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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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1

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.

2

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

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•	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 7 of Notes to Consolidated Financial Statements and Note 9 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 2016 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 July 13, 2015, we announced that our board of directors authorized our purchase of up to $2.5 billion of our outstanding common stock. This authorization has no expiration date. As of December 31, 2016, the approximate dollar value of shares that may yet be purchased under the 2015 authorization is $40 million. On September 21, 2016, we announced that our board of directors authorized our purchase of up to an additional $2.5 billion of our outstanding common stock with no expiration date. As of December 31, 2016, no purchases have been made under the 2016 authorization.

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1	Assumes that an investment in Valero common stock and each index was $100 on December 31, 2011. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2011 through December 31, 2016.

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(a)	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 4 of Notes to Consolidated Financial Statements.

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

(c)	Includes the operations of our retail business prior to its separation from us on May 1, 2013.

(d)	Amounts reported as of December 31, 2015, 2014, 2013, and 2012 have been reclassified to reflect the retrospective adoption of certain amendments to the Accounting Standards Codification as of January 1, 2016 as described in Note 1 of Notes to Consolidated Financial Statements.

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•	future refining margins, including gasoline and distillate margins;

•	future ethanol 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 and ethanol industry fundamentals.

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

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

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

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

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

•	the level of consumer demand, including seasonal fluctuations;

•	refinery overcapacity or undercapacity;

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•	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 tax and environmental regulations, such as those implemented under the California Global Warming Solutions Act (also known as AB 32), Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), 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, and the euro 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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(1)	Net income and operating income have been adjusted for certain items that we believe are not indicative of our core operating performance and that may obscure our underlying business results and trends. Each of these adjustments is reflected in the tables on pages 28 and 29. Adjusted amounts are non-GAAP measurements.

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•	Refining segment - The $4.4 billion decrease in adjusted operating income was primarily due to lower margins on refined petroleum products and lower discounts on light sweet crude oils and sour crude oils relative to Brent crude oil, which also negatively impacted our refining margins. This is more fully described on pages 37 and 38.

•	Ethanol segment - The $98 million increase in adjusted operating income was primarily due to higher ethanol margins that resulted from lower corn prices combined with lower operating expenses, partially offset by lower margins on other co-products. This is more fully described on page 38.

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

•	Crude oil discounts are expected to remain weak due to lower demand resulting from industry-wide refinery maintenance.

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•

Decrease in gasoline margins - We experienced a decrease in gasoline margins throughout all of our regions in 2016 compared to 2015. For example, WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was $11.82 per barrel in 2016 compared to $17.59 per barrel in 2015, representing an unfavorable decrease of $5.77 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB 87 gasoline was $17.04 per barrel in 2016 compared to $25.56 per barrel in 2015, representing an unfavorable decrease of $8.52 per barrel. We estimate that the decrease in gasoline margins per barrel in 2016 compared to 2015 had an unfavorable impact to our refining margin of approximately $1.7 billion.

•

Decrease in distillate margins - We experienced a decrease in distillate margins throughout all of our regions in 2016 compared to 2015. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $10.21 per barrel in 2016 compared to $12.64 per barrel in 2015, representing an unfavorable decrease of $2.43 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was $13.03 per barrel in 2016 compared to $19.02 per barrel in 2015, representing an unfavorable decrease of $5.99 per barrel. We estimate that the decrease in distillate margins per barrel in 2016 compared to 2015 had an unfavorable impact to our refining margin of approximately $1.6 billion.

•

Lower discounts on light sweet crude oils and 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 crude oils that are priced at a discount to Brent crude oil, such as WTI crude oil, in periods when pricing terms are favorable. During 2016, we benefited from processing WTI crude oil; however, that benefit declined compared to the benefit from processing WTI crude oil during 2015. For example, WTI crude oil processed in our U.S. Mid-Continent region sold at a discount of $1.83 per barrel to Brent crude oil in 2016 compared to a discount of $4.91 per barrel in 2015, representing an unfavorable decrease of $3.08 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $8.63 per barrel to Brent crude oil in 2016 compared to a discount of $9.54 per barrel in 2015, representing an unfavorable decrease of $0.91 per barrel. We estimate that the cost of light sweet crude oils and sour crude oils during 2016 had an unfavorable impact to our refining margin of approximately $900 million.

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•

Higher costs of biofuel credits - As more fully described in Note 19 of Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $309 million from $440 million in 2015 to $749 million in 2016. This increase was due to an increase in the market price of RINs caused by an expected shortage in the market of available RINs that worsened in November 2016 with the release of the U.S. EPA’s final 2017 renewable fuel volume requirements.

•	Higher throughput volumes - Refining throughput volumes increased by 56,000 BPD in 2016. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $175 million.

•

Lower corn prices - Corn prices were lower in 2016 compared to 2015 primarily due to higher yields from the current corn crop in the corn-producing regions of the U.S. Mid-Continent. For example, the Chicago Board of Trade (CBOT) corn price was $3.58 per bushel in 2016 compared to $3.77 per bushel in 2015. We estimate that the decrease in the price of corn that we processed during 2016 had a favorable impact to our ethanol margin of approximately $105 million.

•

Higher ethanol prices - Ethanol prices were slightly higher in 2016 compared to 2015 primarily due to increased ethanol demand. Despite higher domestic production during 2016, inventory levels declined during the year primarily due to higher exports. For example, the CBOT ethanol price was $1.53 per gallon in 2016 compared to $1.50 per gallon in 2015. We estimate that the increase in the price of ethanol per gallon during 2016 had a favorable impact to our ethanol margin of approximately $24 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 15,000 gallons per day in 2016 compared to 2015 primarily due to improved operating efficiencies and mechanical reliability. Our ethanol margin was also favorably impacted by higher co-product production volumes between the years. We estimate that the increase in ethanol and co-product production volumes had a favorable impact to our ethanol margin of approximately $22 million.

•	Lower co-product prices - A decrease in export demand for corn-related co-products, primarily distillers grains, had an unfavorable effect on the prices we received. We estimate that the decrease in corn-related co-products prices had an unfavorable impact to our ethanol margin of approximately $70 million.

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(a)

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 periods. As of December 31, 2016, 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 that date. 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. The year ended December 31, 2015 includes a lower of cost or market inventory valuation adjustment that resulted in a noncash charge of $790 million, of which $740 million and $50 million were attributable to our refining segment and ethanol segment, respectively. The noncash benefit for the year ended December 31, 2016 differs from the noncash charge for the year ended December 31, 2015 due to the foreign currency effect of inventories held by our international operations. This adjustment is further discussed in Note 4 of Notes to Consolidated Financial Statements.

(b)

Effective October 1, 2016, we (i) transferred ownership of all of 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 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.”

(c)

The variation in the customary relationship between income tax expense and income before income tax expense for the year ended December 31, 2016 is primarily due to the higher earnings from our international operations that are taxed at statutory rates that are lower than in the U.S. and the recognition of an income tax benefit in the U.S. in connection with the Aruba Disposition (see note (b) above).

(d)	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 lower of cost or market inventory valuation adjustment, its related income tax effect, the asset impairment loss, and the income tax benefit on the Aruba Disposition.

◦	Adjusted net income from continuing operations attributable to Valero Energy Corporation stockholders is defined as net income from continuing operations attributable to Valero Energy Corporation stockholders excluding the lower of cost or market inventory valuation adjustment, its related income tax effect, the LIFO gain, and its related income tax effect (see (e) below).

◦	Gross margin is defined as operating income excluding the lower of cost or market inventory valuation adjustment, operating expenses, depreciation and amortization expense, asset impairment loss, and LIFO gain (see (e) below).

◦	Adjusted operating income is defined as operating income excluding the lower of cost or market inventory valuation adjustment and the asset impairment loss. For the year ended December 31, 2014, adjusted operating income is further defined to exclude the LIFO gain (see (e) below).

(e)	“Cost of sales (excluding the lower of cost or market inventory valuation adjustment)” for the year ended December 31, 2014 reflects a LIFO gain of $233 million, of which $229 million and $4 million were attributable to our refining segment and ethanol segment, respectively.

(f)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.

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

(h)

Throughput margin per barrel represents gross margin (as defined in (d) above) for our refining segment or refining regions divided by the respective throughput volumes. Gross margin per gallon of production represents gross margin (as defined in (d) above) for our ethanol segment divided by production volumes. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period.

(i)

Adjusted operating income per barrel represents adjusted operating income (defined in (d) above) for our refining segment or refining regions divided by the respective throughput volumes. Adjusted operating income per gallon of production represents adjusted operating income (defined in (d) above) for our ethanol segment divided by production volumes. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period.

(j)

Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oils are reflected without adjusting for the impact of the futures pricing for the corresponding delivery month. Therefore, the prices reported reflect the prompt month pricing only, without an adjustment for futures pricing (known in the industry as the Calendar Month Average (CMA) “roll” adjustment). We previously had provided average market reference prices that included the CMA “roll” adjustment. Accordingly, the average market reference price and price differentials for LLS crude oil for the years ended December 31, 2015 and 2014 have been adjusted to conform to the current presentation.

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(k)

Average market reference price differentials to Mars crude oil have been replaced by average market reference price differentials to ASCI crude oil. Mars crude oil is one of the three grades of sour crude oil used to create ASCI crude oil, and therefore, ASCI crude oil is a more comprehensive price marker for medium sour crude oil. Accordingly, the price differentials for ASCI crude oil for the years ended December 31, 2015 and 2014 are included to conform to the current presentation.

•

Increase in gasoline margins - We experienced an increase in gasoline margins throughout all our regions during 2015. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $9.83 per barrel in 2015 compared to $3.54 per barrel in 2014, a favorable increase of $6.29 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB gasoline that was $25.56 per barrel in 2015 compared to $13.40 per barrel in 2014, a favorable increase of $12.16 per barrel. We estimate that the increase in gasoline margins per barrel in 2015 compared to 2014 had a positive impact to our refining margin of approximately $2.9 billion.

•

Increase in other refined petroleum products margins - We experienced an increase in the margins of other refined petroleum products such as petroleum coke, propane, sulfur, and lubes in 2015 compared to 2014. Margins for other refined petroleum products were higher during 2015 due to the lower cost of crude oils in 2015 compared to 2014. Because the market prices for our other refined petroleum products remain relatively stable, we benefit when the cost of crude oils that we process declines. For example, the benchmark price of Brent crude oil was $53.62 per barrel in 2015 compared to $99.57 per barrel in 2014. We estimate that the increase in margins for other refined petroleum products in 2015 compared to 2014 had a positive impact to our refining margin of approximately $1.6 billion.

•

Lower discounts on light sweet and sour crude oils - Because the market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. For 2015, the discount in the price of light sweet and sour crude oils compared to the price of Brent crude oil narrowed. Therefore, while we benefitted from processing crude oils priced at a discount to Brent crude oil, that benefit declined

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Lower benefit from processing other feedstocks - In addition to crude oil, we use other feedstocks and blendstocks in our refining processes, such as natural gas. When combined with steam, natural gas produces hydrogen that is used in our hydrotreater and hydrocracker processing units to produce refined petroleum products. Although natural gas costs declined from 2014 to 2015, the decline was not as significant as the decline in the cost of Brent crude oil; therefore, the benefit we normally derive by using natural gas as a feedstock declined. We estimate that the decline in the benefit we derived from processing other feedstocks had an unfavorable impact to our refining margin of approximately $980 million in 2015 compared to 2014.

•

Decrease in distillate margins - We experienced a decrease in distillate margins throughout all our regions during 2015. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel (a type of distillate) was $19.02 per barrel in 2015 compared to $24.05 per barrel in 2014, an unfavorable decrease of $5.03 per barrel. Another example is the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel that was $12.64 per barrel in 2015 compared to $14.28 per barrel in 2014, an unfavorable decrease of $1.64 per barrel. We estimate that the decrease in distillate margins per barrel in 2015 compared to 2014 had an unfavorable impact to our refining margin of approximately $650 million.

•	Higher throughput volumes - Refining throughput volumes increased by 34,000 BPD in 2015. We estimate that the increase in refining throughput volumes had a positive impact to our refining margin of approximately $160 million in 2015.

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Lower ethanol prices - Ethanol prices were lower in 2015 primarily due to the decrease in crude oil and gasoline prices in 2015 compared to 2014. For example, the New York Harbor ethanol price was $1.59 per gallon in 2015 compared to $2.37 per gallon in 2014. We estimate that the decrease in the price of ethanol per gallon during 2015 had an unfavorable impact to our ethanol margin of approximately $800 million.

•

Lower corn prices - Corn prices were lower in 2015 compared to 2014 due to a higher domestic corn yield realized during the 2014 fall harvest (most of which is processed in the following year). For example, the CBOT corn price was $3.77 per bushel in 2015 compared to $4.16 per bushel in 2014. We estimate that the decrease in the price of corn that we processed during 2015 had a favorable impact to our ethanol margin of approximately $160 million.

•	Lower co-product prices - The decrease in corn prices in 2015 compared to 2014 had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. We estimate that the decrease in co-product prices had an unfavorable impact to our ethanol margin of approximately $40 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 405,000 gallons per day in 2015. Production volumes in 2014 were negatively impacted by weather-related rail disruptions. In addition, production volumes in 2015 were positively impacted by production volumes from our Mount Vernon plant, which began operations in August 2014. We estimate that the increase in production volumes had a favorable impact to our ethanol margin of approximately $50 million.

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•	an increase in accounts payable, offset by an increase in receivables, primarily as a result of higher commodity prices;

•	a reduction of our inventories; and

•	a reduction in income taxes receivable due to utilization in 2016 of our 2015 overpayment of taxes.

•	fund $2.0 billion in capital investments,which include capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments;

•	redeem our 6.125 percent Senior Notes for $778 million (or 103.70 percent of stated value) and our 7.2 percent Senior Notes 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 non-bank 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 of $65 million to noncontrolling interests; and

•	increase available cash on hand by $702 million.

•	a decrease in accounts payable, net of a decrease in receivables, primarily as a result of a decrease in commodity prices from December 2014 to December 2015;

•	an increase in income taxes receivable and a decrease in income taxes payable due to tax payments associated with the settlement of several IRS audits and an overpayment of taxes in 2015. This overpayment resulted from a change in the U.S. Federal tax laws late in the year that reinstated the bonus depreciation deduction, which lowered our current income tax expense; and

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•	an increase in inventories, mainly due to the build in inventory volumes in 2015 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2015.

•	fund $2.4 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments;

•	make payments on debt and capital lease obligations of $513 million, of which $400 million related to our 4.5 percent Senior Notes, $75 million related to our 8.75 percent debentures, $25 million related to the VLP Revolver, $10 million related to capital lease obligations, and $3 million related to other non-bank debt;

•	purchase common stock for treasury of $2.8 billion;

•	pay common stock dividends of $848 million; and

•	increase available cash on hand by $425 million.

•	a decrease in accounts receivable, which was offset by a decrease in accounts payable, primarily as a result of a decrease in commodity prices from December 2013 to December 2014;

•	a decrease in income taxes payable resulting from income tax payments exceeding income tax liabilities incurred in 2014 due to the payment of liabilities associated with prior period earnings; and

•	an increase in inventories mainly due to the build in inventory volumes from 2013 to 2014 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2014.

•	fund $2.8 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments;

•	make payments on debt and capital lease obligations of $204 million, of which $200 million related to our 4.75 percent Senior Notes, and $4 million related to capital lease obligations;

•	purchase common stock for treasury of $1.3 billion; and

•	pay common stock dividends of $554 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. These items are further described in Note 8 of Notes to Consolidated Financial Statements.

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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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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;

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•	income taxes receivable;

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

•	intangible assets.

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2.	ARUBA DISPOSITION

•	In May 2014, we abandoned our Aruba Refinery, except for the associated crude oil and refined petroleum products terminal assets that we continued to operate. As a result, the refinery’s results

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•

In June 2016, we recognized an asset impairment loss of $56 million representing all of the remaining carrying value of our long-lived assets in Aruba. These assets were primarily related to our crude oil and refined petroleum products terminal and transshipment facility in Aruba (collectively, the Aruba Terminal), which were included in our refining segment. We recognized the impairment loss at that time because we concluded that it was more likely than not that we would ultimately transfer ownership of these assets to the GOA as a result of agreements entered into in June 2016 between the GOA and CITGO providing for, among other things, the GOA’s lease of those assets to CITGO. (See Note 18 for disclosure related to the method to determine fair value.) We had previously written off all of the carrying value of the long-lived assets of the refining operations (the Aruba Refinery) and recognized an asset retirement obligation upon the suspension of operations of those assets in 2012. Therefore, there was no other significant effect to our results of operations from the Aruba Disposition during the year ended December 31, 2016, except with respect to income taxes, which are discussed below. In addition, the net cash impact to us upon effectiveness of the Aruba Disposition on October 1, 2016, was not significant.

•

In September 2016 and in connection with the Aruba Disposition, our U.S. subsidiaries were unable to collect outstanding debt obligations owed to them by our Aruba subsidiaries, which resulted in the recognition by us of an income tax benefit in the U.S. of $42 million during the year ended December 31, 2016. We had no income tax effect in Aruba from the cancellation of debt or other effects of the Aruba Disposition because of net operating loss carryforwards associated with our operations in Aruba against which we had previously recorded a full valuation allowance.

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3.	RECEIVABLES

4.	INVENTORIES

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5.	PROPERTY, PLANT, AND EQUIPMENT

6.	DEFERRED CHARGES AND OTHER ASSETS

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7.	ACCRUED EXPENSES AND OTHER LONG-TERM LIABILITIES

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8.	DEBT AND CAPITAL LEASE OBLIGATIONS

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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. We also incurred $10 million of debt issuance costs.

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

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

•	VLP issued $500 million of 4.375 percent Senior Notes due December 15, 2026. Proceeds from this debt issuance totaled $500 million. Debt issuance costs totaled $4 million.

•	We issued $600 million of 3.65 percent Senior Notes due March 15, 2025 and $650 million of 4.9 percent Senior Notes due March 15, 2045. Proceeds from these debt issuances totaled $1.246 billion. We also incurred $12 million of debt issuance costs.

•	We made scheduled debt repayments of $400 million related to our 4.5 percent Senior Notes and $75 million related to our 8.75 percent debentures.

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9.	COMMITMENTS AND CONTINGENCIES

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10.	EQUITY

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(a)	These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost, as further discussed in Note 12. Net periodic benefit cost is reflected in operating expenses and general and administrative expenses.

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11.	VARIABLE INTEREST ENTITIES

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VLP is a publicly traded master limited partnership whose common limited partner units are traded on the New York Stock Exchange under “VLP.” We formed VLP in July 2013 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, 2016, we owned a 66.4 percent limited partner interest and a 2.0 percent general partner interest in VLP, and public unitholders owned a 31.6 percent limited partner interest. See “Valero Energy Partners LP” below for additional information regarding VLP’s equity offering.

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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 also have financial interests in other entities in which we hold a 50 percent ownership interest, which is a significant variable interest. These entities were determined to be VIEs because the entities’ contractual arrangements transfer the power 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 (a) 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 (b) our 50 percent ownership interests provide us with significant economic rights and obligations. The financial position, results of operations, and cash flows of these VIEs are not material to us.

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12.	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 18 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 50 percent equities and 50 percent bonds as of December 31, 2016. As of December 31, 2015, the class included primarily investments in approximately 60 percent equities and 40 percent bonds.

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13.	STOCK-BASED COMPENSATION

(a)	Effective January 1, 2016, the effect of tax deductions in excess of recognized stock-based compensation expense is reported as an operating cash flow. These amounts were previously reported as financing cash flows.

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14.	INCOME TAXES

(a)	Statutory income tax rate applicable through the date of the Aruba Disposition as described in Note 2.

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15.	EARNINGS PER COMMON SHARE

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16.	SEGMENT INFORMATION

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17.	SUPPLEMENTAL CASH FLOW INFORMATION

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18.	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 and swaps, and as disclosed in Note 19, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 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 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 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 Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), (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 further described in Note 19 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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•	The fair value of cash and temporary cash investments approximates the carrying value due to the low level of credit risk of these assets combined with their short maturities and market interest rates (Level 1).

•	The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services (Level 2).

19.	PRICE RISK MANAGEMENT ACTIVITIES

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Economic Hedges – Economic hedges represent commodity derivative instruments that are used to manage price volatility in certain (i) feedstock and refined petroleum product inventories, (ii) fixed-price purchase contracts, and (iii) forecasted feedstock, refined petroleum product or natural gas purchases and refined petroleum product sales. The objectives of our economic hedges are to hedge price volatility in certain feedstock and refined petroleum product inventories and to lock in the price of forecasted feedstock, refined petroleum product, or natural gas purchases or refined petroleum product sales at existing market prices that we deem favorable. Economic hedges are not designated as fair value or cash flow hedges for accounting purposes, usually due to the difficulty of establishing the required documentation at the date the derivative instrument is entered into for them to qualify as hedging instruments for accounting purposes.

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•	Trading Derivatives – Our objective for entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions for crude oil and refined petroleum products.

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20.	QUARTERLY FINANCIAL DATA (Unaudited)

(a)	Operating income for the quarter ended March 31, 2016 reflects a favorable noncash lower of cost or market inventory valuation adjustment of $293 million as described in Note 4.

(b)	Operating income for the quarter ended June 30, 2016 reflects a favorable noncash lower of cost or market inventory valuation adjustment of $454 million as described in Note 4 and an asset impairment loss of $56 million related to the Aruba Disposition as described in Note 2.

(c)	Operating income for the quarter ended December 31, 2015 reflects an unfavorable noncash lower of cost or market inventory valuation adjustment of $790 million as described in Note 4.

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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.

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