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

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

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

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

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

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

•	future ethanol segment margins;

•	future renewable diesel segment margins;

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

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

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

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

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

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

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

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

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

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

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

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

•	the level of consumer demand, including seasonal fluctuations;

•	refinery overcapacity or undercapacity;

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

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

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

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

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

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

•	the levels of government subsidies for alternative fuels;

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

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

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

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

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

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

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

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

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

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

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

NON-GAAP FINANCIAL MEASURES

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

OVERVIEW AND OUTLOOK

Overview

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

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

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

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

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

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

Outlook

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

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

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

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

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

•

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

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

RESULTS OF OPERATIONS

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

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

2019 Compared to 2018

Financial Highlights by Segment and Total Company

(millions of dollars)

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

---

See note references on pages 38 through 42.

Financial Highlights by Segment and Total Company (continued)

(millions of dollars)

	Year Ended December 31, 2018
	Refining				Ethanol				Renewable Diesel				Corporate and Eliminations				Total
Revenues:
Revenues from external customers	$	113,093			$	3,428			$	508			$	4			$	117,033
Intersegment revenues	25				210				170				(405		)		—
Total revenues	113,118				3,638				678				(401		)		117,033
Cost of sales:
Cost of materials and other (a)	101,866				3,008				262				(404		)		104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154				470				66				—				4,690
Depreciation and amortization expense	1,910				78				29				—				2,017
Total cost of sales	107,930				3,556				357				(404		)		111,439
Other operating expenses (b)	45				—				—				—				45
General and administrative expenses (excluding depreciation and amortization expense reflected below) (c)	—				—				—				925				925
Depreciation and amortization expense	—				—				—				52				52
Operating income by segment	$	5,143			$	82			$	321			$	(974	)		4,572
Other income, net (d)																	130
Interest and debt expense, net of capitalized interest																	(470		)
Income before income tax expense																	4,232
Income tax expense (e)																	879
Net income																	3,353
Less: Net income attributable to noncontrolling interests (a)																	231
Net income attributable to Valero Energy Corporation stockholders																	$	3,122

---

See note references on pages 38 through 42.

Average Market Reference Prices and Differentials

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

Average Market Reference Prices and Differentials, (continued)

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

Total Company, Corporate, and Other

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

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

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

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

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

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

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

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

Refining Segment Results

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

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

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

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

•

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

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

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

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

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

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

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

•

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

Ethanol Segment Results

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

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

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

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

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

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

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

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

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

Renewable Diesel Segment Results

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

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

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

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

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

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

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

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

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

2018 Compared to 2017

Financial Highlights by Segment and Total Company

(millions of dollars)

	Year Ended December 31, 2018
	Refining				Ethanol				Renewable Diesel				Corporate and Eliminations				Total
Revenues:
Revenues from external customers	$	113,093			$	3,428			$	508			$	4			$	117,033
Intersegment revenues	25				210				170				(405		)		—
Total revenues	113,118				3,638				678				(401		)		117,033
Cost of sales:
Cost of materials and other (a)	101,866				3,008				262				(404		)		104,732
Operating expenses (excluding depreciation and amortization expense reflected below)	4,154				470				66				—				4,690
Depreciation and amortization expense	1,910				78				29				—				2,017
Total cost of sales	107,930				3,556				357				(404		)		111,439
Other operating expenses (b)	45				—				—				—				45
General and administrative expenses (excluding depreciation and amortization expense reflected below) (c)	—				—				—				925				925
Depreciation and amortization expense	—				—				—				52				52
Operating income by segment	$	5,143			$	82			$	321			$	(974	)		4,572
Other income, net (d)																	130
Interest and debt expense, net of capitalized interest																	(470		)
Income before income tax expense																	4,232
Income tax expense (e)																	879
Net income																	3,353
Less: Net income attributable to noncontrolling interests (a)																	231
Net income attributable to Valero Energy Corporation stockholders																	$	3,122

---

See note references on pages 38 through 42.

Financial Highlights by Segment and Total Company (continued)

(millions of dollars)

	Year Ended December 31, 2017
	Refining				Ethanol				Renewable Diesel				Corporate and Eliminations				Total
Revenues:
Revenues from external customers	$	90,258			$	3,324			$	393			$	5			$	93,980
Intersegment revenues	8				176				241				(425		)		—
Total revenues	90,266				3,500				634				(420		)		93,980
Cost of sales:
Cost of materials and other	80,160				2,804				498				(425		)		83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	4,014				443				47				—				4,504
Depreciation and amortization expense	1,824				81				29				—				1,934
Total cost of sales	85,998				3,328				574				(425		)		89,475
Other operating expenses (b)	61				—				—				—				61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—				—				—				829				829
Depreciation and amortization expense	—				—				—				52				52
Operating income by segment	$	4,207			$	172			$	60			$	(876	)		3,563
Other income, net																	112
Interest and debt expense, net of capitalized interest																	(468		)
Income before income tax expense																	3,207
Income tax benefit (e)																	(949		)
Net income																	4,156
Less: Net income attributable to noncontrolling interests																	91
Net income attributable to Valero Energy Corporation stockholders																	$	4,065

---

See note references on pages 38 through 42.

Average Market Reference Prices and Differentials

	Year Ended December 31,
	2018				2017				Change
Refining
Feedstocks (dollars per barrel)
Brent crude oil	$	71.62			$	54.82			$	16.80
Brent less WTI crude oil	6.71				3.92				2.79
Brent less ANS crude oil	0.31				0.26				0.05
Brent less LLS crude oil	1.72				0.69				1.03
Brent less ASCI crude oil	5.20				4.18				1.02
Brent less Maya crude oil	9.22				7.74				1.48
LLS crude oil	69.90				54.13				15.77
LLS less ASCI crude oil	3.48				3.49				(0.01		)
LLS less Maya crude oil	7.50				7.05				0.45
WTI crude oil	64.91				50.90				14.01
Natural gas (dollars per MMBtu)	3.23				2.98				0.25
Products (dollars per barrel)
U.S. Gulf Coast:
CBOB gasoline less Brent	4.81				10.50				(5.69		)
ULS diesel less Brent	14.02				13.26				0.76
Propylene less Brent	(2.86		)		0.48				(3.34		)
CBOB gasoline less LLS	6.53				11.19				(4.66		)
ULS diesel less LLS	15.74				13.95				1.79
Propylene less LLS	(1.14		)		1.17				(2.31		)
U.S. Mid-Continent:
CBOB gasoline less WTI	13.70				15.65				(1.95		)
ULS diesel less WTI	22.82				18.50				4.32
North Atlantic:
CBOB gasoline less Brent	7.59				12.57				(4.98		)
ULS diesel less Brent	16.29				14.75				1.54
U.S. West Coast:
CARBOB 87 gasoline less ANS	13.05				18.12				(5.07		)
CARB diesel less ANS	18.13				17.11				1.02
CARBOB 87 gasoline less WTI	19.45				21.78				(2.33		)
CARB diesel less WTI	24.53				20.77				3.76

Average Market Reference Prices and Differentials, (continued)

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

---

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

(a)

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

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

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

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

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

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

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

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

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

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

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

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

Non-GAAP financial measures are as follows:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Total Company, Corporate, and Other

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

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

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

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

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

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

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

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

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

Refining Segment Results

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

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

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

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

•

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

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

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

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

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

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

•

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

•

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

Ethanol Segment Results

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

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

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

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

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

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

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

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

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

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

Renewable Diesel Segment Results

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

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

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

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

Cash Flows

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

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

Cash Flows for the Year Ended December 31, 2019

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

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

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

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

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

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

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

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

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

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

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

•	purchase common stock for treasury of $777 million;

•	pay common stock dividends of $1.5 billion;

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

•	pay distributions to noncontrolling interests of $70 million.

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

Cash Flows for the Year Ended December 31, 2018

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

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

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

•	a decrease of $684 million in income taxes payable primarily resulting from (i) $527 million of payments in early 2018 related to 2017 tax liabilities and (ii) $181 million of payments in late 2018 that will be applied to 2019 tax liabilities;

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

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

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

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

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

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

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

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

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

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

•	purchase common stock for treasury of $1.7 billion;

•	pay common stock dividends of $1.4 billion; and

•	pay distributions to noncontrolling interests of $116 million.

Cash Flows for the Year Ended December 31, 2017

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

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

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

•	an increase of $489 million in income taxes payable resulting from deferring the payment of our fourth quarter 2017 estimated taxes to January 2018, as allowed by tax relief authorization from the IRS; partially offset by

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

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

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

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

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

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

•	purchase common stock for treasury of $1.4 billion;

•	pay common stock dividends of $1.2 billion;

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

•	increase available cash on hand by $1.0 billion.

Capital Investments

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

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

We consider capital investments to include the following:

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

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

•	Investments in unconsolidated joint ventures.

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

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

Other Matters Impacting Liquidity and Capital Resources

Stock Purchase Program

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

Pension Plan Funding

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

Environmental Matters

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

Tax Matters

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

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

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

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

Cash Held by Our International Subsidiaries

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

Concentration of Customers

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

OFF-BALANCE SHEET ARRANGEMENTS

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

CONTRACTUAL OBLIGATIONS

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

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

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(a)

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

(b)	Operating lease liabilities include related interest expense.

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

Debt and Finance Lease Obligations

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

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

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

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

Debt Obligations – Interest Payments

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

Operating Lease Liabilities

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

Purchase Obligations

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

Other Long-Term Liabilities

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

NEW ACCOUNTING PRONOUNCEMENTS

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

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

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

Unrecognized Tax Benefits

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

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

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

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

Environmental Matters

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

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

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

Pension and Other Postretirement Benefit Obligations

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

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

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

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

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

Inventory Valuation

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

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