017, representing a favorable increase of $1.48 per barrel. We estimate that the increase in the discounts for crude oils that we processed during 2018 compared to 2017 had a favorable impact to our refining segment margin of approximately $561 million.

•	Lower costs of biofuel credits. As described in Note 20 of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs. The cost of these credits (primarily RINs in the U.S.) was $536 million in 2018 compared to $942 million in 2017, a decrease of $406 million.

•	Higher throughput volumes. Refining segment throughput volumes increased by 46,000 BPD in 2018. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $153 million.

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Decrease in gasoline margins. We experienced a decrease in gasoline margins throughout all of our regions in 2018 compared to 2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $4.81 per barrel for 2018 compared to $10.50 per barrel for 2017, representing an unfavorable decrease of $5.69 per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARBOB 87 gasoline, which was $13.05 per barrel for 2018 compared to $18.12 per barrel for 2017, representing an unfavorable decrease of $5.07 per barrel. We estimate that the decrease in gasoline margins per barrel in 2018 compared to 2017 had an unfavorable impact to our refining segment margin of approximately $1.3 billion.

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Lower ethanol prices. Ethanol prices were lower in 2018 compared to 2017 primarily due to an increase in production. For example, the New York Harbor ethanol price was $1.48 per gallon for 2018 compared to $1.56 per gallon for 2017, representing an unfavorable decrease of $0.08 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $159 million.

•	Higher corn prices. Corn prices were higher in 2018 compared to 2017. For example, the Chicago Board of Trade (CBOT) corn price was $3.68 per bushel for 2018 compared to $3.59 per bushel for 2017, representing an unfavorable increase of $0.09 per bushel. We estimate that the increase in the price of corn had an unfavorable impact to our ethanol segment margin of approximately $36 million.

•	Higher co-product prices. An increase in protein values, as compared to soybean meal, had a favorable effect on the prices received for the corn related co-products that we produced. We estimate the increase in corn related co-product prices had a favorable impact to our ethanol segment margin of approximately $101 million.

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Higher production volumes. Ethanol segment margin was favorably impacted by increased production volumes of 137,000 gallons per day in 2018 compared to 2017 primarily due to reliability improvements at our ethanol plants and the additional production volumes associated with the three plants acquired from Green Plains in November 2018. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of approximately $26 million.

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(a)

Cost of materials and other for the year ended December 31, 2018 includes a benefit of $170 million for the biodiesel blender’s tax credit attributable to volumes blended during 2017. The benefit was recognized in February 2018 because the legislation authorizing the credit was passed and signed into law in that month. The $170 million pre-tax benefit is included in the refining segment and includes $80 million attributable to noncontrolling interest and $90 million attributable to Valero Energy Corporation stockholders.

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

(c)	Other income, net for the year ended December 31, 2018 includes a $38 million charge from the early redemption of $750 million of our 9.375 percent senior notes due March 15, 2019.

(d)

On December 22, 2017, Tax Reform was enacted, resulting in the remeasurement of our U.S. deferred taxes and the recognition of a liability for taxes on the deemed repatriation of our foreign earnings and profits. In addition, Tax Reform lowered the U.S. statutory income tax rate from 35 percent to 21 percent, beginning January 1, 2018. Under U.S. GAAP we are required to recognize the effect of Tax Reform in the period of enactment. As a result, we recognized a $1.9 billion income tax benefit in December 2017, which represented our initial estimate of the impact of Tax Reform in accordance with Staff Accounting Bulletin No. 118 (SAB 118). We finalized our estimates in December 2018 and have recorded an additional benefit of $12 million for the year ended December 31, 2018.

(e)

Excluding the income tax benefits discussed in note (d) from both years and the other adjustments to income tax reflected in the table on page 31 from 2018, the effective tax rates for the years ended December 31, 2018 and 2017 were 22 percent and 28 percent, respectively. The decrease in the effective rate is primarily due to the decline in the U.S. statutory income tax rate from 35 percent to 21 percent as a result of Tax Reform (see note (d)).

(f)

In accordance with U.S. GAAP, we are required to state our inventories at the lower of cost or market. When the market price of our inventory falls below cost, we record a lower of cost or market inventory valuation adjustment to write down the value to market. In subsequent periods, the value of our inventory is reassessed and a lower of cost or market inventory valuation adjustment is recorded to reflect the net change in the lower of cost or market inventory valuation reserve between the periods. As of December 31, 2018 and December 31, 2017, the market price of our inventory was above cost; therefore we did not have a lower of cost or market inventory valuation reserve as of those dates. During the year ended December 31, 2016, we recorded a change in our inventory valuation reserve that was established on December 31, 2015, resulting in a noncash benefit of $747 million, of which $697 million and $50 million were attributable to our refining segment and ethanol segment, respectively.

(g)

Effective October 1, 2016 we (i) transferred ownership of all our assets in Aruba, other than certain hydrocarbon inventories and working capital, to Refineria di Aruba N.V. (RDA), an entity wholly-owned by the Government of Aruba (GOA), (ii) settled our obligations under various agreements with the GOA, including agreements that required us to dismantle our leasehold improvements under certain conditions, and (iii) sold the working capital of our Aruba operations, including hydrocarbon inventories, to the GOA, CITGO Aruba Refining N.V. (CAR), and CITGO Petroleum Corporation (together with CAR and certain other affiliates, collectively, CITGO). We refer to this transaction as the “Aruba Disposition.”

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

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Adjusted net income attributable to Valero Energy Corporation stockholders is defined as net income attributable to Valero Energy Corporation stockholders excluding the items noted below, along with their related income tax effect. We have excluded these items because we believe that they are not indicative of our core operating performance and that their exclusion results in an important measure of our ongoing financial performance to better assess our underlying business results and trends. The basis for our belief with respect to each excluded item is provided below.

–	Blender’s tax credit attributable to Valero Energy Corporation stockholders - The blender’s tax credit is attributable to volumes blended during 2017 and is not related to 2018 activities, as described in note (a).

–	Lower of cost or market inventory valuation adjustment - The noncash benefit recorded during 2016 to adjust our inventory valuation reserve, as described in note (f).

–	Asset impairment loss - The impairment loss of $56 million in 2016 associated with the Aruba Disposition, as described in note (g).

–	Texas City Refinery fire expenses - The costs incurred to respond to and assess the damage caused by the fire that occurred at the Texas City Refinery on April 19, 2018 are specific to that event and are not ongoing costs incurred in our operations.

–	Environmental reserve adjustments - The environmental reserve adjustments are attributable to sites that were shut down by prior owners and subsequently acquired by us (referred to by us as non-operating sites), as described in note (b).

–	Loss on early redemption of debt - The penalty and other expenses incurred in connection with the early redemption of our 9.375 percent senior notes due March 15, 2019 (see note (c)) are not associated with the ongoing costs of our borrowing and financing activities.

–	Income tax benefit from Tax Reform - Income tax benefit from Tax Reform (see note (d)) is associated with changes in U.S. tax legislation and is not indicative of our core performance.

–	Income tax benefit from Aruba Disposition - The income tax benefit in 2016 resulting from the cancellation of outstanding debt obligations associated with the Aruba Disposition, as described in note (g).

◦	Refining margin is defined as refining operating income excluding the blender’s tax credit, the lower of cost or market inventory valuation adjustment, the asset impairment loss, operating expenses (excluding depreciation and amortization expense), other operating expenses, and depreciation and amortization expense, as reflected in the table below.

◦	Ethanol margin is defined as ethanol operating income excluding the lower of cost or market inventory valuation adjustment, operating expenses (excluding depreciation and amortization expense), and depreciation and amortization expense, as reflected in the table below.

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◦	Adjusted refining operating income is defined as refining segment operating income excluding the blender’s tax credit, lower of cost or market inventory valuation adjustment, asset impairment loss, and other operating expenses.

◦	Adjusted ethanol operating income is defined as ethanol segment operating income excluding the lower of cost or market inventory valuation adjustment.

◦	Adjusted VLP operating income is defined as VLP segment operating income excluding other operating expenses.

◦	Adjusted corporate and eliminations is defined as corporate and eliminations excluding the environmental reserve adjustments associated with certain non-operating sites (see note (b)).

(i)	Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.

(j)	Valero uses certain operating statistics (as noted below) to evaluate performance between comparable periods. Different companies may calculate them in different ways.

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Increase in distillate margins. We experienced improved distillate margins throughout all our regions in 2017 compared to 2016. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $13.26 per barrel for 2017 compared to $10.21 per barrel for 2016, representing a favorable increase of $3.05 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was $18.50 per barrel for 2017 compared to $13.03 per barrel for 2016, representing a favorable increase of $5.47 per barrel. We estimate that the increase in distillate margins per barrel in 2017 compared to 2016 had a favorable impact to our refining segment margin of approximately $1.2 billion.

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Increase in gasoline margins. We also experienced improved gasoline margins throughout all our regions in 2017 compared to 2016. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was $15.65 per barrel for 2017 compared to $11.82 per barrel for 2016, representing a favorable increase of $3.83 per barrel. Another example is the Brent-based reference margin for U.S. Gulf Coast CBOB gasoline, which was $10.50 per barrel for 2017 compared to $9.17 per barrel for 2016, representing a favorable increase of $1.33 per barrel. We estimate that the increase in gasoline margins per barrel in 2017 compared to 2016 had a favorable impact to our refining segment margin of approximately $577 million.

•	Higher throughput volumes. Refining segment throughput volumes increased by 85,000 BPD in 2017. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $283 million.

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Lower discounts on sour crude oils. The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process sour crude oils that are priced at a discount to Brent crude oil. While we benefitted from processing these sour crude oils in 2017, that benefit declined compared to 2016. For example, ASCI crude oil processed in our U.S. Gulf Coast region sold at a discount to Brent of $4.18 per barrel for 2017 compared to a discount of $5.18 per barrel for 2016, representing an unfavorable decrease of $1.00 per barrel. Another example is Maya crude oil which sold at a discount to Brent of $7.74 per barrel for 2017 compared to $8.63 per barrel for 2016, representing an unfavorable decrease of $0.89 per barrel. We estimate that the reduction in discounts for sour crude oils that we processed in 2017 had an unfavorable impact to our refining segment margin of approximately $305 million.

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Lower discounts on other feedstocks. In addition to crude oil, we utilize other feedstocks such as residuals, in certain of our refining processes. We benefit when we process these other feedstocks that are priced at a discount to Brent crude oil. While we benefitted from processing these types of feedstocks in 2017, that benefit declined compared to 2016. We estimate that the reduction in the discounts for the other feedstocks that we processed in 2017 had an unfavorable impact to our refining segment margin of approximately $203 million.

•	Higher costs of biofuel credits. As described in Note 20 of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs. The cost of these credits (primarily RINs in the U.S.) was $942 million in 2017 compared to $749 million in 2016, an increase of $193 million.

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Increase in charges from VLP. Charges from the VLP segment for transportation and terminaling services increased $89 million in 2017 compared to 2016 primarily due to additional services provided by terminals and a product pipeline system acquired by VLP in 2017 and 2016 that were formerly a part of the refining segment, as well as an undivided interest in crude system assets acquired by VLP in 2017. Details regarding the increase in charges from VLP are discussed in the VLP segment analysis below.

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Lower ethanol prices. Ethanol prices were lower in 2017 compared to 2016 primarily due to higher industry production, which resulted in higher domestic inventories. For example, the New York Harbor ethanol price was $1.56 per gallon for 2017 compared to $1.60 per gallon for 2016. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $73 million.

•	Lower co-product prices. A decrease in export demand for corn related co-products, primarily distiller’s grains, had an unfavorable effect on the prices we received. We estimate that the decrease in the price for corn related co-products had an unfavorable impact to our ethanol segment margin of approximately $52 million.

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Lower corn prices. Despite a slight increase in the CBOT corn price from $3.58 per bushel for 2016 to $3.59 per bushel for 2017, we acquired corn at lower prices due to favorable location differentials, resulting in a decrease in the price we paid for corn in 2017 compared to 2016. We estimate that the decrease in the price we paid for corn had a favorable impact to our ethanol segment margin of approximately $25 million.

•	Higher production volumes. Ethanol segment margin was favorably impacted by increased production volumes of 130,000 gallons per day in 2017 compared to 2016 primarily due to reliability improvements. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of approximately $25 million.

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(a)	Excludes $235 million of cash and cash equivalents related to our variable interest entities (VIEs) that is available for use only by our VIEs.

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

•	an increase in inventory primarily due to higher inventory levels;

•	a decrease in income taxes payable primarily resulting from (i) $527 million of payments in early 2018 related to 2017 tax liabilities and (ii) $181 million of payments in late 2018 that will be applied to 2019 tax liabilities;

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

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

•	fund $2.7 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;

•	fund (i) $468 million for the Peru Acquisition (as defined and discussed in Note 2 of Notes to Consolidated Financial Statements) in May 2018; (ii) $320 million for the acquisition of three ethanol plants in November 2018; and (iii) $88 million for other minor acquisitions;

•	fund $124 million of capital expenditures of certain VIEs;

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

•	redeem our 9.375 percent Senior Notes due March 15, 2019 for $787 million (or 104.9 percent of stated value);

•	make payments on debt and capital lease obligations of $435 million, of which $410 million related to the repayment of all outstanding borrowings under VLP’s $750 million senior unsecured revolving credit facility (the VLP Revolver);

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•	retire $137 million of debt assumed in connection with the Peru Acquisition;

•	purchase common stock for treasury of $1.7 billion;

•	pay common stock dividends of $1.4 billion; and

•	pay distributions to noncontrolling interests of $116 million.

•	an increase in accounts payable primarily as a result of an increase in commodity prices; and

•	an increase in income taxes payable resulting from deferring the payment of our fourth quarter 2017 estimated taxes to January 2018, as allowed by tax relief authorization from the IRS; partially offset by

•	an increase in receivables primarily as a result of an increase in commodity prices; and

•	an increase in inventory due to higher volumes held combined with an increase in commodity prices.

•	fund $2.3 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;

•	acquire an undivided interest in crude system assets for $72 million;

•	purchase common stock for treasury of $1.4 billion;

•	pay common stock dividends of $1.2 billion;

•	pay distributions to noncontrolling interests of $67 million; and

•	increase available cash on hand by $1.0 billion.

•	an increase in accounts payable primarily as a result of higher commodity prices;

•	a reduction of our inventories; and

•	a reduction in prepaid expenses and other related to income taxes receivable due to utilization in 2016 of our 2015 overpayment of taxes; partially offset by

•	an increase in receivables primarily as a result of higher commodity prices.

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•	fund $2.0 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;

•	redeem our 6.125 percent Senior Notes due June 15, 2017 for $778 million (or 103.70 percent of stated value) and our 7.2 percent Senior Notes due October 15, 2017 for $213 million (or 106.27 percent of stated value);

•	make payments on debt and capital lease obligations of $525 million, of which $494 million related to borrowings under the VLP Revolver, $9 million related to capital lease obligations, and $22 million related to other debt;

•	pay off a long-term liability of $137 million owed to a joint venture partner for an owner-method joint venture investment;

•	purchase common stock for treasury of $1.3 billion;

•	pay common stock dividends of $1.1 billion;

•	pay distributions to noncontrolling interests of $65 million; and

•	increase available cash on hand by $702 million.

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(a)	Debt obligations exclude amounts related to unamortized discounts and debt issuance costs. Capital lease obligations include related interest expense.

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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, natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

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(a)	Excludes unamortized discounts and debt issuance costs.

(b)	As of December 31, 2018 and 2017, we had an interest rate swap associated with $40 million and $49 million, respectively, of our floating rate debt resulting in an effective interest rate of 3.85 percent as of each of those reporting dates. The fair value of the swap was immaterial for all periods presented.

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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 and ethanol plants and which are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs;

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

•	income taxes receivable;

•	investments in joint ventures accounted for under the equity method;

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•	intangible assets; and

•	goodwill.

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•	Transition Elections. We elected the package of practical expedients that permits us to not reassess our prior conclusions about lease identification, lease classification, and initial direct costs under the new standard, as well as the practical expedient that permits us to not assess existing land easements under the new standard.

•	Lessee Accounting Policy Elections. We elected the short-term lease recognition exemption whereby right-of-use (ROU) assets and lease liabilities are not recognized for leasing arrangements with terms less than one year, and the practical expedient to not separate lease and non-lease components for all classes of underlying assets other than the marine transportation asset class.

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2.	ACQUISITIONS AND MERGER

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3.	ARUBA DISPOSITION

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4.	RECEIVABLES

5.	INVENTORIES

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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. There was no current portion of repatriation tax liability as of December 31, 2018 and $114 million as of December 31, 2017.

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9.	DEBT AND CAPITAL LEASE OBLIGATIONS

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(a)	Creditors of our VIEs do not have recourse against us.

(b)	The VLP Revolver was terminated on January 10, 2019. See “VLP Revolver” above.

•

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

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

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•	We issued $1.25 billion of 3.4 percent Senior Notes due September 15, 2026. Proceeds from this debt issuance totaled $1.246 billion before deducting the underwriting discount and other debt issuance costs.

•	We redeemed our 6.125 percent Senior Notes due June 15, 2017 for $778 million, or 103.70 percent of stated value.

•	We redeemed our 7.2 percent Senior Notes due October 15, 2017 for $213 million, or 106.27 percent of stated value.

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VLP issued $500 million of 4.375 percent Senior Notes due December 15, 2026. Proceeds from this debt issuance totaled $500 million before deducting the underwriting discount and other debt issuance costs. The proceeds were available only to the operations of VLP and were used to repay $494 million on the VLP Revolver. On January 10, 2019, in connection with the completion of the Merger Transaction as described in Note 2, Valero entered into a guarantee agreement to fully and unconditionally guarantee the prompt payment, when due, of any amount owed to the holders of these notes.

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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

•

Prior to the completion of the Merger Transaction with VLP on January 10, 2019 as discussed in Note 2, VLP was a publicly traded master limited partnership whose common limited partner units were traded on the New York Stock Exchange under the trading symbol “VLP.” VLP was formed by us to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. VLP’s assets include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of ten of our refineries. As of December 31, 2018, we owned a 66.2 percent limited partner interest and a 2.0 percent general partner interest in VLP, and public unitholders owned a 31.8 percent limited partner interest.

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•

Diamond Green Diesel Holdings LLC (DGD) is a joint venture with Darling Green Energy LLC, a subsidiary of Darling Ingredients Inc., that was formed to construct and operate a biodiesel plant that processes animal fats, used cooking oils, and other vegetable oils into renewable green diesel. The plant is located next to our St. Charles Refinery and began operations in June 2013. Our significant agreements with DGD include an operations agreement that outlines our responsibilities as operator of the plant, a debt agreement whereby we financed approximately 60 percent of the construction costs of the plant, and a marketing agreement.

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

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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

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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)	Equity securities are held in a wide range of industrial sectors, including consumer goods, information technology, healthcare, industrials, and financial services.

(b)	This class includes primarily investments in approximately 60 percent equities and 40 percent bonds as of December 31, 2018. As of December 31, 2017, this class included primarily investments in approximately 70 percent equities and 30 percent bonds.

(c)	This class includes primarily investments in approximately 70 percent equities and 30 percent bonds as of December 31, 2018. As of December 31, 2017, this class included primarily investments in approximately 80 percent equities and 20 percent bonds.

(d)	This class includes primarily investments in approximately 50 percent equities and 50 percent bonds as of December 31, 2018 and 2017.

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14.	STOCK-BASED COMPENSATION

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15.	INCOME TAXES

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

•	repeal of the manufacturing deduction;

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

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

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

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

•

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

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

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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” above.

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

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16.	EARNINGS PER COMMON SHARE

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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 certain logistics assets that support our refining operations that are not owned by VLP. The principal products manufactured by our refineries and sold by this segment include gasolines and blendstocks (e.g., conventional gasolines, premium gasolines, and gasoline meeting the specifications of the California Air Resources Board (CARB)), distillates (e.g., diesel, low-sulfur diesel, ultra-low-sulfur diesel, CARB diesel, jet fuel, and other distillates), and other products (e.g., asphalt, petrochemicals, lubricants, and other refined petroleum products).

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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. We sell some ethanol to our refining segment for blending into gasoline, which is sold to that segment’s customers as a finished gasoline product.

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•	The VLP segment includes the results of VLP. VLP generates revenue from transportation and terminaling activities provided to our refining segment. All of VLP’s revenues are intersegment revenues that are generated under commercial agreements with our refining segment. Revenues generated under these agreements are eliminated in consolidation.

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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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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 the market approach. Exchange-traded futures are valued based on quoted prices from the commodity exchange and are categorized in Level 1 of the fair value hierarchy.

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

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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 entered into for our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.

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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

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21.	QUARTERLY FINANCIAL DATA (Unaudited)

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

(b)	During the quarter ended December 31, 2017, we recognized an income tax benefit of $1.9 billion related to Tax Reform as described in Note 15.

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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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