VALERO ENERGY CORP/TX - Annual Report: 2017 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission file number 1-13175

VALERO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



Delaware	74-1828067
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)



One Valero Way
San Antonio, Texas		78249
(Address of principal executive offices)		(Zip Code)
	Registrant’s telephone number, including area code: (210) 345-2000

Securities registered pursuant to Section 12(b) of the Act: Common stock, $0.01 par value per share listed on the New York Stock Exchange.

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting and non-voting common stock held by non-affiliates was approximately $29.8 billion based on the last sales price quoted as of June 30, 2017 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.

As of January 31, 2018, 433,176,258 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We intend to file with the Securities and Exchange Commission a definitive Proxy Statement for our Annual Meeting of Stockholders scheduled for May 3, 2018, at which directors will be elected. Portions of the 2018 Proxy Statement are incorporated by reference in Part III of this Form 10-K and are deemed to be a part of this report.

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CROSS-REFERENCE SHEET

The following table indicates the headings in the 2018 Proxy Statement where certain information required in Part III of this Form 10-K may be found.



Form 10-K Item No. and Caption		Heading in 2018 Proxy Statement

10.	Directors, Executive Officers and Corporate Governance	Information Regarding the Board of Directors, Independent Directors, Audit Committee, Proposal No. 1 Election of Directors, Information Concerning Nominees and Other Directors, Identification of Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, and Governance Documents and Codes of Ethics

11.	Executive Compensation	Compensation Committee, Compensation Discussion and Analysis, Executive Compensation, Director Compensation, Pay Ratio Disclosure, and Certain Relationships and Related Transactions

12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	Beneficial Ownership of Valero Securities and Equity Compensation Plan Information

13.	Certain Relationships and Related Transactions, and Director Independence	Certain Relationships and Related Transactions and Independent Directors

14.	Principal Accountant Fees and Services	KPMG LLP Fees and Audit Committee Pre-Approval Policy

Copies of all documents incorporated by reference, other than exhibits to such documents, will be provided without charge to each person who receives a copy of this Form 10-K upon written request to Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

CONTENTS



		PAGE
PART I		1
Items 1. & 2.	Business and Properties	1
	Segments	2
	Valero’s Operations	3
	Environmental Matters	15
	Properties	15
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	23
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	24

PART II		24
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	138
Item 9A.	Controls and Procedures	138
Item 9B.	Other Information	138

PART III		138
Item 10.	Directors, Executive Officers and Corporate Governance	138
Item 11.	Executive Compensation	138
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	138
Item 13.	Certain Relationships and Related Transactions, and Director Independence	138
Item 14.	Principal Accountant Fees and Services	138

PART IV		139
Item 15.	Exhibits and Financial Statement Schedules	139

Signature		143

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The terms “Valero,” “we,” “our,” and “us,” as used in this report, may refer to Valero Energy Corporation, to one or more of our consolidated subsidiaries, or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures beginning on page 28 of this report under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”

PART I

ITEMS 1. and 2. BUSINESS AND PROPERTIES

OVERVIEW

We are a Fortune 500 company based in San Antonio, Texas. Our corporate offices are at One Valero Way, San Antonio, Texas, 78249, and our telephone number is (210) 345-2000. We were incorporated in Delaware in 1981 under the name Valero Refining and Marketing Company. We changed our name to Valero Energy Corporation on August 1, 1997. Our common stock trades on the New York Stock Exchange (NYSE) under the symbol “VLO.” On January 31, 2018, we had 10,015 employees.

We own 15 petroleum refineries located in the United States (U.S.), Canada, and the United Kingdom (U.K.) with a combined throughput capacity of approximately 3.1 million barrels per day. Our refineries produce conventional gasolines, premium gasolines, gasoline meeting the specifications of the California Air Resources Board (CARB), diesel, low-sulfur diesel, ultra-low-sulfur diesel, CARB diesel, other distillates, jet fuel, asphalt, petrochemicals, lubricants, and other refined petroleum products. We sell our refined petroleum products in both the wholesale rack and bulk markets, and approximately 7,400 outlets carry our brand names in the U.S., Canada, the U.K., and Ireland. Most of our logistics assets support our refining operations, and some of these assets are owned by Valero Energy Partners LP (VLP), a midstream master limited partnership majority owned by us. We also own 11 ethanol plants in the Mid-Continent region of the U.S. with a combined production capacity of approximately 1.45 billion gallons per year. We sell our ethanol in the wholesale bulk market, and some of our logistics assets support our ethanol operations.

AVAILABLE INFORMATION

Our website address is www.valero.com. Information on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to those reports, filed with (or furnished to) the U.S. Securities and Exchange Commission (SEC) are available on our website (under “Investors”) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines, codes of ethics, and the charters of the committees of our board of directors. These documents are available in print to any stockholder that makes a written request to Valero Energy Corporation, Attn: Secretary, P.O. Box 696000, San Antonio, Texas 78269-6000.

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SEGMENTS

Effective January 1, 2017, 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 — VLP. The results of the VLP segment, which include the results of our majority-owned master limited partnership referred to by the same name, were transferred from the refining segment. The segment information included herein has been retrospectively adjusted for the segment changes described above.

As a result, we have three reportable segments as follows:


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


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


•	VLP segment includes the results of VLP, which provides transportation and terminaling services to our refining segment.

Financial information about our segments is presented in Note 16 of Notes to Consolidated Financial Statements and is incorporated herein by reference.

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VALERO’S OPERATIONS

REFINING

Refining Operations

As of December 31, 2017, our refining operations included 15 petroleum refineries in the U.S., Canada, and the U.K., with a combined total throughput capacity of approximately 3.1 million barrels per day (BPD). The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2017.



Refinery	Location	Throughput Capacity (a) (BPD)
U.S. Gulf Coast:
Port Arthur	Texas	395,000
Corpus Christi (b)	Texas	370,000
St. Charles	Louisiana	340,000
Texas City	Texas	260,000
Houston	Texas	235,000
Meraux	Louisiana	135,000
Three Rivers	Texas	100,000
		1,835,000

U.S. Mid-Continent:
McKee	Texas	200,000
Memphis	Tennessee	195,000
Ardmore	Oklahoma	90,000
		485,000

North Atlantic:
Pembroke	Wales, U.K.	270,000
Quebec City	Quebec, Canada	235,000
		505,000

U.S. West Coast:
Benicia	California	170,000
Wilmington	California	135,000
		305,000
Total		3,130,000


(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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Total Refining System

The following table presents the percentages of principal charges and yields (on a combined basis) for all of our refineries for 2017, during which period our total combined throughput volumes averaged approximately 2.9 million BPD.



Combined Total Refining System Charges and Yields
Charges:
	sour crude oil	32	%
	sweet crude oil	45	%
	residual fuel oil	7	%
	other feedstocks	5	%
	blendstocks	11	%
Yields:
	gasolines and blendstocks	48	%
	distillates	38	%
	other products (primarily includes petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur and asphalt)	14	%

U.S. Gulf Coast

The following table presents the percentages of principal charges and yields (on a combined basis) for the eight refineries in the U.S. Gulf Coast region for 2017, during which period total throughput volumes averaged approximately 1.7 million BPD.



Combined U.S. Gulf Coast Region Charges and Yields
Charges:
	sour crude oil	42	%
	sweet crude oil	28	%
	residual fuel oil	11	%
	other feedstocks	7	%
	blendstocks	12	%
Yields:
	gasolines and blendstocks	45	%
	distillates	39	%
	other products (primarily includes petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur and asphalt)	16	%

Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90 miles east of Houston. The refinery processes heavy sour crude oils and other feedstocks into gasoline, diesel, and jet fuel. The refinery receives crude oil by rail, marine docks, and pipelines. Finished products are distributed into the Colonial, Explorer, and other pipelines and across the refinery docks into ships or barges.

Corpus Christi East and West Refineries. Our Corpus Christi East and West Refineries are located on the Texas Gulf Coast along the Corpus Christi Ship Channel. The East Refinery processes sour crude oil, and the West Refinery processes sweet crude oil, sour crude oil, and residual fuel oil. The feedstocks are delivered by tanker or barge via deepwater docking facilities along the Corpus Christi Ship Channel, and West Texas or South Texas crude oil is delivered via pipelines. The refineries’ physical locations allow for the transfer

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of various feedstocks and blending components between them. The refineries produce gasoline, aromatics, jet fuel, diesel, and asphalt. Truck racks service local markets for gasoline, diesel, jet fuels, liquefied petroleum gases, and asphalt. These and other finished products are also distributed by ship or barge across docks and third-party pipelines.

St. Charles Refinery. Our St. Charles Refinery is located approximately 25 miles west of New Orleans along the Mississippi River. The refinery processes sour crude oils and other feedstocks into gasoline and diesel. The refinery receives crude oil over docks and has access to the Louisiana Offshore Oil Port. Finished products can be shipped over these docks or through our Parkway pipeline or the Bengal pipeline, which ultimately provide access to the Plantation or Colonial pipeline networks.

Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City Ship Channel. The refinery processes crude oils into gasoline, diesel, and jet fuel. The refinery receives its feedstocks by pipeline and by ship or barge via deepwater docking facilities along the Texas City Ship Channel. The refinery uses ships and barges, as well as the Colonial, Explorer, and other pipelines for distribution of its products.

Houston Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes a mix of crude and intermediate oils into gasoline, jet fuel, and diesel. The refinery receives its feedstocks by tankers or barges at deepwater docking facilities along the Houston Ship Channel and by various interconnecting pipelines. The majority of its finished products are delivered to local, mid-continent U.S., and northeastern U.S. markets through various pipelines, including the Colonial and Explorer pipelines.

Meraux Refinery. Our Meraux Refinery is located approximately 15 miles southeast of New Orleans along the Mississippi River. The refinery processes sour and sweet crude oils into gasoline, diesel, jet fuel, and high sulfur fuel oil. The refinery receives crude oil at its dock and has access to the Louisiana Offshore Oil Port. Finished products can be shipped from the refinery’s dock or through the Colonial pipeline. The refinery is located about 40 miles from our St. Charles Refinery, allowing for integration of feedstocks and refined petroleum product blending.

Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi and San Antonio. It processes sweet and sour crude oils into gasoline, distillates, and aromatics. The refinery has access to crude oil from sources outside the U.S. delivered to the Texas Gulf Coast at Corpus Christi, as well as crude oil from local sources through third-party pipelines and trucks. The refinery distributes its refined petroleum products primarily through third-party pipelines.

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U.S. Mid-Continent

The following table presents the percentages of principal charges and yields (on a combined basis) for the three refineries in the U.S. Mid-Continent region for 2017, during which period total throughput volumes averaged approximately 457,000 BPD.



Combined U.S. Mid-Continent Region Charges and Yields
Charges:
	sour crude oil	4	%
	sweet crude oil	89	%
	blendstocks	7	%
Yields:
	gasolines and blendstocks	54	%
	distillates	36	%
	other products (primarily includes petrochemicals, gas oils, No. 6 fuel oil, and asphalt)	10	%

McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily sweet crude oils into gasoline, diesel, jet fuels, and asphalt. The refinery has access to local and Permian Basin crude oil sources via third-party pipelines. The refinery distributes its products primarily via third-party pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.

Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi River. It processes primarily sweet crude oils. Most of its production is gasoline, diesel, and jet fuels. Crude oil supply is primarily from Cushing over the Diamond pipeline, which began operations in November 2017. Crude oil can be received, along with other feedstocks, via barge. Most of the refinery’s products are distributed via truck rack and barges.

Ardmore Refinery. Our Ardmore Refinery is located in Oklahoma, approximately 100 miles south of Oklahoma City. It processes medium sour and sweet crude oils into gasoline, diesel, and asphalt. The refinery receives local crude oil and feedstock supply via third-party pipelines. Refined petroleum products are transported to market via rail, trucks, and the Magellan pipeline system.

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North Atlantic

The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in the North Atlantic region for 2017, during which period total throughput volumes averaged approximately 491,000 BPD.



Combined North Atlantic Region Charges and Yields
Charges:
	sour crude oil	1	%
	sweet crude oil	84	%
	residual fuel oil	5	%
	blendstocks	10	%
Yields:
	gasolines and blendstocks	45	%
	distillates	42	%
	other products (primarily includes petrochemicals, gas oils, and No. 6 fuel oil)	13	%

Pembroke Refinery. Our Pembroke Refinery is located in the County of Pembrokeshire in southwest Wales, U.K. The refinery processes primarily sweet crude oils into gasoline, diesel, jet fuel, heating oil, and low-sulfur fuel oil. The refinery receives all of its feedstocks and delivers the majority of its products by ship and barge via deepwater docking facilities along the Milford Haven Waterway, with its remaining products being delivered by our Mainline pipeline system and by trucks.

Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It processes sweet crude oils into gasoline, diesel, jet fuel, heating oil, and low-sulfur fuel oil. The refinery receives crude oil by ship at its deepwater dock on the St. Lawrence River or by pipeline or ship from western Canada. The refinery transports its products through our pipeline from Quebec City to our terminal in Montreal and to various other terminals throughout eastern Canada by rail, ships, trucks, and third-party pipelines.

U.S. West Coast

The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in the U.S. West Coast region for 2017, during which period total throughput volumes averaged approximately 257,000 BPD.



Combined U.S. West Coast Region Charges and Yields
Charges:
	sour crude oil	65	%
	sweet crude oil	7	%
	other feedstocks	13	%
	blendstocks	15	%
Yields:
	gasolines and blendstocks	59	%
	distillates	25	%
	other products (primarily includes gas oil, No. 6 fuel oil, petroleum coke, sulfur and asphalt)	16	%

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Benicia Refinery. Our Benicia Refinery is located northeast of San Francisco on the Carquinez Straits of San Francisco Bay. It processes sour crude oils into gasoline, diesel, jet fuel, and asphalt. Gasoline production is primarily California Reformulated Blendstock Gasoline for Oxygenate Blending (CARBOB), which meets California Air Resource Board (CARB) specifications when blended with ethanol. The refinery receives crude oil feedstocks via a marine dock and crude oil pipelines connected to a southern California crude oil delivery system. Most of the refinery’s products are distributed via pipeline and truck rack into northern California markets.

Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles, California. The refinery processes a blend of heavy and high-sulfur crude oils. The refinery produces CARBOB gasoline, diesel, CARB diesel, jet fuel, and asphalt. The refinery is connected by pipeline to marine terminals and associated dock facilities that can move and store crude oil and other feedstocks. Refined petroleum products are distributed via pipeline systems to various third-party terminals in southern California, Nevada, and Arizona.

Feedstock Supply

Our crude oil feedstocks are purchased through a combination of term and spot contracts. Our term supply agreements are at market-related prices and are purchased directly or indirectly from various national oil companies as well as international and U.S. oil companies. The contracts generally permit the parties to amend the contracts (or terminate them), effective as of the next scheduled renewal date, by giving the other party proper notice within a prescribed period of time (e.g., 60 days, 6 months) before expiration of the current term. The majority of the crude oil purchased under our term contracts is purchased at the producer’s official stated price (i.e., the “market” price established by the seller for all purchasers) and not at a negotiated price specific to us.

Marketing

Overview

We sell refined petroleum products in both the wholesale rack and bulk markets. These sales include refined petroleum products that are manufactured in our refining operations, as well as refined petroleum products purchased or received on exchange from third parties. Most of our refineries have access to marine transportation facilities and interconnect with common-carrier pipeline systems, allowing us to sell products in the U.S., Canada, the U.K., and other countries.

Wholesale Rack Sales

We sell our gasoline and distillate products, as well as other products, such as asphalt, lube oils, and natural gas liquids (NGLs), on a wholesale basis through an extensive rack marketing network. The principal purchasers of our refined petroleum products from terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users throughout the U.S., Canada, the U.K., and Ireland.

The majority of our rack volume is sold through unbranded channels. The remainder is sold to distributors and dealers that are members of the Valero-brand family that operate 5,631 branded sites in the U.S., 923 branded sites in the U.K. and Ireland, and 839 branded sites in Canada as of December 31, 2017. These sites are independently owned and are supplied by us under multi-year contracts. For branded sites, products are sold under the Valero^®, Beacon^®, Diamond Shamrock^®,and Shamrock^® brands in the U.S., the Texaco^® brand in the U.K. and Ireland, and the Ultramar^® brand in Canada.

Bulk Sales

We also sell our gasoline and distillate products, as well as other products, such as asphalt, petrochemicals, and NGLs, through bulk sales channels in the U.S. and international markets. Our bulk sales are made to

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various oil companies, traders, and bulk end-users, such as railroads, airlines, and utilities. Our bulk sales are transported primarily by pipeline, barges, and tankers to major tank farms and trading hubs.

We also enter into refined petroleum product exchange and purchase agreements. These agreements help minimize transportation costs, optimize refinery utilization, balance refined petroleum product availability, broaden geographic distribution, and provide access to markets not connected to our refined-product pipeline systems. Exchange agreements provide for the delivery of refined petroleum products by us to unaffiliated companies at our and third-parties’ terminals in exchange for delivery of a similar amount of refined petroleum products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined petroleum products from third parties with delivery occurring at specified locations.

Logistics

We own logistics assets (crude oil pipelines, refined petroleum product pipelines, terminals, tanks, marine docks, truck rack bays, and other assets) that support our refining operations, and these assets are not owned by VLP. See discussion of the VLP segment on page 11.

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ETHANOL

We own 11 ethanol plants with a combined ethanol production capacity of 1.45 billion gallons per year. Our ethanol plants are dry mill facilities^(a)that process corn to produce ethanol, distillers grains, and corn oil^(b).We source our corn supply from local farmers and commercial elevators. Our facilities receive corn primarily by rail and truck. We publish on our website a corn bid for local farmers and cooperative dealers to facilitate corn supply transactions.

We sell our ethanol primarily to refiners and gasoline blenders under term and spot contracts in bulk markets such as New York, Chicago, the U.S. Gulf Coast, Florida, and the U.S. West Coast. We ship our dry distillers grains (DDGs) by truck or rail primarily to animal feed customers in the U.S. and Mexico. We also sell modified distillers grains locally at our plant sites, and corn oil by truck or rail. We distribute our ethanol through logistics assets, which include railcars owned by us.

The following table presents the locations of our ethanol plants, their approximate annual production capacities for ethanol (in millions of gallons) and DDGs (in tons), and their approximate corn processing capacities (in millions of bushels).



State	City	Ethanol Production Capacity	Production of DDGs	Corn Processed
Indiana	Linden	135	355,000	47
	Mount Vernon	100	263,000	35
Iowa	Albert City	135	355,000	47
	Charles City	140	368,000	49
	Fort Dodge	140	368,000	49
	Hartley	140	368,000	49
Minnesota	Welcome	140	368,000	49
Nebraska	Albion	135	355,000	47
Ohio	Bloomingburg	135	355,000	47
South Dakota	Aurora	140	368,000	49
Wisconsin	Jefferson	110	352,000	41
Total		1,450	3,875,000	509

The combined production of ethanol from our plants averaged 4.0 million gallons per day for 2017.

________________________

(a)

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

(b)

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

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VLP

VLP is a publicly traded master limited partnership formed by us 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 provide transportation and terminaling services to our refining segment and are integral to the operations of our Ardmore, Corpus Christi, Houston, McKee, Memphis, Meraux, Port Arthur, St. Charles, and Three Rivers Refineries. VLP’s common units, representing limited partner interests, are traded on the NYSE under the symbol “VLP.” VLP is discussed more fully in Note 11 of Notes to Consolidated Financial Statements.

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The following table summarizes information with respect to VLP’s pipelines:

Pipeline

Diameter

(inches)

Length

(miles)

Throughput

Capacity

(thousand BPD)

Commodity

Associated

Valero

Refinery

Significant

Third-party

System Connections

Ardmore logistics system

Hewitt segment of Red
River crude oil pipeline

138

60^(a)

crude oil

Ardmore

Plains Red River, Plains Cushing

Wynnewood refined
products pipeline

refined petroleum products

Ardmore

Magellan Central

McKee logistics system

McKee crude system

multiple segments

145

crude oil

McKee

—

McKee products system

McKee to El Paso pipeline

408

21^(b)

refined petroleum products

McKee

—

SFPP pipeline connection

16, 8

33^(c)

refined petroleum products

McKee

Kinder Morgan

SFPP System

Memphis logistics system^(d)

Collierville crude system

Collierville pipeline

10-20

210

crude oil

Memphis

Capline; Diamond ^(e)

Memphis products system

Memphis Airport pipeline
system

jet fuel

Memphis

Memphis International Airport

Shorthorn pipeline system

14, 12

120

refined petroleum products

Memphis

Exxon Memphis

Port Arthur logistics system

Lucas crude system

Lucas pipeline

400

crude oil

Port Arthur

Sunoco Logistics Nederland; Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway

Nederland pipeline

600

crude oil

Port Arthur

Sunoco Logistics Nederland

Port Arthur products system

12-10 pipeline

12, 10

refined petroleum products

Port Arthur

Sunoco Logistics MagTex;
Enterprise TE Products,
Enterprise Beaumont

20-inch diesel pipeline

216

diesel

Port Arthur

Explorer; Colonial

20-inch gasoline pipeline

144

gasoline

Port Arthur

Explorer; Colonial

St. Charles logistics system

Parkway pipeline

140

110

refined petroleum products

St. Charles

Plantation; Colonial

Three Rivers logistics system

Three Rivers crude system

110

crude oil

Three Rivers

Harvest Arrowhead;
Plains Gardendale;
EOG Eagle Ford West

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


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


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


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


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

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The following table summarizes information with respect to VLP’s terminals:



Terminal	Tank Storage Capacity (thousands of barrels)	Throughput Capacity (thousand BPD)	Commodity	Associated Valero Refinery	Significant Third-party System Connections
Ardmore logistics system
Hewitt Station tanks	300	—	crude oil	Ardmore	Plains Red River
Wynnewood terminal	180	—	refined petroleum products	Ardmore	Magellan Central
Corpus Christi logistics system
Corpus Christi East terminal	6,241	—	crude oil and refined petroleum products	Corpus Christi East	Eagle Ford Pipeline LLC; NuStar North Beach terminal, Eagle Ford pipelines & South Texas pipeline network
Corpus Christi West terminal	3,835	—	crude oil and refined petroleum products	Corpus Christi West	(same as Corpus Christi East terminal)
Houston logistics system
Houston terminal	3,642	—	crude oil and refined petroleum products	Houston	HFOTCO; Magellan crude; Seaway; Kinder Morgan Pasadena & Galena Park; Magellan East Houston & Galena Park
McKee logistics system
McKee crude system
Various terminals	240	—	crude oil	McKee	—
McKee products system
El Paso terminal	166 ^(a)	—	refined petroleum products	McKee	Kinder Morgan SFPP System
El Paso terminal truck rack	—	10 ^(b)	refined petroleum products	McKee	—
McKee terminal	4,400	—	crude oil and refined petroleum products	McKee	NuStar (several); NuStar/Phillips Denver
Memphis logistics system
Collierville crude system
Collierville terminal	975	—	crude oil	Memphis	Capline
St. James crude tank	330	—	crude oil	Memphis	Capline
Memphis products system
Memphis truck rack	8	110	refined petroleum products	Memphis	—
West Memphis terminal	1,080	—	refined petroleum products	Memphis	Exxon Memphis; Enterprise TE Products
West Memphis terminal dock	—	4 ^(c)	refined petroleum products	Memphis	—
West Memphis terminal truck rack	—	50	refined petroleum products	Memphis	—
Meraux logistics system
Meraux terminal	3,900	—	crude oil and refined petroleum products	Meraux	LOOP; CAM; Plantation; Colonial
____________________________
See footnotes on page 14.

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Terminal	Tank Storage Capacity (thousands of barrels)	Throughput Capacity (thousand BPD)	Commodity	Associated Valero Refinery	Significant Third-party System Connections
Port Arthur logistics system
Lucas crude system
Lucas terminal	1,915	—	crude oil	Port Arthur	Sunoco Logistics Nederland; Enterprise Beaumont; Cameron Highway; TransCanada Cushing MarketLink; Seaway
Seaway connection	—	750	crude oil	Port Arthur	Seaway
TransCanada connection	—	400	crude oil	Port Arthur	TransCanada Cushing MarketLink
Port Arthur products system
El Vista terminal	1,210	—	gasoline	Port Arthur	Explorer; Colonial
PAPS terminal	1,144	—	diesel	Port Arthur	Explorer; Colonial
Port Arthur terminal	8,500	—	crude oil and refined petroleum products	Port Arthur	Sunoco Logistics Nederland; Explorer; Colonial; Sunoco Logistics MagTex; Cameron Highway; TransCanada Cushing MarketLink; Enterprise Beaumont
St. Charles logistics system
St. Charles terminal	10,004	—	crude oil and refined petroleum products	St. Charles	LOOP; CAM; Plantation; Colonial
Three Rivers logistics system
Three Rivers terminal	2,250	—	crude oil and refined petroleum products	Three Rivers	NuStar South Texas; Harvest Arrowhead; Plains Gardendale; EOG Eagle Ford West

____________________________


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


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


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

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ENVIRONMENTAL MATTERS

We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:


•	Item 1A, “Risk Factors”—Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance;


•	Item 1A, “Risk Factors”—Compliance with the U.S. Environmental Protection Agency 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.”

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2017, our capital expenditures attributable to compliance with environmental regulations were $145 million, and they are currently estimated to be $290 million for 2018 and $123 million for 2019. The estimates for 2018 and 2019 do not include amounts related to capital investments at our facilities that management has deemed to be strategic investments. These amounts could materially change as a result of governmental and regulatory actions.

PROPERTIES

Our principal properties are described above under the caption “Valero’s Operations,” and that information is incorporated herein by reference. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. As of December 31, 2017, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed more fully in Notes 8 and 9 of Notes to Consolidated Financial Statements. Financial information about our properties is presented in Note 5 of Notes to Consolidated Financial Statements and is incorporated herein by reference.

Our patents relating to our refining operations are not material to us as a whole. The trademarks and tradenames under which we conduct our branded wholesale business — Valero^®, Diamond Shamrock^®, Shamrock^®, Ultramar^®, Beacon^®, and Texaco^®— and other trademarks employed in the marketing of petroleum products are integral to our wholesale rack marketing operations.

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ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results, and/or financial condition, as well as adversely affect the value of an investment in our common stock.

Our financial results are affected by volatile refining margins, which are dependent upon factors beyond our control, including the price of crude oil and the market price at which we can sell refined petroleum products.

Our financial results are primarily affected by the relationship, or margin, between refined petroleum product prices and the prices for crude oil and other feedstocks. Historically, refining margins have been volatile, and we believe they will continue to be volatile in the future. Our cost to acquire feedstocks and the price at which we can ultimately sell refined petroleum products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined petroleum products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of U.S. and international suppliers, levels of refined petroleum product inventories, productivity and growth (or the lack thereof) of U.S. and global economies, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation.

Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refining and marketing margins are uncertain. We do not produce crude oil and must purchase all of the crude oil we refine. We may purchase our crude oil and other refinery feedstocks long before we refine them and sell the refined petroleum products. Price level changes during the period between purchasing feedstocks and selling the refined petroleum products from these feedstocks could have a significant effect on our financial results. A decline in market prices may negatively impact the carrying value of our inventories.

Economic turmoil and political unrest or hostilities, including the threat of future terrorist attacks, could affect the economies of the U.S. and other countries. Lower levels of economic activity could result in declines in energy consumption, including declines in the demand for and consumption of our refined petroleum products, which could cause our revenues and margins to decline and limit our future growth prospects.

Refining margins are also significantly impacted by additional refinery conversion capacity through the expansion of existing refineries or the construction of new refineries. Worldwide refining capacity expansions may result in refining production capability exceeding refined petroleum product demand, which would have an adverse effect on refining margins.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been cheaper than benchmark crude oils, such as Louisiana Light Sweet (LLS) and Brent crude oils. These crude oil feedstock differentials vary significantly depending on overall economic conditions and trends and conditions within the markets for crude oil and refined petroleum products, and they could decline in the future, which would have a negative impact on our results of operations.

Compliance with and changes in environmental laws, including proposed climate change laws and regulations, could adversely affect our performance.

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water, or groundwater. Our operations are subject to extensive environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management,

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pollution prevention measures, greenhouse gas (GHG) emissions, and characteristics and composition of fuels, including gasoline and diesel. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities as well as at formerly owned properties or third-party sites where we have taken wastes for disposal or where our wastes have migrated. Environmental laws and regulations also may impose liability on us for the conduct of third parties, or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned.

Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, such as those relating to GHG emissions and climate change, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we sell, and decreased demand for our products that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations, discontinue use of certain process units, or install pollution control equipment that could materially and adversely affect our business, financial condition, results of operations, and liquidity.

For example, the U.S. Environmental Protection Agency (EPA) recently adopted the Residual Risk and Technology Review Rule (RTR) adding new standards for air toxic emissions, among other requirements. Emerging rules and permitting requirements implementing these revised standards may require us to install more stringent controls at our facilities, which may result in increased capital expenditures. Governmental regulations regarding GHG emissions and low carbon fuel standards could result in increased compliance costs, additional operating restrictions or permitting delays for our business, and an increase in the cost of, and reduction in demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, in 2015, the U.S., Canada, and the U.K. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (which set GHG emission reduction goals) every five years beginning in 2020. While the current U.S. administration announced its intent to withdraw from the Paris Agreement in June 2017, there are no guarantees that it will not be implemented in the U.S., or in part by U.S. states or local governments. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various U.S. states or at the U.S. federal level or in other countries could adversely affect the oil and gas industry.

Severe weather events may have an adverse effect on our assets and operations.

Some members within the scientific community believe that the increasing concentrations of greenhouse gas emissions in the Earth’s atmosphere, among other reasons, may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our assets and operations.

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Compliance with the U.S. Environmental Protection Agency Renewable Fuel Standard could adversely affect our performance.

The U.S. EPA has implemented a Renewable Fuel Standard (RFS) pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into transportation fuels consumed in the U.S. A Renewable Identification Number (RIN) is assigned to each gallon of renewable fuel produced in or imported into the U.S. As a producer of petroleum-based transportation fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at least commensurate to the U.S. EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program.

We are exposed to the volatility in the market price of RINs. We cannot predict the future prices of RINs. RINs prices are dependent upon a variety of factors, including U.S. EPA regulations, the availability of RINs for purchase, and levels of transportation fuels produced, which can vary significantly from quarter to quarter. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the U.S. EPA’s RFS mandates, our results of operations and cash flows could be adversely affected.

Disruption of our ability to obtain crude oil could adversely affect our operations.

A significant portion of our feedstock requirements is satisfied through supplies originating in the Middle East, Africa, Asia, North America, and South America. We are, therefore, subject to the political, geographic, and economic risks attendant to doing business with suppliers located in, and supplies originating from, these areas. If one or more of our supply contracts were terminated, or if political events disrupt our traditional crude oil supply, we believe that adequate alternative supplies of crude oil would be available, but it is possible that we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our results of operations could be materially adversely affected, including reduced sales volumes of refined petroleum products or reduced margins as a result of higher crude oil costs.

In addition, the U.S. government can prevent or restrict us from doing business in or with other countries. These restrictions, and those of other governments, could limit our ability to gain access to business opportunities in various countries. Actions by both the U.S. and other countries have affected our operations in the past and will continue to do so in the future.

Any attempt by the U.S. government to withdraw from or materially modify existing international trade agreements could adversely affect our business, financial condition and results of operations.

The current U.S. administration has questioned certain existing and proposed trade agreements, such as the North American Free Trade Agreement, and has withdrawn the U.S. from others such as the Trans-Pacific Partnership. The current U.S. administration has also raised the possibility of greater restrictions on trade generally, and significant increases on tariffs on goods imported into the U.S.

Changes in U.S. social, political, regulatory and economic conditions or in laws and policies governing foreign trade, manufacturing, development and investment could adversely affect our business. For example, the imposition of tariffs or other trade barriers with other countries could affect our ability to obtain feedstocks from international sources, increase our costs and reduce the competitiveness of our products.

While there is currently a lack of certainty around the likelihood, timing, and details of any such policies and reforms, if the current U.S. administration takes action to withdraw from, or materially modify, existing

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international trade agreements, our business, financial condition and results of operations could be adversely affected.

We are subject to interruptions and increased costs as a result of our reliance on third-party transportation of crude oil and the products that we manufacture.

We generally use the services of third parties to transport feedstocks to our facilities and to transport the products we manufacture to market. If we experience prolonged interruptions of supply or increases in costs to deliver our products to market, or if the ability of the pipelines, vessels, or railroads to transport feedstocks or products is disrupted because of weather events, accidents, derailment, collision, fire, explosion, governmental regulations, or third-party actions, it could have a material adverse effect on our financial position, results of operations, and liquidity.

We may incur additional costs as a result of our use of rail cars for the transportation of crude oil and the products that we manufacture.

We currently use rail cars for the transportation of some feedstocks to certain of our facilities and for the transportation of some of the products we manufacture to their markets. We own and lease rail cars for our operations. Rail transportation is subject to a variety of federal, state, and local regulations. New laws and regulations, and changes in existing laws and regulations, are frequently enacted or proposed, and could result in increased expenditures for compliance, either directly through costs for our owned and leased rail assets, or as passed along to us by rail carriers and operators. For example, in May 2014, the U.S. Department of Transportation (DOT) issued an emergency order requiring rail carriers to provide certain notifications to state agencies along routes used by trains over a certain length carrying crude oil. In addition, in November 2014, the Federal Railroad Administration (FRA) issued a final rule regarding safety training standards under the Rail Safety Improvement Act of 2008. The rule required each railroad or contractor to develop and submit a training program to perform regular oversight and annual written reviews. In May 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA), in coordination with the FRA, issued new final rules for enhanced tank car standards and operational controls for high-hazard flammable trains. In August 2016, PHMSA adopted a final rule expanding the requirements and mandating additional controls for enhanced tank cars, as required by the Fixing America’s Surface Transportation (FAST) Act of 2015. While some recent actions—including (1) a December 2017 statement that PHMSA intends to initiate rulemaking to rescind portions of its May 2015 rule; and (2) an April 2017 final rule from FRA that delays certain training-program requirements—have provided some regulatory relief, the general trend has been toward greater regulation. We do not believe recently adopted rules will have a material impact on our financial position, results of operations, and liquidity, although further changes in law, regulations or industry standards could require us to incur additional costs to the extent they are applicable to us.

Competitors that produce their own supply of feedstocks, own their own retail sites, have greater financial resources, or provide alternative energy sources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined petroleum product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for sites for our refined petroleum products. We do not produce any of our crude oil feedstocks and, following the separation of our retail business in 2013, we do not have a company-owned retail network. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have extensive retail sites. Such competitors are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

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Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial, and individual consumers.

Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms, and can adversely affect the financial strength of our business partners.

Our ability to obtain credit and capital depends in large measure on capital markets and liquidity factors that we do not control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, causing them to fail to meet their obligations to us. In addition, decreased returns on pension fund assets may also materially increase our pension funding requirements.

Our access to credit and capital markets also depends on the credit ratings assigned to our debt by independent credit rating agencies. We currently maintain investment-grade ratings by Standard & Poor’s Ratings Services, Moody’s Investors Service, and Fitch Ratings on our senior unsecured debt. Ratings from credit agencies are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Specifically, if ratings agencies were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which could adversely affect our ability to attract potential investors and our funding sources could decrease. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security, which would increase our operating costs. As a result, a downgrade below investment grade in our credit ratings could have a material adverse impact on our financial position, results of operations, and liquidity.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we were unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. We have existing revolving credit facilities, committed letter of credit facilities, and an accounts receivable sales facility to provide us with available financing to meet our ongoing cash needs. In addition, we rely on the counterparties to our derivative instruments to fund their obligations under such arrangements. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions and other counterparties to fund their commitments to us under our various financing facilities or our derivative instruments, which could have a material adverse effect on our financial position, results of operations, and liquidity.

A significant interruption in one or more of our refineries could adversely affect our business.

Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. Significant interruptions in our refining system could also lead to increased volatility in prices for crude oil feedstocks and refined petroleum products, and could increase instability in

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the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

A significant interruption related to our information technology systems could adversely affect our business.

Our information technology systems and network infrastructure may be subject to unauthorized access or attack, which could result in a loss of intellectual property, proprietary information or employee, customer or vendor data; public disclosure of sensitive information; increased costs to prevent, respond to or mitigate cybersecurity events; systems interruption; or the disruption of our business operations. A breach could also originate from, or compromise, our customers’ and vendors’ or other third-party networks outside of our control. A breach may also result in legal claims or proceedings against us by our shareholders, employees, customers and vendors. There can be no assurance that our infrastructure protection technologies and disaster recovery plans can prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

Our business may be negatively affected by work stoppages, slowdowns or strikes by our employees, as well as new labor legislation issued by regulators.

Workers at some of our refineries are covered by collective bargaining agreements. To the extent we are in negotiations for labor agreements expiring in the future, there is no assurance an agreement will be reached without a strike, work stoppage, or other labor action. Any prolonged strike, work stoppage, or other labor action could have an adverse effect on our financial condition or results of operations. In addition, future federal or state labor legislation could result in labor shortages and higher costs, especially during critical maintenance periods.

We are subject to operational risks and our insurance may not be sufficient to cover all potential losses arising from operating hazards. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our financial position, results of operations, and liquidity.

Our operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards, and natural catastrophes. As protection against these hazards, we maintain insurance coverage against some, but not all, potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage is very limited, and coverage for terrorism risks includes very broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations, and liquidity.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies. We can make no assurances that we will be able to obtain the full amount of our insurance coverage for insured events.

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Large capital projects can take many years to complete, and market conditions could deteriorate over time, negatively impacting project returns.

We may engage in capital projects based on the forecasted project economics and level of return on the capital to be employed in the project. Large-scale projects take many years to complete, and market conditions can change from our forecast. As a result, we may be unable to fully realize our expected returns, which could negatively impact our financial condition, results of operations, and cash flows.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use, gross receipts, and value-added taxes), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

On December 22, 2017, tax legislation commonly known as the Tax Cuts and Jobs Act of 2017 (Tax Reform) was enacted. Among other things, Tax Reform reduces the U.S. corporate income tax rate from 35 percent to 21 percent (beginning in 2018) and implements a new system of taxation for non-U.S. earnings, including by imposing a one-time tax on the deemed repatriation of undistributed earnings of non-U.S. subsidiaries. Beginning in 2018, Tax Reform also generally will (i) limit our annual deductions for interest expense to no more than 30 percent of our “adjusted taxable income” (plus 100 percent of our business interest income) for the year and (ii) permit us to offset only 80 percent (rather than 100 percent) of our taxable income with any net operating losses we generate after 2017. While we are currently evaluating the effects of Tax Reform, including the one-time deemed repatriation tax and the re-measurement of our deferred tax assets and liabilities, we do not expect that the provisions of Tax Reform, taken as a whole, will have any adverse impact on our cash tax liabilities, results of operations, or financial condition. In the absence of guidance on various uncertainties and ambiguities in the application of certain provisions of Tax Reform, we will use what we believe are reasonable interpretations and assumptions in applying Tax Reform, but it is possible that the Internal Revenue Service (IRS) could issue subsequent guidance or take positions on audit that differ from our prior interpretations and assumptions, which could adversely impact our cash tax liabilities, results of operations, and financial condition.

We may incur losses and additional costs as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we use to hedge our exposure to various types of risk are not effective, we may incur losses. In addition, we may be required to incur additional costs in connection with future regulation of derivative instruments to the extent it is applicable to us.

One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, VLP, which may involve a greater exposure to legal liability than our historic business operations.

One of our subsidiaries acts as the general partner of VLP, a publicly traded master limited partnership. Our control of the general partner of VLP may increase the possibility of claims of breach of fiduciary duties, including claims of conflicts of interest, related to VLP. Liability resulting from such claims could have a material adverse effect on our financial position, results of operations, and liquidity.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

LITIGATION

We incorporate by reference into this Item our disclosures made in Part II, Item 8 of this report included in Note 9 of Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

ENVIRONMENTAL ENFORCEMENT MATTERS

While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

U.S. EPA (Fuels). In our quarterly report on Form 10-Q for the quarter ended March 31, 2017, we reported that we had received a Notice of Violation (NOV) from the U.S. EPA related to violations from the Mobile Source Inspection of 2015, which we believe will result in penalties in excess of $100,000. We continue to work with the EPA to resolve this matter.

People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Third Judicial Circuit Court, Madison County (Case No. 03-CH-00459, filed May 29, 2003) (Hartford Refinery and terminal). In our quarterly report on Form 10-Q for the quarter ended September 30, 2017, we reported that the Illinois EPA had filed suit against The Premcor Refining Group Inc. alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and closed refinery. We have entered into a Partial Consent Order resolving various air and permitting violations. Our litigation with other potentially responsible parties (PRPs) and the Illinois EPA continues. We continue to assert our various defenses, limitations and potential rights for contribution from the other PRPs.

Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). We currently have multiple outstanding Violation Notices (VNs) issued by the BAAQMD from 2015 to present. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. In the fourth quarter of 2017, we entered into an agreement with BAAQMD to resolve various VNs and continue to work with the BAAQMD to resolve the remaining VNs.

South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). We currently have multiple NOVs issued by the SCAQMD. These NOVs are for alleged reporting violations and excess emissions at our Wilmington Refinery. We continue to work with the SCAQMD to resolve these NOVs.

Texas Commission on Environmental Quality (TCEQ) (McKee Refinery). In our annual report on Form 10-K for the year ended December 31, 2016, we reported that we had received a proposed Agreed Order in the amount of $121,314 from the TCEQ as an administrative penalty for alleged excess emissions at our McKee Refinery. We continue to work with the TCEQ to resolve this matter.

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ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock trades on the NYSE under the symbol “VLO.”

As of January 31, 2018, there were 5,483 holders of record of our common stock.

The following table shows the high and low sales prices of and dividends declared on our common stock for each quarter of 2017 and 2016.



	Sales Prices of the Common Stock				Dividends Per Common Share
Quarter Ended	High		Low		Dividends Per Common Share
2017:
December 31	$	93.18	$	75.84	$	0.70
September 30	77.77		64.22		0.70
June 30	68.39		60.69		0.70
March 31	71.40		64.45		0.70
2016:
December 31	$	69.85	$	52.51	$	0.60
September 30	58.08		46.88		0.60
June 30	64.06		49.91		0.60
March 31	72.49		52.55		0.60

On January 23, 2018, our board of directors declared a quarterly cash dividend of $0.80 per common share payable March 6, 2018 to holders of record at the close of business on February 13, 2018.

Dividends are considered quarterly by the board of directors, may be paid only when approved by the board, and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, and other factors and restrictions our board deems relevant. There can be no assurance that we will pay a dividend at the rates we have paid historically, or at all, in the future.

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The following table discloses purchases of shares of our common stock made by us or on our behalf during the fourth quarter of 2017.



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
October 2017	515,762	$	77.15	292,145	223,617	$1.6 billion
November 2017	2,186,889	$	81.21	216,415	1,970,474	$1.4 billion
December 2017	2,330,263	$	87.76	798	2,329,465	$1.2 billion
Total	5,032,914	$	83.83	509,358	4,523,556	$1.2 billion

(a)

The shares reported in this column represent purchases settled in the fourth quarter of 2017 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 September 21, 2016, we announced that our board of directors authorized our purchase of up to $2.5 billion of our outstanding common stock (the 2016 program) with no expiration date. As of December 31, 2017, we had $1.2 billion remaining available for purchase under the 2016 program. On January 23, 2018, 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.

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The following performance graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of Valero’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.

This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return^(a) on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the five-year period commencing December 31, 2012 and ending December 31, 2017. Our peer group comprises the following nine companies: Andeavor; BP plc; CVR Energy, Inc.; Delek US Holdings, Inc.; HollyFrontier Corporation; Marathon Petroleum Corporation; PBF Energy Inc.; Phillips 66; and Royal Dutch Shell plc.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN^(a)

Among Valero Energy Corporation, the S&P 500 Index,

and Peer Group



	As of December 31,
	2012		2013		2014		2015		2016		2017
Valero Common Stock	$	100.00	$	165.00	$	165.40	$	242.80	$	244.71	$	342.54
S&P 500	100.00		132.39		150.51		152.59		170.84		208.14
Peer Group	100.00		121.56		111.98		100.82		119.45		151.71

____________________________________


(a)	Assumes that an investment in Valero common stock and each index was $100 on December 31, 2012. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2012 through December 31, 2017.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2017 was derived from our audited financial statements. The following table should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the historical financial statements and accompanying notes included in Item 8, “Financial Statements and Supplementary Data.”

The following summaries are in millions of dollars, except for per share amounts:



	Year Ended December 31,
	2017 (a)		2016 (b)		2015 (c)		2014		2013 (d)
Operating revenues	$	93,980	$	75,659	$	87,804	$	130,844	$	138,074
Income from continuing operations	4,156		2,417		4,101		3,775		2,722
Earnings per common share from continuing operations – assuming dilution	9.16		4.94		7.99		6.97		4.96
Dividends per common share	2.80		2.40		1.70		1.05		0.85
Total assets	50,158		46,173		44,227		45,355		46,957
Debt and capital lease obligations, less current portion	8,750		7,886		7,208		5,747		6,224

_________________________________________________


(a)	Includes the impact of Tax Reform that was enacted on December 22, 2017 and resulted in a net income tax benefit of $1.9 billion ($4.26 per share – assuming dilution) as further described in Note 14 of Notes to Consolidated Financial Statements.


(b)	Includes a noncash lower of cost or market inventory valuation reserve adjustment that resulted in a net benefit to our results of operations of $747 million as described in Note 4 of Notes to Consolidated Financial Statements.


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


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

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

The following review of our results of operations and financial condition should be read in conjunction with Item 1A, “Risk Factors,” and Item 8, “Financial Statements and Supplementary Data,” included in this report.

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

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


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


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


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


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


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


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

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, petrochemicals, and ethanol;


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


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


•	the level of consumer demand, including seasonal fluctuations;

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•	refinery overcapacity or undercapacity;


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


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


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


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


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


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


•	the levels of government subsidies for alternative fuels;


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


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


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


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

•

legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those implemented under the California cap-and-trade system (also known as AB 32), the Quebec cap-and-trade system, the Ontario 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, the euro, and the Mexican peso 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.

This report includes references to financial measures that are not defined under U.S. generally accepted accounting principles (GAAP). These non-GAAP financial measures include adjusted net income attributable to Valero stockholders, adjusted operating income (loss), and refining and ethanol segment margin. We have included these non-GAAP financial measures to help facilitate the comparison of operating results between periods. See the accompanying financial tables in “RESULTS OF OPERATIONS” and note (d) to the

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accompanying tables for reconciliations of these non-GAAP financial measures to the most directly comparable U.S. GAAP financial measures. Also in note (d), we disclose the reasons why we believe our use of the non-GAAP financial measures provides useful information.

OVERVIEW AND OUTLOOK

Overview

For 2017, we reported net income attributable to Valero stockholders of $4.1 billion compared to $2.3 billion for 2016, which represents an increase of $1.8 billion. This increase is primarily due to a $1.9 billion income tax benefit in 2017 resulting from the implementation of the provisions under Tax Reform, which was enacted on December 22, 2017. See Note 14 of Notes to Consolidated Financial Statements for additional information about Tax Reform and the $1.9 billion benefit recorded by us. Excluding the impact of Tax Reform, adjusted net income attributable to Valero stockholders in 2017 was $2.2 billion. This compares to adjusted net income attributable to Valero stockholders of $1.7 billion in 2016, which has been adjusted for the amounts reflected in the table on page 34. The $479 million increase in adjusted net income attributable to Valero stockholders was primarily due to a $779 million increase in adjusted operating income between the years net of the resulting increase in income tax expense.

Operating income was $3.6 billion in each of 2017 and 2016. Excluding the amounts reflected in the tables on page 34 from both years, adjusted operating income was $3.7 billion in 2017 compared to $2.9 billion in 2016, which represents an increase of $779 million.

The $779 million increase in adjusted operating income is primarily due to the following:

•

Refining segment. Refining segment adjusted operating income increased by $942 million due to higher margins on refined petroleum products and higher throughput volumes, partially offset by lower discounts on sour crude oils and other feedstocks, higher cost of biofuel credits, and higher operating expenses (excluding depreciation and amortization expense). This is more fully described on pages 38 through 40.


•	Ethanol segment. Ethanol segment adjusted operating income decreased by $118 million primarily due to lower ethanol and corn related co-products prices. This is more fully described on page 40.

•

VLP segment. VLP segment adjusted operating income increased by $74 million primarily due to incremental revenues generated from transportation and terminaling services provided to our refining segment associated with terminals acquired in 2016 and 2017, a product pipeline system acquired in 2017, and the acquisition of an undivided interest in crude system assets in 2017. This is more fully described on page 41.


•	Corporate and eliminations. Corporate and eliminations, which consists primarily of general and administrative expenses and related depreciation and amortization expense, increased by $119 million primarily due to higher employee related costs, legal and environmental reserves, and other expenses, which are more fully described on page 38.

Additional details and analysis for the changes in operating income and adjusted operating income for our reportable business segments and other components of net income and adjusted net income attributable to Valero stockholders, including a reconciliation of non-GAAP financial measures used in this Overview to their most comparable measures reported under U.S. GAAP, are provided below under “RESULTS OF OPERATIONS”.

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Outlook

Below are several factors that have impacted or may impact our results of operations during the first quarter of 2018:


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


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


•	Sweet crude discounts are expected to remain near current levels as export demand remains strong and increased supplies from the Permian Basin are delivered into U.S. Gulf Coast markets.

•

Legislation authorizing the extension of the $1 per gallon biodiesel blender’s tax credit for biodiesel volumes blended in 2017 was passed and signed into law in February 2018. As a result, we will recognize a benefit to cost of materials and other in our refining segment results of operations for the first quarter of 2018 of approximately $170 million. The majority of this amount will be recognized by one of our consolidated variable interest entities (VIEs) in which we own a 50 percent interest; therefore, approximately one half of this amount (after taxes) will be excluded from net income attributable to Valero stockholders.

RESULTS OF OPERATIONS

The following tables highlight our results of operations, our operating performance, and market reference prices that directly impact our operations. In addition, these tables include financial measures that are not defined under U.S. GAAP and represent non-GAAP financial measures. These non-GAAP financial measures are reconciled to their most comparable U.S. GAAP financial measures and include adjusted net income attributable to Valero stockholders, adjusted operating income, and refining and ethanol segment margin. In note (d) to these tables, we disclose the reasons why we believe our use of non-GAAP financial measures provides useful information.

Effective January 1, 2017, 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 — VLP. The results of the VLP segment, which include the results of our majority-owned master limited partnership referred to by the same name, were transferred from the refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation. The narrative following these tables provides an analysis of our results of operations.

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Financial Highlights by Segment and Total Company

(millions of dollars)



	Year Ended December 31, 2017
	Refining		Ethanol		VLP		Corporate and Eliminations			Total
Operating revenues:
Operating revenues from external customers	$	90,651	$	3,324	$	—	$	5		$	93,980
Intersegment revenues	6		176		452		(634		)	—
Total operating revenues	90,657		3,500		452		(629		)	93,980
Cost of sales:
Cost of materials and other	80,865		2,804		—		(632		)	83,037
Operating expenses (excluding depreciation and amortization expense reflected below)	3,917		443		104		(2		)	4,462
Depreciation and amortization expense	1,800		81		53		—			1,934
Total cost of sales	86,582		3,328		157		(634		)	89,433
Other operating expenses (a)	58		—		3		—			61
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		835			835
Depreciation and amortization expense	—		—		—		52			52
Operating income by segment	$	4,017	$	172	$	292	$	(882	)	3,599
Other income, net										76
Interest and debt expense, net of capitalized interest										(468		)
Income before income tax benefit										3,207
Income tax benefit										(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 48 through 50.

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Financial Highlights by Segment and Total Company (continued)

(millions of dollars)



	Year Ended December 31, 2016
	Refining			Ethanol			VLP		Corporate and Eliminations			Total
Operating revenues:
Operating revenues from external customers	$	71,968		$	3,691		$	—	$	—		$	75,659
Intersegment revenues	—			210			363		(573		)	—
Total operating revenues	71,968			3,901			363		(573		)	75,659
Cost of sales:
Cost of materials and other	63,405			3,130			—		(573		)	65,962
Operating expenses (excluding depreciation and amortization expense reflected below)	3,696			415			96		—			4,207
Depreciation and amortization expense	1,734			66			46		—			1,846
Lower of cost or market inventory valuation adjustment (b)	(697		)	(50		)	—		—			(747		)
Total cost of sales	68,138			3,561			142		(573		)	71,268
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—			—			—		715			715
Depreciation and amortization expense	—			—			—		48			48
Asset impairment loss (c)	56			—			—		—			56
Operating income by segment	$	3,774		$	340		$	221	$	(763	)	3,572
Other income, net												56
Interest and debt expense, net of capitalized interest												(446		)
Income before income tax expense												3,182
Income tax expense												765
Net income												2,417
Less: Net income attributable to noncontrolling interests												128
Net income attributable to Valero Energy Corporation stockholders												$	2,289

________________

See note references on pages 48 through 50.

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Financial Highlights by Segment and Total Company (continued)

(millions of dollars)



	Year Ended December 31,
	2017		2016
Reconciliation of net income attributable to Valero Energy Corporation stockholders to adjusted net income attributable to Valero Energy Corporation stockholders (d)
Net income attributable to Valero Energy Corporation stockholders	$	4,065	$	2,289
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (b)	—		747
Income tax expense related to the lower of cost or market inventory valuation adjustment	—		(168		)
Lower of cost or market inventory valuation adjustment, net of taxes	—		579
Asset impairment loss (c)	—		(56		)
Income tax benefit on Aruba Disposition (c)	—		42
Income tax benefit from Tax Reform (e)	1,862		—
Total adjustments	1,862		565
Adjusted net income attributable to Valero Energy Corporation stockholders	$	2,203	$	1,724



	Year Ended December 31, 2017
	Refining			Ethanol		VLP			Corporate and Eliminations			Total
Reconciliation of operating income to adjusted operating income (d)
Operating income by segment	$	4,017		$	172	$	292		$	(882	)	$	3,599
Exclude:
Other operating expenses (a)	(58		)	—		(3		)	—			(61		)
Adjusted operating income	$	4,075		$	172	$	295		$	(882	)	$	3,660



	Year Ended December 31, 2016
	Refining			Ethanol		VLP		Corporate and Eliminations			Total
Reconciliation of operating income to adjusted operating income (d)
Operating income by segment	$	3,774		$	340	$	221	$	(763	)	$	3,572
Exclude:
Lower of cost or market inventory valuation adjustment (b)	697			50		—		—			747
Asset impairment loss (c)	(56		)	—		—		—			(56		)
Adjusted operating income	$	3,133		$	290	$	221	$	(763	)	$	2,881

________________

See note references on pages 48 through 50.

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Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2017		2016		Change
Throughput volumes (thousand BPD)
Feedstocks:
Heavy sour crude oil	469		396		73
Medium/light sour crude oil	458		526		(68		)
Sweet crude oil	1,323		1,193		130
Residuals	219		272		(53		)
Other feedstocks	148		152		(4		)
Total feedstocks	2,617		2,539		78
Blendstocks and other	323		316		7
Total throughput volumes	2,940		2,855		85

Yields (thousand BPD)
Gasolines and blendstocks	1,423		1,404		19
Distillates	1,127		1,066		61
Other products (f)	428		421		7
Total yields	2,978		2,891		87

Operating statistics
Refining segment margin (d)	$	9,792	$	8,563	$	1,229
Adjusted refining segment operating income (see page 34) (d)	$	4,075	$	3,133	$	942
Throughput volumes (thousand BPD)	2,940		2,855		85

Refining segment margin per barrel of throughput (g)	$	9.12	$	8.20	$	0.92
Less:
Operating expenses (excluding depreciation and amortization expense reflected below) per barrel of throughput	3.65		3.54		0.11
Depreciation and amortization expense per barrel of throughput	1.67		1.66		0.01
Adjusted refining segment operating income per barrel of throughput (h)	$	3.80	$	3.00	$	0.80

_______________

See note references on pages 48 through 50.

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Ethanol Segment Operating Highlights

(millions of dollars, except per gallon amounts)



	Year Ended December 31,
	2017		2016		Change
Operating statistics
Ethanol segment margin (d)	$	696	$	771	$	(75	)
Adjusted ethanol segment operating income (see page 34) (d)	$	172	$	290	$	(118	)
Production volumes (thousand gallons per day)	3,972		3,842		130

Ethanol segment margin per gallon of production (g)	$	0.48	$	0.55	$	(0.07	)
Less:
Operating expenses (excluding depreciation and amortization expense reflected below) per gallon of production	0.31		0.30		0.01
Depreciation and amortization expense per gallon of production	0.05		0.04		0.01
Adjusted ethanol segment operating income per gallon of production (h)	$	0.12	$	0.21	$	(0.09	)

VLP Segment Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2017		2016		Change
Operating statistics
Pipeline transportation revenue	$	101	$	78	$	23
Terminaling revenue	348		284		64
Storage and other revenue	3		1		2
Total VLP segment operating revenues	$	452	$	363	$	89

Pipeline transportation throughput (thousand BPD)	964		829		135
Pipeline transportation revenue per barrel of throughput (g)	$	0.29	$	0.26	$	0.03

Terminaling throughput (thousand BPD)	2,889		2,265		624
Terminaling revenue per barrel of throughput (g)	$	0.33	$	0.34	$	(0.01	)

_______________

See note references on pages 48 through 50.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Year Ended December 31,
	2017		2016			Change
Feedstocks
Brent crude oil	$	54.82	$	45.02		$	9.80
Brent less West Texas Intermediate (WTI) crude oil	3.92		1.83			2.09
Brent less Alaska North Slope (ANS) crude oil	0.26		1.25			(0.99		)
Brent less Louisiana Light Sweet (LLS) crude oil	0.69		0.15			0.54
Brent less Argus Sour Crude Index (ASCI) crude oil	4.18		5.18			(1.00		)
Brent less Maya crude oil	7.74		8.63			(0.89		)
LLS crude oil	54.13		44.87			9.26
LLS less ASCI crude oil	3.49		5.03			(1.54		)
LLS less Maya crude oil	7.05		8.48			(1.43		)
WTI crude oil	50.90		43.19			7.71

Natural gas (dollars per MMBtu)	2.98		2.46			0.52

Products
U.S. Gulf Coast:
CBOB gasoline less Brent	10.50		9.17			1.33
Ultra-low-sulfur diesel less Brent	13.26		10.21			3.05
Propylene less Brent	0.48		(6.68		)	7.16
CBOB gasoline less LLS	11.19		9.32			1.87
Ultra-low-sulfur diesel less LLS	13.95		10.36			3.59
Propylene less LLS	1.17		(6.53		)	7.70
U.S. Mid-Continent:
CBOB gasoline less WTI	15.65		11.82			3.83
Ultra-low-sulfur diesel less WTI	18.50		13.03			5.47
North Atlantic:
CBOB gasoline less Brent	12.57		11.99			0.58
Ultra-low-sulfur diesel less Brent	14.75		11.57			3.18
U.S. West Coast:
CARBOB 87 gasoline less ANS	18.12		17.04			1.08
CARB diesel less ANS	17.11		14.52			2.59
CARBOB 87 gasoline less WTI	21.78		17.62			4.16
CARB diesel less WTI	20.77		15.10			5.67
New York Harbor corn crush (dollars per gallon)	0.26		0.30			(0.04		)

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Total Company, Corporate, and Other

Operating revenues increased $18.3 billion in 2017 compared to 2016 primarily due to increases in refined petroleum product prices associated with our refining segment. This improvement in operating revenues was mostly offset by higher cost of materials and other and increases in other components of cost of sales between the years, resulting in an increase in operating income of $27 million in 2017 compared to 2016.

Excluding the adjustments to operating income in both years reflected in the tables on page 34, adjusted operating income was $3.7 billion in 2017 compared to $2.9 billion in 2016. Details regarding the $779 million increase in adjusted operating income between the years are discussed by segment below.

Corporate and eliminations, which consists primarily of general and administrative expenses and related depreciation and amortization expense, increased by $119 million in 2017 compared to 2016 primarily due to higher employee related costs of $50 million, an increase in legal and environmental reserves of $21 million, expenses associated with the termination of an acquisition transaction of $16 million, and an increase in charitable contributions of $10 million.

Income tax expense decreased $1.7 billion from 2016 to 2017 primarily due to a $1.9 billion income tax benefit in 2017 resulting from Tax Reform, which is more fully described in Note 14 of Notes to Consolidated Financial Statements. Excluding this benefit, the effective tax rate for 2017 was 28 percent. This compares to an effective tax rate of 26 percent in 2016, which has been adjusted for the income tax adjustments reflected in the table on page 34. The effective tax rates are lower than the U.S. statutory rate of 35 percent that was in effect through December 31, 2017, primarily because income from our international operations was taxed at statutory rates that were lower than in the U.S. The effective tax rate in 2016 was lower than the 2017 rate due to a benefit of $35 million resulting from the favorable resolution of an income tax audit.

Refining Segment Results

Refining segment operating revenues increased $18.7 billion and cost of materials and other increased $17.5 billion in 2017 compared to 2016 primarily due to increases in refined petroleum product prices and crude oil feedstock costs, respectively. The resulting $1.2 billion increase in refining segment margin (as defined in note (d) on page 48) was partially offset by increases in other components of cost of sales between the years, resulting in an increase in operating income of $243 million, from $3.8 billion in 2016 to $4.0 billion in 2017.

Excluding the adjustments reflected in the tables on page 34 from operating income in both years, adjusted operating income was $4.1 billion in 2017 compared to $3.1 billion in 2016, an increase of $942 million. The components of this increase are outlined below, along with the reasons for the changes in these components between the years.

Refining segment margin increased $1.2 billion in 2017 compared to 2016, as previously noted, primarily due to the following:

•

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

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•

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


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

•

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

•

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


•	Higher costs of biofuel credits. As 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 $193 million from $749 million in 2016 to $942 million in 2017.

•

Increase in charges from VLP. Charges from the VLP segment for transportation and terminaling services increased $89 million in 2017 compared to 2016 primarily due to additional services provided to the refining segment using terminals acquired by VLP in 2016 and 2017, a pipeline system acquired by VLP in 2017, and an undivided interest in crude system assets acquired by VLP in 2017. The increase in charges from VLP are more fully discussed in the VLP segment analysis below.

Refining segment operating expenses (excluding depreciation and amortization expense) increased $221 million primarily due to an increase in energy costs driven by higher natural gas prices ($2.98 per MMBtu in the 2017 compared to $2.46 per MMBtu in 2016).

Refining segment depreciation and amortization expense associated with our cost of sales increased $66 million due to an increase in refinery turnaround and catalyst amortization expense primarily due to

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costs incurred in the latter part of 2016 in connection with significant turnaround projects at our Port Arthur and Texas City Refineries.

Ethanol Segment Results

Ethanol segment operating revenues decreased $401 million and cost of materials and other decreased $326 million in 2017 compared to 2016 primarily due to decreases in ethanol and corn related co-product prices and lower corn prices, respectively. The resulting $75 million decrease in ethanol segment margin (as defined in note (d) on page 48), along with increases in other components of cost of sales between the years, resulted in a decrease in operating income of $168 million, from $340 million in 2016 to $172 million in 2017.

Excluding the adjustment reflected in the table on page 34 from 2016 operating income, adjusted operating income in 2016 was $290 million. Compared to this adjusted amount, operating income in 2017 decreased $118 million. The components of this decrease are outlined below, along with changes in these components between the years.

Ethanol segment margin decreased $75 million in 2017 compared to 2016, as previously noted, primarily due to the following:

•

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


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

•

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


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

Ethanol segment operating expenses (excluding depreciation and amortization expense) increased $28 million primarily due to an increase in energy costs driven by higher natural gas prices ($2.98 per MMBtu in 2017 compared to $2.46 per MMBtu in 2016).

Ethanol segment depreciation and amortization expense associated with our cost of sales increased $15 million primarily due to the write-off of assets that were idled in 2017.

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VLP Segment Results

VLP segment operating revenues increased $89 million in 2017 compared to 2016 primarily due to incremental revenues generated from transportation and terminaling services provided to our refining segment associated with terminals and pipelines acquired in 2016 and 2017. This increase in VLP segment revenues was partially offset by increases in components of cost of sales between the years, resulting in an increase in operating income of $71 million, from $221 million in 2016 to $292 million in 2017.

Excluding the adjustment reflected in the table on page 34 from 2017 operating income, adjusted operating income in 2017 was $295 million, an increase of $74 million compared to 2016. The components of this increase are outlined below, along with the reasons for the changes in these components between the years.

VLP segment revenues increased $89 million in 2017 compared to 2016, as previously noted, primarily due to the following:

•

Incremental throughput from acquired businesses and assets. VLP generated incremental terminaling revenues of $56 million from services provided to the refining segment by the McKee, Meraux, Three Rivers, and Port Arthur terminals. The McKee, Meraux, and Three Rivers Terminals were acquired in 2016 and the Port Arthur terminal was acquired in 2017. VLP also generated incremental pipeline revenues of $15 million from the Parkway pipeline and Red River crude system, which were acquired in 2017. The incremental revenues generated by these businesses and assets had a favorable impact to VLP’s operating revenues of $71 million.


•	Higher throughput volumes at systems owned or acquired prior to 2016. The refining segment shipped higher volumes of crude oil and refined petroleum products using VLP’s terminals and pipeline systems owned or acquired prior to 2016, which resulted in incremental revenues of $16 million in 2017.

VLP segment operating expenses (excluding depreciation and amortization expense) and depreciation and amortization expense associated with our cost of sales increased $8 million and $7 million, respectively, primarily due to expenses associated with the Port Arthur terminal, the Parkway pipeline, and the Red River crude system, which were acquired in 2017.

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Financial Highlights by Segment and Total Company

(millions of dollars)



	Year Ended December 31, 2016
	Refining			Ethanol			VLP		Corporate and Eliminations			Total
Operating revenues:
Operating revenues from external customers	$	71,968		$	3,691		$	—	$	—		$	75,659
Intersegment revenues	—			210			363		(573		)	—
Total operating revenues	71,968			3,901			363		(573		)	75,659
Cost of sales:
Cost of materials and other	63,405			3,130			—		(573		)	65,962
Operating expenses (excluding depreciation and amortization expense reflected below)	3,696			415			96		—			4,207
Depreciation and amortization expense	1,734			66			46		—			1,846
Lower of cost or market inventory valuation adjustment (b)	(697		)	(50		)	—		—			(747		)
Total cost of sales	68,138			3,561			142		(573		)	71,268
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—			—			—		715			715
Depreciation and amortization expense	—			—			—		48			48
Asset impairment loss (c)	56			—			—		—			56
Operating income by segment	$	3,774		$	340		$	221	$	(763	)	3,572
Other income, net												56
Interest and debt expense, net of capitalized interest												(446		)
Income before income tax expense												3,182
Income tax expense												765
Net income												2,417
Less: Net income attributable to noncontrolling interests												128
Net income attributable to Valero Energy Corporation stockholders												$	2,289

________________

See note references on pages 48 through 50.

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Financial Highlights by Segment and Total Company (continued)

(millions of dollars)



	Year Ended December 31, 2015
	Refining		Ethanol		VLP		Corporate and Eliminations			Total
Operating revenues:
Operating revenues from external customers	$	84,521	$	3,283	$	—	$	—		$	87,804
Intersegment revenues	—		151		244		(395		)	—
Total operating revenues	84,521		3,434		244		(395		)	87,804
Cost of sales:
Cost of materials and other	71,512		2,744		—		(395		)	73,861
Operating expenses (excluding depreciation and amortization expense reflected below)	3,689		448		106		—			4,243
Depreciation and amortization expense	1,699		50		46		—			1,795
Lower of cost or market inventory valuation adjustment (b)	740		50		—		—			790
Total cost of sales	77,640		3,292		152		(395		)	80,689
General and administrative expenses (excluding depreciation and amortization expense reflected below)	—		—		—		710			710
Depreciation and amortization expense	—		—		—		47			47
Operating income by segment	$	6,881	$	142	$	92	$	(757	)	6,358
Other income, net										46
Interest and debt expense, net of capitalized interest										(433		)
Income before income tax expense										5,971
Income tax expense										1,870
Net income										4,101
Less: Net income attributable to noncontrolling interests										111
Net income attributable to Valero Energy Corporation stockholders										$	3,990

________________

See note references on pages 48 through 50.

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Financial Highlights by Segment and Total Company (continued)

(millions of dollars)



	Year Ended December 31,
	2016			2015
Reconciliation of net income attributable to Valero Energy Corporation stockholders to adjusted net income attributable to Valero Energy Corporation stockholders (d)
Net income attributable to Valero Energy Corporation stockholders	$	2,289		$	3,990
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (b)	747			(790		)
Income tax expense related to the lower of cost or market inventory valuation adjustment	(168		)	166
Lower of cost or market inventory valuation adjustment, net of taxes	579			(624		)
Asset impairment loss (c)	(56		)	—
Income tax benefit on Aruba Disposition (c)	42			—
Total adjustments	565			(624		)
Adjusted net income attributable to Valero Energy Corporation stockholders	$	1,724		$	4,614



	Year Ended December 31, 2016
	Refining			Ethanol		VLP		Corporate and Eliminations			Total
Reconciliation of operating income to adjusted operating income (d)
Operating income by segment	$	3,774		$	340	$	221	$	(763	)	$	3,572
Exclude:
Lower of cost or market inventory valuation adjustment (b)	697			50		—		—			747
Asset impairment loss (c)	(56		)	—		—		—			(56		)
Adjusted operating income	$	3,133		$	290	$	221	$	(763	)	$	2,881



	Year Ended December 31, 2015
	Refining			Ethanol			VLP		Corporate and Eliminations			Total
Reconciliation of operating income to adjusted operating income (d)
Operating income by segment	$	6,881		$	142		$	92	$	(757	)	$	6,358
Exclude:
Lower of cost or market inventory valuation adjustment (b)	(740		)	(50		)	—		—			(790		)
Adjusted operating income	$	7,621		$	192		$	92	$	(757	)	$	7,148

_______________

See note references on pages 48 through 50.

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Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2016		2015		Change
Throughput volumes (thousand BPD)
Feedstocks:
Heavy sour crude oil	396		438		(42		)
Medium/light sour crude oil	526		428		98
Sweet crude oil	1,193		1,208		(15		)
Residuals	272		274		(2		)
Other feedstocks	152		140		12
Total feedstocks	2,539		2,488		51
Blendstocks and other	316		311		5
Total throughput volumes	2,855		2,799		56

Yields (thousand BPD)
Gasolines and blendstocks	1,404		1,364		40
Distillates	1,066		1,066		—
Other products (f)	421		408		13
Total yields	2,891		2,838		53

Operating statistics
Refining segment margin (d)	$	8,563	$	13,009	$	(4,446	)
Adjusted refining segment operating income (see page 44) (d)	$	3,133	$	7,621	$	(4,488	)
Throughput volumes (thousand BPD)	2,855		2,799		56

Refining segment margin per barrel of throughput (g)	$	8.20	$	12.73	$	(4.53	)
Less:
Operating expenses (excluding depreciation and amortization expense reflected below) per barrel of throughput	3.54		3.61		(0.07		)
Depreciation and amortization expense per barrel of throughput	1.66		1.66		—
Adjusted refining segment operating income per barrel of throughput (h)	$	3.00	$	7.46	$	(4.46	)

_______________

See note references on pages 48 through 50.

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Ethanol Segment Operating Highlights

(millions of dollars, except per gallon amounts)



	Year Ended December 31,
	2016		2015		Change
Operating statistics
Ethanol segment margin (d)	$	771	$	690	$	81
Adjusted ethanol segment operating income (see page 44) (d)	$	290	$	192	$	98
Production volumes (thousand gallons per day)	3,842		3,827		15

Ethanol segment margin per gallon of production (g)	$	0.55	$	0.49	$	0.06
Less:
Operating expenses (excluding depreciation and amortization expense reflected below) per gallon of production	0.30		0.32		(0.02		)
Depreciation and amortization expense per gallon of production	0.04		0.03		0.01
Adjusted ethanol segment operating income per gallon of production (h)	$	0.21	$	0.14	$	0.07

VLP Segment Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2016		2015		Change
Operating statistics
Pipeline transportation revenue	$	78	$	81	$	(3	)
Terminaling revenue	284		162		122
Storage and other revenue	1		1		—
Total VLP segment operating revenues	$	363	$	244	$	119

Pipeline transportation throughput (thousand barrels per day)	829		950		(121		)
Pipeline transportation revenue per barrel of throughput (g)	$	0.26	$	0.23	$	0.03

Terminaling throughput (thousand barrels per day)	2,265		1,340		925
Terminaling revenue per barrel of throughput (g)	$	0.34	$	0.33	$	0.01

_______________

See note references on pages 48 through 50.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Year Ended December 31,
	2016			2015			Change
Feedstocks
Brent crude oil	$	45.02		$	53.62		$	(8.60	)
Brent less West Texas Intermediate (WTI) crude oil	1.83			4.91			(3.08		)
Brent less Alaska North Slope (ANS) crude oil	1.25			0.67			0.58
Brent less Louisiana Light Sweet (LLS) crude oil	0.15			1.26			(1.11		)
Brent less Argus Sour Crude Index (ASCI) crude oil	5.18			5.63			(0.45		)
Brent less Maya crude oil	8.63			9.54			(0.91		)
LLS crude oil	44.87			52.36			(7.49		)
LLS less ASCI crude oil	5.03			4.37			0.66
LLS less Maya crude oil	8.48			8.28			0.20
WTI crude oil	43.19			48.71			(5.52		)

Natural gas (dollars per MMBtu)	2.46			2.58			(0.12		)

Products
U.S. Gulf Coast:
CBOB gasoline less Brent	9.17			9.83			(0.66		)
Ultra-low-sulfur diesel less Brent	10.21			12.64			(2.43		)
Propylene less Brent	(6.68		)	(5.94		)	(0.74		)
CBOB gasoline less LLS	9.32			11.09			(1.77		)
Ultra-low-sulfur diesel less LLS	10.36			13.90			(3.54		)
Propylene less LLS	(6.53		)	(4.68		)	(1.85		)
U.S. Mid-Continent:
CBOB gasoline less WTI	11.82			17.59