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VALERO ENERGY CORP/TX - Annual Report: 2015 (Form 10-K)

FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(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, 2015
OR
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company 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 $31.3 billion based on the last sales price quoted as of June 30, 2015 on the New York Stock Exchange, the last business day of the registrant’s most recently completed second fiscal quarter.
As of January 29, 2016, 470,392,665 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 12, 2016, at which directors will be elected. Portions of the 2016 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 2016 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 2016 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, Director Compensation, Executive Compensation, 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.




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CONTENTS
 
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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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 24 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. Our common stock trades on the New York Stock Exchange (NYSE) under the symbol “VLO.” 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. On January 31, 2016, we had 10,103 employees.

Our 15 petroleum refineries are located in the United States (U.S.), Canada, and the United Kingdom (U.K.). Our refineries can 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 products. We market branded and unbranded refined products on a wholesale basis in the U.S., Canada, the Caribbean, the U.K., and Ireland through an extensive bulk and rack marketing network and through approximately 7,500 outlets that carry our brand names. We also own 11 ethanol plants in the central plains region of the U.S. that primarily produce ethanol, which we market on a wholesale basis through a bulk marketing network.

Available Information. Our website address is www.valero.com. Information on our website is not part of this annual report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K 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.

SEGMENTS

We have two reportable segments: refining and ethanol. Our refining segment includes refining and marketing operations in the U.S., Canada, the U.K., Aruba, and Ireland. Our ethanol segment includes ethanol and marketing operations in the U.S. Financial information about our segments is presented in Note 17 of Notes to Consolidated Financial Statements and is incorporated herein by reference.

We formerly had a third reportable segment: retail. In 2013, we completed the separation of our retail business by creating an independent public company named CST Brands, Inc. (CST). The separation of our retail business is discussed in Note 3 of Notes to Consolidated Financial Statements and that discussion is incorporated herein by reference.



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VALEROS OPERATIONS
REFINING
On December 31, 2015, our refining operations included 15 petroleum refineries in the U.S., Canada, and the U.K., with a combined total throughput capacity of approximately 3.0 million barrels per day (BPD). The following table presents the locations of these refineries and their approximate feedstock throughput capacities as of December 31, 2015.

Refinery
 
Location
 
Throughput
Capacity (a)
(BPD)
U.S. Gulf Coast:
 
 
 
 
Corpus Christi (b)
 
Texas
 
370,000

Port Arthur
 
Texas
 
375,000

St. Charles
 
Louisiana
 
305,000

Texas City
 
Texas
 
260,000

Houston
 
Texas
 
175,000

Meraux
 
Louisiana
 
135,000

Three Rivers
 
Texas
 
100,000

 
 
 
 
1,720,000

 
 
 
 
 
U.S. Mid-Continent:
 
 
 
 
Memphis
 
Tennessee
 
195,000

McKee
 
Texas
 
200,000

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
 
 
 
3,015,000


(a)
“Throughput capacity” represents estimated capacity for processing crude oil, inter-mediates, and other feedstocks. Total estimated crude oil capacity is approximately 2.5 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 the year ended December 31, 2015. Our total combined throughput volumes averaged approximately 2.8 million BPD for the year ended December 31, 2015.
Combined Total Refining System Charges and Yields
Charges:
 
 
 
sour crude oil
31
%
 
sweet crude oil
43
%
 
residual fuel oil
10
%
 
other feedstocks
5
%
 
blendstocks
11
%
Yields:
 
 
 
gasolines and blendstocks
48
%
 
distillates
38
%
 
petrochemicals
3
%
 
other products (includes gas oils, No. 6 fuel oil,
petroleum coke, and asphalt)
11
%
U.S. Gulf Coast
The following table presents the percentages of principal charges and yields (on a combined basis) for the eight refineries in this region for the year ended December 31, 2015. Total throughput volumes for the U.S. Gulf Coast refining region averaged approximately 1.6 million BPD for the year ended December 31, 2015.
Combined U.S. Gulf Coast Region Charges and Yields
Charges:
 
 
 
sour crude oil
40
%
 
sweet crude oil
25
%
 
residual fuel oil
16
%
 
other feedstocks
7
%
 
blendstocks
12
%
Yields:
 
 
 
gasolines and blendstocks
46
%
 
distillates
38
%
 
petrochemicals
4
%
 
other products (includes gas oil, No. 6 fuel oil,
petroleum coke, and asphalt)
12
%
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. In 2015, we completed construction and placed into service a new 70,000 BPD crude distillation unit in the West Refinery. 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 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



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fuels, liquefied petroleum gases, and asphalt. These and other finished products are also distributed by ship or barge across docks and third-party pipelines.
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. In 2015, we completed a 15,000 BPD hydrocracker expansion project at this refinery. 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.
St. Charles Refinery. Our St. Charles Refinery is located approximately 15 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 the Parkway or Bengal pipelines, 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 with our Texas City Refinery. 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 25 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 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 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 this region for the year ended December 31, 2015. Total throughput volumes for the U.S. Mid-Continent refining region averaged approximately 447,000 BPD for the year ended December 31, 2015.
Combined U.S. Mid-Continent Region Charges and Yields
Charges:
 
 
 
sour crude oil
6
%
 
sweet crude oil
85
%
 
other feedstocks
1
%
 
blendstocks
8
%
Yields:
 
 
 
gasolines and blendstocks
54
%
 
distillates
36
%
 
petrochemicals
4
%
 
other products (includes gas oil, No. 6 fuel oil,
and asphalt)
6
%
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 is supplied to the refinery via the Capline pipeline and can also be received, along with other feedstocks, via barge. Most of the refinery’s products are distributed via truck rack and barges.
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. In 2015, we completed the final phases of a multi-year project, which increased the refinery’s crude oil processing capacity by approximately 20,000 BPD. The refinery distributes its products primarily via third-party pipelines to markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.
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 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 this region for the year ended December 31, 2015. Total throughput volumes for the North Atlantic refining region averaged approximately 494,000 BPD for the year ended December 31, 2015.
Combined North Atlantic Region Charges and Yields
Charges:
 
 
 
sour crude oil
3
%
 
sweet crude oil
84
%
 
residual fuel oil
5
%
 
other feedstocks
1
%
 
blendstocks
7
%
Yields:
 
 
 
gasolines and blendstocks
44
%
 
distillates
44
%
 
petrochemicals
1
%
 
other products (includes gas oil, No. 6 fuel oil,
and other products)
11
%
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/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.



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U.S. West Coast
The following table presents the percentages of principal charges and yields (on a combined basis) for the two refineries in this region for the year ended December 31, 2015. Total throughput volumes for the U.S. West Coast refining region averaged approximately 266,000 BPD for the year ended December 31, 2015.
Combined U.S. West Coast Region Charges and Yields
Charges:
 
 
 
sour crude oil
70
%
 
sweet crude oil
5
%
 
other feedstocks
11
%
 
blendstocks
14
%
Yields:
 
 
 
gasolines and blendstocks
60
%
 
distillates
25
%
 
other products (includes gas oil, No. 6 fuel oil,
petroleum coke, and asphalt)
15
%
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 CARBOB gasoline, which meets 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 products are distributed via pipeline systems to various third-party terminals in southern California, Nevada, and Arizona.



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Feedstock Supply
Approximately 59 percent of our current crude oil feedstock requirements are purchased through term contracts while the remaining requirements are generally purchased on the spot market. Our term supply agreements include arrangements to purchase feedstocks at market-related prices 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.
Refining Segment Sales
Overview
Our refining segment includes sales of refined products in both the wholesale rack and bulk markets. These sales include refined products that are manufactured in our refining operations as well as refined 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 Marketing
We market branded and unbranded refined products on a wholesale basis through an extensive rack marketing network. The principal purchasers of our refined 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 approximately 5,700 branded sites in the U.S. and the Caribbean, approximately 1,000 branded sites in the U.K. and Ireland, and approximately 800 branded sites in Canada. These sites are independently owned and are supplied by us under multi-year contracts. For wholesale branded sites, we promote the Valero®, Beacon®, Diamond Shamrock®, and Shamrock® brands in the U.S. and the Caribbean, the Texaco® brand in the U.K. and Ireland, and we license the Ultramar® brand in Canada.
Bulk Sales and Trading
We sell a significant portion of our gasoline and distillate production through bulk sales channels in U.S. and international markets. Our bulk sales are made to various oil companies and traders as well as certain 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 product exchange and purchase agreements. These agreements help minimize transportation costs, optimize refinery utilization, balance refined 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 products by us to unaffiliated companies at our and third-parties’ terminals in exchange for delivery of a similar amount of refined products to us by these unaffiliated companies at specified locations. Purchase agreements involve our purchase of refined products from third parties with delivery occurring at specified locations.



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Specialty Products
We sell a variety of other products produced at our refineries, which we refer to collectively as “Specialty Products.” Our Specialty Products include asphalt, lube oils, natural gas liquids (NGLs), petroleum coke, petrochemicals, and sulfur.
We produce asphalt at five of our refineries. Our asphalt products are sold for use in road construction, road repair, and roofing applications through a network of refinery and terminal loading racks.
We produce naphthenic oils at one of our refineries suitable for a wide variety of lubricant and process applications.
NGLs produced at our refineries include butane, isobutane, and propane. These products can be used for gasoline blending, home heating, and petrochemical plant feedstocks.
We are a significant producer of petroleum coke, supplying primarily power generation customers and cement manufacturers. Petroleum coke is used largely as a substitute for coal.
We produce and market a number of commodity petrochemicals including aromatics (benzene, toluene, and xylene) and two grades of propylene. Aromatics and propylenes are sold to customers in the chemical industry for further processing into such products as paints, plastics, and adhesives.
We are a large producer of sulfur with sales primarily to customers serving the agricultural sector. Sulfur is used in manufacturing fertilizer.
Logistics and Transportation
We own several transportation and logistics assets (crude oil pipelines, refined product pipelines, terminals, tanks, marine docks, truck rack bays, rail cars, and rail facilities) that support our refining and ethanol operations. In addition, through subsidiaries, we own the 2.0 percent general partner interest in Valero Energy Partners LP (VLP) and a 65.7 percent limited partner interest in VLP. VLP is a midstream master limited partnership. Its common units, representing limited partner interests, are traded on the NYSE under the symbol “VLP.” Its assets support the operations of our Ardmore, Corpus Christi, Houston, McKee, Memphis, Port Arthur, St. Charles, and Three Rivers Refineries. VLP is discussed more fully in Note 4 of Notes to Consolidated Financial Statements.



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ETHANOL
We own 11 ethanol plants with a combined ethanol production capacity of about 1.4 billion gallons per year. Our ethanol plants are dry mill facilities1 that process corn to produce ethanol and distillers grains.2 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 use to facilitate corn supply transactions.
After processing, our ethanol is held in storage tanks on-site pending loading to rail cars, trucks and barges. We sell our ethanol (i) to large customers–primarily refiners and gasoline blenders–under term and spot contracts, and (ii) 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 (DDG) by truck or rail primarily to animal feed customers in the U.S. and Mexico, with some sales into the Far East. We also sell modified distillers grains locally at our plant sites.
The following table presents the locations of our ethanol plants, their approximate ethanol and DDG production capacities, and their approximate corn processing capacities.
State
 
City
 
Ethanol Production
Capacity
(in gallons per year)
 
Production
of DDG
(in tons per year)
 
Corn Processed
(in bushels per year)
Indiana
 
Linden
 
130 million
 
385,000
 
46 million
 
 
Mount Vernon
 
100 million
 
320,000
 
37 million
Iowa
 
Albert City
 
130 million
 
385,000
 
46 million
 
 
Charles City
 
135 million
 
400,000
 
48 million
 
 
Fort Dodge
 
135 million
 
400,000
 
48 million
 
 
Hartley
 
135 million
 
400,000
 
48 million
Minnesota
 
Welcome
 
135 million
 
400,000
 
48 million
Nebraska
 
Albion
 
130 million
 
385,000
 
46 million
Ohio
 
Bloomingburg
 
130 million
 
385,000
 
46 million
South Dakota
 
Aurora
 
135 million
 
400,000
 
48 million
Wisconsin
 
Jefferson
 
105 million
 
335,000
 
39 million
 
 
total
 
1,400 million
 
4,195,000
 
500 million
    

The combined production of denatured ethanol from our plants in 2015 averaged 3.8 million gallons per day.
________________________
1 
Ethanol is commercially produced using either the wet mill or dry mill process. Wet milling involves separating the grain kernel into its component parts (germ, fiber, protein, and starch) prior to fermentation. In the dry mill process, the entire grain kernel is ground into flour. The starch in the flour is converted to ethanol during the fermentation process, creating carbon dioxide and distillers grains.

2 
During fermentation, nearly all of the starch in the grain is converted into ethanol and carbon dioxide, while the remaining nutrients (proteins, fats, minerals, and vitamins) are concentrated to yield 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.



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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”—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 9 of Notes to Consolidated Financial Statements under the caption “Environmental Liabilities,” and Note 11 of Notes to Consolidated Financial Statements under the caption “Environmental Matters.
Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2015, our capital expenditures attributable to compliance with environmental regulations were $140 million, and they are currently estimated to be $83 million for 2016 and $95 million for 2017. The estimates for 2016 and 2017 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, 2015, we were the lessee under a number of cancelable and noncancelable leases for certain properties. Our leases are discussed more fully in Notes 10 and 11 of Notes to Consolidated Financial Statements. Financial information about our properties is presented in Note 7 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–including Valero®, Diamond Shamrock®, Shamrock®, Ultramar®, Beacon®, Texaco®–and other trademarks employed in the marketing of petroleum products are integral to our wholesale 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 products.
Our financial results are primarily affected by the relationship, or margin, between refined 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 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 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 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 products. Price level changes during the period between purchasing feedstocks and selling the refined 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 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 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 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, 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



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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 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) has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards (NAAQS) for ozone, sulfur dioxide, and nitrogen dioxide, and the U.S. EPA is considering further revisions to the NAAQS. 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–including so-called “cap-and-trade” programs targeted at reducing carbon dioxide 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 will be open for signing on April 22, 2016, and will require 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. 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.
Finally, some scientists have concluded that increasing concentrations of GHG emissions in the Earth’s atmosphere 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 effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.
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 products or reduced margins as a result of higher crude oil costs.



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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.
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 continuously being enacted or proposed that could result in increased expenditures for compliance. For example, in May 2014, the U.S. Department of Transportation (DOT) issued an 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 U.S. DOT 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 and the Federal Railroad Administration issued new final rules for enhanced tank car standards and operational controls for high-hazard flammable trains. Although we do not believe recently adopted rules will have a material impact on our financial position, results of operations, and liquidity, 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 product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for sites for our refined products. We do not produce any of our crude oil feedstocks and, following the separation of our retail business, 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.
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.



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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 (S&P), Moody’s Investors Service (Moody’s), and Fitch Ratings (Fitch) 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 products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.



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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 sensitive business information, systems interruption, or the disruption of our business operations. 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.
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.
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



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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.
We may incur losses and incur 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.
If our spin-off of CST (the “Spin-off”), or certain internal transactions undertaken in anticipation of the Spin-off, were determined to be taxable for U.S. federal income tax purposes, then we and certain of our stockholders could be subject to significant tax liability.
We received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, for U.S. federal income tax purposes, the Spin-off, except for cash received in lieu of fractional shares, qualified as tax-free under sections 355 and 361 of the U.S. Internal Revenue Code of 1986, as amended (Code), and that certain internal transactions undertaken in anticipation of the Spin-off qualified for favorable treatment. The IRS did not rule, however, on whether the Spin-off satisfied certain requirements necessary to obtain tax-free treatment under section 355 of the Code. Instead, the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the private letter ruling. In connection with the private letter ruling, we also obtained an opinion from a nationally recognized accounting firm, substantially to the effect that, for U.S. federal income tax purposes, the Spin-off qualified under sections 355 and 361 of the Code. The opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by CST and us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail. Furthermore, notwithstanding the private letter ruling, the IRS could determine on audit that the Spin-off or the internal transactions undertaken in anticipation of the Spin-off should be treated as taxable transactions if it determines that any of the facts, assumptions, representations, or undertakings we or CST have made or provided to the IRS are incorrect or incomplete, or that the Spin-off or the internal transactions should be taxable for other reasons, including as a result of a significant change in stock or asset ownership after the Spin-off.
If the Spin-off ultimately were determined to be taxable, each holder of our common stock who received shares of CST common stock in the Spin-off generally would be treated as receiving a spin-off of property in an amount equal to the fair market value of the shares of CST common stock received by such holder. Any such spin-off would be a dividend to the extent of our current earnings and profits as of the end of 2013, and any accumulated earnings and profits. Any amount that exceeded our relevant earnings and profits would be treated first as a non-taxable return of capital to the extent of such holder’s tax basis in our shares of common stock with any remaining amount generally being taxed as a capital gain. In addition, we would



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recognize gain in an amount equal to the excess of the fair market value of shares of CST common stock distributed to our holders on the Spin-off date over our tax basis in such shares of CST common stock. Moreover, we could incur significant U.S. federal income tax liabilities if it ultimately were determined that certain internal transactions undertaken in anticipation of the Spin-off were taxable.
Under the terms of the tax matters agreement we entered into with CST in connection with the Spin-off, we generally are responsible for any taxes imposed on us and our subsidiaries in the event that the Spin-off and/or certain related internal transactions were to fail to qualify for tax-free treatment. However, if the Spin-off and/or such internal transactions were to fail to qualify for tax-free treatment because of actions or failures to act by CST or its subsidiaries, CST would be responsible for all such taxes. If we were to become liable for taxes under the tax matters agreement, that liability could have a material adverse effect on us. The Spin-off is more fully described in Note 3 of Notes to Consolidated Financial Statements.
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 11 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.
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). The Illinois EPA has issued several Notices of Violation (NOVs) alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and closed refinery. We are negotiating the terms of a consent order for corrective action.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). We currently have multiple outstanding Violation Notices (VNs) issued by the BAAQMD. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. In the fourth quarter of 2015, 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. In the fourth quarter of 2015, we entered into an agreement to resolve various NOVs, and we continue to work with the SCAQMD to resolve the remaining NOVs.



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Texas Commission on Environmental Quality (TCEQ) (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2014, we reported that we had received two proposed Agreed Orders from the TCEQ resolving multiple violations that occurred at our Port Arthur Refinery between May 2007 and April 2013. We continue to work with the TCEQ to finalize these Agreed Orders.
Quebec Ministry of Environment (QME) (Quebec City Refinery). In the fourth quarter of 2015, the QME issued a NOV for alleged excess emissions at our Quebec City Refinery. We are currently working with the QME to resolve the NOV.
ITEM 4. MINE SAFETY DISCLOSURES
None.



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PART II

ITEM 5. MARKET FOR REGISTRANTS 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, 2016, there were 5,911 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 2015 and 2014.

 
 
Sales Prices of the
Common Stock
 
Dividends
Per
Common
Share
Quarter Ended
 
High
 
Low
 
2015:
 
 
 
 
 
 
December 31
 
$
73.88

 
$
58.98

 
$
0.500

September 30
 
71.50

 
51.68

 
0.400

June 30
 
64.28

 
56.09

 
0.400

March 31
 
64.49

 
43.45

 
0.400

2014:
 
 
 
 
 
 
December 31
 
52.10

 
42.53

 
0.275

September 30
 
54.61

 
45.73

 
0.275

June 30
 
59.69

 
50.03

 
0.250

March 31
 
55.96

 
45.90

 
0.250


On January 21, 2016, our board of directors declared a quarterly cash dividend of $0.60 per common share payable March 3, 2016 to holders of record at the close of business on February 9, 2016.

Dividends are considered quarterly by the board of directors and may be paid only when approved by the board.




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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 2015.

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 2015
 
1,658,771

 
$
62.12

 
842,059

 
816,712

 
$2.0 billion
November 2015
 
2,412,467

 
$
71.08

 
212,878

 
2,199,589

 
$1.8 billion
December 2015
 
7,008,414

 
$
70.31

 
980

 
7,007,434

 
$1.3 billion
Total
 
11,079,652

 
$
69.25

 
1,055,917

 
10,023,735

 
$1.3 billion

(a)
The shares reported in this column represent purchases settled in the fourth quarter of 2015 relating to (i) our purchases of shares in open-market transactions to meet our obligations under stock-based compensation plans, and (ii) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our stock-based compensation plans.
(b)
On July 13, 2015, we announced that our board of directors approved our purchase of $2.5 billion of our outstanding common stock (with no expiration date), which was in addition to the remaining amount available under our $3 billion program previously authorized. During the third quarter of 2015, we completed our purchases under the $3 billion program. As of December 31, 2015, we had $1.3 billion remaining available for purchase under the $2.5 billion program.



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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 Valeros 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 return1 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, 2010 and ending December 31, 2015. Our peer group comprises the following 11 companies: Alon USA Energy, Inc.; BP plc; CVR Energy, Inc.; Delek US Holdings, Inc.; HollyFrontier Corporation; Marathon Petroleum Corporation; PBF Energy Inc.; Phillips 66; Royal Dutch Shell plc; Tesoro Corporation; and Western Refining, Inc.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN1 
Among Valero Energy Corporation, the S&P 500 Index,
and Peer Group
 
As of December 31,
 
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Valero Common Stock
$
100.00

 
$
92.15

 
$
153.13

 
$
252.67

 
$
253.28

 
$
371.80

S&P 500
100.00

 
102.11

 
118.45

 
156.82

 
178.29

 
180.75

Peer Group
100.00

 
107.70

 
117.64

 
143.16

 
131.88

 
118.95

____________________________________
1 
Assumes that an investment in Valero common stock and each index was $100 on December 31, 2010. “Cumulative total return” is based on share price appreciation plus reinvestment of dividends from December 31, 2010 through December 31, 2015.



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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data for the five-year period ended December 31, 2015 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,
 
2015 (a)
 
2014
 
2013 (b)
 
2012
 
2011 (c)
Operating revenues
$
87,804

 
$
130,844

 
$
138,074

 
$
138,393

 
$
120,607

Income from continuing
operations
4,101

 
3,775

 
2,722

 
3,114

 
2,336

Earnings per common
share from continuing
operations – assuming dilution
7.99

 
6.97

 
4.96

 
5.61

 
4.11

Dividends per common share
1.70

 
1.05

 
0.85

 
0.65

 
0.30

Total assets
44,343

 
45,550

 
47,260

 
44,477

 
42,783

Debt and capital lease
obligations, less current portion
7,250

 
5,780

 
6,261

 
6,463

 
6,732

_________________________________________________
(a)
Includes a noncash lower of cost or market inventory valuation adjustment of $790 million, as described in Note 6 of Notes to Consolidated Financial Statements.
(b)
Includes the operations of our retail business prior to its separation from us on May 1, 2013, as further described in Note 3 of Notes to Consolidated Financial Statements.
(c)
We acquired the Meraux Refinery on October 1, 2011 and the Pembroke Refinery on August 1, 2011. The information presented for 2011 includes the results of operations from these acquisitions commencing on their respective acquisition dates.




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ITEM 7. MANAGEMENTS 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 margins, including gasoline and distillate margins;
future ethanol margins;
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
anticipated levels of crude oil and refined 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 products in the regions where we operate, as well as globally;
expectations regarding environmental, tax, and other regulatory initiatives; and
the effect of general economic and other conditions on refining and ethanol industry fundamentals.

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 products or receive feedstocks;
political and economic conditions in nations that produce crude oil or consume refined products;
demand for, and supplies of, refined products such as gasoline, diesel, jet fuel, petrochemicals, and ethanol;
demand for, and supplies of, crude oil and other feedstocks;
the ability of the members of the Organization of Petroleum Exporting Countries to agree on and to maintain crude oil price and production controls;
the level of consumer demand, including seasonal fluctuations;
refinery overcapacity or undercapacity;
our ability to successfully integrate any acquired businesses into our operations;



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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 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 Renewable Identification Numbers (RINs) needed to comply with the U.S. federal Renewable Fuel Standard) 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 products and ethanol;
rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those implemented under the California Global Warming Solutions Act (also known as AB 32), Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), and the U.S. EPA’s regulation of GHGs, which may adversely affect our business or operations;
changes in the credit ratings assigned to our debt securities and trade credit;
changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, and the euro relative to the U.S. dollar;
overall economic conditions, including the stability and liquidity of financial markets; and
other factors generally described in the “Risk Factors” section included in Item 1A, “Risk Factors” in this report.

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.




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OVERVIEW AND OUTLOOK

Overview
For the year ended December 31, 2015, we reported net income attributable to Valero stockholders from continuing operations of $4.0 billion, or $7.99 per share (assuming dilution), compared to $3.7 billion, or $6.97 per share (assuming dilution), for the year ended December 31, 2014. Included in our 2015 results was a noncash charge for a lower of cost or market inventory valuation adjustment recorded in December 2015 of $790 million ($624 million after taxes, or $1.25 per share (assuming dilution)), of which $740 million was attributable to our refining segment and $50 million was attributable to our ethanol segment. This matter is more fully described in Note 6 of Notes to Consolidated Financial Statements. Included in our 2014 results was a last-in, first-out (LIFO) inventory gain of $233 million ($151 million after taxes, or $0.29 per share (assuming dilution)) primarily related to our refining segment.

Our operating income increased $456 million from 2014 to 2015 as outlined by business segment in the following table (in millions):
 
 
Year Ended December 31,
 
 
2015
 
2014
 
Change
Operating income (loss) by business segment:
 
 
 
 
 
 
Refining
 
$
6,973

 
$
5,884

 
$
1,089

Ethanol
 
142

 
786

 
(644
)
Corporate
 
(757
)
 
(768
)
 
11

Total
 
$
6,358

 
$
5,902

 
$
456


However, excluding the effect of the lower of cost or market inventory valuation adjustment and the LIFO gain discussed above, total operating income for 2015 and 2014 was $7.1 billion and $5.7 billion, respectively, reflecting a $1.4 billion favorable increase between the years, with refining segment operating income of $7.7 billion and $5.6 billion, respectively, (a favorable increase of $2.1 billion) and ethanol segment operating income of $192 million and $782 million, (an unfavorable decrease of $590 million).

The $2.1 billion increase in refining segment operating income in 2015 compared to 2014 was due to higher margins on gasoline and other refined products (e.g., petroleum coke, propane, sulfur, and lubes), partially offset by lower discounts for most sweet and sour crude oils relative to Brent crude oil and lower distillate margins. Our ethanol segment operating income decreased $590 million in 2015 compared to 2014 due to lower ethanol margins that resulted from lower ethanol and co-product prices, partially offset by lower corn feedstock costs.

Additional details and analysis of the changes in the operating income of our business segments and other components of net income attributable to Valero stockholders are provided below under “RESULTS OF OPERATIONS.”

In March 2015, we issued $600 million of 3.65 percent senior notes due March 15, 2025 and $650 million of 4.9 percent senior notes due March 15, 2045, and our consolidated subsidiary, VLP, borrowed $200 million under its revolving credit facility (the VLP Revolver), as further described in Note 10 of Notes to Consolidated Financial Statements. On July 1, 2015, VLP repaid $25 million of the amount borrowed under the VLP Revolver.



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On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock, with no expiration date to such authorization, and we had $1.3 billion remaining available under that authorization as of December 31, 2015.

Effective November 24, 2015, VLP completed a public offering of 4,250,000 common units at a price of $46.25 per unit and received net proceeds from the offering of $189 million after deducting the underwriting discount and other offering costs. This transaction is further described in Note 4 of Notes to Consolidated Financial Statements.

Outlook
Energy markets and margins were volatile during 2015, and we expect them to continue to be volatile in the 2016. Below is a summary of factors that have impacted or may impact our results of operations during the first quarter of 2016:

Gasoline margins have been volatile, but are expected to recover from seasonal lows in the near term as domestic and export demand is expected to increase. Distillate margins have been negatively impacted by mild winter temperatures and are also expected to recover from their seasonal lows.
Medium and heavy sour crude oil discounts are expected to remain wide as sour crude oil remains oversupplied. Fuel oil price weakness has also put pressure on heavy sour crude oil discounts. Sweet crude oil discounts are expected to remain weak on lower domestic sweet crude oil production and higher foreign sweet and sour crude oil imports.
Ethanol margins are expected to remain depressed as long as gasoline prices remain low.
A further decline in market prices of crude oil and refined products may negatively impact the carrying value of our inventories.




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RESULTS OF OPERATIONS
The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.
2015 Compared to 2014
Financial Highlights
(millions of dollars, except per share amounts)
 
Year Ended December 31,
 
2015
 
2014
 
Change
Operating revenues
$
87,804

 
$
130,844

 
$
(43,040
)
Costs and expenses:
 
 
 
 
 
Cost of sales (excluding the lower of cost or market inventory valuation adjustment) (a)
73,861

 
118,141

 
(44,280
)
Lower of cost or market inventory valuation adjustment (b)
790

 

 
790

Operating expenses:
 
 
 
 
 
Refining
3,795

 
3,900

 
(105
)
Ethanol
448

 
487

 
(39
)
General and administrative expenses
710

 
724

 
(14
)
Depreciation and amortization expense:
 
 
 
 
 
Refining
1,745

 
1,597

 
148

Ethanol
50

 
49

 
1

Corporate
47

 
44

 
3

Total costs and expenses
81,446

 
124,942

 
(43,496
)
Operating income
6,358

 
5,902

 
456

Other income, net
46

 
47

 
(1
)
Interest and debt expense, net of capitalized interest
(433
)
 
(397
)
 
(36
)
Income from continuing operations before income tax expense
5,971

 
5,552

 
419

Income tax expense
1,870

 
1,777

 
93

Income from continuing operations
4,101

 
3,775

 
326

Loss from discontinued operations

 
(64
)
 
64

Net income
4,101

 
3,711

 
390

Less: Net income attributable to noncontrolling interests
111

 
81

 
30

Net income attributable to Valero Energy Corporation stockholders
$
3,990

 
$
3,630

 
$
360

 
 
 
 
 
 
Net income attributable to Valero Energy Corporation stockholders:
 
 
 
 
 
Continuing operations
$
3,990

 
$
3,694

 
$
296

Discontinued operations

 
(64
)
 
64

Total
$
3,990

 
$
3,630

 
$
360

Earnings per common share – assuming dilution:
 
 
 
 
 
Continuing operations
$
7.99

 
$
6.97

 
$
1.02

Discontinued operations

 
(0.12
)
 
0.12

Total
$
7.99

 
$
6.85

 
$
1.14

________________
See note references on page 32.



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Table of Contents

Refining Operating Highlights
(millions of dollars, except per barrel amounts)
 
Year Ended December 31,
 
2015
 
2014
 
Change
Refining (c):
 
 
 
 
 
Operating income
$
6,973

 
$
5,884

 
$
1,089

Throughput margin per barrel (a) (b) (d)
$
12.97

 
$
11.05

 
$
1.92

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.71

 
3.87

 
(0.16
)
Depreciation and amortization expense
1.71

 
1.58

 
0.13

Total operating costs per barrel
5.42

 
5.45

 
(0.03
)
Operating income per barrel
$
7.55

 
$
5.60

 
$
1.95

 
 
 
 
 
 
Throughput volumes (thousand BPD):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude oil
438

 
457

 
(19
)
Medium/light sour crude oil
428

 
466

 
(38
)
Sweet crude oil
1,208

 
1,149

 
59

Residuals
274

 
230

 
44

Other feedstocks
140

 
134

 
6

Total feedstocks
2,488

 
2,436

 
52

Blendstocks and other
311

 
329

 
(18
)
Total throughput volumes
2,799

 
2,765

 
34

 
 
 
 
 
 
Yields (thousand BPD):
 
 
 
 
 
Gasolines and blendstocks
1,364

 
1,329

 
35

Distillates
1,066

 
1,047

 
19

Other products (e)
408

 
423

 
(15
)
Total yields
2,838

 
2,799

 
39

________________
See note references on page 32.



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Table of Contents

Refining Operating Highlights by Region (a) (b) (f)
(millions of dollars, except per barrel amounts)
 
Year Ended December 31,
 
2015
 
2014
 
Change
U.S. Gulf Coast:
 
 
 
 
 
Operating income
$
3,978

 
$
3,368

 
$
610

Throughput volumes (thousand BPD)
1,592

 
1,600

 
(8
)
 
 
 
 
 
 
Throughput margin per barrel (d)
$
12.27

 
$
11.03

 
$
1.24

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.64

 
3.66

 
(0.02
)
Depreciation and amortization expense
1.78

 
1.60

 
0.18

Total operating costs per barrel
5.42

 
5.26

 
0.16

Operating income per barrel
$
6.85

 
$
5.77

 
$
1.08

 
 
 
 
 
 
U.S. Mid-Continent:
 
 
 
 
 
Operating income
$
1,434

 
$
1,323

 
$
111

Throughput volumes (thousand BPD)
447

 
446

 
1

 
 
 
 
 
 
Throughput margin per barrel (d)
$
14.09

 
$
13.63

 
$
0.46

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.59

 
3.90

 
(0.31
)
Depreciation and amortization expense
1.71

 
1.61

 
0.10

Total operating costs per barrel
5.30

 
5.51

 
(0.21
)
Operating income per barrel
$
8.79

 
$
8.12

 
$
0.67

 
 
 
 
 
 
North Atlantic:
 
 
 
 
 
Operating income
$
1,446

 
$
911

 
$
535

Throughput volumes (thousand BPD)
494

 
457

 
37

 
 
 
 
 
 
Throughput margin per barrel (d)
$
12.06

 
$
10.02

 
$
2.04

Operating costs per barrel:
 
 
 
 
 
Operating expenses
2.88

 
3.40

 
(0.52
)
Depreciation and amortization expense
1.17

 
1.16

 
0.01

Total operating costs per barrel
4.05

 
4.56

 
(0.51
)
Operating income per barrel
$
8.01

 
$
5.46

 
$
2.55

 
 
 
 
 
 
U.S. West Coast:
 
 
 
 
 
Operating income
$
855

 
$
53

 
$
802

Throughput volumes (thousand BPD)
266

 
262

 
4

 
 
 
 
 
 
Throughput margin per barrel (d)
$
17.00

 
$
8.60

 
$
8.40

Operating costs per barrel:
 
 
 
 
 
Operating expenses
5.92

 
5.91

 
0.01

Depreciation and amortization expense
2.26

 
2.14

 
0.12

Total operating costs per barrel
8.18

 
8.05

 
0.13

Operating income per barrel
$
8.82

 
$
0.55

 
$
8.27

 
 
 
 
 
 
Operating income for regions above
$
7,713

 
$
5,655

 
$
2,058

Lower of cost or market inventory valuation adjustment (b)
(740
)
 

 
(740
)
LIFO gain (a)

 
229

 
(229
)
Total refining operating income
$
6,973

 
$
5,884

 
$
1,089

________________
See note references on page 32.



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Table of Contents

Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)
 
Year Ended December 31,
 
2015
 
2014
 
Change
Feedstocks:
 
 
 
 
 
Brent crude oil
$
53.62

 
$
99.57

 
$
(45.95
)
Brent less West Texas Intermediate (WTI) crude oil
4.91

 
6.40

 
(1.49
)
Brent less Alaska North Slope (ANS) crude oil
0.67

 
1.73

 
(1.06
)
Brent less LLS crude oil
2.37

 
2.79

 
(0.42
)
Brent less Mars crude oil
6.54

 
6.75

 
(0.21
)
Brent less Maya crude oil
9.54

 
13.73

 
(4.19
)
LLS crude oil
51.25

 
96.78

 
(45.53
)
LLS less Mars crude oil
4.17

 
3.96

 
0.21

LLS less Maya crude oil
7.17

 
10.94

 
(3.77
)
WTI crude oil
48.71

 
93.17

 
(44.46
)
 
 
 
 
 
 
Natural gas (dollars per million British thermal units (MMBtu))
2.58

 
4.36

 
(1.78
)
 
 
 
 
 
 
Products:
 
 
 
 
 
U.S. Gulf Coast:
 
 
 
 
 
CBOB gasoline less Brent
9.83

 
3.54

 
6.29

Ultra-low-sulfur diesel less Brent
12.64

 
14.28

 
(1.64
)
Propylene less Brent
(5.94
)
 
5.57

 
(11.51
)
CBOB gasoline less LLS
12.20

 
6.33

 
5.87

Ultra-low-sulfur diesel less LLS
15.01

 
17.07

 
(2.06
)
Propylene less LLS
(3.57
)
 
8.36

 
(11.93
)
U.S. Mid-Continent:
 
 
 
 
 
CBOB gasoline less WTI
17.59

 
12.28

 
5.31

Ultra-low-sulfur diesel less WTI
19.02

 
24.05

 
(5.03
)
North Atlantic:
 
 
 
 
 
CBOB gasoline less Brent
12.85

 
9.07

 
3.78

Ultra-low-sulfur diesel less Brent
16.05

 
18.25

 
(2.20
)
U.S. West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
25.56

 
13.40

 
12.16

CARB diesel less ANS
16.90

 
19.14

 
(2.24
)
CARBOB 87 gasoline less WTI
29.80

 
18.07

 
11.73

CARB diesel less WTI
21.14

 
23.81

 
(2.67
)
New York Harbor corn crush (dollars per gallon)
0.22

 
0.85

 
(0.63
)




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Ethanol Operating Highlights (a) (b)
(millions of dollars, except per gallon amounts)
 
Year Ended December 31,
 
2015
 
2014
 
Change
Ethanol (c):
 
 
 
 
 
Operating income
$
192

 
$
782

 
$
(590
)
Production (thousand gallons per day)
3,827

 
3,422

 
405

 
 
 
 
 
 
Gross margin per gallon of production (d)
$
0.49

 
$
1.06

 
$
(0.57
)
Operating costs per gallon of production:
 
 
 
 
 
Operating expenses
0.32

 
0.39

 
(0.07
)
Depreciation and amortization expense
0.03

 
0.04

 
(0.01
)
Total operating costs per gallon of production
0.35

 
0.43

 
(0.08
)
Operating income per gallon of production
$
0.14

 
$
0.63

 
$
(0.49
)
 
 
 
 
 
 
Operating income from above
$
192

 
$
782

 
$
(590
)
Lower of cost or market inventory valuation adjustment (b)
(50
)
 

 
(50
)
LIFO gain (a)

 
4

 
(4
)
Total ethanol operating income
$
142

 
$
786

 
$
(644
)
________________
See note references below.
The following notes relate to references on pages 28 through 32.
(a)
Cost of sales for the year ended December 31, 2014 reflects a LIFO gain of $233 million ($151 million after taxes), of which $229 million is attributable to our refining segment and $4 million is attributable to our ethanol segment. These amounts have been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the operating income and gross margin per gallon of production amounts for the ethanol segment.
(b)
In December 2015, we recorded a lower of cost or market inventory valuation adjustment of $790 million ($624 million after taxes), of which $740 million is attributable to our refining segment and $50 million is attributable to our ethanol segment. In accordance with U.S. generally accepted accounting principles (GAAP), we are required to state our inventories at the lower of cost or market. Cost is primarily determined using the LIFO inventory valuation methodology, whereby the most recently incurred costs are charged to cost of sales in the statement of income and inventories are valued at base layer acquisition costs in the balance sheet. Market is determined based on an assessment of the net realizable value of our inventory. In periods where the market price of our inventory falls below cost, we record an inventory valuation adjustment to write down the value to market in accordance with U.S. GAAP. The lower of cost or market inventory valuation adjustment for the year ended December 31, 2015 has been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the gross operating income and the gross margin per gallon of production amounts for the ethanol segment. This adjustment is further discussed in Note 6 of Notes to Consolidated Financial Statements.
(c)
The LIFO gain of $233 million recorded in 2014 (see note (a)) and the lower of cost or market inventory valuation adjustment of $790 million recorded in 2015 (see note (b)) are reflected in refining operating income and ethanol operating income for the years ended December 31, 2015 and 2014, but are excluded from throughput margin per barrel and operating income per barrel for the refining segment, and from gross margin per gallon and operating income per gallon for the ethanol segment, respectively, as also described in notes (a) and (b).
(d)
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
(e)
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.



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

General
Operating revenues decreased $43.0 billion (or 33 percent) and cost of sales decreased $44.3 billion (or 37 percent) for the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to a decrease in refined product prices and crude oil feedstock costs, respectively. Despite the decrease in operating revenues, cost of sales decreased to a greater extent resulting in an increase in operating income of $456 million in 2015, with refining segment operating income increasing by $1.1 billion and ethanol segment operating income decreasing by $644 million. The reasons for these changes in the operating results of our segments and corporate expenses, as well as other items that affected our income, are discussed below.

Refining
Refining segment operating income increased $1.1 billion from $5.9 billion in 2014 to $7.0 billion in 2015. Excluding the effect of the lower of cost or market inventory valuation adjustment of $740 million in 2015 and the LIFO gain of $229 million in 2014, our refining segment operating income increased $2.1 billion. This increase was primarily due to a $2.1 billion (or $1.92 per barrel) increase in refining margin and a $105 million decrease in operating expenses, partially offset by a $148 million increase in depreciation and amortization expense.

The increase in refining margin of $2.1 billion was due primarily to the following:

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

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

Lower discounts on light sweet and sour crude oils - Because the market prices for refined products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. For 2015, the discount in the price of light sweet and sour crude oils compared to the price of Brent crude oil narrowed. Therefore, while we benefitted from processing crude oils priced at a discount to Brent crude oil, that benefit declined in 2015 compared to 2014. For example, we processed LLS crude oil (a type of light sweet crude oil) in our U.S. Gulf Coast region that sold at a discount of $2.37 per barrel to Brent crude oil in 2015 compared



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to $2.79 per barrel in 2014, representing an unfavorable decrease of $0.42 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $9.54 per barrel to Brent crude oil in 2015 compared to a discount of $13.73 per barrel in 2014, representing an unfavorable decrease of $4.19 per barrel. We estimate that the narrowing of the discounts for sweet crude oils and sour crude oils that we processed during 2015 had an unfavorable impact to our refining margin of approximately $260 million and $770 million, respectively.

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

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

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

The decrease of $105 million in operating expenses was primarily due to a $196 million decrease in energy costs driven by lower natural gas prices ($2.58 per MMBtu in 2015 compared to $4.36 per MMBtu in 2014). This decrease in energy costs was partially offset by a $47 million increase in employee-related expenses primarily due to higher employee benefit costs and incentive compensation expenses, and a $26 million increase in costs associated with higher levels of maintenance activities in 2015.

The increase of $148 million in depreciation and amortization expense was primarily associated with the impact of new capital projects that began operating in 2015 and higher refinery turnaround and catalyst amortization.

Ethanol
Ethanol segment operating income was $142 million in 2015 compared to $786 million in 2014. Excluding the effect of the lower of cost or market inventory valuation adjustment of $50 million in 2015 and the LIFO gain of $4 million in 2014, our ethanol segment operating income decreased $590 million. This decrease was primarily due to a $628 million (or $0.57 per gallon) decrease in gross margin, partially offset by a $39 million decrease in operating expenses.

The decrease in ethanol gross margin of $628 million was due primarily to the following:
Lower ethanol prices - Ethanol prices were lower in 2015 primarily due to the decrease in crude oil and gasoline prices in 2015 compared to 2014. For example, the New York Harbor ethanol price was $1.59 per



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gallon in 2015 compared to $2.37 per gallon in 2014. We estimate that the decrease in the price of ethanol per gallon during 2015 had an unfavorable impact to our ethanol margin of approximately $800 million.

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

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

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

The $39 million decrease in operating expenses was primarily due to a $40 million decrease in energy costs related to lower natural gas prices ($2.58 per MMBtu in 2015 compared to $4.36 per MMBtu in 2014).

Other
“Interest and debt expense, net of capitalized interest” increased by $36 million in 2015. This increase was primarily due to the impact from $1.25 billion of debt issued by Valero and $200 million borrowed by VLP under the VLP Revolver in 2015.

Income tax expense increased $93 million in 2015. This increase was lower than expected given the increase in income from continuing operations of $419 million and was due primarily to earnings from our international operations that are taxed at statutory tax rates that are lower than in the U.S. In addition, in 2015, the U.K. statutory rate was lowered and we favorably settled various U.S. income tax audits.

The loss from discontinued operations in 2014 includes expenses of $64 million primarily related to an asset retirement obligation associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 2 of Notes to Consolidated Financial Statements.



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2014 Compared to 2013

Financial Highlights (a)
(millions of dollars, except per share amounts)
 
Year Ended December 31,
 
2014
 
2013 (c)
 
Change
Operating revenues
$
130,844

 
$
138,074

 
$
(7,230
)
Costs and expenses:
 
 
 
 
 
Cost of sales (b)
118,141

 
127,316

 
(9,175
)
Operating expenses:
 
 
 
 
 
Refining
3,900

 
3,710

 
190

Retail

 
226

 
(226
)
Ethanol
487

 
387

 
100

General and administrative expenses
724

 
758

 
(34
)
Depreciation and amortization expense:
 
 
 
 
 
Refining
1,597

 
1,566

 
31

Retail

 
41

 
(41
)
Ethanol
49

 
45

 
4

Corporate
44

 
68

 
(24
)
Total costs and expenses
124,942

 
134,117

 
(9,175
)
Operating income
5,902

 
3,957

 
1,945

Gain on disposition of retained interest in CST Brands, Inc. (c)

 
325

 
(325
)
Other income, net
47

 
59

 
(12
)
Interest and debt expense, net of capitalized interest
(397
)
 
(365
)
 
(32
)
Income from continuing operations before income tax expense
5,552

 
3,976

 
1,576

Income tax expense
1,777

 
1,254

 
523

Income from continuing operations
3,775

 
2,722

 
1,053

Income (loss) from discontinued operations
(64
)
 
6

 
(70
)
Net income
3,711

 
2,728

 
983

Less: Net income attributable to noncontrolling interest
81

 
8

 
73

Net income attributable to Valero Energy Corporation stockholders
$
3,630

 
$
2,720

 
$
910

 
 
 
 
 
 
Net income attributable to Valero Energy Corporation stockholders:
 
 
 
 
 
Continuing operations
$
3,694

 
$
2,714

 
$
980

Discontinued operations
(64
)
 
6

 
(70
)
Total
$
3,630

 
$
2,720

 
$
910

Earnings per common share – assuming dilution:
 
 
 
 
 
Continuing operations
$
6.97

 
$
4.96

 
$
2.01

Discontinued operations
(0.12
)
 
0.01

 
(0.13
)
Total
$
6.85

 
$
4.97

 
$
1.88

________________
See note references on page 40.



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Refining Operating Highlights (a)
(millions of dollars, except per barrel amounts)
 
Year Ended December 31,
 
2014
 
2013
 
Change
Refining (d):
 
 
 
 
 
Operating income
$
5,884

 
$
4,211

 
$
1,673

Throughput margin per barrel (b) (e)
$
11.05

 
$
9.69

 
$
1.36

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.87

 
3.79

 
0.08

Depreciation and amortization expense
1.58

 
1.60

 
(0.02
)
Total operating costs per barrel
5.45

 
5.39

 
0.06

Operating income per barrel
$
5.60

 
$
4.30

 
$
1.30

 
 
 
 
 
 
Throughput volumes (thousand BPD):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude oil
457

 
486

 
(29
)
Medium/light sour crude oil
466

 
466

 

Sweet crude oil
1,149

 
1,039

 
110

Residuals
230

 
282

 
(52
)
Other feedstocks
134

 
106

 
28

Total feedstocks
2,436

 
2,379

 
57

Blendstocks and other
329

 
303

 
26

Total throughput volumes
2,765

 
2,682

 
83

 
 
 
 
 
 
Yields (thousand BPD):
 
 
 
 
 
Gasolines and blendstocks
1,329

 
1,287

 
42

Distillates
1,047

 
984

 
63

Other products (f)
423

 
440

 
(17
)
Total yields
2,799

 
2,711

 
88

________________
See note references on page 40.



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Refining Operating Highlights by Region (b) (g)
(millions of dollars, except per barrel amounts)
 
Year Ended December 31,
 
2014
 
2013
 
Change
U.S. Gulf Coast (a):
 
 
 
 
 
Operating income
$
3,368

 
$
2,375

 
$
993

Throughput volumes (thousand BPD)
1,600

 
1,523

 
77

 
 
 
 
 
 
Throughput margin per barrel (e)
$
11.03

 
$
9.57

 
$
1.46

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.66

 
3.67

 
(0.01
)
Depreciation and amortization expense
1.60

 
1.63

 
(0.03
)
Total operating costs per barrel
5.26

 
5.30

 
(0.04
)
Operating income per barrel
$
5.77

 
$
4.27

 
$
1.50

 
 
 
 
 
 
U.S. Mid-Continent:
 
 
 
 
 
Operating income
$
1,323

 
$
1,293

 
$
30

Throughput volumes (thousand BPD)
446

 
435

 
11

 
 
 
 
 
 
Throughput margin per barrel (e)
$
13.63

 
$
13.37

 
$
0.26

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.90

 
3.58

 
0.32

Depreciation and amortization expense
1.61

 
1.64

 
(0.03
)
Total operating costs per barrel
5.51

 
5.22

 
0.29

Operating income per barrel
$
8.12

 
$
8.15

 
$
(0.03
)
 
 
 
 
 
 
North Atlantic:
 
 
 
 
 
Operating income
$
911

 
$
570

 
$
341

Throughput volumes (thousand BPD)
457

 
459

 
(2
)
 
 
 
 
 
 
Throughput margin per barrel (e)
$
10.02

 
$
7.93

 
$
2.09

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.40

 
3.50

 
(0.10
)
Depreciation and amortization expense
1.16

 
1.03

 
0.13

Total operating costs per barrel
4.56

 
4.53

 
0.03

Operating income per barrel
$
5.46

 
$
3.40

 
$
2.06

 
 
 
 
 
 
U.S. West Coast:
 
 
 
 
 
Operating income (loss)
$
53

 
$
(27
)
 
$
80

Throughput volumes (thousand BPD)
262

 
265

 
(3
)
 
 
 
 
 
 
Throughput margin per barrel (e)
$
8.60

 
$
7.43

 
$
1.17

Operating costs per barrel:
 
 
 
 
 
Operating expenses
5.91

 
5.35

 
0.56

Depreciation and amortization expense
2.14

 
2.35

 
(0.21
)
Total operating costs per barrel
8.05

 
7.70

 
0.35

Operating income (loss) per barrel
$
0.55

 
$
(0.27
)
 
$
0.82

 
 
 
 
 
 
Operating income for regions above
$
5,655

 
$
4,211

 
$
1,444

LIFO gain (b)
229

 

 
229

Total refining operating income
$
5,884

 
$
4,211

 
$
1,673

________________
See note references on page 40.



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Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)
 
Year Ended December 31,
 
2014
 
2013
 
Change
Feedstocks:
 
 
 
 
 
Brent crude oil
$
99.57

 
$
108.74

 
$
(9.17
)
Brent less WTI crude oil
6.40

 
10.80

 
(4.40
)
Brent less ANS crude oil
1.73

 
1.00

 
0.73

Brent less LLS crude oil
2.79

 
0.41

 
2.38

Brent less Mars crude oil
6.75

 
5.52

 
1.23

Brent less Maya crude oil
13.73

 
11.31

 
2.42

LLS crude oil
96.78

 
108.33

 
(11.55
)
LLS less Mars crude oil
3.96

 
5.11

 
(1.15
)
LLS less Maya crude oil
10.94

 
10.90

 
0.04

WTI crude oil
93.17

 
97.94

 
(4.77
)
 
 
 
 
 
 
Natural gas (dollars per MMBtu)
4.36

 
3.69

 
0.67

 
 
 
 
 
 
Products:
 
 
 
 
 
U.S. Gulf Coast:
 
 
 
 
 
CBOB gasoline less Brent
3.54

 
2.69

 
0.85

Ultra-low-sulfur diesel less Brent
14.28

 
15.95

 
(1.67
)
Propylene less Brent
5.57

 
(2.72
)
 
8.29

CBOB gasoline less LLS
6.33

 
3.10

 
3.23

Ultra-low-sulfur diesel less LLS
17.07

 
16.36

 
0.71

Propylene less LLS
8.36

 
(2.31
)
 
10.67

U.S. Mid-Continent:
 
 
 
 
 
CBOB gasoline less WTI
12.28

 
16.77

 
(4.49
)
Ultra-low-sulfur diesel less WTI
24.05

 
28.33

 
(4.28
)
North Atlantic:
 
 
 
 
 
CBOB gasoline less Brent
9.07

 
8.50

 
0.57

Ultra-low-sulfur diesel less Brent
18.25

 
17.84

 
0.41

U.S. West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
13.40

 
12.69

 
0.71

CARB diesel less ANS
19.14

 
18.83

 
0.31

CARBOB 87 gasoline less WTI
18.07

 
22.49

 
(4.42
)
CARB diesel less WTI
23.81

 
28.63

 
(4.82
)
New York Harbor corn crush (dollars per gallon)
0.85

 
0.42

 
0.43





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Ethanol and Retail Operating Highlights
(millions of dollars, except per gallon amounts)
 
Year Ended December 31,
 
2014
 
2013
 
Change
Ethanol (d):
 
 
 
 
 
Operating income
$
782

 
$
491

 
$
291

Production (thousand gallons per day)
3,422

 
3,294

 
128

 
 
 
 
 
 
Gross margin per gallon of production (e)
$
1.06

 
$
0.77

 
$
0.29

Operating costs per gallon of production:
 
 
 
 
 
Operating expenses
0.39

 
0.32

 
0.07

Depreciation and amortization expense
0.04

 
0.04

 

Total operating costs per gallon of production
0.43

 
0.36

 
0.07

Operating income per gallon of production
$
0.63

 
$
0.41

 
$
0.22

 
 
 
 
 
 
Operating income from above
$
782

 
$
491

 
$
291

LIFO gain (b)
4

 

 
4

Total ethanol operating income
$
786

 
$
491

 
$
295

 
 
 
 
 
 
Retail:
 
 
 
 
 
Operating income
$

 
$
81

 
$
(81
)
________________
See note references below.
The following notes relate to references on pages 36 through 40.
(a)
In May 2014, we abandoned our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result, the refinery’s results of operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all years presented.This transaction is more fully described in Note 2 of Notes to Consolidated Financial Statements.
(b)
Cost of sales for the year ended December 31, 2014 reflects a LIFO gain of $233 million ($151 million after taxes), of which $229 million is attributable to our refining segment and $4 million is attributable to our ethanol segment. These amounts have been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the operating income and gross margin per gallon of production amounts for the ethanol segment.
(c)
On May 1, 2013, we completed the separation of our retail business. As a result and effective May 1, 2013, our results of operations no longer include those of CST, our former retail business. The nature and significance of our post-separation participation in the supply of motor fuel to CST represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations related to CST have not been reported as discontinued operations in the statements of income. This transaction is more fully discussed in Note 3 of Notes to Consolidated Financial Statements.
(d)
The LIFO gain of $233 million recorded in 2014 (see note (b)) is reflected in refining operating income and ethanol operating income for the year ended December 31, 2014, but is excluded from throughput margin per barrel and operating income per barrel for the refining segment, and from gross margin per gallon and operating income per gallon for the ethanol segment, respectively, as also described in note (b).
(e)
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
(f)
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.



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

General
Operating revenues decreased $7.2 billion (or 5 percent) for the year ended December 31, 2014 compared to the year ended December 31, 2013. This decrease was primarily due to a decrease in refined product prices in all of our regions. Despite the decline in operating revenues, operating income increased $1.9 billion in 2014 due primarily to a $1.7 billion increase in refining segment operating income, a $295 million increase in ethanol segment operating income, and a $34 million decrease in general and administrative expenses, partially offset by an $81 million decrease in retail segment operating income due to the spin-off of our retail business in 2013 as mentioned previously. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.

Refining
Refining segment operating income increased $1.7 billion from $4.2 billion in 2013 to $5.9 billion in 2014. Excluding the LIFO gain of $229 million in 2014 related to our refining segment, our refining segment operating income increased by $1.4 billion. This increase was primarily due to a $1.7 billion (or $1.36 per barrel) increase in refining margin, partially offset by a $190 million increase in operating expenses and a $31 million increase in depreciation and amortization expense.

The increase in refining margin of $1.7 billion was due primarily to the following:

Higher discounts on light sweet crude oils and sour crude oils - Because the market prices for refined products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. For 2014, the discount in the price of some light sweet crude oils and sour crude oils compared to the price of Brent crude oil widened. For example, LLS crude oil processed in our U.S. Gulf Coast region, which is a light sweet crude oil, sold at a discount of $2.79 per barrel to Brent crude oil in 2014 compared to $0.41 per barrel in 2013, representing a favorable increase of $2.38 per barrel. Another example is Maya crude oil, a sour crude oil, which sold at a discount of $13.73 per barrel to Brent crude oil in 2014 compared to a discount of $11.31 per barrel in 2013, representing a favorable increase of $2.42 per barrel. We estimate that the discounts for light sweet crude oils and sour crude oils that we processed in 2014 had a positive impact to our refining margin of approximately $680 million and $800 million, respectively.

Higher throughput volumes - Refining throughput volumes increased 83,000 BPD in 2014. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $340 million.

Lower costs of biofuel credits - As more fully described in Note 20 of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligations under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) decreased by $145 million from $517 million in 2013 to $372 million in 2014. This decrease was due primarily to a reduction in the market price of RINs between the years.




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Increase in other refinery products margins - We experienced an increase in the margins of other refinery products relative to Brent crude oil, such as petroleum coke and sulfur during 2014 compared to 2013. Margins for other refinery products were higher during 2014 due to the decrease in the cost of crude oils during the year compared to 2013. For example, the benchmark price of Brent crude oil was $99.57 per barrel in 2014 compared to $108.74 in 2013. We estimate that the increase in other refinery products margins in 2014 had a positive impact to our refining margin of approximately $430 million.

Decrease in distillate margins - We experienced a decrease in distillate margins in our U.S. Gulf Coast region primarily due to the decrease in refined product prices . For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low sulfur diesel was $14.28 per barrel in 2014 compared to $15.95 per barrel in 2013, representing an unfavorable decrease of $1.67 per barrel. We estimate that the decline in distillate margins in 2014 had a negative impact to our refining margin of approximately $400 million.

The increase of $190 million in operating expenses was primarily due to a $128 million increase in energy costs related to higher natural gas prices ($4.36 per MMBtu in 2014 compared to $3.69 per MMBtu in 2013) and a $22 million increase in maintenance expense primarily related to higher levels of routine maintenance activities in 2014.

The increase of $31 million in depreciation and amortization expense was primarily due to additional depreciation expense of $25 million associated with the new hydrocracker unit at our St. Charles Refinery that began operating in July 2013.

Ethanol
Ethanol segment operating income was $786 million in 2014 compared to $491 million in 2013. The $295 million increase in operating income was due primarily to a $399 million (or $0.29 per gallon) increase in gross margin, partially offset by a $100 million increase in operating expenses.

The increase in ethanol gross margin of $399 million was due primarily to the following:

Lower corn prices - Corn prices were lower in 2014 due to higher corn inventories in 2014 compared to 2013, which resulted from a higher yielding harvest in 2013 compared to the drought-stricken harvest of 2012. For example, the CBOT corn price was $4.16 per bushel in 2014 compared to $5.80 per bushel in 2013. The decrease in the price of corn that we processed during 2014 favorably impacted our ethanol margin by approximately $910 million.

Lower ethanol prices - Ethanol prices were lower in 2014 due to higher ethanol inventories resulting from higher industry run rates in 2014 as compared to 2013. The decrease in crude oil and gasoline prices in 2014 also contributed to the decrease in ethanol prices. For example, the New York Harbor ethanol price was $2.37 per gallon in 2014 compared to $2.53 per gallon in 2013. The decrease in the price of ethanol per gallon during 2014 had an unfavorable impact to our ethanol margin of approximately $260 million.

Lower co-product prices - The decrease in corn prices in 2014 had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. The decrease in co-products prices had an unfavorable impact to our ethanol segment margin of approximately $250 million.




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The $100 million increase in operating expenses in 2014 was partially due to $22 million in operating expenses of the Mount Vernon plant acquired in March 2014. The remaining increase of $78 million was primarily due to increased energy costs and chemical costs. The increase in energy costs of $57 million was due primarily to the severe winter weather in the U.S. in the first quarter of 2014 that caused a significant increase in regional natural gas prices combined with higher use of natural gas due to the increase in production volumes. The increase in chemical costs of $16 million was due to higher production volumes.

Corporate Expenses and Other
General and administrative expenses decreased $34 million in 2014 primarily due to $30 million of transaction costs in 2013 related to the separation of our retail business on May 1, 2013.

Depreciation and amortization expense decreased $24 million primarily due to a $20 million loss on the sale of certain corporate property in 2013 that was reflected in depreciation and amortization expense.

“Interest and debt expense, net of capitalized interest” increased $32 million in 2014. This increase was primarily due to a $48 million decrease in capitalized interest due to the completion of several large capital projects during 2013, including the new hydrocracker at our St. Charles Refinery, partially offset by a $20 million favorable impact from a decrease in average borrowings.

Income tax expense increased $523 million in 2014 due to higher income from continuing operations before income tax expense. The effective rate for both years is lower than the U.S. statutory rate because income from continuing operations from our international operations was taxed at statutory rates that were lower than in the U.S. and due to a higher benefit from our U.S. manufacturing deduction.

Income (loss) from discontinued operations in 2014 includes expenses of $59 million for an asset retirement obligation and $4 million for certain contractual obligations associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 2 of Notes to Consolidated Financial Statements.




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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2015
Our operations generated $5.6 billion of cash in 2015, driven primarily by net income of $4.1 billion and excluding $2.6 billion of noncash charges to income ($1.8 billion for depreciation and amortization expense and $790 million for a lower of cost or market inventory valuation adjustment). See “RESULTS OF OPERATIONS” for further discussion of our operations. However, the change in working capital during the year had a negative impact to cash generated by our operations of $1.3 billion. This use of cash was composed primarily of (i) a decrease in accounts payable, net of a decrease in receivables, of $493 million, (ii) an increase in income taxes receivable and a decrease in income taxes payable totaling $432 million, and (iii) an increase in inventories of $222 million as shown in Note 18 of Notes to Consolidated Financial Statements. The unfavorable effect of accounts payable, net of accounts receivable, was mainly due to a decrease in commodity prices from December 2014 to December 2015. The unfavorable effect in income taxes was due to tax payments associated with the settlement of several IRS audits and an overpayment of taxes in 2015. This overpayment resulted from a change in the U.S. Federal tax laws late in the year that reinstated the bonus depreciation deduction, which lowered our current income tax expense. The unfavorable effect in inventories was mainly due to the build in inventory volumes in 2015 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2015.

The $5.6 billion of cash generated by our operations in 2015, along with (i) $1.45 billion in proceeds from the issuance of debt and (ii) net proceeds of $189 million from VLP’s public offering of 4,250,000 common units as discussed in Note 4 of Notes to Consolidated Financial Statements, were used mainly to:
fund $2.5 billion of investing activities, including $2.4 billion in capital investments. Capital investments are comprised of capital expenditures, deferred turnaround and catalyst costs, and joint venture investments;
make payments on debt and capital lease obligations of $513 million, of which $400 million related to our 4.5 percent senior notes, $75 million related to our 8.75 percent debentures, $25 million related to the VLP Revolver, $10 million related to capital lease obligations, and $3 million related to other non-bank debt;
purchase common stock for treasury of $2.8 billion;
pay common stock dividends of $848 million; and
increase available cash on hand by $425 million.

Cash Flows for the Year Ended December 31, 2014
Our operations generated $4.2 billion of cash in 2014, driven primarily by net income of $3.7 billion and excluding $1.7 billion of noncash charges to income (primarily depreciation and amortization expense). See “RESULTS OF OPERATIONS” for further discussion of our operations. However, the change in our working capital during the year had a negative impact to cash generated by our operations of $1.8 billion. This use of cash was composed primarily of a decrease in accounts receivable of $2.8 billion, which was offset by a decrease in accounts payable of $3.1 billion, a decrease in income taxes payable of $319 million, and an increase in inventories of $1.0 billion as shown in Note 18 of Notes to Consolidated Financial Statements. The favorable effect in accounts receivable and the unfavorable effect in accounts payable were mainly due to a decrease in commodity prices from December 2013 to December 2014. The unfavorable effect associated with income taxes payable resulted from income tax payments exceeding income tax liabilities incurred in 2014 due to the payment of liabilities associated with prior period earnings. The unfavorable effect in inventories was mainly due to the build in inventory volumes from 2013 to 2014 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2014.




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The $4.2 billion of cash provided by our operations in 2014, along with $603 million from available cash on hand, was used mainly to:
fund $2.8 billion of capital investments, which included capital expenditures and deferred turnaround and catalyst costs;
make debt and capital lease obligations repayments of $204 million, of which $200 million related to our 4.75 percent senior notes, and $4 million related to capital lease obligations;
purchase common stock for treasury of $1.3 billion; and
pay common stock dividends of $554 million.

Capital Investments
We define capital investments as capital expenditures for additions to and improvements of our refining and ethanol segment assets (including turnaround and catalyst costs) and investments in joint ventures.

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

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

We hold investments in joint ventures and we invest in these joint ventures or enter into new joint venture arrangements to enhance our operations. In December 2015, we exercised our option to purchase a 50 percent interest in Diamond Pipeline LLC (Diamond Pipeline), which was formed by Plains Pipeline, L.P. (Plains) to construct and operate a 440-mile, 20-inch crude oil pipeline expected to provide capacity of up to 200,000 BPD of domestic sweet crude oil from the Plains Cushing, Oklahoma terminal to our Memphis Refinery, with the ability to connect into the Capline Pipeline. The pipeline is expected to be completed in 2017 for an estimated $925 million, pending receipt of necessary regulatory approvals. We contributed $136 million upon exercise of our option and expect to invest an additional $170 million in 2016.

For 2016, we expect to incur approximately $2.6 billion for capital investments, including capital expenditures, deferred turnaround and catalyst costs, and joint venture investments. This consists of approximately $1.6 billion for stay-in-business capital and $1.0 billion for growth strategies, including our continued investment in Diamond Pipeline. This capital investment estimate excludes potential strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.




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Contractual Obligations
Our contractual obligations as of December 31, 2015 are summarized below (in millions).
 
Payments Due by Period
 
 
 
2016
 
2017
 
2018
 
2019
 
2020
 
Thereafter
 
Total
Debt and capital
lease obligations (a)
$
134

 
$
966

 
$
16

 
$
766

 
$
1,039

 
$
4,517

 
$
7,438

Operating lease obligations
430

 
283

 
200

 
143

 
100

 
311

 
1,467

Purchase obligations
14,975

 
3,204

 
2,458

 
1,197

 
985

 
4,535

 
27,354

Other long-term liabilities

 
172

 
134

 
131

 
125

 
1,049

 
1,611

Total
$
15,539

 
$
4,625

 
$
2,808

 
$
2,237

 
$
2,249

 
$
10,412

 
$
37,870

______________________________
(a)
Debt obligations exclude amounts related to unamortized discount and fair value adjustments. Capital lease obligations include related interest expense. These items are further described in Note 10 of Notes to Consolidated Financial Statements.

Debt and Capital Lease Obligations
We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis. In July 2015, we amended our agreement to decrease the facility from $1.5 billion to $1.4 billion and extended the maturity date to July 2016. As of December 31, 2015, the actual availability under the facility fell below the facility borrowing capacity to $1.1 billion primarily due to a decrease in eligible trade receivables as a result of the ongoing decline in the market prices of the finished products that we produce. As of December 31, 2015, the amount of eligible receivables sold was $100 million. All amounts outstanding under this facility are reflected as debt.

Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of our ratings on our senior unsecured debt are at or above investment grade level as follows:
Rating Agency
 
Rating
Moody’s Investors Service
 
Baa2 (stable outlook)
Standard & Poor’s Ratings Services
 
BBB (stable outlook)
Fitch Ratings
 
BBB (stable outlook)

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

Operating Lease Obligations
Our operating lease obligations include leases for land, office facilities and equipment, transportation equipment, time charters for ocean-going tankers and coastal vessels, dock facilities, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks, refined products, and corn inventories. Operating lease obligations include all operating leases that have initial or



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remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be received by us under subleases.

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

Other Long-term Liabilities
Our other long-term liabilities are described in Note 9 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we made our best estimate of expected payments for each type of liability based on information available as of December 31, 2015.

Summary of Credit Facilities
As of December 31, 2015, we had outstanding borrowings and letters of credit issued under our credit facilities as follows (in millions):
 
 
 
 
 
 
December 31, 2015
 
 
Facility
Amount
 
Maturity Date
 
Borrowings
 
Letters of
Credit
 
Available
 
 
 
 
 
 
Committed facilities:
 
 
 
 
 
 
 
 
 
 
Revolver
 
$
3,000

 
November 2020
 
$

 
$
57

 
$
2,943

VLP Revolver
 
$
750

 
November 2020
 
$
175

 
$

 
$
575

Canadian Revolver
 
C$
50

 
November 2016
 
C$

 
C$
10

 
C$
40

Accounts receivable sales facility
 
$
1,400

 
July 2016
 
$
100

 
$

 
$
992

Letter of credit facilities
 
$
275

 
June 2016 and
November 2016
 
$

 
$
9

 
$
266

 
 
 
 
 
 
 
 
 
 
 
Uncommitted facilities:
 
 
 
 
 
 
 
 
 
 
Letter of credit facilities
 
$
775

 
N/A
 
$

 
$
87

 
$
688


Letters of credit issued as of December 31, 2015 expire in 2016 through 2018.

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




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Other Matters Impacting Liquidity and Capital Resources
Stock Purchase Programs
On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock with no expiration date to such authorization. This authorization was in addition to the remaining amount available under a $3 billion program previously authorized. During the third quarter of 2015, we completed our purchases under the $3 billion program. As of December 31, 2015, we had approximately $1.3 billion remaining available under the $2.5 billion program, but we have no obligation to make purchases under this program.

Pension Plan Funding
We plan to contribute approximately $36 million to our pension plans and $20 million to our other postretirement benefit plans during 2016.

Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, GHG emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future as previously discussed above in “OUTLOOK.” In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Notes 9 and 11 of Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters
The IRS has ongoing tax audits related to our U.S. federal tax returns from 2008 through 2011, and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2008 and 2009. We are contesting certain tax positions and assertions included in the RARs and continue to make progress in resolving certain of these matters with the IRS. During 2015, we settled the audits related to our 2004 through 2007 tax years consistent with the recorded amounts of uncertain tax position liabilities associated with those audits. In addition, we expect to settle our audit for tax years 2008 and 2009 within the next 12 months and we believe it will be settled for amounts consistent with the recorded amounts of uncertain tax position liabilities associated with that audit. As a result, we have classified a portion of our uncertain tax position liabilities as a current liability. Our net uncertain tax position liabilities, including related penalties and interest, was $391 million as of December 31, 2015. Should we ultimately settle for amounts consistent with our estimates, we believe that we will have sufficient cash on hand at that time to make such payments.

Cash Held by Our International Subsidiaries
We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations, as further discussed in Note 15 of Notes to Consolidated Financial Statements. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of December 31, 2015, $1.7 billion of our cash and temporary cash investments was held by our international subsidiaries.




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Emissions Allowances and Cap-and-Trade
The cost to implement certain provisions of the AB 32 cap-and-trade system and low carbon fuel standard in California and the Quebec cap-and-trade system are significant; however, we are recovering the majority of these costs from our customers. If we are unable to recover these costs from our customers in the future, we believe that we will have sufficient cash on hand to cover these costs.

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

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

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements will become effective for our financial statements in the future. The adoption of these pronouncements is not expected to have a material effect on our financial statements, except as otherwise disclosed.

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

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

Lower of Cost or Market Inventory Valuation
Inventories are carried at the lower of cost or market. Cost is principally determined under the LIFO method using the dollar-value LIFO approach. Market value is determined based on the net realizable value of the inventories.

We compare the market value of inventories to their cost on an aggregate basis, excluding materials and supplies. In determining the market value of our inventories, we assume our refinery and ethanol feedstocks



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are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined products. We also estimate the usual and customary transportation costs required to move the inventory from our refineries and ethanol plants to the appropriate points of sale. We then apply an estimated selling price to our inventories. If the aggregate market value is less than cost, we record a lower of cost or market inventory valuation adjustment to reflect our inventories at market value.

The lower of cost or market inventory valuation adjustment for the year ended December 31, 2015 is discussed in Note 6 of Notes to Consolidated Financial Statements.

Property, Plant, and Equipment
Depreciation of property assets used in our refining segment is recorded on a straight-line basis over the estimated useful lives of these assets primarily using the composite method of depreciation. We maintain a separate composite group of property assets for each of our refineries. We estimate the useful life of each group based on an evaluation of the property assets comprising the group, and such evaluations consist of, but are not limited to, the physical inspection of the assets to determine their condition, consideration of the manner in which the assets are maintained, assessment of the need to replace assets, and evaluation of the manner in which improvements impact the useful life of the group. The estimated useful lives of our composite groups range primarily from 25 to 30 years.

Under the composite method of depreciation, the cost of an improvement is added to the composite group to which it relates and is depreciated over that group’s estimated useful life. We design improvements to our refineries in accordance with engineering specifications, design standards, and practices accepted in our industry, and these improvements have design lives consistent with our estimated useful lives. Therefore, we believe the use of the group life to depreciate the cost of improvements made to the group is reasonable because the estimated useful life of each improvement is consistent with that of the group. It should be noted, however, that factors such as competition, regulation, or environmental matters could cause us to change our estimates, thus impacting depreciation expense in the future.

Impairment of Assets
Long-lived assets and equity method investments are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss should be recognized if the carrying amount of the asset exceeds its fair value.

In order to test for recoverability, we must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Our impairment evaluations are based on assumptions that we deem to be reasonable.

Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating primarily to the discharge of materials into the environment, waste management, and pollution prevention measures. Future legislative action and regulatory initiatives, as discussed in Note 11 of Notes to Consolidated Financial Statements could result in changes to required operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.




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

The amount of our accruals for environmental matters as of December 31, 2015 and 2014 are included in Note 9 of Notes to Consolidated Financial Statements.

Pension and Other Postretirement Benefit Obligations
We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. These assumptions are disclosed and described in Note 13 of Notes to Consolidated Financial Statements. Changes in these assumptions are primarily influenced by factors outside of our control. For example, the discount rate assumption represents a yield curve comprised of various long-term bonds that have an average rating of double-A when averaging all available ratings by the recognized rating agencies, while the expected return on plan assets is based on a compounded return calculated assuming an asset allocation that is representative of the asset mix in our pension plans. To determine the expected return on plan assets, we utilized a forward-looking model of asset returns. The historical geometric average return over the 10 years prior to December 31, 2015 was 5.69 percent. The actual return on assets for the years ended December 31, 2015, 2014, and 2013 was 1.46 percent, 7.33 percent, and 19.38 percent, respectively. These assumptions can have a significant effect on the amounts reported in our financial statements. For example, a 0.25 percent decrease in the assumptions related to the discount rate or expected return on plan assets or a 0.25 percent increase in the assumptions related to the health care cost trend rate or rate of compensation increase would have the following effects on the projected benefit obligation as of December 31, 2015 and net periodic benefit cost for the year ending December 31, 2016 (in millions):

 

Pension
Benefits
 
Other
Postretirement
Benefits
Increase in projected benefit obligation resulting from:
 
 
 
Discount rate decrease
$
101

 
$
11

Compensation rate increase
10

 
n/a

Health care cost trend rate increase
n/a

 
1

 
 
 
 
Increase in expense resulting from:
 
 
 
Discount rate decrease
9

 

Expected return on plan assets decrease
5

 
n/a

Compensation rate increase
3

 
n/a

Health care cost trend rate increase
n/a

 





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Beginning in 2016, our net periodic benefit cost will be determined using the spot-rate approach. Under this approach, our net periodic benefit cost will be impacted by the spot rates of the corporate bond yield curve used to calculate our liability discount rate. If the yield curve were to flatten entirely and our liability discount rate remained unchanged, our net periodic benefit cost would increase by $19 million for pension benefits and $3 million for other postretirement benefits in 2016.

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

Tax Matters
We record tax liabilities based on our assessment of existing tax laws and regulations. A contingent loss related to an indirect tax (excise/duty, sales/use, gross receipts, and/or value-added tax) claim is recorded if the loss is both probable and estimable. The recording of our tax liabilities requires significant judgments and estimates. Actual tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due. In addition, in determining our income tax provision, we must assess the likelihood that our deferred tax assets, primarily consisting of net operating loss and tax credit carryforwards, will be recovered through future taxable income. Judgment is required in estimating the amount of a valuation allowance, if any, that should be recorded against those deferred income tax assets. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised. See Notes 11 and 15 of Notes to Consolidated Financial Statements for a further discussion of our tax liabilities.

Legal Matters
A variety of claims have been made against us in various lawsuits. We record a liability related to a loss contingency attributable to such legal matters if we determine that it is probable that a loss has been incurred and that the loss is reasonably estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE RISK

We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options to manage the volatility of:
inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a LIFO basis) differ from our previous year-end LIFO inventory levels and
forecasted feedstock and refined product purchases, refined product sales, natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our price risk activities. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.



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Our positions in commodity derivative instruments are monitored and managed on a daily basis by our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):
 
Derivative Instruments Held For
 
Non-Trading
 Purposes
 
Trading
Purposes
December 31, 2015:
 
 
 
Gain (loss) in fair value resulting from:
 
 
 
10% increase in underlying commodity prices
$
(45
)
 
$

10% decrease in underlying commodity prices
45

 
5

 
 
 
 
December 31, 2014:
 
 
 
Gain (loss) in fair value resulting from:
 
 
 
10% increase in underlying commodity prices
(127
)
 
(2
)
10% decrease in underlying commodity prices
126

 
7


See Note 20 of Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of December 31, 2015.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of biofuel credits and GHG emission credits needed to comply with various governmental and regulatory programs. To manage these risks, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. As of December 31, 2015, there was an immaterial amount of gain or loss in the fair value of derivative instruments that would result from a 10 percent increase or decrease in the underlying price of the contracts. See Note 20 of Notes to Consolidated Financial Statements for a discussion about these compliance programs.




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INTEREST RATE RISK

The following table provides information about our debt obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of December 31, 2015 or 2014.

 
December 31, 2015
 
Expected Maturity Dates
 
 
 
 
 
2016
 
2017
 
2018
 
2019
 
2020
 
There-
after
 
Total (a)
 
Fair
Value
Fixed rate
$

 
$
950

 
$

 
$
750

 
$
850

 
$
4,474

 
$
7,024

 
$
7,467

Average interest rate
%
 
6.4
%
 
%
 
9.4
%
 
6.1
%
 
6.3
%
 
6.6
%
 
 
Floating rate
$
117

 
$

 
$

 
$

 
$
175

 
$

 
$
292

 
$
292

Average interest rate
1.7
%
 
%
 
%
 
%
 
1.5
%
 
%
 
1.6
%
 
 

 
December 31, 2014
 
Expected Maturity Dates
 
 
 
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
There-
after
 
Total (a)
 
Fair
Value
Fixed rate
$
475

 
$

 
$
950

 
$

 
$
750

 
$
4,074

 
$
6,249

 
$
7,436

Average interest rate
5.2
%
 
%
 
6.4
%
 
%
 
9.4
%
 
6.9
%
 
7.0
%
 
 
Floating rate
$
126

 
$

 
$

 
$

 
$

 
$

 
$
126

 
$
126

Average interest rate
2.0
%
 
%
 
%
 
%
 
%
 
%
 
2.0
%
 
 

________________________
(a)
Excludes unamortized discount and fair value adjustments recorded when the debt was acquired in connection with a business combination.

FOREIGN CURRENCY RISK

As of December 31, 2015, we had commitments to purchase $292 million of U.S. dollars. Our market risk was minimal on these contracts, as all of them matured on or before January 31, 2016, resulting in a gain of $10 million in the first quarter of 2016.




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Valero. Our management evaluated the effectiveness of Valero’s internal control over financial reporting as of December 31, 2015. In its evaluation, management used the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management believes that as of December 31, 2015, our internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on the effectiveness of our internal control over financial reporting, which begins on page 57 of this report.




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



The Board of Directors and Stockholders
Valero Energy Corporation:

We have audited the accompanying consolidated balance sheets of Valero Energy Corporation and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Valero Energy Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the PCAOB, the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP


San Antonio, Texas
February 25, 2016




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



The Board of Directors and Stockholders
Valero Energy Corporation:

We have audited Valero Energy Corporation (the Company’s) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (the PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Valero Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.




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We also have audited, in accordance with the standards of the PCAOB, the consolidated balance sheets of Valero Energy Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 25, 2016 expressed an unqualified opinion on those consolidated financial statements.


/s/ KPMG LLP


San Antonio, Texas
February 25, 2016




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VALERO ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
 
December 31,
 
2015
 
2014
ASSETS
 
 
 
Current assets:
 
 
 
Cash and temporary cash investments
$
4,114

 
$
3,689

Receivables, net
4,464

 
5,879

Inventories
5,898

 
6,623

Income taxes receivable
218

 
97

Deferred income taxes
74

 
162

Prepaid expenses and other
204

 
164

Total current assets
14,972

 
16,614

Property, plant, and equipment, at cost
36,907

 
35,933

Accumulated depreciation
(10,204
)
 
(9,198
)
Property, plant, and equipment, net
26,703

 
26,735

Deferred charges and other assets, net
2,668

 
2,201

Total assets
$
44,343

 
$
45,550

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Current portion of debt and capital lease obligations
$
127

 
$
606

Accounts payable
4,907

 
6,760

Accrued expenses
554

 
596

Taxes other than income taxes
1,069