e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|
|
|
þ |
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For
the fiscal year ended December 31, 2008
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
(State or other jurisdiction of
incorporation or organization)
|
|
74-1828067
(I.R.S. Employer
Identification No.) |
|
|
|
One Valero Way
San Antonio, Texas
(Address of principal executive
offices)
|
|
78249
(Zip Code) |
Registrants 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants 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. o
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. (Check one):
|
|
|
|
|
|
|
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
Act). Yes o No þ
The aggregate market value of the voting and non-voting common stock held by non-affiliates was
approximately $21.6 billion based on the last sales price quoted as of June 30, 2008 on the New
York Stock Exchange, the last business day of the registrants most recently completed second
fiscal quarter.
As of January 31, 2009, 516,308,274 shares of the registrants common stock were issued and
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 April 30, 2009, at which directors will be elected.
Portions of the 2009 Proxy Statement are incorporated by reference in Part III of this Form 10-K
and are deemed to be a part of this report.
CROSS-REFERENCE SHEET
The following table indicates the headings in the 2009 Proxy Statement where certain information
required in Part III of Form 10-K may be found.
|
|
|
Form
10-K Item No. and Caption |
|
Heading
in 2009 Proxy Statement |
|
|
|
10. Directors, Executive Officers and
Corporate
Governance
|
|
Information Regarding the
Board of Directors,
Independent Directors, Audit
Committee, Governance
Documents and Codes of Ethics,
Proposal No. 1 Election of
Directors, Information
Concerning Nominees and Other
Directors, and Section 16(a)
Beneficial Ownership Reporting
Compliance |
|
|
|
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 Fees for Fiscal Year
2008, KPMG Fees for Fiscal
Year 2007, 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 Jay D. Browning, Senior Vice President-Corporate Law and Secretary, Valero Energy Corporation,
P.O. Box 696000, San Antonio, Texas 78269-6000.
ii
CONTENTS
|
|
|
|
|
|
|
|
|
|
|
PAGE |
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
16 |
|
|
|
|
|
|
16 |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
18 |
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
23 |
|
|
|
|
|
|
24 |
|
|
|
|
|
|
51 |
|
|
|
|
|
|
57 |
|
|
|
|
|
|
132 |
|
|
|
|
|
|
132 |
|
|
|
|
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133 |
|
Item 11. |
|
Executive Compensation |
|
|
133 |
|
Item 12. |
|
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters |
|
|
133 |
|
Item 13. |
|
Certain Relationships and Related Transactions, and Director
Independence |
|
|
133 |
|
Item 14. |
|
Principal Accountant Fees and Services |
|
|
133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
138 |
|
|
|
|
|
|
|
|
iii
PART I
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 below under the
heading: CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995.
ITEMS 1., 1A. and 2. BUSINESS, RISK FACTORS 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 under the symbol VLO. We were incorporated in
Delaware in 1981 under the name Valero Refining and Marketing Company, and our name was changed to
Valero Energy Corporation on August 1, 1997. On January 31, 2009, we had 21,765 employees.
We own and operate 16 refineries located in the United States, Canada, and Aruba that produce
conventional gasolines, distillates, jet fuel, asphalt, petrochemicals, lubricants, and other
refined products as well as a slate of premium products including CBOB and RBOB1,
gasoline meeting the specifications of the California Air Resources Board (CARB), CARB diesel fuel,
low-sulfur and ultra-low-sulfur diesel fuel, and oxygenates (liquid hydrocarbon compounds
containing oxygen).
We market branded and unbranded refined products on a wholesale basis in the United States and
Canada through an extensive bulk and rack marketing network. We also sell refined products through
a network of about 5,800 retail and wholesale branded outlets in the United States, Canada, and
Aruba.
Available
Information. Our internet website address is www.valero.com. Information contained 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
Securities and Exchange Commission (SEC) are available on our internet website (in the Investor
Relations section), free of charge, soon after we file or furnish such material. We also post our
corporate governance guidelines, code of business conduct and ethics, code of ethics for senior
financial officers, and the charters of the committees of our board of directors in the same
website location. Our governance documents are available in print to any stockholder that makes a
written request to Jay D. Browning, Senior Vice President-Corporate Law and Secretary, Valero
Energy Corporation, P.O. Box 696000, San Antonio, Texas 78269-6000.
|
|
|
1 |
|
CBOB, or conventional blendstock for oxygenate
blending, is conventional gasoline blendstock intended for blending with
oxygenates downstream of the refinery where it was produced. CBOB becomes
conventional gasoline after blending with oxygenates. RBOB is a base
unfinished reformulated gasoline mixture known as reformulated gasoline
blendstock for oxygenate blending. It is a specially produced reformulated
gasoline blendstock intended for blending with oxygenates downstream of the
refinery where it was produced to produce finished gasoline that meets or
exceeds U.S. emissions performance requirements for federal reformulated
gasoline. |
1
SEGMENTS
Our business is organized into two reportable segments: refining and retail. Our refining segment
includes refining operations, wholesale marketing, product supply and distribution, and
transportation operations. The refining segment is segregated geographically into the Gulf Coast,
Mid-Continent, West Coast, and Northeast regions.
Our retail segment includes company-operated convenience stores, Canadian dealers/jobbers,
truckstop facilities, cardlock facilities, and home heating oil operations. The retail segment is
segregated into two geographic regions. Our retail operations in eastern Canada are referred to as
Retail Canada. Our retail operations in the United States are referred to as Retail U.S. The
financial information about our segments in Note 20 of Notes to
Consolidated Financial Statements is incorporated herein by reference.
2
VALEROS OPERATIONS
REFINING
On December 31, 2008, our refining operations included 16 refineries in the United States, Canada,
and Aruba 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, 2008.
|
|
|
|
|
|
|
|
|
|
|
Throughput Capacity(a) |
Refinery |
|
Location |
|
(barrels
per day) |
|
Gulf Coast: |
|
|
|
|
|
|
Corpus Christi (b) |
|
Texas |
|
|
315,000 |
|
Port Arthur |
|
Texas |
|
|
310,000 |
|
St. Charles |
|
Louisiana |
|
|
250,000 |
|
Texas City |
|
Texas |
|
|
245,000 |
|
Aruba |
|
Aruba |
|
|
235,000 |
|
Houston |
|
Texas |
|
|
145,000 |
|
Three Rivers |
|
Texas |
|
|
100,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,600,000 |
|
|
|
|
|
|
|
|
West Coast: |
|
|
|
|
|
|
Benicia |
|
California |
|
|
170,000 |
|
Wilmington |
|
California |
|
|
135,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
305,000 |
|
|
|
|
|
|
|
|
Mid-Continent: |
|
|
|
|
|
|
Memphis |
|
Tennessee |
|
|
195,000 |
|
McKee |
|
Texas |
|
|
170,000 |
|
Ardmore |
|
Oklahoma |
|
|
90,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
455,000 |
|
|
|
|
|
|
|
|
Northeast: |
|
|
|
|
|
|
Quebec City |
|
Quebec, Canada |
|
|
235,000 |
|
Delaware City |
|
Delaware |
|
|
210,000 |
|
Paulsboro |
|
New Jersey |
|
|
185,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
630,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
2,990,000 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Throughput capacity represents estimated capacity for
processing crude oil, intermediates, and other feedstocks. Total
estimated crude oil capacity is approximately 2.6 million BPD. |
|
(b) |
|
Represents the combined capacities of two refineries the
Corpus Christi East and Corpus Christi West Refineries. |
3
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, 2008. Our total combined throughput
volumes averaged 2,643,000 BPD for the 12 months ended December 31, 2008. (The information
presented below includes the charges and yields of the Krotz Springs, Louisiana refinery, which we
sold effective July 1, 2008. The sale is more fully described in Note 2 of Notes to Consolidated
Financial Statements.)
Combined Refining Charges and Yields
|
|
|
|
|
|
|
|
|
|
|
Percentage |
|
Charges: |
|
|
|
|
|
|
|
|
sour crude oil |
|
|
48 |
% |
|
|
acidic sweet crude oil |
|
|
3 |
% |
|
|
sweet crude oil |
|
|
23 |
% |
|
|
residual fuel oil |
|
|
9 |
% |
|
|
other feedstocks |
|
|
5 |
% |
|
|
blendstocks |
|
|
12 |
% |
Yields: |
|
|
|
|
|
|
|
|
gasolines and blendstocks |
|
|
45 |
% |
|
|
distillates |
|
|
35 |
% |
|
|
petrochemicals |
|
|
3 |
% |
|
|
other products (includes vacuum gas oil,
No. 6 fuel oil, petroleum coke, asphalt,
and other) |
17 |
% |
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, 2008. Total throughput
volumes for the Gulf Coast refining region averaged 1,404,000 BPD for the 12 months ended
December 31, 2008. (The information presented below includes the charges and yields of the Krotz
Springs, Louisiana refinery, which we sold effective July 1, 2008.)
Combined Gulf Coast Region Charges and Yields
|
|
|
|
|
|
|
|
|
|
|
Percentage |
|
Charges: |
|
|
|
|
|
|
|
|
sour crude oil |
|
|
57 |
% |
|
|
sweet crude oil |
|
|
9 |
% |
|
|
residual fuel oil |
|
|
13 |
% |
|
|
other feedstocks |
|
|
7 |
% |
|
|
blendstocks |
|
|
14 |
% |
Yields: |
|
|
|
|
|
|
|
|
gasolines and blendstocks |
|
|
41 |
% |
|
|
distillates |
|
|
34 |
% |
|
|
petrochemicals |
|
|
4 |
% |
|
|
other products (includes vacuum gas
oil, No. 6 fuel oil, petroleum coke,
asphalt, and other) |
21 |
% |
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 West Refinery specializes in
processing primarily lower-cost sour crude oil and resid into premium products such as RBOB. The
East Refinery processes heavy, high-sulfur crude oil into conventional gasoline, diesel, jet fuel,
asphalt, aromatics, and other light products. The East and West Refineries are substantially
integrated allowing for the transfer of various feedstocks and blending components between the two
refineries and the sharing
4
of resources. The refineries typically receive and deliver feedstocks and products by tanker and
barge via deepwater docking facilities along the Corpus Christi Ship Channel. Three truck racks
with a total of 16 bays service local markets for gasoline, diesel, jet fuels, liquefied petroleum
gases, and asphalt. The refineries distribute refined products using the Colonial, Explorer,
Valley, and other major pipelines.
Port Arthur Refinery. Our Port Arthur Refinery is located on the Texas Gulf Coast approximately 90
miles east of Houston. The refinery processes primarily heavy sour crude oils and other feedstocks
into conventional and premium gasoline and RBOB, as well as diesel, jet fuel, petrochemicals,
petroleum coke, and sulfur. The refinery receives crude oil over marine docks and through crude
oil pipelines, and has access to the Sunoco and Oiltanking terminals at Nederland, Texas. Finished
products are distributed into the Colonial, Explorer, and TEPPCO pipelines, across the refinery
docks into ships or barges, and through a local truck rack.
St. Charles Refinery. Our St. Charles Refinery is located approximately 15 miles from New Orleans
along the Mississippi River. The refinery processes sour crude oils and other feedstocks into
gasoline, distillates, and other light products. The refinery receives crude oil over five marine
docks and has access to the Louisiana Offshore Oil Port where it can receive crude oil through a
24-inch pipeline. Finished products can be shipped over these docks or through the Colonial
pipeline network for distribution to the eastern United States.
Texas City Refinery. Our Texas City Refinery is located southeast of Houston on the Texas City
Ship Channel. The refinery processes primarily heavy sour crude oils into a wide slate of
products. The refinery receives and delivers its feedstocks and products by tanker and barge via
deepwater docking facilities along the Texas City Ship Channel and uses the Colonial, Explorer, and
TEPPCO pipelines for distribution of its products.
Aruba Refinery. Our Aruba Refinery is located on the island of Aruba in the Caribbean Sea. It
processes primarily heavy sour crude oil and produces primarily intermediate feedstocks and
finished distillate products. Significant amounts of the refinerys intermediate feedstock
production are transported and further processed in our other refineries in the Gulf Coast, West
Coast, and Northeast regions. The refinery receives crude oil by ship at its two deepwater marine
docks, which can berth ultra-large crude carriers. The refinerys products are delivered by ship
primarily into markets in the United States, the Caribbean, Europe, and South America.
Houston
Refinery. Our Houston Refinery is located on the Houston Ship Channel. It processes
primarily sour crude oils and low-sulfur resid into conventional gasoline and distillates. The
refinery receives its feedstocks via tanker at deepwater docking facilities along the Houston Ship
Channel and delivers its products through major refined-product pipelines, including the Colonial,
Explorer, and TEPPCO pipelines.
Three Rivers Refinery. Our Three Rivers Refinery is located in South Texas between Corpus Christi
and San Antonio. It processes primarily heavy sweet and medium sour crude oils into conventional
gasoline, distillates, and aromatics. The refinery has access to crude oil from foreign sources
delivered to the Texas Gulf Coast at Corpus Christi as well as crude oil from domestic sources
through third-party pipelines. A 70-mile pipeline with capacity of 120,000 BPD transports crude
oil via connections to the Three Rivers Refinery from Corpus Christi. The refinery distributes its
refined products primarily through pipelines owned by NuStar Energy L.P.
5
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, 2008. Total throughput
volumes for the West Coast refining region averaged approximately 276,000 BPD for the 12 months
ended December 31, 2008.
Combined West Coast Region Charges and Yields
|
|
|
|
|
|
|
|
|
|
|
Percentage |
|
Charges: |
|
|
|
|
|
|
|
|
sour crude oil |
|
|
68 |
% |
|
|
acidic sweet crude oil |
|
|
4 |
% |
|
|
residual fuel oil |
|
|
1 |
% |
|
|
other feedstocks |
|
|
11 |
% |
|
|
blendstocks |
|
|
16 |
% |
Yields: |
|
|
|
|
|
|
|
|
gasolines and blendstocks |
|
|
60 |
% |
|
|
distillates |
|
|
25 |
% |
|
|
other products (includes vacuum gas
oil, No. 6 fuel oil, petroleum coke,
asphalt, and other) |
|
|
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 premium products, primarily CARBOB
gasoline. (CARBOB is a reformulated gasoline mixture that meets the specifications of the
California Air Resources Board when blended with ethanol.) The refinery receives crude oil
supplies via a deepwater dock that can berth large crude oil carriers and a 20-inch crude oil
pipeline connected to a southern California crude oil delivery system. Most of the refinerys
products are distributed via the Kinder Morgan pipeline in California.
Wilmington Refinery. Our Wilmington Refinery is located near Los Angeles, California. The
refinery processes a blend of lower-cost heavy and high-sulfur crude oils. The refinery can
produce all of its gasoline as CARBOB gasoline and produces both ultra-low-sulfur diesel and CARB
diesel. 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 the
Kinder Morgan pipeline system and various third-party terminals in southern California, Nevada, and
Arizona.
6
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, 2008. Total throughput
volumes for the Mid-Continent refining region averaged 423,000 BPD for the 12 months ended
December 31, 2008.
Combined Mid-Continent Region Charges and Yields
|
|
|
|
|
|
|
|
|
|
|
Percentage |
|
Charges: |
|
|
|
|
|
|
|
|
sour crude oil |
|
|
13 |
% |
|
|
sweet crude oil |
|
|
79 |
% |
|
|
other feedstocks |
|
|
1 |
% |
|
|
blendstocks |
|
|
7 |
% |
Yields: |
|
|
|
|
|
|
|
|
gasolines and blendstocks |
|
|
49 |
% |
|
|
distillates |
|
|
40 |
% |
|
|
petrochemicals |
|
|
3 |
% |
|
|
other products (includes vacuum gas
oil, No. 6 fuel oil, asphalt, and
other) |
|
|
8 |
% |
Memphis Refinery. Our Memphis Refinery is located in Tennessee along the Mississippi Rivers Lake
McKellar. It processes primarily light sweet crude oils. Almost all of its production is light
products, including regular and premium gasoline, diesel, jet fuels, and petrochemicals. Crude oil
is supplied to the refinery via the Capline pipeline and can also be received, along with other
feedstocks, via barge. The refinerys products are distributed via truck racks at our three
product terminals, barges, and a pipeline directly to the Memphis airport.
McKee Refinery. Our McKee Refinery is located in the Texas Panhandle. It processes primarily
sweet crude oils and produces conventional gasoline, RBOB, low-sulfur diesel, jet fuels, and
asphalt. The refinery has access to crude oil from Texas, Oklahoma, Kansas, and Colorado through
third-party pipelines. The refinery also has access at Wichita Falls, Texas to third-party
pipelines that transport crude oil from the Texas Gulf Coast and West Texas to the Mid-Continent
region. The refinery distributes its products primarily via NuStar Energy L.P.s pipelines to
markets in Texas, New Mexico, Arizona, Colorado, and Oklahoma.
Ardmore
Refinery. Our Ardmore Refinery is located in Ardmore, Oklahoma, approximately 90 miles
south of Oklahoma City. It processes medium sour and light sweet crude oils into conventional
gasoline, low-sulfur diesel, liquefied petroleum gas products, and asphalt. Local crude oil is
gathered by TEPPCOs crude oil gathering/trunkline systems and trucking operations, and then
transported to the refinery through NuStar Energy L.P.s crude oil pipeline systems. Foreign,
midland, and other domestic crude oils are received via third-party pipelines. Refined products
are transported via the Magellan pipeline system, railcars, and trucks.
7
Northeast
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, 2008. Total throughput
volumes for the Northeast refining region averaged 540,000 BPD for the 12 months ended December 31,
2008.
Combined Northeast Region Charges and Yields
|
|
|
|
|
|
|
|
|
|
|
Percentage |
|
Charges: |
|
|
|
|
|
|
|
|
sour crude oil |
|
|
40 |
% |
|
|
acidic sweet crude oil |
|
|
11 |
% |
|
|
sweet crude oil |
|
|
29 |
% |
|
|
residual fuel oil |
|
|
7 |
% |
|
|
other feedstocks |
|
|
4 |
% |
|
|
blendstocks |
|
|
9 |
% |
Yields: |
|
|
|
|
|
|
|
|
gasolines and blendstocks |
|
|
43 |
% |
|
|
distillates |
|
|
38 |
% |
|
|
petrochemicals |
|
|
1 |
% |
|
|
other products (includes vacuum gas
oil, No. 6 fuel oil, petroleum coke,
asphalt, and other) |
|
|
18 |
% |
Quebec City Refinery. Our Quebec City Refinery is located in Lévis, Canada (near Quebec City). It
processes sweet crude oils and lower-quality, sweet acidic crude oils into conventional gasoline,
low-sulfur diesel, jet fuels, heating oil, and propane. The refinery receives crude oil by ship at
its deepwater dock on the St. Lawrence River. We charter large ice-strengthened, double-hulled
crude oil tankers that can navigate the St. Lawrence River year-round. The refinery transports its
products to its primary terminals in Quebec and Ontario primarily by train, and also uses ships and
trucks extensively throughout eastern Canada.
Delaware City Refinery. Our Delaware City Refinery is located along the Delaware River near
Wilmington, Delaware. The refinery processes primarily sour crude oils into a wide slate of
products including conventional gasoline, CBOB, RBOB, petroleum coke, sulfur, low-sulfur diesel,
home heating oil, and petrochemicals (benzene). Feedstocks and refined products are transported
via pipeline, barge, and truck-rack facilities. The refinerys production is sold primarily in the
northeastern U.S.
Paulsboro Refinery. Our Paulsboro Refinery is located in Paulsboro, New Jersey, approximately
15 miles south of Philadelphia on the Delaware River. The refinery processes primarily sour crude
oils into a wide slate of products including gasoline, distillates, lube oil basestocks, asphalt,
petroleum coke, sulfur, fuel oil, propane, and butane. Feedstocks and refined products are
typically transported by tanker and barge via refinery-owned dock facilities along the Delaware
River, Buckeye Partners product distribution system (into western Pennsylvania and Ohio), an
onsite truck rack owned by NuStar Energy L.P., railcars, and the Colonial pipeline, which allows
products to be sold into the New York Harbor market.
8
Feedstock Supply
Approximately 65% 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 foreign national oil companies (including feedstocks originating in the
Middle East, Africa, Asia, Mexico, and South America) as well as international and domestic oil
companies. The term 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 Valeros term contracts is purchased at the
producers official stated price (i.e., the market price established by the seller for all
purchasers) and not at a negotiated price specific to Valero. About 80% of our crude oil
feedstocks under term supply agreements are imported from foreign sources and about 20% are
domestic. In the event we become unable to purchase crude oil from any one of these sources, we
believe that adequate alternative supplies of crude oil would be available.
The U.S. network of crude oil pipelines and terminals allows us to acquire crude oil from producing
leases, domestic crude oil trading centers, and ships delivering cargoes of foreign and domestic
crude oil. Our Quebec City and Aruba Refineries rely on foreign crude oil that is delivered to the
refineries dock facilities by ship. We use the futures market to manage a portion of the price
risk inherent in purchasing crude oil in advance of the delivery date and holding inventories of
crude oils and refined products.
Refining Segment Sales
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 deepwater transportation facilities and interconnect with common-carrier
pipeline systems, allowing us to sell products in most major geographic regions of the United
States and eastern Canada. No customer accounted for more than 10% of our total operating revenues
in 2008.
Wholesale Marketing
We market branded and unbranded transportation fuels on a wholesale basis in 44 states through an
extensive rack marketing network. The principal purchasers of our transportation fuels from
terminal truck racks are wholesalers, distributors, retailers, and truck-delivered end users
throughout the United States.
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
3,950 branded sites. These sites are independently owned and are supplied by us under multi-year
contracts. For wholesale branded sites, we promote our Valero® brand throughout the
United States. In addition, we offer the Beacon® brand in California and the
Shamrock® brand elsewhere in the United States.
Bulk Sales and Trading
We sell a significant portion of our gasoline and distillate production through bulk sales channels
in domestic 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.
9
We also enter into refined product exchange and purchase agreements. These agreements help to
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.
Specialty Products
We also 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 six 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 lube oils at two of our refineries. We produce and market paraffinic,
naphthenic, and aromatic oils suitable for use in 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 aromatic
solvents (benzene, toluene, and xylene) and two grades of propylene. Aromatic solvents
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 in the
agricultural sector. Sulfur is used in manufacturing fertilizer. |
10
RETAIL
Our retail segment operations include the following:
|
|
|
sales of transportation fuels at retail stores and unattended self-service
cardlocks, |
|
|
|
|
sales of convenience store merchandise in retail stores, and |
|
|
|
|
sales of home heating oil to residential customers. |
We are one of the largest independent retailers of refined products in the central and southwest
United States and eastern Canada. Our retail operations are segregated geographically into two
groups: Retail U.S. and Retail Canada.
Retail U.S.
Sales in Retail U.S. represent sales of transportation fuels and convenience store merchandise
through our company-operated retail sites. For the year ended December 31, 2008, total sales of
refined products through Retail U.S.s retail sites averaged approximately 115,900 BPD. In
addition to transportation fuels, our company-operated convenience stores sell snacks, candy, beer,
fast foods, cigarettes, and fountain drinks. On December 31, 2008, we had 1,010 company-operated
sites in Retail U.S. (of which 79% were owned and 21% were leased). Our company-operated stores
are operated primarily under the brand name Corner Store®. Transportation fuels sold in
our Retail U.S. stores are sold primarily under the Valero® brand.
Retail Canada
Sales in Retail Canada include the following:
|
|
|
sales of refined products and convenience store merchandise through our
company-operated retail sites and cardlocks, |
|
|
|
|
sales of refined products through sites owned by independent dealers and jobbers,
and |
|
|
|
|
sales of home heating oil to residential customers. |
Retail Canada includes retail operations in eastern Canada where we are a major supplier of
refined products serving Quebec, Ontario, and the Atlantic Provinces of Newfoundland, Nova Scotia,
New Brunswick, and Prince Edward Island. For the year ended December 31, 2008, total retail sales
of refined products through Retail Canada averaged approximately 76,000 BPD. Transportation
fuels are sold under the Ultramar® brand through a network of 865 outlets throughout
eastern Canada. On December 31, 2008, we owned or leased 412 retail stores in Retail Canada and
distributed gasoline to 453 dealers and independent jobbers. In addition, Retail Canada operates
85 cardlocks, which are card- or key-activated, self-service, unattended stations that allow
commercial, trucking, and governmental fleets to buy transportation fuel 24 hours a day. Retail
Canada operations also include a large home heating oil business that provides home heating oil to
approximately 141,000 households in eastern Canada. Our home heating oil business tends to be
seasonal to the extent of increased demand for home heating oil during the winter.
11
RISK FACTORS
Our financial results are affected by volatile refining margins and global economic activity.
Our financial results are primarily affected by the relationship, or margin, between refined
product prices and the prices for crude oil and other feedstocks. 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 domestic and foreign 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. Historically, refining margins have been volatile, and we believe they
will continue to be volatile in the future.
Continued economic turmoil and hostilities, including the threat of future terrorist attacks, could
affect the economies of the United States and other countries. Lower levels of economic activity
during periods of recession 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 far exceeding refined product
demand, which would have a significant 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 West
Texas Intermediate crude oil. 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
earnings.
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 over which we exert no control. Recent disruptions in the credit and capital markets and
concerns about economic growth have had a significant adverse impact on global financial markets.
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.
We currently maintain investment-grade ratings by Standard & Poors Ratings Services (S&P), Moodys
Investors Service (Moodys), 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 S&P, Moodys,
12
or Fitch 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 in our credit
ratings could have a material adverse impact on our future operations and financial position.
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 generation 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. Uncertainty and illiquidity continues to exist in the
financial markets that may materially impact the ability of the participating financial
institutions to fund their commitments to us under our various financing facilities. In light of
these uncertainties and the volatile current market environment, we can make no assurances that we
will be able to obtain the full amount of the funds available under our financing facilities to
satisfy our cash requirements. Our failure to do so could have a material adverse effect on our
operations and financial position.
Compliance with and changes in environmental laws 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
federal, state, and local environmental laws and regulations, including those relating to the
discharge of materials into the environment, waste management, pollution prevention measures,
greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels. 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 greenhouse gas emissions and climate change (e.g., Californias AB-32 Global Warming
Solutions Act), the level of expenditures required for environmental matters could increase in the
future. Future legislative action and regulatory initiatives could result in changes to operating
permits, additional remedial actions, material changes in operations, or increased capital
expenditures and operating costs that cannot be assessed with certainty at this time. In addition,
any major upgrades in any of our refineries could require material additional expenditures to
comply with environmental laws and regulations.
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, those 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.
In addition, the U.S. government can prevent or restrict us from doing business in or with foreign
countries. These restrictions, and those of foreign governments, could limit our ability to gain
access to business opportunities in various countries. Actions by both the United States and
foreign countries have affected our operations in the past and will continue to do so in the
future.
13
Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or
have greater financial resources 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 outlets for our refined products. We do not produce any of our crude oil
feedstocks. Many of our competitors, however, obtain a significant portion of their feedstocks
from company-owned production and some have more extensive retail outlets than we have.
Competitors that have their own production or extensive retail outlets (and greater brand-name
recognition) 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.
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, encounter work stoppages relating to organized labor issues, 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. A significant interruption in one or more
of our refineries 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.
We maintain insurance against many, but not 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 future cash flows, operating results, and financial condition.
Our refining and marketing 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, such
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 have increased substantially, and could escalate
further. 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.
Our insurance program includes a number of insurance carriers. Disruptions in the U.S. financial
markets have resulted in the deterioration in the financial condition of many financial
institutions, including insurance companies. We are not currently aware of any information that
would indicate that any of our insurers is unlikely to perform in the event of a covered incident.
However, in light of this uncertainty and the volatile current market environment, we can make no
assurances that we will be able to obtain the full amount of our insurance coverage for insured
events.
14
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including United States, state, and foreign income
taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, and ad
valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are
continuously being enacted or proposed that could result in increased expenditures for tax
liabilities in the future. Many of these liabilities are subject to periodic audits by the
respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits
may subject us to interest and penalties.
15
ENVIRONMENTAL MATTERS
We incorporate by reference into this Item the environmental disclosures contained in the following
sections of this report:
|
|
|
Item 1 under the caption Risk Factors Compliance with and changes in environmental
laws could adversely affect our performance, |
|
|
|
|
Item 3 Legal Proceedings under the caption Environmental Enforcement Matters, and |
|
|
|
|
Item 8 Financial
Statements and Supplementary Data in Note 24 of Notes to
Consolidated Financial Statements under the caption Environmental Matters. |
Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2008, our
capital expenditures attributable to compliance with environmental regulations were approximately
$480 million, and are currently estimated to be approximately $635 million for 2009 and
approximately $830 million for 2010. The estimates for 2009 and 2010 do not include amounts
related to capital investments at our facilities that management has deemed to be strategic
investments rather than expenditures relating to environmental regulatory compliance.
PROPERTIES
Our principal properties are described above under the caption Valeros Operations, and that
information is incorporated herein by reference. We also own feedstock and refined product storage
facilities in various locations. 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, 2008, we were the lessee under a number of cancelable and non-cancelable leases for
certain properties. Our leases are discussed more fully in Note 23
of Notes to Consolidated Financial Statements.
Our patents relating to our refining operations are not material to us as a whole. The trademarks
and tradenames under which we conduct our retail and branded wholesale business including
Valero®, Diamond Shamrock®, Shamrock®, Ultramar®,
Beacon®, Corner Store®, and Stop N Go® and other trademarks
employed in the marketing of petroleum products are integral to our wholesale and retail marketing
operations.
16
EXECUTIVE OFFICERS OF THE REGISTRANT
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Age* |
|
Positions Held with Valero |
|
Officer Since |
|
William R. Klesse
|
|
|
62 |
|
|
Chief Executive Officer, President, and
Chairman of the Board
|
|
|
2001 |
|
Kimberly S. Bowers
|
|
|
44 |
|
|
Executive Vice President and General
Counsel
|
|
|
2003 |
|
Michael S. Ciskowski
|
|
|
51 |
|
|
Executive Vice President and Chief Financial
Officer
|
|
|
1998 |
|
S. Eugene Edwards
|
|
|
52 |
|
|
Executive Vice President-Corporate Development
and Strategic Planning
|
|
|
1998 |
|
Joseph W. Gorder
|
|
|
51 |
|
|
Executive Vice President-Marketing
and Supply
|
|
|
2003 |
|
Richard J. Marcogliese
|
|
|
56 |
|
|
Executive Vice President and Chief
Operating Officer
|
|
|
2001 |
|
Mr. Klesse was elected as Valeros Chairman of the Board in January 2007, and
as Chief Executive Officer on December 31, 2005. He added the title of
President in January 2008. He was Valeros Vice-Chairman of the Board from
October 31, 2005 to January 18, 2007. He previously served as Executive Vice
President and Chief Operating Officer since January 2003. He served as an
Executive Vice President of Valero since the date of our acquisition of
Ultramar Diamond Shamrock Corporation (UDS) on December 31, 2001.
Ms. Bowers was elected Executive Vice President and General Counsel in October
2008. She previously served as Senior Vice President and General Counsel of
the Company since April 2006. Before that, she was Valeros Vice
President-Legal Services from 2003 to 2006. Ms. Bowers joined Valeros legal
department in 1997.
Mr. Ciskowski was elected Executive Vice President and Chief Financial Officer
in August 2003. Before that, he served as Executive Vice President-Corporate
Development since April 2003, and Senior Vice President in charge of business
and corporate development since 2001.
Mr. Edwards was elected Executive Vice President-Corporate Development and
Strategic Planning in December 2005. He previously served as Senior Vice
President since December 2001 with responsibilities for product supply,
trading, and wholesale marketing. He has held several positions in the company
with responsibility for planning and economics, business development, risk
management, and marketing.
Mr. Gorder was elected Executive Vice President-Marketing and Supply in
December 2005. He previously served as Senior Vice President-Corporate
Development since August 2003. Prior to that he held several positions with
Valero and UDS with responsibilities for corporate development and marketing.
Mr. Marcogliese was elected Executive Vice President and Chief Operating
Officer in October 2007. He previously held the title Executive Vice
President-Operations since December 2005. Prior to that he served as Senior
Vice President overseeing refining operations since July 2001.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
17
ITEM 3. LEGAL PROCEEDINGS
Litigation
For the legal proceedings listed below, we incorporate by reference into this Item our disclosures
made in Part II, Item 8 of this report included in Note 25 of Notes
to Consolidated Financial Statements under the caption Litigation Matters.
|
|
|
MTBE Litigation |
|
|
|
Retail Fuel Temperature Litigation |
|
|
|
Rosolowski |
|
|
|
Other Litigation |
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 consolidated financial position or results of operations. 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.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). From 2006 to 2008, the
BAAQMD issued 86 violation notices (VNs) for various alleged air regulation and air permit
violations at our Benicia Refinery and asphalt plant. No penalties have been specified in these
VNs. We are pursuing settlement of all VNs.
Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City
Refinery). Our Delaware City Refinery is subject to 12 outstanding notices of violation (NOVs)
issued by the DDNREC. Ten of the NOVs allege unauthorized air emission events at the refinery.
Two NOVs allege solid waste violations. No penalties have been specified in these NOVs. We are
pursuing settlement of these NOVs.
Los Angeles Regional Water Quality Control Board (LARWQCB) (Wilmington Marine Terminal). In
December 2007, as part of the National Pollutant Discharge Elimination System Permit renewal
process for our Wilmington marine terminal, the LARWQCB issued an NOV and Request for Information.
The NOV alleges violations of acute toxicity effluent limits between 2000 and 2006 and reporting
violations between 2001 and 2005. We are currently pursuing settlement of this NOV.
New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). In 2008, the NJDEP
issued three air-related Administrative Order and Notice of Civil Administrative Penalty
Assessments (Notices) to our Paulsboro Refinery that we reasonably believe may result in monetary
sanctions of $100,000 or more. The Notices allege the refinerys failure to comply with a number
of air permit and regulatory requirements. The Notices propose penalties of approximately $780,000
in the aggregate. We are pursuing settlement of these Notices with the NJDEP.
Oklahoma Department of Environmental Quality (ODEQ) (Ardmore Refinery). We have received a penalty
demand of $385,839 from the ODEQ for alleged excess air emission violations at our Ardmore Refinery
occurring from 2006 to 2008. We are in settlement discussions with the ODEQ to resolve this
matter.
18
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 Environmental Protection Agency has issued several NOVs alleging
violations of air and waste regulations at Premcors Hartford, Illinois terminal and now-closed
refinery. We are negotiating the terms of a consent order for corrective action.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In November 2008, the
SCAQMD issued an NOV for alleged air regulation and air permit violations related to a September
2008 flaring event at our Wilmington Refinery. We are pursuing settlement of the NOV.
State of Ohio, Office of the Attorney General, Environmental Enforcement (The Premcor Refining
Group Inc. former Clark Retail Enterprises, Inc. retail sites). In June 2008, the Attorney
Generals office of the State of Ohio issued a penalty demand of $11,133,000 to our wholly owned
subsidiary, The Premcor Refining Group Inc., for alleged environmental violations arising from a
predecessors operation or ownership of underground storage tanks at several sites. We are in
settlement discussions with the Ohio Attorney General to resolve this matter.
Texas Commission on Environmental Quality (TCEQ) (McKee Refinery). In March 2008, we received a
proposed Agreed Order from the TCEQ for $101,386 to resolve nine alleged violations of air
regulations at our McKee Refinery. We are currently in settlement discussions with the TCEQ to
resolve this matter.
TCEQ (Port Arthur Refinery). In September 2005, we received two enforcement actions from the TCEQ
relating to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002.
The TCEQ had originally proposed penalties of $880,240 for these events. In 2007, these
enforcement actions were referred to the Texas Attorney Generals office and consolidated with TCEQ
Docket No. 2005-1596-AIR-E, which assessed an additional penalty of $130,563. We recently reached
a tentative agreement with the Texas Attorney Generals office to resolve this matter.
TCEQ (Texas City Refinery). In January 2008, we received a proposed Agreed Order from the TCEQ for
$181,200 relating to an open valve and associated flaring at the Texas City Refinery. We agreed to
the terms of the order, which was adopted by the TCEQ in February 2009, thus resolving this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
19
PART II
ITEM
5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY SECURITIES
Our common stock trades on the New York Stock Exchange under the symbol VLO.
As of January 31, 2009, there were 6,927 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 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Prices of the |
|
Dividends |
|
|
Common Stock |
|
Per |
Quarter Ended |
|
High |
|
Low |
|
Common Share |
|
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
$ |
30.36 |
|
|
$ |
13.94 |
|
|
$ |
0.15 |
|
September 30 |
|
|
40.74 |
|
|
|
28.20 |
|
|
|
0.15 |
|
June 30 |
|
|
55.00 |
|
|
|
39.20 |
|
|
|
0.15 |
|
March 31 |
|
|
71.12 |
|
|
|
44.94 |
|
|
|
0.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
$ |
75.75 |
|
|
$ |
60.80 |
|
|
$ |
0.12 |
|
September 30 |
|
|
78.68 |
|
|
|
60.00 |
|
|
|
0.12 |
|
June 30 |
|
|
77.89 |
|
|
|
63.53 |
|
|
|
0.12 |
|
March 31 |
|
|
66.02 |
|
|
|
47.66 |
|
|
|
0.12 |
|
On January 20, 2009, our board of directors declared a quarterly cash dividend of $0.15 per common
share payable March 11, 2009 to holders of record at the close of business on February 11, 2009.
Dividends are considered quarterly by the board of directors and may be paid only when approved by
the board.
20
The following table discloses purchases of shares of Valeros common stock made by us or on our
behalf during the fourth quarter of 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
Total |
|
|
Average |
|
|
Total Number of |
|
|
Total Number of |
|
|
Approximate Dollar |
|
|
|
|
|
Number of |
|
|
Price |
|
|
Shares Not |
|
|
Shares Purchased |
|
|
Value of Shares that |
|
|
|
|
|
Shares |
|
|
Paid per |
|
|
Purchased as Part |
|
|
as Part of |
|
|
May Yet Be Purchased |
|
|
|
|
|
Purchased |
|
|
Share |
|
|
of Publicly |
|
|
Publicly |
|
|
Under the Plans or |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Announced Plans |
|
|
Announced Plans |
|
|
Programs (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
or Programs (1) |
|
|
or Programs |
|
|
|
|
|
October 2008 |
|
|
|
8,366,493 |
|
|
|
$ |
21.62 |
|
|
|
|
446,928 |
|
|
|
|
7,919,565 |
|
|
|
$ 3.46 billion |
|
|
November 2008 |
|
|
|
20,526 |
|
|
|
$ |
19.61 |
|
|
|
|
20,526 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
December 2008 |
|
|
|
507 |
|
|
|
$ |
17.52 |
|
|
|
|
507 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
Total |
|
|
|
8,387,526 |
|
|
|
$ |
21.61 |
|
|
|
|
467,961 |
|
|
|
|
7,919,565 |
|
|
|
$ 3.46 billion |
|
|
|
|
|
(1) |
|
The shares reported in this column represent purchases settled in the fourth
quarter of 2008 relating to (a) our purchases of shares in open-market transactions to
meet our obligations under employee benefit plans, and (b) 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 incentive compensation plans. |
|
(2) |
|
On April 26, 2007, we publicly announced an increase in our common stock
purchase program from $2 billion to $6 billion, as authorized by our board of directors
on April 25, 2007. The $6 billion common stock purchase program has no expiration
date. On February 28, 2008, we announced that our board of directors approved a new
$3 billion common stock purchase program. This program is in addition to the
$6 billion program. This new $3 billion program has no expiration date. Our stock
purchase programs are more fully described in Note 14
of Notes to Consolidated Financial Statements, and we hereby incorporate by reference
into this Item our disclosures made in Note 14. |
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.
21
The following line graph compares the cumulative total return* 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
(selected by us) for the five-year period commencing December 31, 2003 and ending December 31,
2008. The New Peer Group consists of the following 13 companies that are engaged in domestic
refining operations: Alon USA Energy, Inc., Chevron Corporation, ConocoPhillips, CVR Energy, Inc.,
Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Holly Corporation, Marathon
Oil Corporation, Murphy Oil Corporation, Sunoco, Inc., Tesoro Corporation, and Western Refining,
Inc. The Old Peer Group consisted of the following ten companies: Chevron Corporation,
ConocoPhillips, Exxon Mobil Corporation, Frontier Oil Corporation, Hess Corporation, Marathon Oil
Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Sunoco, Inc., and Tesoro
Corporation. The New Peer Group serves as an update to our Old Peer Group by including additional
domestic independent refiners (Alon USA Energy, Inc., CVR Energy, Inc., Holly Corporation, and
Western Refining, Inc.) and removing one energy company that does not conduct domestic refining
operations (Occidental Petroleum Corporation).
COMPARISON
OF 5-YEAR CUMULATIVE TOTAL RETURN*
Among Valero Energy Corporation, The S&P 500 Index,
A New Peer Group and an Old Peer Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/2003 |
|
12/2004 |
|
12/2005 |
|
12/2006 |
|
12/2007 |
|
12/2008 |
|
Valero Common Stock |
|
$ |
100 |
|
|
$ |
197.64 |
|
|
$ |
451.53 |
|
|
$ |
450.06 |
|
|
$ |
620.65 |
|
|
$ |
195.21 |
|
S&P 500 |
|
|
100 |
|
|
|
110.88 |
|
|
|
116.33 |
|
|
|
134.70 |
|
|
|
142.10 |
|
|
|
89.53 |
|
New Peer Group |
|
|
100 |
|
|
|
128.93 |
|
|
|
152.64 |
|
|
|
205.69 |
|
|
|
263.27 |
|
|
|
202.99 |
|
Old Peer Group |
|
|
100 |
|
|
|
129.30 |
|
|
|
153.99 |
|
|
|
206.52 |
|
|
|
268.02 |
|
|
|
207.99 |
|
|
|
|
* |
|
Assumes that an investment in Valero common stock and each index was $100 on December 31,
2003. Cumulative total return is based on share price appreciation plus reinvestment of
dividends from December 31, 2003 through December 31, 2008. |
22
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for the five-year period ended December 31, 2008 was derived from our
audited consolidated financial statements. The following table should be read together with the
historical consolidated financial statements and accompanying notes included in Item 8, Financial
Statements and Supplementary Data, and with Item 7, Managements Discussion and Analysis of
Financial Condition and Results of Operations.
The following summaries are in millions of dollars except for per share amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 (a) |
|
2007 (a) (b) |
|
2006 (a) (b) |
|
2005 (a) (b) (c) |
|
2004 (a) (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues (e) |
|
$ |
119,114 |
|
|
$ |
95,327 |
|
|
$ |
87,640 |
|
|
$ |
80,616 |
|
|
$ |
54,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
563 |
|
|
|
6,918 |
|
|
|
7,722 |
|
|
|
5,268 |
|
|
|
2,979 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
continuing operations |
|
|
(1,131 |
) |
|
|
4,565 |
|
|
|
5,287 |
|
|
|
3,473 |
|
|
|
1,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share
from continuing operations
assuming dilution |
|
|
(2.16 |
) |
|
|
7.72 |
|
|
|
8.36 |
|
|
|
5.90 |
|
|
|
3.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per common share |
|
|
0.57 |
|
|
|
0.48 |
|
|
|
0.30 |
|
|
|
0.19 |
|
|
|
0.145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
23,213 |
|
|
|
21,560 |
|
|
|
20,032 |
|
|
|
17,266 |
|
|
|
10,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
|
|
|
|
4,019 |
|
|
|
4,061 |
|
|
|
4,792 |
|
|
|
2,388 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
34,417 |
|
|
|
42,722 |
|
|
|
37,753 |
|
|
|
32,798 |
|
|
|
19,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt and capital lease
obligations (less current portion) |
|
|
6,264 |
|
|
|
6,470 |
|
|
|
4,619 |
|
|
|
5,156 |
|
|
|
3,901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity |
|
|
15,620 |
|
|
|
18,507 |
|
|
|
18,605 |
|
|
|
15,050 |
|
|
|
7,798 |
|
|
|
|
(a) |
|
Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon Refining Krotz Springs,
Inc. Therefore, the assets and liabilities related to the sale are presented as assets held
for sale and liabilities related to assets held for sale, respectively, in the consolidated
balance sheets as of December 31, 2007, 2006, 2005, and 2004, and as a result, certain balance
sheet amounts reflected herein have been reclassified. |
|
(b) |
|
Effective July 1, 2007, we sold our Lima Refinery to Husky Refining Company. The results of
operations of the Lima Refinery are reported as discontinued operations in the consolidated
statements of income for the years ended December 31, 2007, 2006, and 2005 and therefore are
not included in the statement of income information presented in this table. |
|
(c) |
|
Includes the operations related to the Premcor Acquisition beginning September 1, 2005. |
|
(d) |
|
Includes the operations related to the acquisition of the Aruba Refinery and related
businesses beginning March 5, 2004. |
|
(e) |
|
Operating revenues reported for 2005 and 2004 include approximately $7.8 billion and $4.9
billion, respectively, related to crude oil buy/sell arrangements. |
23
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 Items 1, 1A and 2, Business, Risk Factors and Properties, and Item 8, Financial
Statements and Supplementary Data, included in this report. In the discussions that follow, all
per-share amounts assume dilution.
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 Results of
Operations 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 retail margins, including gasoline, diesel, home heating oil, and convenience
store merchandise 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 refinery turnaround and
catalyst costs and capital expenditures for environmental and other purposes, 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 United States, Canada, and elsewhere; |
|
|
|
|
expectations regarding environmental, tax, and other regulatory initiatives; and |
|
|
|
|
the effect of general economic and other conditions on refining and retail 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 consume refined products, including
the United States, and in crude oil producing regions, including the Middle East and South
America; |
|
|
|
|
the domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet
fuel, home heating oil, and petrochemicals; |
|
|
|
|
the domestic and foreign supplies of crude oil and other feedstocks; |
|
|
|
|
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC)
to agree on and to maintain crude oil price and production controls; |
|
|
|
|
the level of consumer demand, including seasonal fluctuations; |
24
|
|
|
refinery overcapacity or undercapacity; |
|
|
|
|
the actions taken by competitors, including both pricing and adjustments to refining
capacity in response to market conditions; |
|
|
|
|
environmental, tax, and other regulations at the municipal, state, and federal levels
and in foreign countries; |
|
|
|
|
the level of foreign imports of refined products; |
|
|
|
|
accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines,
or equipment, 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; |
|
|
|
|
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 and other feedstocks, and
refined products; |
|
|
|
|
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 federal,
state, municipal, or foreign legislation or rulemakings, 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 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 Items 1.,
1A. & 2. Business, Risk Factors and Properties 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 the results of 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.
25
OVERVIEW
In this overview, we describe some of the primary factors that we believe affected our results of
operations during the year ended December 31, 2008. We reported a loss from continuing operations
of $1.1 billion, or $2.16 per share, for the year ended December 31, 2008 compared to income from
continuing operations of $4.6 billion, or $7.72 per share, for the year ended December 31, 2007.
The 2008 results included a charge in the fourth quarter of 2008 of $4.1 billion ($4.0 billion
after tax) resulting from the impairment of goodwill.
The goodwill impairment loss, which represented a write-off of the entire balance of our goodwill,
was associated with a significant decline in our market capitalization in the fourth quarter of
2008 that resulted in large part from severe disruptions in the capital and commodities markets.
In performing our goodwill impairment test under applicable accounting rules, we estimate fair
value by discounting the estimated future cash flows from our refineries. The decline in our
market capitalization during the fourth quarter of 2008 resulted in the use of higher,
risk-adjusted discount rates in determining the fair values of our reporting units, which reflected
the significant risk premium implied by our stock price as of December 31, 2008. As a result of
applying these higher discount rates to the cash flows of our reporting units, the fair values in
each of our reporting units were below their net book values including goodwill, thus indicating
potential impairment. Due to this conclusion of potential impairment, existing accounting rules
required additional analysis for each of the reporting units to determine the amount of the loss,
and this additional analysis indicated that all of the goodwill in each of our reporting units
should be written off.
Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana to a subsidiary of Alon
USA Energy, Inc. The sale resulted in a pre-tax gain of $305 million, or $170 million after tax,
as discussed in Note 2 of Notes to Consolidated Financial
Statements. Net cash proceeds from the sale were $463 million, including approximately
$135 million from the sale of working capital. In addition, we received contingent consideration
in the form of a three-year earn-out agreement based on certain product margins.
Our profitability is substantially determined by the spread between the price of refined products
and the price of crude oil, referred to as the refined product margin. The weakening of industry
fundamentals for refined products that we experienced in the fourth quarter of 2007 continued
throughout 2008. Gasoline margins declined significantly in all of our refining regions in 2008
compared to 2007. The decline in margins was primarily due to a decrease in gasoline demand and an
increase in ethanol production. Margins on certain secondary refined products, such as petroleum
coke and petrochemical feedstocks, also declined during 2008 due to a significant increase in the
cost of crude oil and other feedstocks used to produce them. However, these decreases were
partially offset by the effect of favorable diesel margins in 2008, which increased compared to
2007 primarily due to strong global demand.
Because more than 65% of our total crude oil throughput consists of sour crude oil and acidic sweet
crude oil feedstocks that historically have been purchased at prices less than sweet crude oil, our
profitability is also significantly affected by the spread between sweet crude oil and sour crude
oil prices, referred to as the sour crude oil differential. During 2008, sour crude oil
differentials remained wide and improved somewhat in 2008 compared to 2007 levels.
Regarding operations, on January 25, 2008, our Aruba Refinery was shut down due to a fire in its
vacuum unit. We resumed partial operation of the refinery in mid-February, and during the second
quarter of 2008 we completed the repairs and resumed full operations of the refinery. During the
third quarter of 2008, certain of our refineries were shut down as a result of two hurricanes that
impacted the Gulf Coast.
26
Although we avoided major damage from the hurricanes, repair costs and downtime attributable to the
hurricanes and the Aruba downtime reduced our results of operations for 2008.
During the year ended December 31, 2008, we increased our quarterly common stock dividend from
$0.12 per share to $0.15 per share and purchased 23.0 million shares of our common stock under our
board-authorized programs, which represented more than 4% of our shares outstanding at the
beginning of 2008. We also redeemed $350 million of 9.5% callable debt that was due in 2013 and
invested $3.2 billion in capital expenditures and deferred turnaround and catalyst costs.
27
RESULTS OF OPERATIONS
2008 Compared to 2007
Financial Highlights
(millions of dollars, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 (a) |
|
Change |
|
Operating revenues |
|
$ |
119,114 |
|
|
$ |
95,327 |
|
|
$ |
23,787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
107,429 |
|
|
|
81,645 |
|
|
|
25,784 |
|
Refining operating expenses |
|
|
4,555 |
|
|
|
4,016 |
|
|
|
539 |
|
Retail selling expenses |
|
|
768 |
|
|
|
750 |
|
|
|
18 |
|
General and administrative expenses |
|
|
559 |
|
|
|
638 |
|
|
|
(79 |
) |
Depreciation and amortization expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
|
1,327 |
|
|
|
1,222 |
|
|
|
105 |
|
Retail |
|
|
105 |
|
|
|
90 |
|
|
|
15 |
|
Corporate |
|
|
44 |
|
|
|
48 |
|
|
|
(4 |
) |
Gain on sale of Krotz Springs Refinery |
|
|
(305 |
) |
|
|
|
|
|
|
(305 |
) |
Goodwill impairment loss (b) |
|
|
4,069 |
|
|
|
|
|
|
|
4,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
118,551 |
|
|
|
88,409 |
|
|
|
30,142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
563 |
|
|
|
6,918 |
|
|
|
(6,355 |
) |
Other income, net |
|
|
113 |
|
|
|
167 |
|
|
|
(54 |
) |
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(451 |
) |
|
|
(466 |
) |
|
|
15 |
|
Capitalized |
|
|
111 |
|
|
|
107 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income
tax
expense |
|
|
336 |
|
|
|
6,726 |
|
|
|
(6,390 |
) |
Income tax expense |
|
|
1,467 |
|
|
|
2,161 |
|
|
|
(694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
|
(1,131 |
) |
|
|
4,565 |
|
|
|
(5,696 |
) |
Income from discontinued operations, net of income
tax expense (a) |
|
|
|
|
|
|
669 |
|
|
|
(669 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(1,131 |
) |
|
$ |
5,234 |
|
|
$ |
(6,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
(2.16 |
) |
|
$ |
7.72 |
|
|
$ |
(9.88 |
) |
Discontinued operations |
|
|
|
|
|
|
1.16 |
|
|
|
(1.16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(2.16 |
) |
|
$ |
8.88 |
|
|
$ |
(11.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references
on page 31. |
28
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
Change |
|
Refining (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (b) |
|
$ |
797 |
|
|
$ |
7,355 |
|
|
$ |
(6,558 |
) |
Throughput margin per barrel (c) |
|
$ |
10.79 |
|
|
$ |
12.33 |
|
|
$ |
(1.54 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.71 |
|
|
$ |
3.93 |
|
|
$ |
0.78 |
|
Depreciation and amortization |
|
|
1.37 |
|
|
|
1.20 |
|
|
|
0.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
6.08 |
|
|
$ |
5.13 |
|
|
$ |
0.95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
Heavy sour crude |
|
|
592 |
|
|
|
638 |
|
|
|
(46 |
) |
Medium/light sour crude |
|
|
673 |
|
|
|
635 |
|
|
|
38 |
|
Acidic sweet crude |
|
|
79 |
|
|
|
80 |
|
|
|
(1 |
) |
Sweet crude |
|
|
606 |
|
|
|
724 |
|
|
|
(118 |
) |
Residuals |
|
|
228 |
|
|
|
247 |
|
|
|
(19 |
) |
Other feedstocks |
|
|
149 |
|
|
|
173 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks |
|
|
2,327 |
|
|
|
2,497 |
|
|
|
(170 |
) |
Blendstocks and other |
|
|
316 |
|
|
|
301 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput volumes |
|
|
2,643 |
|
|
|
2,798 |
|
|
|
(155 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yields (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines and blendstocks |
|
|
1,187 |
|
|
|
1,285 |
|
|
|
(98 |
) |
Distillates |
|
|
915 |
|
|
|
919 |
|
|
|
(4 |
) |
Petrochemicals |
|
|
71 |
|
|
|
82 |
|
|
|
(11 |
) |
Other products (d) |
|
|
463 |
|
|
|
507 |
|
|
|
(44 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total yields |
|
|
2,636 |
|
|
|
2,793 |
|
|
|
(157 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
260 |
|
|
$ |
154 |
|
|
$ |
106 |
|
Company-operated fuel sites (average) |
|
|
973 |
|
|
|
957 |
|
|
|
16 |
|
Fuel volumes (gallons per day per site) |
|
|
5,000 |
|
|
|
4,979 |
|
|
|
21 |
|
Fuel margin per gallon |
|
$ |
0.229 |
|
|
$ |
0.174 |
|
|
$ |
0.055 |
|
Merchandise sales |
|
$ |
1,097 |
|
|
$ |
1,024 |
|
|
$ |
73 |
|
Merchandise margin (percentage of sales) |
|
|
29.9 |
% |
|
|
29.7 |
% |
|
|
0.2 |
% |
Margin on miscellaneous sales |
|
$ |
99 |
|
|
$ |
101 |
|
|
$ |
(2 |
) |
Retail selling expenses |
|
$ |
505 |
|
|
$ |
494 |
|
|
$ |
11 |
|
Depreciation and amortization expense |
|
$ |
70 |
|
|
$ |
59 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Canada: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
109 |
|
|
$ |
95 |
|
|
$ |
14 |
|
Fuel volumes (thousand gallons per day) |
|
|
3,193 |
|
|
|
3,234 |
|
|
|
(41 |
) |
Fuel margin per gallon |
|
$ |
0.268 |
|
|
$ |
0.248 |
|
|
$ |
0.020 |
|
Merchandise sales |
|
$ |
200 |
|
|
$ |
187 |
|
|
$ |
13 |
|
Merchandise margin (percentage of sales) |
|
|
28.5 |
% |
|
|
27.8 |
% |
|
|
0.7 |
% |
Margin on miscellaneous sales |
|
$ |
36 |
|
|
$ |
37 |
|
|
$ |
(1 |
) |
Retail selling expenses |
|
$ |
263 |
|
|
$ |
256 |
|
|
$ |
7 |
|
Depreciation and amortization expense |
|
$ |
35 |
|
|
$ |
31 |
|
|
$ |
4 |
|
|
|
|
See the footnote references
on page 31. |
29
Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
Change |
|
Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
3,191 |
|
|
$ |
4,505 |
|
|
$ |
(1,314 |
) |
Throughput volumes (thousand barrels per day) |
|
|
1,404 |
|
|
|
1,537 |
|
|
|
(133 |
) |
Throughput margin per barrel (c) |
|
$ |
11.57 |
|
|
$ |
12.81 |
|
|
$ |
(1.24 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.65 |
|
|
$ |
3.70 |
|
|
$ |
0.95 |
|
Depreciation and amortization |
|
|
1.30 |
|
|
|
1.08 |
|
|
|
0.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.95 |
|
|
$ |
4.78 |
|
|
$ |
1.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
577 |
|
|
$ |
910 |
|
|
$ |
(333 |
) |
Throughput volumes (thousand barrels per day) |
|
|
423 |
|
|
|
402 |
|
|
|
21 |
|
Throughput margin per barrel (c) |
|
$ |
9.27 |
|
|
$ |
11.66 |
|
|
$ |
(2.39 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.26 |
|
|
$ |
4.13 |
|
|
$ |
0.13 |
|
Depreciation and amortization |
|
|
1.29 |
|
|
|
1.33 |
|
|
|
(0.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.55 |
|
|
$ |
5.46 |
|
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
724 |
|
|
$ |
1,084 |
|
|
$ |
(360 |
) |
Throughput volumes (thousand barrels per day) |
|
|
540 |
|
|
|
570 |
|
|
|
(30 |
) |
Throughput margin per barrel (c) |
|
$ |
9.95 |
|
|
$ |
10.46 |
|
|
$ |
(0.51 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.88 |
|
|
$ |
3.98 |
|
|
$ |
0.90 |
|
Depreciation and amortization |
|
|
1.40 |
|
|
|
1.27 |
|
|
|
0.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
6.28 |
|
|
$ |
5.25 |
|
|
$ |
1.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
374 |
|
|
$ |
856 |
|
|
$ |
(482 |
) |
Throughput volumes (thousand barrels per day) |
|
|
276 |
|
|
|
289 |
|
|
|
(13 |
) |
Throughput margin per barrel (c) |
|
$ |
10.84 |
|
|
$ |
14.41 |
|
|
$ |
(3.57 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
5.37 |
|
|
$ |
4.82 |
|
|
$ |
0.55 |
|
Depreciation and amortization |
|
|
1.77 |
|
|
|
1.49 |
|
|
|
0.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
7.14 |
|
|
$ |
6.31 |
|
|
$ |
0.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income for regions above |
|
$ |
4,866 |
|
|
$ |
7,355 |
|
|
$ |
(2,489 |
) |
Goodwill impairment loss (b) |
|
|
(4,069 |
) |
|
|
|
|
|
|
(4,069 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refining operating income |
|
$ |
797 |
|
|
$ |
7,355 |
|
|
$ |
(6,558 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references
on page 31. |
30
Average Market Reference Prices and Differentials (f)
(dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
Change |
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) crude oil |
|
$ |
99.56 |
|
|
$ |
72.27 |
|
|
$ |
27.29 |
|
WTI less sour crude oil at U.S. Gulf Coast (g) |
|
|
5.20 |
|
|
|
4.95 |
|
|
|
0.25 |
|
WTI less Mars crude oil |
|
|
6.13 |
|
|
|
5.61 |
|
|
|
0.52 |
|
WTI less Alaska North Slope (ANS) crude oil |
|
|
1.22 |
|
|
|
0.58 |
|
|
|
0.64 |
|
WTI less Maya crude oil |
|
|
15.71 |
|
|
|
12.41 |
|
|
|
3.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Products: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
4.85 |
|
|
|
13.78 |
|
|
|
(8.93 |
) |
No. 2 fuel oil less WTI |
|
|
18.35 |
|
|
|
11.94 |
|
|
|
6.41 |
|
Ultra-low-sulfur diesel less WTI |
|
|
22.96 |
|
|
|
17.76 |
|
|
|
5.20 |
|
Propylene less WTI |
|
|
(3.69 |
) |
|
|
11.05 |
|
|
|
(14.74 |
) |
U.S. Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
4.46 |
|
|
|
18.02 |
|
|
|
(13.56 |
) |
Low-sulfur diesel less WTI |
|
|
24.12 |
|
|
|
21.30 |
|
|
|
2.82 |
|
U.S. Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
3.22 |
|
|
|
13.98 |
|
|
|
(10.76 |
) |
No. 2 fuel oil less WTI |
|
|
20.23 |
|
|
|
12.96 |
|
|
|
7.27 |
|
Lube oils less WTI |
|
|
68.79 |
|
|
|
48.29 |
|
|
|
20.50 |
|
U.S. West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
CARBOB 87 gasoline less ANS |
|
|
11.15 |
|
|
|
23.80 |
|
|
|
(12.65 |
) |
CARB diesel less ANS |
|
|
23.81 |
|
|
|
22.66 |
|
|
|
1.15 |
|
|
|
|
The following notes relate to
references on pages 28 through 31. |
|
(a) |
|
Effective July 1, 2007, we sold our Lima Refinery to Husky Refining Company (Husky).
Therefore, the results of operations of the Lima Refinery for the six months of 2007 prior to
its sale, as well as the gain on the sale of the refinery, are reported as discontinued
operations, and all refining operating highlights, both consolidated and for the Mid-Continent
region, exclude the Lima Refinery. The sale resulted in a pre-tax gain of $827 million ($426
million after tax), which is included in Income from discontinued operations, net of income
tax expense for the year ended December 31, 2007. |
|
(b) |
|
Upon applying the goodwill impairment testing criteria under existing accounting rules during
the fourth quarter of 2008, we
determined that the goodwill in all four of our reporting units was impaired, which resulted in
a goodwill impairment loss of $4.1 billion ($4.0 billion after tax). This goodwill impairment
loss is included in the refining segment operating income but is excluded from the consolidated
and regional throughput margins per barrel and the regional operating income amounts presented
for the year ended December 31, 2008 in order to make that information comparable between
periods. |
|
(c) |
|
Throughput margin per barrel represents operating revenues less cost of sales divided by
throughput volumes. |
|
(d) |
|
Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt. |
|
(e) |
|
The regions reflected herein contain the following refineries: the Gulf Coast refining region
includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers,
Krotz Springs (for periods prior to its sale effective July 1, 2008), St. Charles, Aruba, and
Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and
Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and
Delaware City Refineries; and the West Coast refining region includes the Benicia and
Wilmington Refineries. |
|
(f) |
|
The average market reference prices and differentials, with the exception of the propylene
and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene
differential is based on posted propylene prices in Chemical Market Associates, Inc. and the
lube oil differential is based on Exxon Mobil Corporation postings provided by Independent
Commodity Information Services London Oil Reports. The average market reference prices and
differentials are presented to provide users of the consolidated financial statements with
economic indicators that significantly affect our operations and profitability. |
|
(g) |
|
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab
Light posted prices. |
31
General
Operating revenues increased 25% for the year ended December 31, 2008 compared to the year ended
December 31, 2007 primarily as a result of higher average refined product prices. Refined product
prices were significantly higher in the first nine months of 2008 compared to the same period of
2007, but fourth quarter 2008 refined product prices declined to levels substantially below the
fourth quarter of 2007. This resulted in a $10.1 billion decrease in fourth quarter 2008 revenues
compared to 2007, which lowered the revenue increase for the year to $23.8 billion. Offsetting the
higher revenues were substantially higher average feedstock costs.
Operating income decreased $6.4 billion, or 92%, and income from continuing operations decreased
$5.7 billion for the year ended December 31, 2008 compared to the year ended December 31, 2007
primarily due to a $6.6 billion decrease in refining segment operating income. The decrease was
primarily due to a goodwill impairment loss of $4.1 billion recorded in the fourth quarter of 2008
as discussed in Note 8 of Notes to Consolidated Financial Statements. Also, see Impairment of
Assets under Critical Accounting Policies Involving Critical Accounting Estimates below for a
detailed analysis of the methodology and assumptions used in the determination of this goodwill
impairment loss. The goodwill impairment loss is included in the refining segment operating income
but is excluded from the consolidated and regional throughput margins per barrel and regional
operating income amounts for the year ended December 31, 2008 for comparability purposes. The
refining segment operating income and income from continuing operations for the year ended
December 31, 2007 exclude the operations of the Lima Refinery and the gain on its sale, which are
classified as discontinued operations due to our sale of that refinery effective July 1, 2007 as
discussed in Note 2 of Notes to Consolidated Financial Statements.
Refining
Operating income for our refining segment decreased from $7.4 billion for the year ended
December 31, 2007 to $797 million for the year ended December 31, 2008, resulting mainly from the
$4.1 billion goodwill impairment loss discussed above, a 12% decrease in throughput margin per
barrel, a 12% increase in refining operating expenses (including depreciation and amortization
expense), and a 6% decline in throughput volumes. These decreases were partially offset by a
$305 million gain on the sale of our Krotz Springs Refinery effective July 1, 2008, which is
discussed in Note 2 of Notes to Consolidated Financial Statements.
Total refining throughput margins for 2008 compared to 2007 were impacted by the following factors:
|
|
|
Distillate margins in 2008 increased in all of our refining regions from the margins in
2007. The increase in distillate margins was primarily due to strong global demand. |
|
|
|
|
Gasoline margins decreased significantly in all of our refining regions in 2008 compared
to the margins in 2007. The decline in gasoline margins was primarily due to a decrease in
gasoline demand and an increase in ethanol production. |
|
|
|
|
Margins on various secondary refined products such as asphalt, fuel oils, propylene, and
petroleum coke declined from 2007 to 2008 as prices for these products did not increase in
proportion to the large increase in the costs of the feedstocks used to produce them. |
|
|
|
|
Sour crude oil feedstock differentials to WTI crude oil in 2008 remained favorable and
were wider than the differentials in 2007. These favorable differentials were attributable
to continued ample supplies of sour crude oils and heavy sour residual fuel oils on the
world market. Differentials on sour crude oil feedstocks also continued to benefit from
increased demand for sweet crude oil resulting from lower sulfur specifications for
gasoline and diesel. |
|
|
|
|
Throughput volumes decreased 155,000 barrels per day during 2008 compared to 2007
primarily due to a fire in the vacuum unit at our Aruba Refinery in January of 2008,
downtime for
|
32
|
|
|
maintenance at our Port Arthur and Delaware City Refineries, unplanned downtime at our Port
Arthur, Texas City, St. Charles, and Houston Refineries related to Hurricanes Ike and
Gustav, the sale of our Krotz Springs Refinery, and economic decisions to reduce throughputs
in certain of our refineries as a result of unfavorable market fundamentals, partially
offset by the 2007 shutdown of our McKee Refinery discussed in Note 23 of Notes to
Consolidated Financial Statements. |
|
|
|
|
Throughput margin in 2008 included approximately $100 million related to the McKee
Refinery business interruption settlement discussed in Note 23 of Notes to Consolidated
Financial Statements. |
Refining operating expenses, excluding depreciation and amortization expense, increased $0.78 per
barrel, or 20%, for the year ended December 31, 2008 compared to the year ended December 31, 2007.
Per-barrel operating expenses increased mainly due to an increase in energy costs, as well as the
effect of the throughput volume decline discussed above. Refining depreciation and amortization
expense increased 9% from 2007 to 2008 primarily due to the implementation of new capital projects
and increased turnaround and catalyst amortization.
Retail
Retail operating income was $369 million for the year ended December 31, 2008 compared to
$249 million for the year ended December 31, 2007. This 48% increase in operating income was
primarily attributable to a $0.055 per gallon increase in retail fuel margins and increased
in-store sales in our U.S. retail operations. The significant improvement in fuel margins was
largely the result of rapidly declining crude oil prices in the second half of 2008.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense,
decreased $83 million for the year ended December 31, 2008 compared to the year ended December 31,
2007. This decrease was primarily due to lower variable incentive compensation expenses combined
with the nonrecurrence of 2007 expenses related to executive retirement costs and a $13 million
termination fee paid for the cancellation of our services agreement with NuStar Energy L.P.
Other income, net decreased for the year ended December 31, 2008 compared to the year ended
December 31, 2007 primarily due to a $91 million foreign currency exchange rate gain in 2007
resulting from the repayment of a loan by a foreign subsidiary, reduced interest income resulting
from lower cash balances and interest rates, and a reduction in the fair value of certain
nonqualified benefit plan assets. These decreases were partially offset by income related to the
Alon earn-out agreement discussed in Notes 2 and 17 of Notes to Consolidated Financial Statements,
lower costs incurred under our accounts receivable sales program, an increase in earnings from our
equity investment in Cameron Highway Oil Pipeline Company, and a $14 million gain in 2008 on the
redemption of our 9.5% senior notes as discussed in Note 12 of Notes to Consolidated Financial
Statements.
Interest and debt expense decreased primarily due to reduced interest on tax liabilities, partially
offset by higher average debt balances.
Income tax expense decreased $694 million from 2007 to 2008 mainly as a result of lower operating
income, excluding the effect on operating income of the $4.1 billion goodwill impairment loss
discussed above that has an insignificant tax effect. Excluding this goodwill impairment loss, our
effective tax rate for the year ended December 31, 2008 was comparable to the effective tax rate
for the year ended December 31, 2007.
33
Income from discontinued operations for the year ended December 31, 2007 represents a $426 million
after-tax gain on the sale of the Lima Refinery effective July 1, 2007 and net income from its
operations prior to the sale.
34
2007 Compared to 2006
Financial Highlights
(millions of dollars, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 (a) |
|
2006 (a) |
|
Change |
|
Operating revenues |
|
$ |
95,327 |
|
|
$ |
87,640 |
|
|
$ |
7,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
81,645 |
|
|
|
73,863 |
|
|
|
7,782 |
|
Refining operating expenses |
|
|
4,016 |
|
|
|
3,622 |
|
|
|
394 |
|
Retail selling expenses |
|
|
750 |
|
|
|
719 |
|
|
|
31 |
|
General and administrative expenses |
|
|
638 |
|
|
|
598 |
|
|
|
40 |
|
Depreciation and amortization expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
|
1,222 |
|
|
|
985 |
|
|
|
237 |
|
Retail |
|
|
90 |
|
|
|
87 |
|
|
|
3 |
|
Corporate |
|
|
48 |
|
|
|
44 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
88,409 |
|
|
|
79,918 |
|
|
|
8,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
6,918 |
|
|
|
7,722 |
|
|
|
(804 |
) |
Equity in earnings of NuStar Energy L.P. (b) |
|
|
|
|
|
|
45 |
|
|
|
(45 |
) |
Other income, net |
|
|
167 |
|
|
|
350 |
|
|
|
(183 |
) |
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(466 |
) |
|
|
(377 |
) |
|
|
(89 |
) |
Capitalized |
|
|
107 |
|
|
|
165 |
|
|
|
(58 |
) |
Minority interest in net income of
NuStar GP Holdings, LLC (b) |
|
|
|
|
|
|
(7 |
) |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income
tax
expense |
|
|
6,726 |
|
|
|
7,898 |
|
|
|
(1,172 |
) |
Income tax expense |
|
|
2,161 |
|
|
|
2,611 |
|
|
|
(450 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
4,565 |
|
|
|
5,287 |
|
|
|
(722 |
) |
Income from discontinued operations, net of income
tax expense (a) |
|
|
669 |
|
|
|
176 |
|
|
|
493 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
5,234 |
|
|
|
5,463 |
|
|
|
(229 |
) |
Preferred stock dividends |
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common stock |
|
$ |
5,234 |
|
|
$ |
5,461 |
|
|
$ |
(227 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share assuming dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
7.72 |
|
|
$ |
8.36 |
|
|
$ |
(0.64 |
) |
Discontinued operations |
|
|
1.16 |
|
|
|
0.28 |
|
|
|
0.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8.88 |
|
|
$ |
8.64 |
|
|
$ |
0.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references
on page 38. |
35
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
Change |
|
Refining (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
7,355 |
|
|
$ |
8,182 |
|
|
$ |
(827 |
) |
Throughput margin per barrel (c) |
|
$ |
12.33 |
|
|
$ |
12.47 |
|
|
$ |
(0.14 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.93 |
|
|
$ |
3.53 |
|
|
$ |
0.40 |
|
Depreciation and amortization |
|
|
1.20 |
|
|
|
0.96 |
|
|
|
0.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.13 |
|
|
$ |
4.49 |
|
|
$ |
0.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
Heavy sour crude |
|
|
638 |
|
|
|
697 |
|
|
|
(59 |
) |
Medium/light sour crude |
|
|
635 |
|
|
|
618 |
|
|
|
17 |
|
Acidic sweet crude |
|
|
80 |
|
|
|
65 |
|
|
|
15 |
|
Sweet crude |
|
|
724 |
|
|
|
752 |
|
|
|
(28 |
) |
Residuals |
|
|
247 |
|
|
|
234 |
|
|
|
13 |
|
Other feedstocks |
|
|
173 |
|
|
|
147 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks |
|
|
2,497 |
|
|
|
2,513 |
|
|
|
(16 |
) |
Blendstocks and other |
|
|
301 |
|
|
|
298 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput volumes |
|
|
2,798 |
|
|
|
2,811 |
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yields (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines and blendstocks |
|
|
1,285 |
|
|
|
1,348 |
|
|
|
(63 |
) |
Distillates |
|
|
919 |
|
|
|
891 |
|
|
|
28 |
|
Petrochemicals |
|
|
82 |
|
|
|
80 |
|
|
|
2 |
|
Other products (d) |
|
|
507 |
|
|
|
491 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total yields |
|
|
2,793 |
|
|
|
2,810 |
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
154 |
|
|
$ |
113 |
|
|
$ |
41 |
|
Company-operated fuel sites (average) |
|
|
957 |
|
|
|
982 |
|
|
|
(25 |
) |
Fuel volumes (gallons per day per site) |
|
|
4,979 |
|
|
|
4,985 |
|
|
|
(6 |
) |
Fuel margin per gallon |
|
$ |
0.174 |
|
|
$ |
0.162 |
|
|
$ |
0.012 |
|
Merchandise sales |
|
$ |
1,024 |
|
|
$ |
960 |
|
|
$ |
64 |
|
Merchandise margin (percentage of sales) |
|
|
29.7 |
% |
|
|
29.6 |
% |
|
|
0.1 |
% |
Margin on miscellaneous sales |
|
$ |
101 |
|
|
$ |
85 |
|
|
$ |
16 |
|
Retail selling expenses |
|
$ |
494 |
|
|
$ |
485 |
|
|
$ |
9 |
|
Depreciation and amortization expense |
|
$ |
59 |
|
|
$ |
60 |
|
|
$ |
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Canada: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
95 |
|
|
$ |
69 |
|
|
$ |
26 |
|
Fuel volumes (thousand gallons per day) |
|
|
3,234 |
|
|
|
3,176 |
|
|
|
58 |
|
Fuel margin per gallon |
|
$ |
0.248 |
|
|
$ |
0.217 |
|
|
$ |
0.031 |
|
Merchandise sales |
|
$ |
187 |
|
|
$ |
167 |
|
|
$ |
20 |
|
Merchandise margin (percentage of sales) |
|
|
27.8 |
% |
|
|
27.4 |
% |
|
|
0.4 |
% |
Margin on miscellaneous sales |
|
$ |
37 |
|
|
$ |
32 |
|
|
$ |
5 |
|
Retail selling expenses |
|
$ |
256 |
|
|
$ |
234 |
|
|
$ |
22 |
|
Depreciation and amortization expense |
|
$ |
31 |
|
|
$ |
27 |
|
|
$ |
4 |
|
|
|
|
See the footnote references
on page 38. |
36
Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
Change |
|
Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
4,505 |
|
|
$ |
5,109 |
|
|
$ |
(604 |
) |
Throughput volumes (thousand barrels per day) |
|
|
1,537 |
|
|
|
1,532 |
|
|
|
5 |
|
Throughput margin per barrel (c) |
|
$ |
12.81 |
|
|
$ |
13.23 |
|
|
$ |
(0.42 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.70 |
|
|
$ |
3.26 |
|
|
$ |
0.44 |
|
Depreciation and amortization |
|
|
1.08 |
|
|
|
0.84 |
|
|
|
0.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
4.78 |
|
|
$ |
4.10 |
|
|
$ |
0.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
910 |
|
|
$ |
1,041 |
|
|
$ |
(131 |
) |
Throughput volumes (thousand barrels per day) |
|
|
402 |
|
|
|
410 |
|
|
|
(8 |
) |
Throughput margin per barrel (c) |
|
$ |
11.66 |
|
|
$ |
11.32 |
|
|
$ |
0.34 |
|
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.13 |
|
|
$ |
3.36 |
|
|
$ |
0.77 |
|
Depreciation and amortization |
|
|
1.33 |
|
|
|
1.00 |
|
|
|
0.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.46 |
|
|
$ |
4.36 |
|
|
$ |
1.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
1,084 |
|
|
$ |
944 |
|
|
$ |
140 |
|
Throughput volumes (thousand barrels per day) |
|
|
570 |
|
|
|
563 |
|
|
|
7 |
|
Throughput margin per barrel (c) |
|
$ |
10.46 |
|
|
$ |
9.80 |
|
|
$ |
0.66 |
|
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.98 |
|
|
$ |
4.10 |
|
|
$ |
(0.12 |
) |
Depreciation and amortization |
|
|
1.27 |
|
|
|
1.11 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.25 |
|
|
$ |
5.21 |
|
|
$ |
0.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
856 |
|
|
$ |
1,088 |
|
|
$ |
(232 |
) |
Throughput volumes (thousand barrels per day) |
|
|
289 |
|
|
|
306 |
|
|
|
(17 |
) |
Throughput margin per barrel (c) |
|
$ |
14.41 |
|
|
$ |
15.07 |
|
|
$ |
(0.66 |
) |
Operating costs per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.82 |
|
|
$ |
4.04 |
|
|
$ |
0.78 |
|
Depreciation and amortization |
|
|
1.49 |
|
|
|
1.27 |
|
|
|
0.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
6.31 |
|
|
$ |
5.31 |
|
|
$ |
1.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references
on page 38. |
37
Average Market Reference Prices and Differentials (f)
(dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
Change |
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
WTI crude oil |
|
$ |
72.27 |
|
|
$ |
66.00 |
|
|
$ |
6.27 |
|
WTI less sour crude oil at U.S. Gulf Coast (g) |
|
|
4.95 |
|
|
|
7.01 |
|
|
|
(2.06 |
) |
WTI less Mars crude oil |
|
|
5.61 |
|
|
|
7.12 |
|
|
|
(1.51 |
) |
WTI less ANS crude oil |
|
|
0.58 |
|
|
|
2.47 |
|
|
|
(1.89 |
) |
WTI less Maya crude oil |
|
|
12.41 |
|
|
|
14.80 |
|
|
|
(2.39 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Products: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
13.78 |
|
|
|
11.34 |
|
|
|
2.44 |
|
No. 2 fuel oil less WTI |
|
|
11.94 |
|
|
|
9.80 |
|
|
|
2.14 |
|
Ultra-low-sulfur diesel less WTI (h) |
|
|
17.76 |
|
|
|
N.A. |
|
|
|
N.A. |
|
Propylene less WTI |
|
|
11.05 |
|
|
|
8.78 |
|
|
|
2.27 |
|
U.S. Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
18.02 |
|
|
|
12.16 |
|
|
|
5.86 |
|
Low-sulfur diesel less WTI |
|
|
21.30 |
|
|
|
18.59 |
|
|
|
2.71 |
|
U.S. Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
13.98 |
|
|
|
10.62 |
|
|
|
3.36 |
|
No. 2 fuel oil less WTI |
|
|
12.96 |
|
|
|
9.60 |
|
|
|
3.36 |
|
Lube oils less WTI |
|
|
48.29 |
|
|
|
55.56 |
|
|
|
(7.27 |
) |
U.S. West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
CARBOB 87 gasoline less ANS |
|
|
23.80 |
|
|
|
21.52 |
|
|
|
2.28 |
|
CARB diesel less ANS |
|
|
22.66 |
|
|
|
23.96 |
|
|
|
(1.30 |
) |
|
|
|
The following notes relate to
references on pages 35 through 38. |
|
(a) |
|
Effective July 1, 2007, we sold our Lima Refinery to Husky. Therefore, the results of
operations of the Lima Refinery are reported as discontinued operations, and all refining
operating highlights, both consolidated and for the Mid-Continent region, exclude the Lima
Refinery. |
|
(b) |
|
On December 22, 2006, we sold our remaining ownership interest in NuStar GP Holdings, LLC
(formerly Valero GP Holdings, LLC), which indirectly owned the general partner interest, the
incentive distribution rights, and a 21.4% limited partner interest in NuStar Energy L.P.
(formerly Valero L.P.). As a result, the financial highlights reflect no equity in earnings of
NuStar Energy L.P. or minority interest in net income of NuStar GP Holdings, LLC subsequent to
December 21, 2006. |
|
(c) |
|
Throughput margin per barrel represents operating revenues less cost of sales divided by
throughput volumes. |
|
(d) |
|
Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt. |
|
(e) |
|
The regions reflected herein contain the following refineries: the Gulf Coast refining region
includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers,
Krotz Springs, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining
region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region
includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining
region includes the Benicia and Wilmington Refineries. |
|
(f) |
|
The average market reference prices and differentials, with the exception of the propylene
and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene
differential is based on posted propylene prices in Chemical Market Associates, Inc. and the
lube oil differential is based on Exxon Mobil Corporation postings provided by Independent
Commodity Information Services London Oil Reports. The average market reference prices and
differentials are presented to provide users of the consolidated financial statements with
economic indicators that significantly affect our operations and profitability. |
|
(g) |
|
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab
Light posted prices. |
|
(h) |
|
The market reference differential for ultra-low-sulfur diesel was not available prior to
May 1, 2006, and therefore no market reference differential is presented for the year ended
December 31, 2006. |
38
General
Operating revenues increased 9% for the year ended December 31, 2007 compared to the year ended
December 31, 2006 primarily as a result of higher refined product prices. Operating income
decreased $804 million, or 10%, and income from continuing operations decreased $722 million, or
14%, for the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily
due to an $827 million decrease in refining segment operating income. The refining segment
operating income and income from continuing operations exclude the operations of the Lima Refinery,
which are classified as discontinued operations due to our sale of that refinery as discussed in
Note 2 of Notes to Consolidated Financial Statements.
Refining
Operating income for our refining segment decreased from $8.2 billion for the year ended
December 31, 2006 to $7.4 billion for the year ended December 31, 2007 resulting mainly from
increased refining operating expenses (including depreciation and amortization expense) of
$631 million. In addition, total throughput margin for the refining segment declined by
$196 million due to a $0.14 per barrel decrease in refining throughput margin and lower throughput
volumes.
Refining operating expenses, excluding depreciation and amortization expense, increased $0.40 per
barrel, or 11%, for the year ended December 31, 2007 compared to the year ended December 31, 2006.
Operating expenses increased mainly due to increases in maintenance expense, employee compensation
and related benefits, outside services, and energy costs, as well as increased accruals for sales
and use taxes. Refining depreciation and amortization expense increased 24% from 2006 to 2007
primarily due to the implementation of new capital projects, increased turnaround and catalyst
amortization, and the write-off of costs related to the McKee Refinery as a result of a fire
originating in its propane deasphalting unit in February 2007.
Total refining throughput margins for 2007 compared to 2006 were impacted by the following factors:
|
|
|
Overall, gasoline and distillate margins relative to WTI increased in 2007 compared to
2006 due to a decline in refined product inventory levels resulting from unplanned refinery
outages, lower imports, more stringent product specifications and regulations, and heavy
industry turnaround activity, as well as moderately stronger demand. |
|
|
|
|
Sour crude oil feedstock differentials to WTI crude oil during 2007 decreased from the
strong differentials in 2006. However, other light, sweet crude oils priced at a premium
to WTI in 2007; thus, sour crude oil feedstock differentials relative to those other light,
sweet crude oils in 2007 were comparable to the wide differentials experienced in 2006.
These wide differentials are attributable to continued ample supplies of sour crude oils
and heavy sour residual fuel oils on the world market. Differentials on sour crude oil
feedstocks also continued to benefit from increased demand for sweet crude oil resulting
from lower sulfur specifications for gasoline and diesel and a global increase in refined
product demand. |
|
|
|
|
Margins on various secondary refined products such as asphalt, fuel oils, petroleum
coke, and sulfur were lower in 2007 compared to 2006 as prices for these products did not
increase in proportion to the costs of the feedstocks used to produce them. |
|
|
|
|
Throughput volumes decreased 13,000 barrels per day during 2007 compared to 2006
primarily due to a reduction in throughput volumes at our McKee Refinery as a result of the
fire discussed above. |
39
Retail
Retail operating income was $249 million for the year ended December 31, 2007 compared to
$182 million for the year ended December 31, 2006. This 37% increase in operating income was
primarily attributable to increased in-store sales and improved retail fuel margins in our U.S. and
Canadian retail operations, partially offset by higher selling expenses related mainly to retail
reorganization expenses and an increase in the Canadian dollar exchange rate relative to the U.S.
dollar.
Corporate Expenses and Other
General and administrative expenses, including corporate depreciation and amortization expense,
increased $44 million for the year ended December 31, 2007 compared to the year ended December 31,
2006. This increase was primarily due to 2007 executive retirement expenses, an increase in
employee compensation and benefits, including incentive compensation, a $13 million termination fee
paid in 2007 for the cancellation of our services agreement with NuStar Energy L.P., and increased
charitable contributions, partially offset by 2006 expenses attributable to Premcor headquarters
personnel that were not incurred during 2007.
Other income, net for the year ended December 31, 2007 included a $91 million pre-tax gain
related to a foreign currency exchange rate gain resulting from the repayment of a loan by a
foreign subsidiary. Other income, net for the year ended December 31, 2006 included a pre-tax
gain of $328 million related to the sale of our ownership interest in NuStar GP Holdings, LLC, as
discussed in Note 9 of Notes to Consolidated Financial Statements. Excluding these effects, other
income, net increased $54 million from 2006 to 2007 primarily due to increased interest income
related to our significantly higher cash balance during 2007.
Interest and debt expense increased primarily due to the issuance of $2.25 billion of notes in June
2007 to fund the accelerated share repurchase program (as discussed in Note 12 of Notes to
Consolidated Financial Statements), increased interest on tax liabilities, and reduced capitalized
interest due to a reduced balance of capital projects under construction.
Income tax expense decreased $450 million from 2006 to 2007 mainly as a result of lower income from
continuing operations before income tax expense. Our effective tax rate for the year ended
December 31, 2007 decreased from the year ended December 31, 2006 primarily due to an increase in
the percentage of pre-tax income contributed by the Aruba Refinery, the profits of which are
non-taxable in Aruba through December 31, 2010, combined with favorable tax law changes.
Income from discontinued operations, net of income tax expense, increased $493 million from the
year ended December 31, 2006 to the year ended December 31, 2007 due primarily to a pre-tax gain of
$827 million, or $426 million after tax, on the sale of the Lima Refinery in July 2007 combined
with a $67 million increase in net income from the operations of the Lima Refinery between the two
years. The increase in net income from the operations of the Lima Refinery was mainly attributable
to a 94% increase in the refinerys throughput margin per barrel, from $8.99 per barrel for the
year ended December 31, 2006 to $17.41 per barrel for the six months ended June 30, 2007, which
more than offset the effect of a decline in throughput volumes resulting from only six months of
operations in 2007 prior to its sale.
40
OUTLOOK
Based on current forward market indicators, we expect both refined product margins and sour crude
oil differentials for 2009 to be lower than the corresponding amounts reported in 2008. We expect
the current economic slowdown to unfavorably impact demand for refined products. Although gasoline
margins in the first quarter of 2009 have recovered somewhat from the negative margins experienced
in late 2008, gasoline margins are expected to remain under pressure until demand begins to
recover. Distillate margins are also expected to be unfavorably affected by reduced demand
attributable to the current economic recession. We believe that distillate margins will continue
to depend primarily on the pace of global economic activity and the rate at which new refining
capacity is brought online.
In regard to feedstocks, thus far in 2009, sour crude oil differentials have decreased from fourth
quarter 2008 levels and are expected to remain lower for the first half of 2009. Reduced overall
crude oil production by OPEC has caused a reduction in the supply of sour crude oil and a resulting
increase in the price of such crude oils relative to sweet crude oils. In light of the current and
expanding weakness in the U.S. and global economies, we expect 2009 will be a challenging year for
the refining industry and our company.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Year Ended December 31, 2008
Net cash provided by operating activities for the year ended December 31, 2008 was $3.0 billion
compared to $5.3 billion for the year ended December 31, 2007. The decrease in cash generated from
operating activities was due primarily to the decrease in operating income discussed above under
Results of Operations, after excluding the effect of the goodwill impairment loss included in the
2008 operating income that had no effect on cash. Changes in cash provided by or used for working
capital during the years ended December 31, 2008 and 2007 are shown in Note 16 of Notes to
Consolidated Financial Statements. Both receivables and accounts payable decreased in 2008 due to
a significant decrease in crude oil and refined product prices at December 31, 2008 compared to
such prices at the end of 2007. Receivables for 2008 also decreased due to the termination in the
first quarter of 2008 of certain agreements related to the sale of the Lima Refinery to Husky and
the timing of receivable collections at year-end 2007. The change in working capital for 2007
includes a $900 million decrease in the eligible trade receivables sold under our accounts
receivable sales facility as discussed below in the discussion of 2007 versus 2006 cash flows.
See the 2007 cash flow discussion below for information related to the cash flows of the
discontinued operations of the Lima Refinery.
The net cash generated from operating activities during the year ended December 31, 2008, combined
with $1.5 billion of available cash on hand and $463 million of proceeds from the sale of our Krotz
Springs Refinery, were used mainly to:
|
|
|
fund $3.2 billion of capital expenditures and deferred turnaround and catalyst costs; |
|
|
|
|
make an early redemption of our 9.5% senior notes for $367 million and scheduled debt
repayments of $7 million; |
|
|
|
|
purchase 23.0 million shares of our
common stock at a cost of $955 million; |
|
|
|
|
fund a $25 million contingent earn-out payment in connection with the acquisition of the
St. Charles Refinery, an $87 million acquisition of retail fuel sites, and a $57 million
acquisition primarily of an interest in a refined product pipeline; and |
|
|
|
|
pay common stock dividends of $299 million. |
41
Cash Flows for the Year Ended December 31, 2007
Net cash provided by operating activities for the year ended December 31, 2007 was $5.3 billion
compared to $6.3 billion for the year ended December 31, 2006. The decrease in cash generated from
operating activities was due primarily to the decrease in operating income discussed above under
Results of Operations and a $900 million decrease in the eligible trade receivables sold under
our accounts receivable sales facility, as discussed in Note 4 of Notes to Consolidated Financial
Statements. Other changes in cash provided by or used for working capital during the years ended
December 31, 2007 and 2006 are shown in Note 16 of Notes to Consolidated Financial Statements.
Both receivables and accounts payable increased in 2007 due to a significant increase in gasoline,
distillate, and crude oil prices at December 31, 2007 compared to such prices at the end of 2006.
Cash flows related to the discontinued operations of the Lima Refinery have been combined with the
cash flows from continuing operations within each category in the consolidated statement of cash
flows for each period presented. Cash provided by operating activities related to our discontinued
operations was $260 million and $215 million for the years ended December 31, 2007 and 2006,
respectively. Cash used in investing activities related to the Lima Refinery was $14 million and
$133 million for the years ended December 31, 2007 and 2006, respectively.
The net cash generated from operating activities during the year ended December 31, 2007, combined
with $2.2 billion of proceeds from the issuance of long-term notes, $2.4 billion of proceeds from
the sale of our Lima Refinery, a $311 million benefit from tax deductions in excess of recognized
stock-based compensation cost, and $159 million of proceeds from the issuance of common stock
related to our employee benefit plans, were used mainly to:
|
|
|
fund $2.8 billion of capital expenditures and deferred turnaround and catalyst costs; |
|
|
|
|
purchase 84.3 million shares of our common stock at a cost of $5.8 billion; |
|
|
|
|
make an early debt redemption of $183 million and scheduled debt repayments of
$280 million; |
|
|
|
|
fund capital contributions, net of distributions, of $209 million to the Cameron Highway
Oil Pipeline Company mainly to enable the joint venture to redeem all of its outstanding
debt; |
|
|
|
|
fund contingent earn-out payments in connection with the acquisition of the St. Charles
Refinery and the Delaware City Refinery of $50 million and $25 million, respectively; |
|
|
|
|
pay common stock dividends of $271 million; and |
|
|
|
|
increase available cash on hand by $874 million. |
Capital Investments
During the year ended December 31, 2008, we expended $2.8 billion for capital expenditures and
$408 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended
December 31, 2008 included $479 million of costs related to environmental projects.
In connection with our acquisition of the St. Charles Refinery in 2003, the seller was entitled to
receive payments in any of the seven years following this acquisition if certain average refining
margins during any of those years exceeded a specified level (see the discussion in Note 23 of
Notes to Consolidated Financial Statements). Payments due under this earn-out arrangement were
limited based on annual and aggregate limits. In January 2008, we made a $25 million earn-out
payment related to the St. Charles Refinery, which was the final payment based on the aggregate
limitation under that agreement. Subsequent to this payment, we have no further commitments with
respect to contingent earn-out agreements.
For 2009, we expect to incur approximately $2.7 billion for capital investments, including
approximately $2.2 billion for capital expenditures (approximately $635 million of which is for
environmental projects)
and approximately $490 million for deferred turnaround and catalyst costs. The capital expenditure
42
estimate excludes anticipated expenditures related to strategic acquisitions. We continuously
evaluate our capital budget and make changes as conditions warrant.
Krotz Springs Refinery Disposition
Effective July 1, 2008, we consummated the sale of our Krotz Springs Refinery to Alon Refining
Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. The sale resulted in a pre-tax
gain of $305 million, or $170 million after tax. Cash proceeds, net of certain costs related to
the sale, were $463 million, including approximately $135 million from the sale of working capital
to Alon primarily related to the sale of inventory by our marketing and supply subsidiary. In
addition to the cash consideration received, we also received contingent consideration in the form
of a three-year earn-out agreement based on certain product margins, which had a fair value of
$171 million as of July 1, 2008. We have hedged the risk of a decline in the referenced product
margins by entering into certain commodity derivative contracts. In addition, we entered into
various agreements with Alon as further described in Note 2 of Notes to Consolidated Financial
Statements.
Contractual Obligations
Our contractual obligations as of December 31, 2008 are summarized below (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
Thereafter |
|
Total |
|
Debt and capital
lease obligations |
|
$ |
315 |
|
|
$ |
39 |
|
|
$ |
424 |
|
|
$ |
765 |
|
|
$ |
495 |
|
|
$ |
4,619 |
|
|
$ |
6,657 |
|
Operating lease obligations |
|
|
397 |
|
|
|
272 |
|
|
|
174 |
|
|
|
84 |
|
|
|
51 |
|
|
|
257 |
|
|
|
1,235 |
|
Purchase obligations |
|
|
12,812 |
|
|
|
2,507 |
|
|
|
1,589 |
|
|
|
1,208 |
|
|
|
623 |
|
|
|
1,752 |
|
|
|
20,491 |
|
Other long-term liabilities |
|
|
|
|
|
|
163 |
|
|
|
150 |
|
|
|
150 |
|
|
|
149 |
|
|
|
1,549 |
|
|
|
2,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
13,524 |
|
|
$ |
2,981 |
|
|
$ |
2,337 |
|
|
$ |
2,207 |
|
|
$ |
1,318 |
|
|
$ |
8,177 |
|
|
$ |
30,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt and Capital Lease Obligations
Payments for debt and capital lease obligations in the table above reflect stated values and
minimum rental payments, respectively.
On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated
value. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to
certain of our other debt.
As of December 31, 2008, current portion of debt and capital lease obligations as reflected in
the consolidated balance sheet consisted primarily of $200 million related to our 3.5% notes that
matures in April 2009, $100 million of debt secured by certain of our accounts receivable that
matures in June 2009 (discussed below), and the remaining $9 million of our 5.125% Series 1997D
industrial revenue bonds that matures in April 2009.
We have an accounts receivable sales facility with a group of third-party entities and financial
institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. In June
2008, we amended the agreement to extend the maturity date from August 2008 to June 2009. As of
December 31, 2008, the amount of eligible receivables sold to the third-party entities and
financial institutions was $100 million; the proceeds from the sale are reflected as debt in our
consolidated balance sheet as of December 31, 2008. The amount outstanding as of December 31,
2008 was repaid in February 2009. Note 4 of Notes to Consolidated Financial Statements includes
additional discussion of this program.
Our 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 to
below investment
43
grade ratings by Moodys Investors Service and Standard & Poors Ratings Services,
the cost of borrowings under some of our bank credit facilities and other arrangements would
increase. As of December 31, 2008, all of our ratings on our senior unsecured debt are at or above
investment grade level as follows:
|
|
|
Rating Agency |
|
Rating |
|
Standard & Poors Ratings Services
|
|
BBB (stable outlook) |
Moodys Investors Service
|
|
Baa2 (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 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, retail
facilities and equipment, dock facilities, transportation equipment, and various facilities and
equipment used in the storage, transportation, production, and sale of refinery feedstocks and
refined products. Operating lease obligations include all operating leases that have initial or
remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be
received by us under subleases. The operating lease obligations reflected in the table above have
been reduced by related obligations that are included in other long-term liabilities.
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
included in the table above include both short-term 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. As of December 31, 2008, our short-term and long-term purchase
obligations decreased by $18.2 billion from the amount reported as of December 31, 2007. The
decrease is primarily attributable to lower crude oil and other feedstock prices at December 31,
2008 compared to December 31, 2007.
Other Long-term Liabilities
Our other long-term liabilities are described in Note 13 of Notes to Consolidated Financial
Statements. For purposes of reflecting amounts for other long-term liabilities in the table above,
we have made our best estimate of expected payments for each type of liability based on information
available as of December 31, 2008.
44
Other Commercial Commitments
As of December 31, 2008, our committed lines of credit were as follows:
|
|
|
|
|
|
|
Borrowing |
|
|
|
|
Capacity |
|
Expiration |
|
Letter of credit facility
|
|
$300 million
|
|
June 2009 |
Letter of credit facility
|
|
$275 million
|
|
July 2009 |
Revolving credit facility
|
|
$2.5 billion
|
|
November 2012 |
Canadian revolving credit facility
|
|
Cdn. $115 million
|
|
December 2012 |
In June 2008, we entered into a one-year committed revolving letter of credit facility under which
we may obtain letters of credit of up to $300 million. In July 2008, we entered into another
one-year committed revolving letter of credit facility under which we may obtain letters of credit
of up to $275 million. Both of these credit facilities support certain of our crude oil purchases.
We are being charged letter of credit issuance fees in connection with these letter of credit
facilities.
As of December 31, 2008, we had $201 million of letters of credit outstanding under uncommitted
short-term bank credit facilities, $431 million of letters of credit outstanding under our three
U.S. committed revolving credit facilities, and Cdn. $19 million of letters of credit outstanding
under our Canadian committed revolving credit facility. These letters of credit expire during 2009
and 2010.
Stock Purchase Programs
On February 28, 2008, our board of directors approved a new $3 billion common stock purchase
program. This program is in addition to the remaining amount under the $6 billion program
previously authorized. This new $3 billion program has no expiration date. As of December 31,
2008, we had made no purchases of our common stock under the new $3 billion program. As of
December 31, 2008, we have approvals under these stock purchase programs to purchase approximately
$3.5 billion of our common stock.
During 2008, we purchased 18.0 million shares of our common stock for $667 million under our
$6 billion common stock purchase program and 5.0 million shares for $288 million in connection with
the administration of our employee benefit plans. These purchases represented approximately 4% of
our outstanding shares of common stock as of December 31, 2008.
Pension Plan Funded Status
During 2008, we contributed $110 million to our qualified pension plans. Based on a 5.40% discount
rate and fair values of plan assets as of December 31, 2008, the fair value of the assets in our
qualified pension plans was equal to approximately 76% of the projected benefit obligation under
those plans as of the end of 2008. The fair value of the assets in our qualified pension plans was
in excess of the projected benefit obligation under those plans as of December 31, 2007. However,
due primarily to a significant decline in the fair value of the plan assets during 2008 resulting
from unfavorable economic and market conditions, the qualified pension plans were underfunded as of
December 31, 2008.
Although we have only $8 million of minimum required contributions to our Qualified Plans during
2009 under the Employee Retirement Income Security Act, we plan to contribute approximately
$130 million to our Qualified Plans during 2009. In January 2009, $50 million of this total
expected contribution was contributed to our main Qualified Plan.
Environmental Matters
As discussed in Note 24 of Notes to Consolidated Financial Statements, we are subject to extensive
federal, state, and local environmental laws and regulations, including those relating to the
discharge of materials into the environment, waste management, pollution prevention measures,
greenhouse gas
45
emissions, and
characteristics and composition of gasolines and distillates. Because environmental
laws and regulations are becoming more complex and stringent and new environmental laws and
regulations are continuously being enacted or proposed, the level of future expenditures required
for environmental matters could increase in the future. In addition, any major upgrades in any of
our refineries could require material additional expenditures to comply with environmental laws and
regulations.
Tax Matters
As discussed in Note 23 of Notes to Consolidated Financial Statements, we are subject to extensive
tax liabilities. New tax laws and regulations and changes in existing tax laws and regulations are
continuously being enacted or proposed that could result in increased expenditures for tax
liabilities in the future. Many of these liabilities are subject to periodic audits by the
respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits
may subject us to interest and penalties.
Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from
the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for
on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our
Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by
the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba
Refinery should not be subject to this turnover tax. Accordingly, no expense or liability has been
recognized in our consolidated financial statements with respect to this turnover tax on exports.
We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which
we are seeking to enforce our rights under the tax holiday and other agreements related to the
refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision
sometime later this year. We have also filed protests of these assessments through proceedings in
Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile
Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax
on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in
Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the
disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings.
Amounts deposited under this escrow agreement, which totaled $102 million as of December 31, 2008,
are reflected as restricted cash in our consolidated balance sheet.
In addition to the turnover tax described above, the GOA has also asserted other tax amounts
aggregating approximately $25 million related to dividends and other tax items. The GOA, through
the arbitration, is also now questioning the validity of the tax holiday generally, although the
GOA has never issued any formal assessment for profit tax at any time during the tax holiday
period. We believe that the provisions of our tax holiday agreement exempt us from all of these
taxes and, accordingly, no expense or liability has been recognized in our consolidated financial
statements. We are also challenging approximately $30 million in foreign exchange payments made to
the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons.
These taxes and assessments are also being addressed in the arbitration proceedings discussed
above.
Other
In July 2008, we entered into an agreement to participate as a prospective shipper on the 500,000
barrel-per-day expansion of the Keystone crude oil pipeline system, which is expected to be
completed by 2012. Once completed, the pipeline will enable crude oil to be transported from
Western Canada to the U.S. Gulf Coast at Port Arthur, Texas. In addition to our commitment to ship
crude oil through the pipeline, we have an option to acquire an equity interest in the Keystone
partnerships. We have also secured commitments from several Canadian oil producers to sell to us
heavy sour crude oil for shipment through the pipeline.
During the first quarter of 2007, our McKee Refinery was shut down due to a fire originating in its
propane deasphalting unit, resulting in business interruption losses for which we submitted claims
to our insurance
46
carriers under our insurance policies. We reached a settlement with the insurance carriers on our
claims, resulting in pre-tax income of approximately $100 million in the first quarter of 2008 that
was recorded as a reduction to cost of sales.
On January 25, 2008, our Aruba Refinery was shut down due to a fire in its vacuum unit. During the
second quarter, we completed the repairs and resumed full operations of the refinery. This
incident reduced our operating income for the year ended December 31, 2008.
In November 2007, we announced plans to explore strategic alternatives related to our Aruba
Refinery. We are continuing to pursue potential transactions for this refinery, which may include
the sale of the refinery.
Our refining and marketing 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.
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 have been issued that either have already been reflected in the
accompanying consolidated financial statements, or will become effective for our financial
statements at various dates in the future. The adoption of these pronouncements has not had, and
is not expected to have, a material effect on our consolidated financial statements.
CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with United States generally accepted
accounting principles requires management to make estimates and assumptions that affect the amounts
reported in the consolidated 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 sensitivity and judgment involved, as well as the impact on our
consolidated financial position and results of operations. We believe that all of our estimates
are reasonable.
Impairment of Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method
investments, and deferred tax assets) are required to be 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 only if the carrying amount of the asset is not recoverable
and exceeds its fair value.
47
Goodwill and intangible assets that have indefinite useful lives must be tested for impairment
annually or more frequently if events or changes in circumstances indicate that the asset might be
impaired. An impairment loss should be recognized if the carrying amount of the asset exceeds its
fair value. We evaluate our equity method investments for impairment when there is evidence that
we may not be able to recover the carrying amount of our investments or the investee is unable to
sustain an earnings capacity that justifies the carrying amount. A loss in the value of an
investment that is other than a temporary decline is recognized currently in earnings, and is based
on the difference between the estimated current fair value of the investment and its carrying
amount.
In order to test for recoverability, management 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. Due to the
significant subjectivity of the assumptions used to test for recoverability and to determine fair
value, changes in market conditions could result in significant impairment charges in the future,
thus affecting our earnings. Due to adverse changes in market conditions during the fourth quarter
of 2008, as discussed further below in our discussion of goodwill, we evaluated our significant
operating assets for potential impairment as of December 31, 2008, and we determined that the
carrying amount of each of these assets was recoverable. Our impairment evaluations are based on
assumptions that management deems to be reasonable. Providing sensitivity analysis if other
assumptions were used in performing the impairment evaluations is not practicable due to the
significant number of assumptions involved in the estimates.
In regard to goodwill, we have historically performed our goodwill impairment test as of October 1
of each year. However, during the fourth quarter of 2008, there were severe disruptions in the
capital and commodities markets that contributed to a significant decline in our common stock
price, thus causing our market capitalization to decline to a level substantially below our net
book value. Because a low market capitalization relative to net book value represents a key
indicator that goodwill may be impaired, we determined that goodwill needed to be evaluated for
impairment as of December 31, 2008 in addition to our normal annual testing date. As of the date
of this goodwill impairment evaluation, all of our goodwill was allocated among four reporting
units, namely each of the four geographic regions of our refining segment (the Gulf Coast,
Mid-Continent, Northeast, and West Coast regions). No goodwill was reported in our retail segment.
Goodwill impairment testing is comprised of two steps. The first step (step 1) is to compare the
estimated fair value of each reporting unit to its net book value, including any goodwill assigned
to that reporting unit. If the estimated fair value of a reporting unit is higher than its
recorded net book value, no impairment is deemed to exist and no further testing is required. If,
however, the estimated fair value of a reporting unit is less than its recorded net book value,
then the second step of the goodwill impairment test (step 2) is required to determine the amount
of the goodwill impairment loss, if any. In the second step, the estimated fair value derived for
the reporting unit in step 1 is deemed to represent the purchase price in a hypothetical
acquisition of that reporting unit. The fair values of each of the reporting units identifiable
assets and liabilities are determined as they would be in a purchase business combination, and the
excess of the deemed purchase price over the net fair value of all of the identifiable assets and
liabilities represents the implied fair value of the goodwill of that reporting unit. If the
carrying amount of that reporting units goodwill exceeds this implied fair value of goodwill, an
impairment loss is recognized in the amount of that excess to reduce the carrying amount of
goodwill to the implied fair value determined in this hypothetical purchase price allocation.
48
Because quoted market prices for our reporting units are not available, the impairment testing
rules required management to exercise its judgment to determine the estimated fair values of our
four reporting units for purposes of performing step 1 of the goodwill impairment test. Management
considered the cyclicality of the refining business in deriving the set of prices that were applied
to the anticipated charge and production volumes in each reporting unit. In determining the
present values of each reporting units cash flow streams, management utilized discount rates that
were commensurate with the risks involved in the assets. To this applicable discount rate,
management added a reasonable risk premium in order to consider the impact of volatility within the
refining industry and current tightness in the capital markets on an investors required rate of
return.
An important requirement related to this fair value determination process is to reconcile the sum
of the fair values determined for the various reporting units to our market capitalization. In
order to perform this reconciliation, we first determined a fair value for our retail segment using
an appropriate discount rate. Then we compared the sum of the fair values of the retail segment
and the four refining reporting units to our total enterprise value, with our market capitalization
determined based on our common stock price as of December 31, 2008. For this purpose, we also
added a control premium to our market capitalization, in recognition of the fact that an acquiring
entity generally is willing to pay more for equity ownership that gives it a controlling interest
than an individual investor would pay for shares that constitute less than a controlling interest.
The control premium that we added to our market capitalization represented a reasonable premium for
acquisitions in our industry. Because the enterprise value, including the control premium, was
comparable to the sum of the fair values determined above, we concluded that the assumptions
utilized to determine the fair values of our reporting units were reasonable. The computed fair
value of each of the reporting units was less than its net book value including goodwill, and
therefore the goodwill in each of the reporting units was potentially impaired.
We then applied step 2 of the goodwill impairment test to each of the reporting units, with the
fair value for each reporting unit derived in step 1 constituting the assumed purchase price in a
hypothetical acquisition of each of those reporting units. In allocating value to the property,
plant and equipment of each of the reporting units, we used current replacement costs for the
refineries that comprised each reporting unit and applied a depreciation factor based on historical
depreciation. We adjusted deferred income taxes based on the fair value assigned to property,
plant and equipment and reflected the fair value of inventory and other working capital included in
each reporting unit. Our calculations indicated that the net fair
value of each reporting units identifiable assets and
liabilities was significantly in excess of the deemed purchase
price, and therefore no implied fair value of goodwill existed in any of the four reporting units.
As a result, we concluded that an impairment of the entire amount of recorded goodwill was
required, which resulted in a $4.1 billion pre-tax goodwill impairment loss, or $4.0 billion after
tax, in the fourth quarter of 2008.
Environmental Liabilities
Our operations are subject to extensive environmental regulation by federal, state, and local
authorities relating primarily to discharge of materials into the environment, waste management,
and pollution prevention measures. Future legislative action and regulatory initiatives could
result in changes to required operating permits, additional remedial actions, or increased capital
expenditures and operating costs that cannot be assessed with certainty at this time.
Accruals for environmental liabilities are based on best estimates of probable undiscounted future
costs assuming currently available remediation 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
49
laws and regulations and their interpretation, additional information related to the extent and
nature of remediation efforts, and potential improvements in remediation technologies. An estimate
of the sensitivity to earnings for changes in those factors is not practicable due to the number of
contingencies that must be assessed, the number of underlying assumptions, and the wide range of
possible outcomes.
The balance of and changes in our accruals for environmental matters as of and for the years ended
December 31, 2008, 2007, and 2006 is included in Note 24 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. Changes in these assumptions are primarily influenced by factors outside our control.
For example, the discount rate assumption represents a yield curve comprised of various long-term
bonds that each receive one of the two highest ratings given by the recognized rating agencies as
of the end of each year, while the expected return on plan assets is based on a compounded return
calculated for us by an outside consultant using historical market index data with an asset
allocation of 65% equities and 35% bonds, which is representative of the asset mix in our qualified
pension plans. These assumptions can have a significant effect on the amounts reported in our
consolidated financial statements. For example, a 0.25% decrease in the assumptions related to the
discount rate or expected return on plan assets or a 0.25% 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, 2008 and net periodic benefit cost for the
year ending December 31, 2009 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
|
Increase in projected benefit obligation resulting from: |
|
|
|
|
|
|
|
|
Discount rate decrease |
|
$ |
66 |
|
|
$ |
15 |
|
Compensation rate increase |
|
|
28 |
|
|
|
|
|
Health care cost trend rate increase |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
Increase in expense resulting from: |
|
|
|
|
|
|
|
|
Discount rate decrease |
|
|
10 |
|
|
|
1 |
|
Expected return on plan assets decrease |
|
|
4 |
|
|
|
|
|
Compensation rate increase |
|
|
6 |
|
|
|
|
|
Health care cost trend rate increase |
|
|
|
|
|
|
1 |
|
Tax Liabilities
Our operations are subject to extensive tax liabilities, including federal, state, and foreign
income taxes. We are also subject to various transactional taxes such as excise, sales/use,
payroll, franchise, withholding, and ad valorem taxes. New tax laws and regulations and changes in
existing tax laws and regulations are continuously being enacted or proposed, and the
implementation of future legislative and regulatory tax initiatives could result in increased tax
liabilities that cannot be predicted at this time. In addition, we have received claims from
various jurisdictions related to certain tax matters. Tax liabilities include potential
assessments of penalty and interest amounts.
We record tax liabilities based on our assessment of existing tax laws and regulations. A
contingent loss related to a transactional 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
50
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.
Significant judgment is required in estimating the amount of 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. However, an estimate of the sensitivity to earnings that would
result from changes in the assumptions and estimates used in determining our tax liabilities is not
practicable due to the number of assumptions and tax laws involved, the various potential
interpretations of the tax laws, and the wide range of possible outcomes.
Legal Liabilities
A variety of claims have been made against us in various lawsuits. Although we have been
successful in defending litigation in the past, we cannot be assured of similar success in future
litigation due to the inherent uncertainty of litigation and the individual fact circumstances in
each case. We record a liability related to a loss contingency attributable to such legal matters
if we determine the loss to be both probable and 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. However, an
estimate of the sensitivity to earnings if other assumptions were used in recording our legal
liabilities is not practicable due to the number of contingencies that must be assessed and the
wide range of reasonably possible outcomes, both in terms of the probability of loss and the
estimates of such loss.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
We are exposed to market risks related to the volatility of crude oil and refined product prices,
as well as volatility in the price of natural gas used in our refining operations. In order to
reduce the risks of these price fluctuations, we use derivative commodity instruments to hedge a
portion of our refinery feedstock and refined product inventories and a portion of our unrecognized
firm commitments to purchase these inventories (fair value hedges). From time to time, we use
derivative commodity instruments to hedge the price risk of forecasted transactions such as
forecasted feedstock and product purchases, refined product sales, and natural gas purchases (cash
flow hedges). We also use derivative commodity instruments that do not receive hedge accounting
treatment to manage our exposure to price volatility on a portion of our refinery feedstock and
refined product inventories and on certain forecasted feedstock and product purchases, refined
product sales, and natural gas purchases. These derivative instruments are considered economic
hedges for which changes in their fair value are recorded currently in income. Finally, we enter
into derivative commodity instruments based on our fundamental and technical analysis of market
conditions that we mark to market for accounting purposes. See Derivative Instruments in Note 1
of Notes to Consolidated Financial Statements for a discussion of our accounting for the various
types of derivative transactions.
The types of instruments used in our hedging and trading activities described above include swaps,
futures, and options. Our positions in derivative commodity instruments are monitored and managed
on a daily basis by a risk control group to ensure compliance with our stated risk management
policy that has been approved by our board of directors.
51
The following tables provide information about our derivative commodity instruments as of
December 31, 2008 and 2007 (dollars in millions, except for the weighted-average pay and receive
prices as described below), including:
Fair
Value Hedges Fair value hedges are used to hedge certain recognized refining inventories (which had
a carrying amount of $4.4 billion and $3.8 billion as of December 31, 2008 and 2007, respectively, and
a fair value of $5.1 billion and $10.0 billion as of December 31, 2008 and 2007, respectively) and our
unrecognized firm commitments (i.e., binding agreements to purchase inventories in the future). The
gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the
offsetting loss or gain on the hedged item are recognized currently in income in the same period.
Cash
Flow Hedges Cash flow hedges are used to hedge certain forecasted feedstock and product purchases,
refined product sales, and natural gas purchases. The effective portion of the gain or loss on a
derivative instrument designated and qualifying as a cash flow hedge is initially reported as a
component of other comprehensive income and is then recorded in income in the period or periods
during which the hedged forecasted transaction affects income. The ineffective portion of the gain or
loss on the cash flow derivative instrument, if any, is recognized in income as incurred.
Economic Hedges Economic hedges are hedges not designated as fair value or cash flow hedges that are
used to:
|
|
|
manage price volatility in refinery feedstock and refined product inventories, |
|
|
|
|
manage price volatility in forecasted feedstock and product purchases, refined
product sales, and natural gas purchases; and |
|
|
|
|
manage price volatility in the referenced product margins associated with the Alon
earn-out
agreement as discussed in Note 2 of Notes to Consolidated Financial Statements. |
The derivative instruments related to economic hedges are recorded at fair value and changes in
the fair value of the derivative instruments are recognized currently in income.
Trading Activities These represent derivative commodity instruments held or issued for
trading purposes. The derivative instruments entered into by us for trading activities are
recorded at fair value and changes in the fair value of the derivative instruments are
recognized currently in income.
The following tables include only open positions at the end of the reporting period. Contract
volumes are presented in thousands of barrels (for crude oil and refined products) or in billions
of British thermal units (for natural gas). The weighted-average pay and receive prices represent
amounts per barrel (for crude oil and refined products) or amounts per million British thermal
units (for natural gas). Volumes shown for swaps represent notional volumes, which are used to
calculate amounts due under the agreements. For futures, the contract value represents the
contract price of either the long or short position multiplied by the derivative contract volume,
while the market value amount represents the period-end market price of the commodity being hedged
multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and
options represents the fair value of the derivative contract. The pre-tax fair value for swaps
represents the excess of the receive price over the pay price multiplied by the notional contract
volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market
value amount over the contract amount for long positions, or (ii) the excess of the contract amount
over the market value amount for short positions. Additionally, for futures and options, the
weighted-average pay price represents the contract price for long positions and the
weighted-average receive price represents the contract price for short positions. The
weighted-average pay price and weighted-average receive price for options represents their strike
price.
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
Wtd Avg |
|
Wtd Avg |
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
Contract |
|
Pay |
|
Receive |
|
Contract |
|
Market |
|
Fair |
|
|
Volumes |
|
Price |
|
Price |
|
Value |
|
Value |
|
Value |
|
Fair Value Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
6,904 |
|
|
|
N/A |
|
|
$ |
48.28 |
|
|
$ |
333 |
|
|
$ |
320 |
|
|
$ |
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
60,162 |
|
|
$ |
121.69 |
|
|
|
58.44 |
|
|
|
N/A |
|
|
|
(3,805 |
) |
|
|
(3,805 |
) |
2010 (crude oil and refined products) |
|
|
4,680 |
|
|
|
63.72 |
|
|
|
64.03 |
|
|
|
N/A |
|
|
|
1 |
|
|
|
1 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
60,162 |
|
|
|
62.38 |
|
|
|
129.80 |
|
|
|
N/A |
|
|
|
4,056 |
|
|
|
4,056 |
|
2010 (crude oil and refined products) |
|
|
4,680 |
|
|
|
76.32 |
|
|
|
78.69 |
|
|
|
N/A |
|
|
|
11 |
|
|
|
11 |
|
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
780 |
|
|
|
38.62 |
|
|
|
N/A |
|
|
|
30 |
|
|
|
27 |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economic Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
25,987 |
|
|
|
96.88 |
|
|
|
55.25 |
|
|
|
N/A |
|
|
|
(1,082 |
) |
|
|
(1,082 |
) |
2010 (crude oil and refined products) |
|
|
19,734 |
|
|
|
105.96 |
|
|
|
63.94 |
|
|
|
N/A |
|
|
|
(829 |
) |
|
|
(829 |
) |
2011 (crude oil and refined products) |
|
|
3,900 |
|
|
|
124.78 |
|
|
|
67.99 |
|
|
|
N/A |
|
|
|
(221 |
) |
|
|
(221 |
) |
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
25,931 |
|
|
|
59.65 |
|
|
|
106.81 |
|
|
|
N/A |
|
|
|
1,223 |
|
|
|
1,223 |
|
2010 (crude oil and refined products) |
|
|
19,734 |
|
|
|
72.18 |
|
|
|
121.96 |
|
|
|
N/A |
|
|
|
982 |
|
|
|
982 |
|
2011 (crude oil and refined products) |
|
|
3,900 |
|
|
|
74.08 |
|
|
|
136.66 |
|
|
|
N/A |
|
|
|
244 |
|
|
|
244 |
|
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
135,882 |
|
|
|
59.17 |
|
|
|
N/A |
|
|
|
8,040 |
|
|
|
7,319 |
|
|
|
(721 |
) |
2010 (crude oil and refined products) |
|
|
3,466 |
|
|
|
78.33 |
|
|
|
N/A |
|
|
|
271 |
|
|
|
240 |
|
|
|
(31 |
) |
2009 (natural gas) |
|
|
4,310 |
|
|
|
8.46 |
|
|
|
N/A |
|
|
|
36 |
|
|
|
24 |
|
|
|
(12 |
) |
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
135,091 |
|
|
|
N/A |
|
|
|
62.74 |
|
|
|
8,475 |
|
|
|
7,510 |
|
|
|
965 |
|
2010 (crude oil and refined products) |
|
|
3,692 |
|
|
|
N/A |
|
|
|
84.66 |
|
|
|
313 |
|
|
|
276 |
|
|
|
37 |
|
2009 (natural gas) |
|
|
4,310 |
|
|
|
N/A |
|
|
|
5.68 |
|
|
|
24 |
|
|
|
24 |
|
|
|
|
|
Options long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
57 |
|
|
|
60.64 |
|
|
|
N/A |
|
|
|
1 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trading Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
19,887 |
|
|
|
77.56 |
|
|
|
45.09 |
|
|
|
N/A |
|
|
|
(646 |
) |
|
|
(646 |
) |
2010 (crude oil and refined products) |
|
|
10,050 |
|
|
|
40.66 |
|
|
|
35.35 |
|
|
|
N/A |
|
|
|
(53 |
) |
|
|
(53 |
) |
2011 (crude oil and refined products) |
|
|
1,950 |
|
|
|
78.36 |
|
|
|
65.80 |
|
|
|
N/A |
|
|
|
(24 |
) |
|
|
(24 |
) |
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
16,084 |
|
|
|
56.44 |
|
|
|
97.17 |
|
|
|
N/A |
|
|
|
655 |
|
|
|
655 |
|
2010 (crude oil and refined products) |
|
|
5,850 |
|
|
|
64.19 |
|
|
|
73.12 |
|
|
|
N/A |
|
|
|
52 |
|
|
|
52 |
|
2011 (crude oil and refined products) |
|
|
1,950 |
|
|
|
68.06 |
|
|
|
80.59 |
|
|
|
N/A |
|
|
|
24 |
|
|
|
24 |
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
Wtd Avg |
|
Wtd Avg |
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
Contract |
|
Pay |
|
Receive |
|
Contract |
|
Market |
|
Fair |
|
|
Volumes |
|
Price |
|
Price |
|
Value |
|
Value |
|
Value |
|
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
24,039 |
|
|
$ |
71.70 |
|
|
|
N/A |
|
|
$ |
1,724 |
|
|
$ |
1,300 |
|
|
$ |
(424 |
) |
2010 (crude oil and refined products) |
|
|
956 |
|
|
|
84.12 |
|
|
|
N/A |
|
|
|
80 |
|
|
|
70 |
|
|
|
(10 |
) |
2009 (natural gas) |
|
|
200 |
|
|
|
5.79 |
|
|
|
N/A |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
21,999 |
|
|
|
N/A |
|
|
|
73.38 |
|
|
|
1,614 |
|
|
|
1,209 |
|
|
|
405 |
|
2010 (crude oil and refined products) |
|
|
956 |
|
|
|
N/A |
|
|
|
83.63 |
|
|
|
80 |
|
|
|
70 |
|
|
|
10 |
|
2009 (natural gas) |
|
|
200 |
|
|
|
N/A |
|
|
|
5.82 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Options
long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
100 |
|
|
|
30.00 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax fair value of open
positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
|
|
|
|
Wtd Avg |
|
Wtd Avg |
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
Contract |
|
Pay |
|
Receive |
|
Contract |
|
Market |
|
Fair |
|
|
Volumes |
|
Price |
|
Price |
|
Value |
|
Value |
|
Value |
|
Fair Value Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
68,873 |
|
|
$ |
97.69 |
|
|
|
N/A |
|
|
$ |
6,728 |
|
|
$ |
6,961 |
|
|
$ |
233 |
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
79,188 |
|
|
|
N/A |
|
|
$ |
96.89 |
|
|
|
7,673 |
|
|
|
8,005 |
|
|
|
(332 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
18,175 |
|
|
|
81.44 |
|
|
|
98.50 |
|
|
|
N/A |
|
|
|
310 |
|
|
|
310 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
18,175 |
|
|
|
102.55 |
|
|
|
86.25 |
|
|
|
N/A |
|
|
|
(296 |
) |
|
|
(296 |
) |
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
80,960 |
|
|
|
103.50 |
|
|
|
N/A |
|
|
|
8,379 |
|
|
|
8,596 |
|
|
|
217 |
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
73,735 |
|
|
|
N/A |
|
|
|
103.62 |
|
|
|
7,640 |
|
|
|
7,826 |
|
|
|
(186 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economic Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
12,012 |
|
|
|
33.16 |
|
|
|
39.48 |
|
|
|
N/A |
|
|
|
76 |
|
|
|
76 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
7,397 |
|
|
|
63.91 |
|
|
|
54.25 |
|
|
|
N/A |
|
|
|
(71 |
) |
|
|
(71 |
) |
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
77,902 |
|
|
|
96.20 |
|
|
|
N/A |
|
|
|
7,494 |
|
|
|
7,802 |
|
|
|
308 |
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
76,426 |
|
|
|
N/A |
|
|
|
96.18 |
|
|
|
7,351 |
|
|
|
7,663 |
|
|
|
(312 |
) |
Options long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
89 |
|
|
|
47.72 |
|
|
|
N/A |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trading Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
14,677 |
|
|
|
11.77 |
|
|
|
12.98 |
|
|
|
N/A |
|
|
|
18 |
|
|
|
18 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
15,952 |
|
|
|
12.47 |
|
|
|
11.56 |
|
|
|
N/A |
|
|
|
(15 |
) |
|
|
(15 |
) |
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
28,801 |
|
|
|
98.01 |
|
|
|
N/A |
|
|
|
2,823 |
|
|
|
2,923 |
|
|
|
100 |
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
28,766 |
|
|
|
N/A |
|
|
|
98.20 |
|
|
|
2,824 |
|
|
|
2,920 |
|
|
|
(96 |
) |
Options short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (crude oil and refined products) |
|
|
66 |
|
|
|
N/A |
|
|
|
49.00 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax fair value of open
positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(45 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
INTEREST RATE RISK
In general, our primary market risk exposure for changes in interest rates relates to our debt
obligations. We manage our exposure to changing interest rates through the use of a combination of
fixed-rate and floating-rate debt. In addition, we sometimes utilize interest rate swap agreements
to manage a portion of our exposure to changing interest rates by converting certain fixed-rate
debt to floating rate. These interest rate swap agreements are generally accounted for as fair
value hedges. The gain or loss on the derivative instrument and the gain or loss on the debt that
is being hedged are recorded in interest expense. The recorded amounts of the derivative
instrument and debt balances are adjusted accordingly. We had no interest rate derivative
instruments outstanding as of December 31, 2008 and 2007.
The following table provides information about our debt instruments (dollars in millions), the fair
value of which is sensitive to changes in interest rates. Principal cash flows and related
weighted-average interest rates by expected maturity dates are presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
Expected Maturity Dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There- |
|
|
|
|
|
Fair |
|
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
after |
|
Total |
|
Value |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate |
|
$ |
209 |
|
|
$ |
33 |
|
|
$ |
418 |
|
|
$ |
759 |
|
|
$ |
489 |
|
|
$ |
4,597 |
|
|
$ |
6,505 |
|
|
$ |
6,362 |
|
Average interest rate |
|
|
3.6 |
% |
|
|
6.8 |
% |
|
|
6.4 |
% |
|
|
6.9 |
% |
|
|
5.5 |
% |
|
|
6.8 |
% |
|
|
6.6 |
% |
|
|
|
|
Floating rate |
|
$ |
100 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
100 |
|
|
$ |
100 |
|
Average interest rate |
|
|
3.9 |
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
3.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
Expected Maturity Dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There- |
|
|
|
|
|
Fair |
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
after |
|
Total |
|
Value |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate |
|
$ |
356 |
|
|
$ |
209 |
|
|
$ |
33 |
|
|
$ |
418 |
|
|
$ |
759 |
|
|
$ |
5,086 |
|
|
$ |
6,861 |
|
|
$ |
7,109 |
|
Average interest rate |
|
|
9.4 |
% |
|
|
3.6 |
% |
|
|
6.8 |
% |
|
|
6.4 |
% |
|
|
6.9 |
% |
|
|
6.7 |
% |
|
|
6.8 |
% |
|
|
|
|
FOREIGN CURRENCY RISK
We enter into foreign currency exchange and purchase contracts to manage our exposure to exchange
rate fluctuations on transactions related to our Canadian operations. Changes in the fair value of
these contracts are recognized currently in income and are intended to offset the income effect of
translating the foreign currency denominated transactions that they are intended to hedge.
As of December 31, 2008, we had commitments to purchase $280 million of U.S. dollars. Our market
risk was minimal on these contracts, as they matured on or before January 30, 2009, resulting in a
2009 gain of $2 million.
56
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 Valeros internal control over financial
reporting as of December 31, 2008. In its evaluation, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control -
Integrated Framework. Management believes that as of December 31, 2008, 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 59 of this
report.
57
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
of Valero Energy Corporation and subsidiaries:
We have audited the accompanying consolidated balance sheets of Valero Energy Corporation and
subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated
statements of income, stockholders equity, cash flows and comprehensive income for each of the
years in the three-year period ended December 31, 2008. These consolidated financial statements are
the responsibility of the Companys 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, 2008 and 2007, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2008, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the PCAOB, the Companys internal control
over financial reporting as of December 31, 2008, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 26, 2009, expressed an unqualified opinion on the
effectiveness of the Companys internal control over financial reporting.
/s/ KPMG LLP
San Antonio, Texas
February 26, 2009
58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
of Valero Energy Corporation and subsidiaries:
We
have audited Valero Energy Corporation and subsidiaries (the
Companys) internal control over
financial reporting as of December 31, 2008, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Companys 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 Managements Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Companys 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 companys 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
companys 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 companys 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 and subsidiaries maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2008, based on criteria
established in Internal ControlIntegrated Framework issued by COSO.
59
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, 2008 and 2007, and the
related consolidated statements of income, stockholders equity, cash flows and comprehensive
income for each of the years in the three-year period ended December 31, 2008, and our report dated
February 26, 2009 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 26, 2009
60
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and temporary cash investments |
|
$ |
940 |
|
|
$ |
2,464 |
|
Restricted cash |
|
|
131 |
|
|
|
31 |
|
Receivables, net |
|
|
2,897 |
|
|
|
7,691 |
|
Inventories |
|
|
4,637 |
|
|
|
4,073 |
|
Income taxes receivable |
|
|
197 |
|
|
|
|
|
Deferred income taxes |
|
|
98 |
|
|
|
247 |
|
Prepaid expenses and other |
|
|
550 |
|
|
|
175 |
|
Assets held for sale |
|
|
|
|
|
|
306 |
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
9,450 |
|
|
|
14,987 |
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
28,103 |
|
|
|
25,599 |
|
Accumulated depreciation |
|
|
(4,890 |
) |
|
|
(4,039 |
) |
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
23,213 |
|
|
|
21,560 |
|
|
|
|
|
|
|
|
|
|
Intangible assets, net |
|
|
224 |
|
|
|
290 |
|
Goodwill |
|
|
|
|
|
|
4,019 |
|
Deferred charges and other assets, net |
|
|
1,530 |
|
|
|
1,866 |
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
34,417 |
|
|
$ |
42,722 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Current portion of debt and capital lease obligations |
|
$ |
312 |
|
|
$ |
392 |
|
Accounts payable |
|
|
4,446 |
|
|
|
9,587 |
|
Accrued expenses |
|
|
374 |
|
|
|
500 |
|
Taxes other than income taxes |
|
|
592 |
|
|
|
632 |
|
Income taxes payable |
|
|
|
|
|
|
499 |
|
Deferred income taxes |
|
|
485 |
|
|
|
293 |
|
Liabilities related to assets held for sale |
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
6,209 |
|
|
|
11,914 |
|
|
|
|
|
|
|
|
|
|
Debt and capital lease obligations, less current portion |
|
|
6,264 |
|
|
|
6,470 |
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
4,163 |
|
|
|
4,021 |
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities |
|
|
2,161 |
|
|
|
1,810 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value; 1,200,000,000 shares authorized;
627,501,593 and 627,501,593 shares issued |
|
|
6 |
|
|
|
6 |
|
Additional paid-in capital |
|
|
7,190 |
|
|
|
7,111 |
|
Treasury stock, at cost; 111,290,436 and 90,841,602 common shares |
|
|
(6,884 |
) |
|
|
(6,097 |
) |
Retained earnings |
|
|
15,484 |
|
|
|
16,914 |
|
Accumulated other comprehensive income (loss) |
|
|
(176 |
) |
|
|
573 |
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
15,620 |
|
|
|
18,507 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
34,417 |
|
|
$ |
42,722 |
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
61
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
Operating revenues (1) |
|
$ |
119,114 |
|
|
$ |
95,327 |
|
|
$ |
87,640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
107,429 |
|
|
|
81,645 |
|
|
|
73,863 |
|
Refining operating expenses |
|
|
4,555 |
|
|
|
4,016 |
|
|
|
3,622 |
|
Retail selling expenses |
|
|
768 |
|
|
|
750 |
|
|
|
719 |
|
General and administrative expenses |
|
|
559 |
|
|
|
638 |
|
|
|
598 |
|
Depreciation and amortization expense |
|
|
1,476 |
|
|
|
1,360 |
|
|
|
1,116 |
|
Gain on sale of Krotz Springs Refinery |
|
|
(305 |
) |
|
|
|
|
|
|
|
|
Goodwill impairment loss |
|
|
4,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
118,551 |
|
|
|
88,409 |
|
|
|
79,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
563 |
|
|
|
6,918 |
|
|
|
7,722 |
|
Equity in earnings of NuStar Energy L.P. |
|
|
|
|
|
|
|
|
|
|
45 |
|
Other income, net |
|
|
113 |
|
|
|
167 |
|
|
|
350 |
|
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(451 |
) |
|
|
(466 |
) |
|
|
(377 |
) |
Capitalized |
|
|
111 |
|
|
|
107 |
|
|
|
165 |
|
Minority interest in net income of NuStar GP Holdings, LLC |
|
|
|
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income tax expense |
|
|
336 |
|
|
|
6,726 |
|
|
|
7,898 |
|
Income tax expense |
|
|
1,467 |
|
|
|
2,161 |
|
|
|
2,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
|
(1,131 |
) |
|
|
4,565 |
|
|
|
5,287 |
|
Income from discontinued operations, net of income tax
expense |
|
|
|
|
|
|
669 |
|
|
|
176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(1,131 |
) |
|
|
5,234 |
|
|
|
5,463 |
|
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common stock |
|
$ |
(1,131 |
) |
|
$ |
5,234 |
|
|
$ |
5,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
(2.16 |
) |
|
$ |
8.08 |
|
|
$ |
8.65 |
|
Discontinued operations |
|
|
|
|
|
|
1.19 |
|
|
|
0.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(2.16 |
) |
|
$ |
9.27 |
|
|
$ |
8.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding (in millions) |
|
|
524 |
|
|
|
565 |
|
|
|
611 |
|
Earnings (loss) per common share assuming dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
(2.16 |
) |
|
$ |
7.72 |
|
|
$ |
8.36 |
|
Discontinued operations |
|
|
|
|
|
|
1.16 |
|
|
|
0.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(2.16 |
) |
|
$ |
8.88 |
|
|
$ |
8.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
common shares outstanding
assuming dilution (in millions) |
|
|
524 |
|
|
|
579 |
|
|
|
632 |
|
Dividends per common share |
|
$ |
0.57 |
|
|
$ |
0.48 |
|
|
$ |
0.30 |
|
|
|
|
Supplemental information: |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes excise taxes on sales by our U.S. retail system |
|
$ |
816 |
|
|
$ |
801 |
|
|
$ |
782 |
|
See Notes to Consolidated Financial Statements.
62
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(Millions of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
Other |
|
|
Preferred |
|
Common |
|
Paid-in |
|
Treasury |
|
Retained |
|
Comprehensive |
|
|
Stock |
|
Stock |
|
Capital |
|
Stock |
|
Earnings |
|
Income (Loss) |
|
Balance as of December 31, 2005 |
|
$ |
68 |
|
|
$ |
6 |
|
|
$ |
8,164 |
|
|
$ |
(196 |
) |
|
$ |
6,673 |
|
|
$ |
335 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,463 |
|
|
|
|
|
Dividends on common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(183 |
) |
|
|
|
|
Dividends on and accretion of preferred
stock |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
Conversion of preferred stock |
|
|
(69 |
) |
|
|
|
|
|
|
69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Credits from subsidiary stock sales, net
of tax |
|
|
|
|
|
|
|
|
|
|
101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense |
|
|
|
|
|
|
|
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares repurchased, net of shares issued,
in connection with employee stock
plans and other |
|
|
|
|
|
|
|
|
|
|
(636 |
) |
|
|
(1,200 |
) |
|
|
|
|
|
|
|
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29 |
|
Adjustment to initially apply
FASB Statement No. 158, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(99 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006 |
|
|
|
|
|
|
6 |
|
|
|
7,779 |
|
|
|
(1,396 |
) |
|
|
11,951 |
|
|
|
265 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,234 |
|
|
|
|
|
Dividends on common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
Stock-based compensation expense |
|
|
|
|
|
|
|
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares repurchased under $6 billion
common
stock purchase program |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,873 |
) |
|
|
|
|
|
|
|
|
Shares issued, net of shares repurchased,
in connection with employee stock
plans and other |
|
|
|
|
|
|
|
|
|
|
(757 |
) |
|
|
172 |
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
|
|
|
|
|
6 |
|
|
|
7,111 |
|
|
|
(6,097 |
) |
|
|
16,914 |
|
|
|
573 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,131 |
) |
|
|
|
|
Dividends on common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(299 |
) |
|
|
|
|
Stock-based compensation expense |
|
|
|
|
|
|
|
|
|
|
62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares repurchased under $6 billion
common
stock purchase program |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(667 |
) |
|
|
|
|
|
|
|
|
Shares repurchased, net of shares issued,
in connection with employee stock
plans and other |
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
(120 |
) |
|
|
|
|
|
|
|
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(749 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
$ |
|
|
|
$ |
6 |
|
|
$ |
7,190 |
|
|
$ |
(6,884 |
) |
|
$ |
15,484 |
|
|
$ |
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
63
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(1,131 |
) |
|
$ |
5,234 |
|
|
$ |
5,463 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense |
|
|
1,476 |
|
|
|
1,376 |
|
|
|
1,155 |
|
Goodwill impairment loss |
|
|
4,069 |
|
|
|
|
|
|
|
|
|
Gain on sale of Krotz Springs Refinery |
|
|
(305 |
) |
|
|
|
|
|
|
|
|
Gain on sale of Lima Refinery |
|
|
|
|
|
|
(827 |
) |
|
|
|
|
Gain on sale of NuStar GP Holdings, LLC |
|
|
|
|
|
|
|
|
|
|
(328 |
) |
Noncash interest expense and other income, net |
|
|
(76 |
) |
|
|
(10 |
) |
|
|
31 |
|
Stock-based compensation expense |
|
|
59 |
|
|
|
100 |
|
|
|
108 |
|
Deferred income tax expense (benefit) |
|
|
675 |
|
|
|
(131 |
) |
|
|
290 |
|
Changes in current assets and current liabilities |
|
|
(1,630 |
) |
|
|
(469 |
) |
|
|
(144 |
) |
Changes in deferred charges and credits and other operating activities, net |
|
|
(145 |
) |
|
|
(15 |
) |
|
|
(263 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
2,992 |
|
|
|
5,258 |
|
|
|
6,312 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(2,790 |
) |
|
|
(2,260 |
) |
|
|
(3,187 |
) |
Deferred turnaround and catalyst costs |
|
|
(408 |
) |
|
|
(518 |
) |
|
|
(569 |
) |
Proceeds from sale of Krotz Springs Refinery |
|
|
463 |
|
|
|
|
|
|
|
|
|
Proceeds from sale of Lima Refinery |
|
|
|
|
|
|
2,428 |
|
|
|
|
|
Proceeds from sale of NuStar GP Holdings, LLC |
|
|
|
|
|
|
|
|
|
|
880 |
|
Contingent payments in connection with acquisitions |
|
|
(25 |
) |
|
|
(75 |
) |
|
|
(101 |
) |
(Investment) return of investment in Cameron Highway Oil Pipeline Company, net |
|
|
24 |
|
|
|
(209 |
) |
|
|
(26 |
) |
Proceeds from minor dispositions of property, plant and equipment |
|
|
25 |
|
|
|
63 |
|
|
|
64 |
|
Minor acquisitions |
|
|
(144 |
) |
|
|
|
|
|
|
|
|
Other investing activities, net |
|
|
(7 |
) |
|
|
(11 |
) |
|
|
(32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(2,862 |
) |
|
|
(582 |
) |
|
|
(2,971 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-bank debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings |
|
|
|
|
|
|
2,245 |
|
|
|
|
|
Repayments |
|
|
(374 |
) |
|
|
(463 |
) |
|
|
(249 |
) |
Bank credit agreements: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings |
|
|
296 |
|
|
|
3,000 |
|
|
|
830 |
|
Repayments |
|
|
(296 |
) |
|
|
(3,000 |
) |
|
|
(830 |
) |
Termination of interest rate swaps |
|
|
|
|
|
|
|
|
|
|
(54 |
) |
Purchase of common stock for treasury |
|
|
(955 |
) |
|
|
(5,788 |
) |
|
|
(2,020 |
) |
Issuance of common stock in connection with employee benefit plans |
|
|
16 |
|
|
|
159 |
|
|
|
122 |
|
Benefit from tax deduction in excess of recognized stock-based compensation
cost |
|
|
9 |
|
|
|
311 |
|
|
|
206 |
|
Common and preferred stock dividends |
|
|
(299 |
) |
|
|
(271 |
) |
|
|
(184 |
) |
Other financing activities |
|
|
(4 |
) |
|
|
(24 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(1,607 |
) |
|
|
(3,831 |
) |
|
|
(2,188 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
(47 |
) |
|
|
29 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and temporary cash investments |
|
|
(1,524 |
) |
|
|
874 |
|
|
|
1,154 |
|
Cash and temporary cash investments at beginning of year |
|
|
2,464 |
|
|
|
1,590 |
|
|
|
436 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and temporary cash investments at end of year |
|
$ |
940 |
|
|
$ |
2,464 |
|
|
$ |
1,590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
64
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
Net income (loss) |
|
$ |
(1,131 |
) |
|
$ |
5,234 |
|
|
$ |
5,463 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment, net of
income tax expense of $-, $31, and $- |
|
|
(490 |
) |
|
|
250 |
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and other postretirement benefits: |
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) arising during the year, net of
income tax (expense) benefit of $227, $(56),
and $- |
|
|
(410 |
) |
|
|
80 |
|
|
|
(1 |
) |
Net (gain) loss reclassified into income,
net of income tax expense (benefit) of $-,
$(3), and $- |
|
|
(1 |
) |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on pension and other
postretirement benefits |
|
|
(411 |
) |
|
|
86 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on derivative instruments
designated and qualifying as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) arising during the year, net of
income
tax (expense) benefit of $(46), $6, and $(38) |
|
|
85 |
|
|
|
(11 |
) |
|
|
70 |
|
Net (gain) loss reclassified into income, net
of income
tax expense (benefit) of $(36), $9, and $15 |
|
|
67 |
|
|
|
(17 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on cash flow hedges |
|
|
152 |
|
|
|
(28 |
) |
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
|
(749 |
) |
|
|
308 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(1,880 |
) |
|
$ |
5,542 |
|
|
$ |
5,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
65
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
As used in this report, the terms Valero, we, us, or our may refer to Valero Energy
Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole. We are
an independent refining and marketing company and own and operate 16 refineries with a combined
total throughput capacity as of December 31, 2008 of approximately 3.0 million barrels per day. We
market our refined products through an extensive bulk and rack marketing network and approximately
5,800 retail and wholesale branded outlets in the United States and eastern Canada under various
brand names including Valero®, Diamond Shamrock®, Shamrock®,
Ultramar®, and Beacon®. Our operations are affected by:
|
|
|
company-specific factors, primarily refinery utilization rates and refinery maintenance
turnarounds; |
|
|
|
|
seasonal factors, such as the demand for refined products during the summer driving
season and heating oil during the winter season; and |
|
|
|
|
industry factors, such as movements in and the level of crude oil prices including the
effect of quality differential between grades of crude oil, the demand for and prices of
refined products, industry supply capacity, and competitor refinery maintenance
turnarounds. |
These consolidated financial statements include the accounts of Valero and subsidiaries in which
Valero has a controlling interest. Intercompany balances and transactions have been eliminated in
consolidation. Investments in significant noncontrolled entities are accounted for using the
equity method.
As discussed in Note 2, we sold our Krotz Springs Refinery and our Lima Refinery effective July 1,
2008 and July 1, 2007, respectively. The assets and liabilities of the Krotz Springs Refinery, as
well as inventory sold by our marketing and supply subsidiary associated with that transaction,
have been reclassified as held for sale as of December 31, 2007. See Note 2 for a discussion of
the presentation in the statements of income of the results of operations for these two refineries
for periods preceding the effective dates of the sales.
On July 19, 2006, we sold a 40.6% interest in NuStar GP Holdings, LLC (formerly Valero GP Holdings,
LLC), which indirectly owned the general partner interest, incentive distribution rights, and a
21.4% limited partner interest in NuStar Energy L.P. (formerly Valero L.P.) On December 22, 2006,
we sold our remaining interest in NuStar GP Holdings, LLC. These financial statements consolidate
NuStar GP Holdings, LLC through December 21, 2006, with net income attributable to the 40.6%
interest held by public unitholders from July 19, 2006 through December 21, 2006 presented as a
minority interest in the consolidated statement of income. See Note 9 under Sale of NuStar GP
Holdings, LLC for a discussion of the sale of NuStar GP Holdings, LLC.
The term UDS Acquisition refers to the merger of Ultramar Diamond Shamrock Corporation (UDS) into
Valero effective December 31, 2001. The term Premcor Acquisition refers to the merger of Premcor
Inc. (Premcor) into Valero effective September 1, 2005.
66
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Hierarchy of Generally Accepted Accounting Principles
In May 2008, the Financial Accounting Standards Board (FASB) issued Statement No. 162, The
Hierarchy of Generally Accepted Accounting Principles. Statement No. 162 identifies the sources
of accounting principles and the framework for selecting the principles used in the preparation of
financial statements that are presented in conformity with United States generally accepted
accounting principles (GAAP). Statement No. 162 was effective November 15, 2008. The adoption of
Statement No. 162 has not affected our financial position or results of operations.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires our management to make
estimates and assumptions that affect the amounts reported in the consolidated financial statements
and accompanying notes. Actual results could differ from those estimates. On an ongoing basis,
management reviews its estimates based on currently available information. Changes in facts and
circumstances may result in revised estimates.
Cash and Temporary Cash Investments
Our temporary cash investments are highly liquid, low-risk debt instruments that have a maturity of
three months or less when acquired. Cash and temporary cash investments exclude cash that is not
available to us due to restrictions related to its use. Such amounts are segregated in the
consolidated balance sheets in restricted cash as described in Note 3.
Inventories
Inventories are carried at the lower of cost or market. The cost of refinery feedstocks purchased
for processing and refined products are determined under the last-in, first-out (LIFO) method using
the dollar-value LIFO method, with any increments valued based on average purchase prices during
the year. The cost of feedstocks and products purchased for resale and the cost of materials,
supplies, and convenience store merchandise are determined principally under the weighted-average
cost method.
Property, Plant and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs
allocable to construction and property purchases, are recorded at cost.
The costs of minor property units (or components of property units), net of salvage value, retired
or abandoned are charged or credited to accumulated depreciation under the composite method of
depreciation. Gains or losses on sales or other dispositions of major units of property are
recorded in income and are reported in depreciation and amortization expense in the consolidated
statements of income, except gains or losses on dispositions of certain property, plant and
equipment that are reported on a separate line item due to materiality.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the
estimated useful lives of the related facilities primarily using the composite method of
depreciation. Leasehold improvements and assets acquired under capital leases are amortized using
the straight-line method over the shorter of the lease term or the estimated useful life of the
related asset.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets
acquired less liabilities assumed. Intangible assets are assets that lack physical substance
(excluding financial
67
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
assets). Goodwill acquired in a business combination and intangible assets
with indefinite useful lives are not amortized and intangible assets with finite useful lives are
amortized on a straight-line basis over 1 to 40 years. Goodwill and intangible assets not subject
to amortization are tested for impairment annually or
more frequently if events or changes in circumstances indicate the asset might be impaired. We use
October 1 of each year as our valuation date for annual impairment testing purposes. See
Note 8.
Deferred Charges and Other Assets
Deferred charges and other assets, net include the following:
|
|
|
refinery turnaround costs, which are incurred in connection with planned major
maintenance activities at our refineries and which are deferred when incurred and amortized
on a straight-line basis over the period of time estimated to lapse until the next
turnaround occurs; |
|
|
|
|
fixed-bed catalyst costs, representing the cost of catalyst that is changed out at
periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed
function, which are deferred when incurred and amortized on a straight-line basis over the
estimated useful life of the specific catalyst; |
|
|
|
|
investments in entities that we do not control; and |
|
|
|
|
other noncurrent assets such as long-term investments, convenience store dealer
incentive programs, pension plan assets, debt issuance costs, and various other costs. |
We evaluate our equity method investments for impairment when there is evidence that we may not be
able to recover the carrying amount of our investments or the investee is unable to sustain an
earnings capacity that justifies the carrying amount. A loss in the value of an investment that is
other than a temporary decline is recognized currently in earnings, and is based on the difference
between the estimated current fair value of the investment and its carrying amount. We believe
that the carrying amounts of our equity method investments as of December 31, 2008 are recoverable.
Impairment and Disposal of Long-Lived Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, equity method
investments, and deferred tax assets) are tested for recoverability whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. A long-lived asset is not
recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to
result from its use and eventual disposition. If a long-lived asset is not recoverable, an
impairment loss is recognized in an amount by which its carrying amount exceeds its fair value,
with fair value determined based on discounted estimated net cash flows. We believe that the
carrying amounts of our long-lived assets as of December 31, 2008 are recoverable.
Taxes Other than Income Taxes
Taxes other than income taxes includes primarily liabilities for ad valorem, excise, sales and
use, and payroll taxes.
Income Taxes
Income taxes are accounted for under the asset and liability method. Under this method, deferred
tax assets and liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred amounts are measured using enacted tax rates expected to
apply to taxable income in the year those temporary differences are expected to be recovered or
settled.
68
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes -
an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprises financial statements in accordance with
FASB Statement No. 109, Accounting for Income Taxes, by prescribing a recognition threshold and
measurement attribute for the financial statement recognition and measurement of a tax position
taken or expected to be
taken in a tax return. If a tax position is more likely than not to be sustained upon examination,
then an enterprise would be required to recognize in its financial statements the largest amount of
benefit that is greater than 50% likely of being realized upon ultimate settlement. As discussed
in Note 19, the adoption of FIN 48 effective January 1, 2007 did
not materially affect our financial position or results of operations.
We have elected to classify any interest expense and penalties related to the underpayment of
income taxes in income tax expense in our consolidated statements of income.
Asset Retirement Obligations
We record a liability, which is referred to as an asset retirement obligation, at fair value for
the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which
is generally when the asset is purchased, constructed, or leased. We record the liability when we
have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the
fair value of the liability can be made. If a reasonable estimate cannot be made at the time the
liability is incurred, we record the liability when sufficient information is available to estimate
the liabilitys fair value.
We have asset retirement obligations with respect to certain of our refinery assets due to various
legal obligations to clean and/or dispose of various component parts of each refinery at the time
they are retired. However, these component parts can be used for extended and indeterminate
periods of time as long as they are properly maintained and/or upgraded. It is our practice and
current intent to maintain our refinery assets and continue making improvements to those assets
based on technological advances. As a result, we believe that our refineries have indeterminate
lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon
which we would retire refinery assets cannot reasonably be estimated at this time. When a date or
range of dates can reasonably be estimated for the retirement of any component part of a refinery,
we estimate the cost of performing the retirement activities and record a liability for the fair
value of that cost using established present value techniques.
We also have asset retirement obligations for the removal of underground storage tanks (USTs) for
refined products at owned and leased retail locations. There is no legal obligation to remove USTs
while they remain in service. However, environmental laws require that unused USTs be removed
within certain periods of time after the USTs no longer remain in service, usually one to two years
depending on the jurisdiction in which the USTs are located. We have estimated that USTs at our
owned retail locations will not remain in service after 25 years of use and that we will have an
obligation to remove those USTs at that time. For our leased retail locations, our lease
agreements generally require that we remove certain improvements, primarily USTs and signage, upon
termination of the lease. While our lease agreements typically contain options for multiple
renewal periods, we have not assumed that such leases will be renewed for purposes of estimating
our obligation to remove USTs and signage.
Foreign Currency Translation
The functional currencies of our Canadian and Aruban operations are the Canadian dollar and the
Aruban florin, respectively. The translation of the Canadian operations into U.S. dollars is
computed for balance
69
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
sheet accounts using exchange rates in effect as of the balance sheet date and
for revenue and expense accounts using the weighted-average exchange rates during the year.
Adjustments resulting from this translation are reported in accumulated other comprehensive income
(loss). The value of the Aruban florin is fixed to the U.S. dollar at 1.79 Aruban florins to one
U.S. dollar. The translation of the Aruban operations into U.S. dollars is computed based on this
fixed exchange rate for both balance sheet and income statement accounts. As a result, there are
no adjustments resulting from this translation reported in accumulated other comprehensive income
(loss).
Revenue Recognition
Revenues for products sold by both the refining and retail segments are recorded upon delivery of
the products to our customers, which is the point at which title to the products is transferred,
and when payment has either been received or collection is reasonably assured. Revenues for
services are recorded when the services have been provided.
In June 2006, the FASB ratified its consensus on Emerging Issues Task Force (EITF) Issue No. 06-3,
How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in
the Income Statement (That Is, Gross versus Net Presentation) (EITF No. 06-3). The scope of EITF
No. 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or
subsequent to a revenue-producing transaction between a seller and a customer. For taxes within
the scope of this issue that are significant in amount, the consensus requires the following
disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes
reflected gross in the income statement on an interim and annual basis for all periods presented.
The disclosure of those taxes can be provided on an aggregate basis. We adopted the consensus
effective January 1, 2007. We present excise taxes on sales by our U.S. retail system on a gross
basis with supplemental information regarding the amount of such taxes included in revenues
provided in a footnote on the face of the income statement. All other excise taxes are presented
on a net basis in the income statement.
We enter into certain purchase and sale arrangements with the same counterparty that are deemed to
be made in contemplation of one another. Commencing January 1, 2006, the date of our adoption of
EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty,
we combine these transactions and, as a result, revenues and cost of sales are not recognized in
connection with these arrangements.
We also enter into refined product exchange transactions to fulfill sales contracts with our
customers by accessing refined products in markets where we do not operate our own refinery. These
refined product exchanges are accounted for as exchanges of non-monetary assets, and no revenues
are recorded on these transactions.
Product Shipping and Handling Costs
Costs incurred for shipping and handling of products are included in cost of sales in the
consolidated statements of income.
Environmental Matters
Liabilities for future remediation costs are recorded when environmental assessments and/or
remedial efforts are probable and the costs can be reasonably estimated. Other than for
assessments, the timing and magnitude of these accruals generally are based on the completion of
investigations or other studies or a commitment to a formal plan of action. Environmental
liabilities are based on best estimates of probable
70
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. Amounts recorded for environmental liabilities have not been
reduced by possible recoveries from third parties.
Derivative Instruments
All derivative instruments are recorded in the balance sheet as either assets or liabilities
measured at their fair values. When we enter into a derivative instrument, it is designated as a
fair value hedge, a cash flow hedge, an economic hedge, or a trading activity. The gain or loss on
a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting
loss or gain on the hedged item attributable to the hedged risk, are recognized currently in income
in the same period. The effective portion of the gain or loss on a derivative instrument
designated and qualifying as a cash flow hedge is initially reported
as a component of other comprehensive income and is then recorded in income in the period or
periods during which the hedged forecasted transaction affects income. The ineffective portion of
the gain or loss on the cash flow derivative instrument, if any, is recognized in income as
incurred. For our economic hedging relationships (hedges not designated as fair value or cash flow
hedges) and for derivative instruments entered into by us for trading purposes, the derivative
instrument is recorded at fair value and changes in the fair value of the derivative instrument are
recognized currently in income. Income effects of commodity derivative instruments, other than
certain contracts related to an earn-out agreement discussed in Notes 2 and 17, are recorded in cost of sales while income effects of interest rate swaps (if
applicable) are recorded in interest and debt expense.
In September 2008, the FASB issued Staff Position No. FAS 133-1 and FIN 45-4, Disclosures about
Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB
Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161
(FSP No. FAS 133-1 and FIN 45-4). FSP No. FAS 133-1 and FIN 45-4 amends FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers
of credit derivatives, including those embedded in hybrid instruments. FSP No. FAS 133-1 and
FIN 45-4 also amends FASB Interpretation No. 45, Guarantors Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require
disclosure about the current status of the payment/performance risk of a guarantee. Additionally,
FSP No. FAS 133-1 and FIN 45-4 clarifies the FASBs intent that disclosures required by FASB
Statement No. 161, Disclosures about Derivatives and Hedging Activities, should be provided for
any reporting period beginning after November 15, 2008. The provisions of FSP No. FAS 133-1 and
FIN 45-4 that amend Statement No. 133 and Interpretation No. 45 are effective for fiscal years, and
interim periods within those fiscal years, ending after November 15, 2008. Since FSP No. FAS 133-1
and FIN 45-4 only affects disclosure requirements, the adoption of FSP No. FAS 133-1 and FIN 45-4
effective December 31, 2008 has not affected our financial position or results of operations.
Financial Instruments
Our financial instruments include cash and temporary cash investments, restricted cash,
receivables, payables, debt, capital lease obligations, commodity derivative contracts, and foreign
currency derivative contracts. The estimated fair values of these financial instruments
approximate their carrying amounts as reflected in the consolidated balance sheets, except for
certain debt as discussed in Note 12. The fair values of our debt,
commodity derivative contracts, and foreign currency derivative contracts were estimated primarily
based on year-end quoted market prices.
71
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In February 2006, the FASB issued Statement No. 155, Accounting for Certain Hybrid Financial
Instruments, which amends Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities, and Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities. This statement improves the financial reporting of certain hybrid
financial instruments and simplifies the accounting for these instruments. In particular,
Statement No. 155 (i) permits fair value remeasurement for any hybrid financial instrument that
contains an embedded derivative that otherwise would require bifurcation, (ii) clarifies which
interest-only and principal-only strips are not subject to the requirements of Statement No. 133,
(iii) establishes a requirement to evaluate interests in securitized financial assets to identify
interests that are freestanding derivatives or that are hybrid financial instruments that contain
an embedded derivative requiring bifurcation, (iv) clarifies that concentrations of credit risk in
the form of subordination are not embedded derivatives, and (v) amends Statement No. 140 to
eliminate the prohibition on a qualifying special-purpose entity holding a derivative financial
instrument that pertains to a beneficial interest other than another derivative financial
instrument. The adoption of Statement No. 155 effective January 1, 2007 did not affect our
financial position or results of operations.
In March 2006, the FASB issued Statement No. 156, Accounting for Servicing of Financial Assets,
which amends Statement No. 140. Statement No. 156 requires the initial recognition at fair value
of a servicing asset or servicing liability when an obligation to service a financial asset is
undertaken by entering into a servicing contract. The adoption of Statement No. 156 effective
January 1, 2007 did not affect our financial position or results of operations.
In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities Including an Amendment of FASB Statement No. 115. Statement No. 159
permits entities to choose to measure many financial instruments and certain other items at fair
value that are not currently required to be measured at fair value. The adoption of Statement
No. 159 effective January 1, 2008 did not materially affect our financial position or results of
operations.
Fair Value Measurements
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements. Statement No. 157
defines fair value, establishes a framework for measuring fair value under GAAP, and expands
disclosures about fair value measures, but does not require any new fair value measurements. We
adopted Statement No. 157 effective January 1, 2008, with the exceptions allowed under FASB Staff
Position No. FAS 157-2 (FSP No. FAS 157-2) (further described under New Accounting
Pronouncements"), the adoption of which did not affect our financial position or results of
operations but did result in additional required disclosures, which are provided in Note 17.
In October 2008, the FASB issued Staff Position No. FAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active (FSP No. FAS 157-3).
FSP No. FAS 157-3 applies to financial assets within the scope of accounting pronouncements that
require or permit fair value measurements in accordance with Statement No. 157. FSP No. FAS 157-3
clarifies the application of Statement No. 157 in a market that is not active and provides an
example to illustrate key considerations in determining the fair value of a financial asset when
the market for that financial asset is not active. We adopted FSP No. FAS 157-3 effective
October 10, 2008 and applied its provisions to our financial statements commencing in the third
quarter of 2008. The adoption of FSP No. FAS 157-3 has not materially affected our financial
position or results of operations.
72
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Earnings per Common Share
Earnings per common share is computed by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding for the year. Earnings per common share
assuming dilution reflects the potential dilution of our outstanding stock options and nonvested
shares granted to employees in connection with our stock compensation plans, as well as the 2%
mandatory convertible preferred stock prior to its conversion as discussed in Note 14. In addition, see Notes 14 and 15 for a discussion of an accelerated share repurchase program during 2007 and its
effect on earnings per common share assuming dilution for the year ended December 31, 2007. Common
equivalent shares were excluded from the computation of diluted earnings per share for the year
ended December 31, 2008 because the effect of including such shares would be anti-dilutive.
Comprehensive Income
Comprehensive income consists of net income (loss) and other gains and losses affecting
stockholders equity that, under GAAP, are excluded from net income (loss), including foreign
currency translation adjustments, gains and losses related to certain derivative contracts, and
gains or losses, prior service
costs or credits, and transition assets or obligations associated with pension or other
postretirement benefits that have not been recognized as components of net periodic benefit cost.
Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued Statement No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans, which amends Statement No. 87, Employers Accounting for
Pensions, Statement No. 88, Employers Accounting for Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination Benefits, Statement No. 106, Employers Accounting for
Postretirement Benefits Other Than Pensions, Statement No. 132 (revised 2003), Employers
Disclosures about Pensions and Other Postretirement Benefits, and other related accounting
literature.
Statement No. 158 requires an employer to recognize the overfunded or underfunded status of a
defined benefit postretirement plan as an asset or a liability in the statement of financial
position and to recognize changes in that funded status through comprehensive income in the year
the changes occur. This statement also requires an employer to measure the funded status of a plan
as of the date of the employers year-end statement of financial position. We adopted the funded
status recognition and related disclosure requirements of Statement No. 158 as of December 31,
2006, the adoption of which did not materially affect our financial position or results of
operations in 2006. See Note 21 for information regarding the
funded status of our defined benefit plans as of December 31, 2008 and 2007.
Stock-Based Compensation
Effective January 1, 2006, we adopted Statement No. 123 (revised 2004), Share-Based Payment
(Statement No. 123(R)), which requires the expensing of the fair value of stock options. We
adopted the fair value recognition provisions of Statement No. 123(R) using the modified
prospective application. Accordingly, we recognize compensation expense for all newly granted
stock options and stock options modified, repurchased, or cancelled on or after January 1, 2006.
Compensation expense for stock options granted on or after January 1, 2006 is being recognized on a
straight-line basis. In addition, compensation cost for the unvested portion of stock options and
other awards that were outstanding as of January 1, 2006 is being recognized over the remaining
vesting period based on the fair value at date of grant and applying the attribution approach
utilized in determining the pro forma effect of expensing stock options that was required for
periods prior to the effective date of Statement No. 123(R). Our total stock-based compensation
expense recognized for the years ended December 31, 2008, 2007, and 2006 was
73
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$38 million, net of
tax benefits of $21 million, $65 million, net of tax benefits of $35 million, and $70 million, net
of tax benefits of $38 million, respectively.
Under our employee stock compensation plans, certain awards of stock options and restricted stock
provide that employees vest in the award when they retire or will continue to vest in the award
after retirement over the nominal vesting period established in the award. Upon the adoption of
Statement No. 123(R), we changed our method of recognizing compensation cost for new grants that
have retirement-eligibility provisions from recognizing such costs over the nominal vesting period
to the non-substantive vesting period approach. Under the non-substantive vesting period approach,
compensation cost is recognized immediately for awards granted to retirement-eligible employees or
over the period from the grant date to the date retirement eligibility is achieved if that date is
expected to occur during the nominal vesting period. If the non-substantive vesting period
approach had been used by us for awards granted prior to January 1, 2006, net income (loss)
applicable to common stock and net income (loss) would have increased by $2 million, $4 million,
and $4 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Statement No. 123(R) also requires the benefits of tax deductions in excess of recognized
stock-based
compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as
previously required. While we cannot estimate the specific magnitude of this change on future cash
flows because it depends on, among other things, when employees exercise stock options, the cash
flows recognized in financing activities for such excess tax deductions were $9 million,
$311 million, and $206 million for the years ended December 31, 2008, 2007, and 2006, respectively.
Sales of Subsidiary Stock
Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 51, Accounting for Sales of
Stock by a Subsidiary (SAB 51), provides guidance on accounting for the effect of issuances of a
subsidiarys stock on the parents investment in that subsidiary. SAB 51 allows registrants to
elect an accounting policy of recording such increases or decreases in a parents investment
(SAB 51 credits or charges, respectively) either in income or in stockholders equity. In
accordance with the election provided in SAB 51, we adopted a policy of recording such SAB 51
credits or charges directly to additional paid-in capital in stockholders equity. As further
discussed in Note 9, we recognized in 2006 certain SAB 51 credits
related to our investment in NuStar Energy L.P. under this policy.
New Accounting Pronouncements
FSP No. FAS 157-2
In February 2008, the FASB issued Staff Position No. FAS 157-2, which delayed the effective date of
Statement No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in the financial statements on a recurring basis (at least
annually), until fiscal years beginning after November 15, 2008. The exceptions apply to the
following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business
combination; impaired property, plant and equipment; goodwill; and the initial recognition of the
fair value of asset retirement obligations and restructuring costs. The implementation of
Statement No. 157 for these assets and liabilities effective January 1, 2009 has not had a material
effect on our financial position or results of operations.
FASB Statement No. 141 (revised 2007)
In December 2007, the FASB issued Statement No. 141 (revised 2007), Business Combinations
(Statement No. 141(R)). This statement improves the financial reporting of business combinations
and
74
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
clarifies the accounting for these transactions. The provisions of Statement No. 141(R) are to
be applied prospectively to business combinations with acquisition dates on or after the beginning
of an entitys fiscal year that begins on or after December 15, 2008, with early adoption
prohibited. Due to its application to future acquisitions, the adoption of Statement No. 141(R)
effective January 1, 2009 has not had any immediate effect on our financial position or results of
operations.
FASB Statement No. 160
In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51. Statement No. 160 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after December 15, 2008.
This statement provides guidance for the accounting and reporting of noncontrolling interests,
changes in controlling interests, and the deconsolidation of subsidiaries. In addition, Statement
No. 160 amends FASB Statement No. 128, Earnings per Share, to specify the computation,
presentation, and disclosure requirements for earnings per share if an entity has one or more
noncontrolling interests. The adoption of Statement No. 160 effective January 1, 2009 is not
expected to materially affect our financial position or results of operations.
FASB Statement No. 161
In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and
Hedging Activities. Statement No. 161 establishes, among other things, the disclosure
requirements for derivative instruments and for hedging activities. This statement requires
qualitative disclosures about objectives and strategies for using derivatives, quantitative
disclosures about fair value amounts of and gains and losses on derivative instruments, and
disclosures about contingent features related to credit risk in derivative agreements. Statement
No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning
after November 15, 2008. Since Statement No. 161 only affects disclosure requirements, the
adoption of Statement No. 161 effective January 1, 2009 has not affected our financial position or
results of operations.
FSP No. EITF 03-6-1
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities (FSP No. EITF 03-6-1).
FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are
participating securities prior to vesting and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two-class method described in Statement No.
128. FSP No. EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal
years, beginning after December 15, 2008; early adoption is not permitted. The adoption of
FSP No. EITF 03-6-1 effective January 1, 2009 is not expected to materially affect our calculation
of earnings per common share.
EITF Issue No. 08-6
In November 2008, the FASB ratified its consensus on EITF Issue No. 08-6, Equity Method Investment
Accounting Considerations (EITF No. 08-6). EITF No. 08-6 applies to all investments accounted for
under the equity method and provides guidance regarding (i) initial measurement of an equity
investment, (ii) recognition of other-than-temporary impairment of an equity method investment,
including any impairment charge taken by the investee, and (iii) accounting for a change in
ownership level or degree of influence on an investee. The consensus is effective for fiscal years
beginning on or after December 15, 2008, and interim periods within those fiscal years. EITF
No. 08-6 is to be applied prospectively and earlier application is not permitted. Due to its
application to future equity method investments, the
75
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
adoption of EITF No. 08-6 effective January 1,
2009 has not had any immediate effect on our financial position or results of operations.
FSP No. FAS 132(R)-1
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers Disclosures about
Postretirement Benefit Plan Assets (FSP No. FAS 132(R)-1). FSP No. FAS 132(R)-1 amends FASB
Statement No. 132 (revised 2003), Employers Disclosures about Pensions and Other Postretirement
Benefits, to provide guidance on an employers disclosures about plan assets of a defined benefit
pension or other postretirement plan. The additional requirements of FSP No. FAS 132(R)-1 are
designed to enhance disclosures regarding (i) investment policies and strategies, (ii) categories
of plan assets, (iii) fair value measurements of plan assets, and (iv) significant concentrations
of risk. FSP No. FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with
earlier application permitted. Since FSP No. FAS 132(R)-1 only affects disclosure requirements,
the adoption of FSP No. FAS 132(R)-1 will not affect our financial position or results of
operations.
Reclassifications
Our consolidated balance sheet as of December 31, 2007 has been reclassified to present the assets
and liabilities of the Krotz Springs Refinery as assets held for sale and liabilities related to
assets held for sale, respectively. In addition, certain other minor amounts previously reported
in our annual report on Form 10-K for the year ended December 31, 2007 have been reclassified to
conform to the 2008 presentation.
2. ACQUISITIONS AND DISPOSITIONS
Sale of Krotz Springs Refinery
Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana to Alon Refining Krotz
Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. As a result, the assets and
liabilities related to the Krotz Springs Refinery as of December 31, 2007 have been presented in
the consolidated balance sheet as assets held for sale and liabilities related to assets held
for sale, respectively. The nature and significance of our post-closing participation in the
offtake agreement described below represents a continuation of activities with the Krotz Springs
Refinery for accounting purposes, and as such the results of operations related to the Krotz
Springs Refinery have not been presented as discontinued operations in the consolidated statements
of income for any of the periods presented.
The sale resulted in a pre-tax gain of $305 million ($170 million after tax), which is presented in
gain on sale of Krotz Springs Refinery in the consolidated statement of income for the year ended
December 31, 2008. Cash proceeds, net of certain costs related to the sale, were $463 million,
including approximately $135 million from the sale of working capital to Alon primarily related to
the sale of inventory by our marketing and supply subsidiary. In addition to the cash
consideration received, we also received contingent consideration in the form of a three-year
earn-out agreement based on certain product margins, which had a fair value of $171 million as of
July 1, 2008. We have hedged the risk of a decline in the referenced product margins by entering
into certain commodity derivative contracts.
In connection with the sale, we also entered into the following agreements with Alon:
|
|
|
an agreement to supply crude oil and other feedstocks to the Krotz Springs Refinery
through September 30, 2008, which was subsequently extended until November 30, 2008; |
76
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
an offtake agreement under which we agreed to (i) purchase all refined products from the
Krotz Springs Refinery for three months after the effective date of the sale, (ii) purchase
certain products for an additional one to five years after the expiration of the initial
three-month period of the agreement, and (iii) provide certain refined products to Alon
that are not produced at the Krotz Springs Refinery for an initial term of 15 months and
thereafter until terminated by either party; and |
|
|
|
|
a transition services agreement under which we agreed to provide certain accounting and
administrative services to Alon, with the services terminating by July 31, 2009.
Substantially all of these services had been transitioned to Alon as of December 31, 2008. |
Financial information related to the Krotz Springs Refinery assets and liabilities sold is
summarized as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
July 1, |
|
December 31, |
|
|
2008 |
|
2007 |
|
Current assets (primarily inventory) |
|
$ |
138 |
|
|
$ |
111 |
|
Property, plant and equipment, net |
|
|
153 |
|
|
|
149 |
|
Goodwill |
|
|
42 |
|
|
|
42 |
|
Deferred charges and other assets, net |
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
Assets held for sale |
|
$ |
337 |
|
|
$ |
306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
10 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
Liabilities related to assets held for sale |
|
$ |
10 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
Sale of Lima Refinery
Effective July 1, 2007, we sold our refinery in Lima, Ohio to Husky Refining Company (Husky), a
wholly owned subsidiary of Husky Energy Inc. In addition, our marketing and supply subsidiary
separately sold certain inventory amounts to Husky as part of this transaction. The consolidated
statements of income reflect the operations related to the Lima Refinery for the periods prior to
the effective date of the sale in income from discontinued operations, net of income tax expense.
Proceeds from the sale were approximately $2.4 billion, including approximately $550 million from
the sale of working capital to Husky primarily related to the sale of inventory by our marketing
and supply subsidiary. The sale resulted in a pre-tax gain of $827 million, or $426 million after
tax, which is included in income from discontinued operations, net of income tax expense in the
consolidated statement of income for the year ended December 31, 2007. In connection with the
sale, we entered into a transition services agreement with Husky under which we agreed to provide
certain accounting and administrative services to Husky; all of these services were transitioned to
Husky by the middle of 2008.
77
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Financial information related to the assets and liabilities sold is summarized as follows
(in millions). The statement of income information presented below for 2007 does not include the
gain on the sale of the Lima Refinery.
|
|
|
|
|
|
|
|
|
|
|
July 1, |
|
December 31, |
|
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
Current assets (primarily inventory) |
|
$ |
570 |
|
|
$ |
456 |
|
Property, plant and equipment, net |
|
|
929 |
|
|
|
918 |
|
Goodwill |
|
|
107 |
|
|
|
108 |
|
Deferred charges and other assets, net |
|
|
46 |
|
|
|
45 |
|
|
|
|
|
|
|
|
|
|
Assets held for sale |
|
$ |
1,652 |
|
|
$ |
1,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities, including current portion
of capital lease obligation |
|
$ |
15 |
|
|
$ |
29 |
|
Capital lease obligation, excluding current portion |
|
|
38 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
Liabilities related to assets held for sale |
|
$ |
53 |
|
|
$ |
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
2,231 |
|
|
$ |
4,119 |
|
Income before income tax expense |
|
|
391 |
|
|
|
291 |
|
Minor Acquisitions
In February 2008, we purchased ConocoPhillips one-third undivided joint interest in a refined
product pipeline and terminal for $57 million. These assets provide transportation and storage
services for moving refined products from our McKee Refinery to markets in El Paso, Texas and
Phoenix and Tucson, Arizona.
In August 2008, we purchased 70 convenience stores and fueling kiosks from Albertsons LLC for
$87 million, including $4 million for inventory. These retail sites, which are located in Texas,
Colorado, Arizona, and Louisiana, enhance our existing retail network and supply chain.
3. RESTRICTED CASH
Restricted cash consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Cash held in trust related to the UDS Acquisition |
|
$ |
22 |
|
|
$ |
23 |
|
Cash held in trust related to the Premcor Acquisition |
|
|
7 |
|
|
|
8 |
|
Cash related to escrow agreement with
the Government of Aruba (see Note 23) |
|
|
102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash |
|
$ |
131 |
|
|
$ |
31 |
|
|
|
|
|
|
|
|
|
|
78
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. RECEIVABLES
Receivables consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
2,939 |
|
|
$ |
7,702 |
|
Notes receivable and other |
|
|
16 |
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,955 |
|
|
|
7,734 |
|
Allowance for doubtful accounts |
|
|
(58 |
) |
|
|
(43 |
) |
|
|
|
|
|
|
|
|
|
Receivables, net |
|
$ |
2,897 |
|
|
$ |
7,691 |
|
|
|
|
|
|
|
|
|
|
The changes in the allowance for doubtful accounts consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of beginning of year |
|
$ |
43 |
|
|
$ |
33 |
|
|
$ |
31 |
|
Increase in allowance charged to expense |
|
|
43 |
|
|
|
34 |
|
|
|
16 |
|
Accounts charged against the allowance,
net of recoveries |
|
|
(27 |
) |
|
|
(25 |
) |
|
|
(14 |
) |
Foreign currency translation |
|
|
(1 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of end of year |
|
$ |
58 |
|
|
$ |
43 |
|
|
$ |
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have an accounts receivable sales facility with a group of third-party entities and financial
institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. In June
2008, we amended the agreement to extend the maturity date from August 2008 to June 2009. We use
this program as a source of working capital funding. Under this program, one of our marketing
subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our
subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing.
Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible
receivables, without recourse, to the third-party entities and financial institutions. To the
extent that Valero Capital retains an ownership interest in the receivables it has purchased from
Valero Marketing, such interest is included in our consolidated financial statements solely as a
result of the consolidation of the financial statements of Valero Capital with those of Valero
Energy Corporation; the receivables are not available to satisfy the claims of the creditors of
Valero Marketing or Valero Energy Corporation.
As of December 31, 2008 and 2007, $1.3 billion and $4.0 billion, respectively, of our accounts
receivable composed the designated pool of accounts receivable included in the program. As of
December 31, 2008 and 2007, the amount of eligible receivables sold to the third-party entities and
financial institutions was $100 million. At December 31, 2008, proceeds from the sale of
receivables under this facility were reflected as debt in our consolidated balance sheet. The
amount outstanding as of December 31, 2008 was repaid in February 2009. Prior to December 31,
2008, amounts received under the program were reflected as a reduction of receivables, net in the
consolidated balance sheet, with the residual interest that we retained in the designated pool of
receivables recorded at fair value. Due to (i) a short average collection cycle for such
receivables, (ii) our collection experience history, and (iii) the composition of the designated
pool of trade accounts receivable that are part of this program, the fair value of our retained
interest approximated the total amount of the designated pool of accounts receivable reduced by
79
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the
amount of accounts receivable sold to the third-party entities and financial institutions under the
program.
We remain responsible for servicing the receivables sold to the third-party entities and financial
institutions and pay certain fees related to our sale of receivables under the program. The costs
we incurred related to this facility, which were included in other income, net in the
consolidated statements of income, were $6 million, $40 million, and $55 million for the years ended December 31, 2008,
2007, and 2006, respectively. Proceeds from collections under this facility of $3.3 billion,
$19.3 billion, and $31.2 billion for the years ended December 31, 2008, 2007, and 2006,
respectively, were reinvested in the program by the third-party entities and financial
institutions. However, the third-party entities and financial institutions interests in our
accounts receivable were never in excess of the sales facility limits at any time under this
program. No accounts receivable included in this program were written off during 2008, 2007, or
2006.
5. INVENTORIES
Inventories consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Refinery feedstocks |
|
$ |
2,140 |
|
|
$ |
1,701 |
|
Refined products and blendstocks |
|
|
2,224 |
|
|
|
2,117 |
|
Convenience store merchandise |
|
|
90 |
|
|
|
85 |
|
Materials and supplies |
|
|
183 |
|
|
|
170 |
|
|
|
|
|
|
|
|
|
|
Inventories |
|
$ |
4,637 |
|
|
$ |
4,073 |
|
|
|
|
|
|
|
|
|
|
Refinery feedstock and refined product and blendstock inventory volumes totaled 114 million barrels
and 105 million barrels as of December 31, 2008 and 2007, respectively. There were no substantial
liquidations of LIFO inventory layers for the years ended December 31, 2008, 2007, and 2006.
As of December 31, 2008 and 2007, the replacement cost (market value) of LIFO inventories exceeded
their LIFO carrying amounts by approximately $686 million and $6.2 billion, respectively.
80
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment, which include capital lease assets, consisted of
the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
December 31, |
|
|
Useful Lives |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Land |
|
|
|
|
|
$ |
602 |
|
|
$ |
574 |
|
Crude oil processing facilities |
|
10 - 33 years |
|
|
21,194 |
|
|
|
20,509 |
|
Butane processing facilities |
|
30 years |
|
|
246 |
|
|
|
246 |
|
Pipeline and terminal facilities |
|
24 - 42 years |
|
|
549 |
|
|
|
511 |
|
Retail facilities |
|
5 - 22 years |
|
|
787 |
|
|
|
735 |
|
Buildings |
|
13 - 47 years |
|
|
872 |
|
|
|
775 |
|
Other |
|
1 - 44 years |
|
|
1,102 |
|
|
|
1,006 |
|
Construction in progress |
|
|
|
|
|
|
2,751 |
|
|
|
1,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
|
|
|
|
28,103 |
|
|
|
25,599 |
|
Accumulated depreciation |
|
|
|
|
|
|
(4,890 |
) |
|
|
(4,039 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
$ |
23,213 |
|
|
$ |
21,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We had crude oil processing facilities, pipeline and terminal facilities, and certain buildings and
other equipment under capital leases totaling $54 million as of both December 31, 2008 and 2007.
Accumulated amortization on assets under capital leases was $13 million and $10 million,
respectively, as of December 31, 2008 and 2007.
Depreciation expense for the years ended December 31, 2008, 2007, and 2006 was $990 million,
$916 million, and $776 million, respectively.
7. INTANGIBLE ASSETS
Intangible assets consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
December 31, 2007 |
|
|
Gross |
|
Accumulated |
|
Gross |
|
Accumulated |
|
|
Cost |
|
Amortization |
|
Cost |
|
Amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets subject to amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer lists |
|
$ |
97 |
|
|
$ |
(43 |
) |
|
$ |
116 |
|
|
$ |
(45 |
) |
Canadian retail operations |
|
|
127 |
|
|
|
(22 |
) |
|
|
156 |
|
|
|
(23 |
) |
U.S. retail store operations |
|
|
95 |
|
|
|
(76 |
) |
|
|
94 |
|
|
|
(66 |
) |
Air emission credits |
|
|
62 |
|
|
|
(29 |
) |
|
|
62 |
|
|
|
(23 |
) |
Royalties and licenses |
|
|
25 |
|
|
|
(12 |
) |
|
|
25 |
|
|
|
(11 |
) |
Gasoline and diesel sulfur credits |
|
|
27 |
|
|
|
(27 |
) |
|
|
27 |
|
|
|
(23 |
) |
Other |
|
|
4 |
|
|
|
(4 |
) |
|
|
4 |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets subject to amortization |
|
$ |
437 |
|
|
$ |
(213 |
) |
|
$ |
484 |
|
|
$ |
(194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of our intangible assets are subject to amortization. Amortization expense for intangible
assets was $33 million, $48 million, and $35 million for the years ended December 31, 2008, 2007,
and 2006,
81
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
respectively. The estimated aggregate amortization expense for the years ending
December 31, 2009 through December 31, 2013 is as follows (in millions):
|
|
|
|
|
|
|
Amortization |
|
|
Expense |
|
|
|
|
|
2009 |
|
$ |
23 |
|
2010 |
|
|
20 |
|
2011 |
|
|
14 |
|
2012 |
|
|
14 |
|
2013 |
|
|
14 |
|
During the year ended December 31, 2008, gross cost and accumulated amortization of intangible
assets decreased by $50 million and $14 million, respectively, due to fluctuations in the Canadian
dollar exchange rate.
8. GOODWILL
The changes in the carrying amount of goodwill were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Balance as of beginning of year |
|
$ |
4,019 |
|
|
$ |
4,061 |
|
Settlements and adjustments related to
acquisition tax contingencies,
stock option exercises, and other |
|
|
50 |
|
|
|
(42 |
) |
Goodwill impairment loss |
|
|
(4,069 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of end of year |
|
$ |
|
|
|
$ |
4,019 |
|
|
|
|
|
|
|
|
|
|
Settlements and adjustments related to acquisition tax contingencies, stock option exercises, and
other reflected in the table above relate primarily to settlements and adjustments of various
income tax contingencies assumed in the UDS and Premcor Acquisitions and exercises of stock options
assumed in those acquisitions, the effects of which were recorded as purchase price adjustments.
All of our goodwill was allocated among four reporting units that comprise the refining segment.
These reporting units are the Gulf Coast, Mid-Continent, Northeast, and West Coast refining
regions. Our annual test for impairment of goodwill has historically been performed as of October
1 of each year. However, during the fourth quarter of 2008, there were severe disruptions in the
capital and commodities markets that contributed to a significant decline in our common stock
price. As a result, our equity market capitalization fell significantly below our net book value.
Because this situation is an indicator that goodwill may be impaired, we performed an additional
analysis to evaluate the potential impairment of our goodwill as of December 31, 2008. Based on
this additional analysis, we determined that all of the goodwill in our four reporting units was
impaired, which resulted in the recognition of a goodwill impairment loss of $4.1 billion
($4.0 billion after tax). For purposes of this goodwill impairment test, the fair value of each
reporting unit was estimated based on the present value of expected future cash flows, with the
present value determined using discount rates that reflected the risk inherent in the assets and
risk premiums that reflected the volatility in the industry and the financial markets.
82
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. INVESTMENT IN AND TRANSACTIONS WITH NUSTAR ENERGY L.P.
NuStar Energy L.P. is a limited partnership that owns and operates crude oil and refined product
pipeline, terminalling, and storage tank assets. As discussed in Note 1 under Basis of
Presentation and Principles of Consolidation, one of our previously wholly owned subsidiaries,
NuStar GP Holdings, LLC, served as the general partner of and held our limited partner interest in
NuStar Energy L.P. Our ownership interest in NuStar Energy L.P. was 23.4% as of June 30, 2006 (the
end of the quarter prior to the offerings discussed below under the heading Sale of NuStar GP
Holdings, LLC), which was composed of a 2% general partner interest, incentive distribution
rights, and a 21.4% limited partner interest. The limited partner interest was represented by
10,222,630 common units of NuStar Energy L.P., of which 9,599,322 were previously subordinated
units that converted to common units on May 8, 2006 upon the termination of the subordination
period in accordance with the terms of NuStar Energy L.P.s partnership agreement.
Through the date of termination of the subordination period, NuStar Energy L.P. had issued common
units to the public on three separate occasions, which had diluted our ownership percentage. These
three issuances resulted in increases, or SAB 51 credits (see Note 1 under Sales of Subsidiary
Stock), in our proportionate share of NuStar Energy L.P.s capital because, in each case, the
issuance price per unit exceeded our carrying amount per unit at the time of issuance. We had not
recognized any SAB 51 credits in our consolidated financial statements through March 31, 2006 and
were not permitted to do so until the subordinated units converted to common units. In conjunction
with the conversion of the subordinated units held by us to common units in the second quarter of
2006, we recognized the entire balance of $158 million in SAB 51 credits as an increase in our
investment in NuStar Energy L.P. and $101 million after tax as an increase to additional paid-in
capital in our consolidated balance sheet.
Sale of NuStar GP Holdings, LLC
On July 19, 2006, NuStar GP Holdings, LLC consummated an initial public offering (IPO) of
17,250,000 of its units representing limited liability company interests to the public at $22.00
per unit, before an underwriters discount of $1.265 per unit. On December 22, 2006, NuStar GP
Holdings, LLC completed a secondary public offering of 20,550,000 units representing limited
liability company interests at a price of $21.62 per unit, before an underwriters discount of
$0.8648 per unit. In addition, NuStar GP Holdings, LLC sold 4,700,000 unregistered units to its
chairman of the board of directors (who was at that time also chairman of Valeros board of
directors) at $21.62 per unit. All such units were sold by our subsidiaries that held various
ownership interests in NuStar GP Holdings, LLC. As a result, NuStar GP Holdings, LLC did not
receive any proceeds from these offerings, and our indirect ownership interest in NuStar GP
Holdings, LLC was reduced to zero.
Proceeds to our selling subsidiaries from the IPO totaled approximately $355 million, net of the
underwriters discount and other offering expenses, which resulted in a pre-tax gain to us of
$132 million on the sale of the units. Proceeds to our selling subsidiaries from the secondary
offering and private sale of units totaled approximately $525 million, net of the underwriters
discount and other offering expenses, which resulted in an additional pre-tax gain to us of
$196 million. The total pre-tax gain of $328 million is included in other income, net in the
consolidated statement of income for the year ended December 31, 2006. The funds received from
these offerings were used for general corporate purposes.
83
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summary Financial Information
Financial information reported by NuStar Energy L.P. for the year ended December 31, 2006 is
summarized below (in millions):
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,136 |
|
Operating income |
|
|
211 |
|
Net income |
|
|
150 |
|
Related-Party Transactions
Under various throughput, handling, terminalling, and service agreements, we use NuStar Energy
L.P.s pipelines to transport crude oil shipped to and refined products shipped from certain of our
refineries and use NuStar Energy L.P.s refined product terminals for certain terminalling
services. In addition, through 2006, we provided personnel to NuStar Energy L.P. to perform
operating and maintenance services with respect to certain assets for which we received
reimbursement from NuStar Energy L.P. We recognized in cost of sales both our costs related to
the throughput, handling, terminalling, and service agreements with NuStar Energy L.P. and the
receipt from NuStar Energy L.P. of payment for operating and maintenance services we provided to
NuStar Energy L.P. We have indemnified NuStar Energy L.P. for certain environmental liabilities
related to assets we previously sold to NuStar Energy L.P. that were known on the date the assets
were sold or are discovered within a specified number of years after the assets were sold and
result from events occurring or conditions existing prior to the date of sale.
Under
a services agreement in existence during 2006, we provided NuStar Energy L.P. with certain
corporate functions for an administrative fee, which was recorded as a reduction of general and
administrative expenses. Effective January 1, 2007, the services agreement was amended to provide
for limited services. This amended services agreement provided for a termination date of
December 31, 2010, unless we terminated the agreement earlier, in which case we were required to
pay a termination fee of $13 million. In April 2007, we notified NuStar Energy L.P. of our
decision to terminate the services agreement. Accordingly, the $13 million termination fee was
accrued and paid during the second quarter of 2007.
The following table summarizes the results of transactions with NuStar Energy L.P. for the year
ended December 31, 2006 (in millions):
|
|
|
|
|
|
|
|
|
|
Expenses
charged by us to NuStar Energy L.P. |
|
$ |
127 |
|
Fees and
expenses charged to us by NuStar Energy L.P. |
|
|
261 |
|
10. DEFERRED CHARGES AND OTHER ASSETS
Deferred charges and other assets, net includes refinery turnaround and catalyst costs. As
indicated in Note 1, refinery turnaround costs are deferred when incurred and amortized on a
straight-line basis over the period of time estimated to lapse until the next turnaround occurs.
Fixed-bed catalyst costs are deferred when incurred and amortized on a straight-line basis over the
estimated useful life of the specific catalyst. Amortization expense for deferred refinery
turnaround and catalyst costs was $438 million, $383 million, and $293 million for the years ended
December 31, 2008, 2007, and 2006, respectively.
84
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cameron Highway Oil Pipeline Project
We own a 50% interest in Cameron Highway Oil Pipeline Company, a general partnership formed to
construct and operate a crude oil pipeline. The 390-mile crude oil pipeline delivers up to 500,000
barrels per day from the Gulf of Mexico to the major refining areas of Port Arthur and Texas City,
Texas. Our investment in Cameron Highway Oil Pipeline Company is accounted for using the equity
method and is included in deferred charges and other assets, net in the consolidated balance
sheets. During May and June of 2007, we made cash capital contributions of $215 million
representing our 50% portion of the amount required to enable the joint venture to redeem its
fixed-rate notes and variable-rate debt. As of December 31, 2008 and 2007, our investment in
Cameron Highway Oil Pipeline Company totaled $289 million and $297 million, respectively.
11. ACCRUED EXPENSES
Accrued expenses consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Employee wage and benefit costs |
|
$ |
169 |
|
|
$ |
258 |
|
Interest expense |
|
|
66 |
|
|
|
79 |
|
Contingent earn-out obligations |
|
|
|
|
|
|
25 |
|
Derivative liabilities |
|
|
7 |
|
|
|
10 |
|
Environmental liabilities |
|
|
42 |
|
|
|
55 |
|
Other |
|
|
90 |
|
|
|
73 |
|
|
|
|
|
|
|
|
|
|
Accrued expenses |
|
$ |
374 |
|
|
$ |
500 |
|
|
|
|
|
|
|
|
|
|
85
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. DEBT AND CAPITAL LEASE OBLIGATIONS
Debt balances, at stated values, and capital lease obligations consisted of the following (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
Maturity |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank credit facilities |
|
Various |
|
$ |
|
|
|
$ |
|
|
Industrial revenue bonds: |
|
|
|
|
|
|
|
|
|
|
|
|
Tax-exempt Revenue Refunding Bonds (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Series 1997A, 5.45% |
|
|
2027 |
|
|
|
24 |
|
|
|
24 |
|
Series 1997B, 5.40% |
|
|
2018 |
|
|
|
33 |
|
|
|
33 |
|
Series 1997C, 5.40% |
|
|
2018 |
|
|
|
33 |
|
|
|
33 |
|
Series 1997D, 5.125% |
|
|
2009 |
|
|
|
9 |
|
|
|
9 |
|
Tax-exempt Waste Disposal Revenue Bonds: |
|
|
|
|
|
|
|
|
|
|
|
|
Series 1997, 5.6% |
|
|
2031 |
|
|
|
25 |
|
|
|
25 |
|
Series 1998, 5.6% |
|
|
2032 |
|
|
|
25 |
|
|
|
25 |
|
Series 1999, 5.7% |
|
|
2032 |
|
|
|
25 |
|
|
|
25 |
|
Series 2001, 6.65% |
|
|
2032 |
|
|
|
19 |
|
|
|
19 |
|
3.50% notes |
|
|
2009 |
|
|
|
200 |
|
|
|
200 |
|
4.75% notes |
|
|
2013 |
|
|
|
300 |
|
|
|
300 |
|
4.75% notes |
|
|
2014 |
|
|
|
200 |
|
|
|
200 |
|
6.125% notes |
|
|
2017 |
|
|
|
750 |
|
|
|
750 |
|
6.625% notes |
|
|
2037 |
|
|
|
1,500 |
|
|
|
1,500 |
|
6.875% notes |
|
|
2012 |
|
|
|
750 |
|
|
|
750 |
|
7.50% notes |
|
|
2032 |
|
|
|
750 |
|
|
|
750 |
|
8.75% notes |
|
|
2030 |
|
|
|
200 |
|
|
|
200 |
|
Debentures: |
|
|
|
|
|
|
|
|
|
|
|
|
7.25% (non-callable) |
|
|
2010 |
|
|
|
25 |
|
|
|
25 |
|
7.65% |
|
|
2026 |
|
|
|
100 |
|
|
|
100 |
|
8.75% (non-callable) |
|
|
2015 |
|
|
|
75 |
|
|
|
75 |
|
Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
6.125% |
|
|
2011 |
|
|
|
200 |
|
|
|
200 |
|
6.70% |
|
|
2013 |
|
|
|
180 |
|
|
|
180 |
|
6.75% |
|
|
2011 |
|
|
|
210 |
|
|
|
210 |
|
6.75% |
|
|
2014 |
|
|
|
185 |
|
|
|
185 |
|
6.75% (putable October 15, 2009; callable thereafter) |
|
|
2037 |
|
|
|
100 |
|
|
|
100 |
|
7.20% (callable) |
|
|
2017 |
|
|
|
200 |
|
|
|
200 |
|
7.45% (callable) |
|
|
2097 |
|
|
|
100 |
|
|
|
100 |
|
7.50% (callable) |
|
|
2015 |
|
|
|
287 |
|
|
|
287 |
|
9.50% (callable) |
|
|
2013 |
|
|
|
|
|
|
|
350 |
|
Other debt |
|
Various |
|
|
100 |
|
|
|
6 |
|
Net unamortized discount, including fair value adjustments |
|
|
|
|
|
|
(68 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
|
|
|
|
6,537 |
|
|
|
6,819 |
|
Capital
lease obligations, including unamortized fair value adjustments of $3 and $4 |
|
|
|
|
|
|
39 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt and capital lease obligations |
|
|
|
|
|
|
6,576 |
|
|
|
6,862 |
|
Less current portion, including net unamortized premium of $- and $31 |
|
|
|
|
|
|
(312 |
) |
|
|
(392 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt and capital lease obligations, less current portion |
|
|
|
|
|
$ |
6,264 |
|
|
$ |
6,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The maturity dates reflected for the Series 1997A, 1997B, and 1997C tax-exempt revenue
refunding bonds represent their final maturity dates; however, principal payments on these
bonds commence in 2010. |
86
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Bank Credit Facilities
We have a $2.5 billion revolving credit facility (the Revolver) that has a maturity date of
November 2012. Borrowings under the Revolver bear interest at LIBOR plus a margin, or an alternate
base rate as defined under the agreement. We are also being charged various fees and expenses in
connection with the Revolver, including facility fees and letter of credit fees. The interest rate
and fees under the Revolver are subject to adjustment based upon the credit ratings assigned to our
non-bank debt. The Revolver also includes certain restrictive covenants including a
debt-to-capitalization ratio. During the years ended December 31, 2008 and 2006, we borrowed and
repaid $296 million and $830 million, respectively, under the Revolver. There were no borrowings
under the Revolver during the year ended December 31, 2007. As of December 31, 2008 and 2007,
there were no borrowings outstanding under the Revolver and outstanding letters of credit issued
under this facility totaled $199 million and $292 million, respectively.
In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit
facility under which it may borrow and obtain letters of credit up to Cdn. $115 million. In
December 2007, the Canadian credit facility was amended to extend the maturity date from December
2010 to December 2012. As of December 31, 2008 and 2007, we had no borrowings outstanding under
our Canadian credit facility and letters of credit issued under this credit facility totaled
Cdn. $19 million and Cdn. $11 million, respectively.
In June 2008, we entered into a one-year committed revolving letter of credit facility under which
we may obtain letters of credit of up to $300 million. In July 2008, we entered into another
one-year committed revolving letter of credit facility under which we may obtain letters of credit
of up to $275 million. Both of these credit facilities support certain of our crude oil purchases.
We are being charged letter of credit issuance fees in connection with these letter of credit
facilities. As of December 31, 2008, we had $232 million of outstanding letters of credit issued
under these revolving credit facilities.
We also have various uncommitted short-term bank credit facilities. As of December 31, 2008 and
2007, we had no borrowings outstanding under our uncommitted short-term bank credit facilities;
however, there were $201 million and $502 million, respectively, of letters of credit outstanding
under such facilities for which we are charged letter of credit issuance fees. The uncommitted
credit facilities have no commitment fees or compensating balance requirements.
During April 2007, we borrowed $3 billion under a 364-day term credit agreement with a financial
institution to fund the accelerated share repurchase program discussed in Note 14. The term loan
bore interest at LIBOR plus a margin, or an alternate base rate as defined under the term credit
agreement. In May 2007, we repaid $500 million of the borrowings under the term credit agreement.
The remaining balance of $2.5 billion was repaid in June 2007 using available cash and proceeds
from our issuance of long-term notes in June 2007 described below.
87
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Non-Bank Debt
On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated
value. These notes had a carrying amount of $381 million on the date of redemption, resulting in a
gain of $14 million that was included in other income, net in the consolidated statement of
income. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to
certain of our other debt.
In February 2007, we redeemed our 9.25% senior notes for $183 million, or 104.625% of stated value.
These notes had a carrying amount of $187 million on the date of redemption, resulting in a gain
of $4 million that was included in other income, net in the consolidated statement of income. In
addition, we made scheduled debt repayments of $230 million in April 2007 related to our 6.125%
notes and $50 million in November 2007 related to our 6.311% CORE notes.
In June 2007, we issued $750 million of 6.125% notes due June 15, 2017 and $1.5 billion of 6.625%
notes due June 15, 2037. Proceeds from the issuance of these notes totaled $2.245 billion, before
deducting underwriting discounts of $18 million.
During March 2006, we made a scheduled debt repayment of $220 million related to our 7.375% notes.
In addition, during the year ended December 31, 2006, we made the following debt payments:
|
|
|
$1 million during March 2006 related to our 7.75% notes due in February 2012, |
|
|
|
$14 million during July 2006 related to our 6.75% senior notes due in May 2014, and |
|
|
|
$14 million during July 2006 related to our 7.5% senior notes due in June 2015. |
Other Disclosures
Our revolving bank credit facilities and other debt arrangements contain various customary
restrictive covenants, including cross-default and cross-acceleration clauses.
Principal payments due on debt as of December 31, 2008 were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
2009 |
|
$ |
309 |
|
2010 |
|
|
33 |
|
2011 |
|
|
418 |
|
2012 |
|
|
759 |
|
2013 |
|
|
489 |
|
Thereafter |
|
|
4,597 |
|
Net unamortized discount and
fair value adjustments |
|
|
(68 |
) |
|
|
|
|
|
Total |
|
$ |
6,537 |
|
|
|
|
|
|
For payments due on capital lease obligations, see Note 23.
88
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2008 and 2007, the estimated fair value of our debt, including current portion,
was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Carrying amount |
|
$ |
6,537 |
|
|
$ |
6,819 |
|
Fair value |
|
|
6,462 |
|
|
|
7,109 |
|
13. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Employee benefit plan liabilities |
|
$ |
1,047 |
|
|
$ |
701 |
|
Environmental liabilities |
|
|
255 |
|
|
|
230 |
|
Tax liabilities for uncertain income tax positions |
|
|
226 |
|
|
|
160 |
|
Other tax liabilities |
|
|
189 |
|
|
|
163 |
|
Deferred gain on sale of assets to NuStar Energy L.P. |
|
|
92 |
|
|
|
114 |
|
Insurance liabilities |
|
|
90 |
|
|
|
86 |
|
Asset retirement obligations |
|
|
72 |
|
|
|
70 |
|
Unfavorable lease obligations |
|
|
38 |
|
|
|
51 |
|
Other |
|
|
152 |
|
|
|
235 |
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities |
|
$ |
2,161 |
|
|
$ |
1,810 |
|
|
|
|
|
|
|
|
|
|
Employee benefit plan liabilities include the long-term obligation for our pension and other
postretirement benefit plans as discussed in Note 21.
Environmental liabilities reflect the long-term portion of our estimated remediation costs for
environmental matters as discussed in Note 24. Tax liabilities for
uncertain income tax positions reflect obligations under FIN 48 as discussed in Note 19
.. Other tax liabilities include long-term liabilities for various taxes
such as sales, franchise, and excise taxes as well as interest accrued on all tax-related
liabilities, including income taxes. Deferred gain reflects the unamortized balance of the
proceeds in excess of the carrying amount of assets we sold to NuStar Energy L.P., which we
recognize in income over the term of certain throughput and handling agreements with NuStar Energy
L.P. (see Note 9). Insurance liabilities reflect reserves established by our captive insurance
subsidiary, self-insured liabilities, and obligations for losses related to our participation in
certain mutual insurance companies.
Unfavorable lease obligations reflect the fair value of liabilities assumed in connection with the
Premcor Acquisition related to lease agreements for closed retail facilities and the UDS
Acquisition related to lease agreements for retail facilities and vessel charters. Included in
other are liabilities for various matters including legal and regulatory liabilities and various
contractual obligations.
89
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below reflects the changes in our asset retirement obligations (in millions). See
Note 1 under Asset Retirement Obligations for a discussion of
the liability related to these obligations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of beginning of year |
|
$ |
70 |
|
|
$ |
51 |
|
|
$ |
51 |
|
Additions to accrual |
|
|
4 |
|
|
|
1 |
|
|
|
1 |
|
Accretion expense |
|
|
3 |
|
|
|
2 |
|
|
|
2 |
|
Settlements |
|
|
(4 |
) |
|
|
(13 |
) |
|
|
(5 |
) |
Changes in timing and amount of
estimated cash flows |
|
|
|
|
|
|
28 |
|
|
|
2 |
|
Foreign currency translation |
|
|
(1 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of end of year |
|
$ |
72 |
|
|
$ |
70 |
|
|
$ |
51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14. STOCKHOLDERS EQUITY
Share Activity
For the years ended December 31, 2008, 2007, and 2006, activity in the number of shares of
preferred stock, common stock, and treasury stock was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred |
|
Common |
|
Treasury |
|
|
Stock |
|
Stock |
|
Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2005 |
|
|
3 |
|
|
|
621 |
|
|
|
(4 |
) |
Conversion of preferred stock |
|
|
(3 |
) |
|
|
6 |
|
|
|
|
|
Shares repurchased, net of shares issued,
in connection with employee stock plans and other |
|
|
|
|
|
|
|
|
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006 |
|
|
|
|
|
|
627 |
|
|
|
(24 |
) |
Shares repurchased under $6 billion common stock
purchase program |
|
|
|
|
|
|
|
|
|
|
(70 |
) |
Shares issued, net of shares repurchased,
in connection with employee stock plans and other |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
|
|
|
|
|
627 |
|
|
|
(91 |
) |
Shares repurchased under $6 billion common stock
purchase program |
|
|
|
|
|
|
|
|
|
|
(18 |
) |
Shares repurchased, net of shares issued,
in connection with employee stock plans and other |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
|
|
|
|
|
627 |
|
|
|
(111 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock
We have 20 million shares of preferred stock authorized with a par value of $.01 per share. As of
December 31, 2008 and 2007, no shares of preferred stock were outstanding.
In connection with the acquisition of the St. Charles Refinery on July 1, 2003, we issued
10 million shares of 2% mandatory convertible preferred stock. Each share of convertible preferred
stock was convertible, at the option of the holder, at any time before July 1, 2006 into 1.982
shares of our common stock. All mandatory convertible preferred stock not previously converted
automatically converted to our common
90
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
stock on July 1, 2006. Upon automatic conversion of the
convertible preferred stock on July 1, 2006, 1.982 shares of common stock were issued for each
share of convertible preferred stock based on the average closing price of our common stock over
the 20-day trading period ending on the second trading day prior to July 1, 2006. During 2006,
3,164,151 shares of the preferred stock were converted into 6,271,327 shares of our common stock.
Prior to the issuance of shares of our common stock upon conversion of the convertible preferred
stock, the number of shares of our common stock included in the calculation of earnings per common
share assuming dilution for each reporting period was based on the average closing price of our
common stock over the 20-day trading period ending on the second trading day prior to the end of
the reporting period.
Treasury Stock
We purchase shares of our common stock in open market transactions to meet our obligations under
employee benefit plans. We also purchase shares of our common stock 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.
On October 19, 2006, our board of directors approved a $2 billion common stock purchase program.
This authorization was in addition to our existing authorization to purchase shares to offset
dilution created by our employee stock incentive programs. On April 25, 2007, our board of
directors approved an amendment to our $2 billion common stock purchase program to increase the
authorized purchases under the program to $6 billion. Stock purchases under the program are made
from time to time at prevailing prices as permitted by securities laws and other legal
requirements, and are subject to market conditions and other factors. The program does not have a
scheduled expiration date.
In conjunction with the increase in our common stock purchase program, we entered into an agreement
with a financial institution to purchase $3 billion of our shares under an accelerated share
repurchase program, and in late April 2007, 42.1 million shares were purchased under this
agreement. As described in Note 12 above, the purchase of these shares was initially funded with a
364-day term credit agreement, which we subsequently replaced with longer-term financing. The cost
of the shares purchased under this accelerated share repurchase program was to be adjusted at the
expiration of the program, with the final purchase cost based on a discount to the average trading
price of our common stock, weighted by the daily volume of shares traded, during the program
period. Any adjustment to the cost could be paid in cash or stock, at our option.
The accelerated share repurchase program was completed on July 23, 2007, and we elected to pay in
cash an additional $94 million for the shares purchased. This cash payment was deducted from
reported income from continuing operations in calculating earnings per common share from continuing
operations assuming dilution for the year ended December 31, 2007 (see Note 15).
On February 28, 2008, our board of directors approved a new $3 billion common stock purchase
program. This program is in addition to the remaining amount under the $6 billion program
previously authorized. This new $3 billion program has no expiration date. As of December 31,
2008, we had made no purchases of our common stock under the new $3 billion program. As of
December 31, 2008, we have approvals under these stock purchase programs to purchase approximately
$3.5 billion of our common stock.
91
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During the years ended December 31, 2008, 2007, and 2006, we purchased 23.0 million, 84.3 million,
and 34.6 million shares of our common stock, respectively, at a cost of $955 million, $5.8 billion,
and $2.0 billion, respectively. These purchases were made in connection with the administration of
our employee benefit plans and the $6 billion common stock purchase program authorized by our board
of directors, including the effect of the accelerated share repurchase program discussed above.
During the years ended December 31, 2008, 2007, and 2006, we issued 2.5 million, 16.1 million, and
14.7 million shares from treasury, respectively, at an average cost of $65.85, $62.89, and $55.70
per share, respectively, for our employee benefit plans.
Common Stock Dividends
On January 20, 2009, our board of directors declared a quarterly cash dividend of $0.15 per common
share payable March 11, 2009 to holders of record at the close of business on February 11, 2009.
Accumulated Other Comprehensive Income
Accumulated balances for each component of accumulated other comprehensive income (loss) were as
follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign |
|
|
|
|
|
Net Gain |
|
Accumulated |
|
|
Currency |
|
Pension/OPEB |
|
(Loss) On |
|
Other |
|
|
Translation |
|
Liability |
|
Cash Flow |
|
Comprehensive |
|
|
Adjustment |
|
Adjustment |
|
Hedges |
|
Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2005 |
|
$ |
341 |
|
|
$ |
(10 |
) |
|
$ |
4 |
|
|
$ |
335 |
|
2006 change |
|
|
(11 |
) |
|
|
(100 |
) |
|
|
41 |
|
|
|
(70 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006 |
|
|
330 |
|
|
|
(110 |
) |
|
|
45 |
|
|
|
265 |
|
2007 change |
|
|
250 |
|
|
|
86 |
|
|
|
(28 |
) |
|
|
308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
|
580 |
|
|
|
(24 |
) |
|
|
17 |
|
|
|
573 |
|
2008 change |
|
|
(490 |
) |
|
|
(411 |
) |
|
|
152 |
|
|
|
(749 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
$ |
90 |
|
|
$ |
(435 |
) |
|
$ |
169 |
|
|
$ |
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Share Purchase Rights
Prior to June 30, 2007, each outstanding share of our common stock was accompanied by one preferred
share purchase right (Right). With certain exceptions, each Right entitled the registered holder
to purchase from us .0025 of a share of our Junior Participating Preferred Stock, Series I at a
price of $100 per .0025 of a share, subject to adjustment for certain recapitalization events.
These Rights expired on June 30, 2007.
92
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. EARNINGS (LOSS) PER SHARE
Earnings (loss) per common share amounts from continuing operations were computed as follows
(dollars and shares in millions, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share from
continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
$ |
(1,131 |
) |
|
$ |
4,565 |
|
|
$ |
5,287 |
|
Less: Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
applicable to common stock |
|
$ |
(1,131 |
) |
|
$ |
4,565 |
|
|
$ |
5,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
524 |
|
|
|
565 |
|
|
|
611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share from
continuing operations |
|
$ |
(2.16 |
) |
|
$ |
8.08 |
|
|
$ |
8.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share from
continuing operations assuming dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
$ |
(1,131 |
) |
|
$ |
4,565 |
|
|
$ |
5,287 |
|
Less: Cash paid in final settlement of
accelerated share repurchase program |
|
|
|
|
|
|
94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
assuming dilution |
|
$ |
(1,131 |
) |
|
$ |
4,471 |
|
|
$ |
5,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
524 |
|
|
|
565 |
|
|
|
611 |
|
Effect of dilutive securities (1): |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
|
|
|
|
13 |
|
|
|
18 |
|
Restricted stock and performance awards |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Mandatory convertible preferred stock |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
common shares outstanding
assuming dilution |
|
|
524 |
|
|
|
579 |
|
|
|
632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share from
continuing operations assuming dilution |
|
$ |
(2.16 |
) |
|
$ |
7.72 |
|
|
$ |
8.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Common equivalent shares were excluded from the computation of diluted earnings
per share for the year ended December 31, 2008 because the effect of including such shares would be anti-dilutive. |
93
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects potentially dilutive securities that were excluded from the
calculation of earnings (loss) per common share from
continuing operations assuming dilution as
the effect of including such securities would have been anti-dilutive (in millions). For the year
ended December 31, 2008, the common equivalent shares presented represent potentially dilutive
securities, primarily stock options, that were excluded as a result of the net loss reported for
2008. For 2008, 2007, and 2006, the stock option amounts presented represent outstanding stock
options for which the exercise prices were greater than the average market price of the common
shares during each respective reporting period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Common equivalent shares |
|
|
7 |
|
|
|
|
|
|
|
|
|
Stock options |
|
|
7 |
|
|
|
2 |
|
|
|
|
|
16. STATEMENTS OF CASH FLOWS
In order to determine net cash provided by operating activities, net income (loss) is adjusted by,
among other things, changes in current assets and current liabilities as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash |
|
$ |
(100 |
) |
|
$ |
|
|
|
$ |
(1 |
) |
Receivables, net |
|
|
4,815 |
|
|
|
(3,227 |
) |
|
|
(837 |
) |
Inventories |
|
|
(705 |
) |
|
|
(249 |
) |
|
|
(405 |
) |
Income taxes receivable |
|
|
(197 |
) |
|
|
32 |
|
|
|
38 |
|
Prepaid expenses and other |
|
|
(190 |
) |
|
|
(58 |
) |
|
|
(81 |
) |
Increase (decrease) in current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
(4,985 |
) |
|
|
2,557 |
|
|
|
1,362 |
|
Accrued expenses |
|
|
182 |
|
|
|
(20 |
) |
|
|
(54 |
) |
Taxes other than income taxes |
|
|
(4 |
) |
|
|
15 |
|
|
|
(4 |
) |
Income taxes payable |
|
|
(446 |
) |
|
|
481 |
|
|
|
(162 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in current assets and
current liabilities |
|
$ |
(1,630 |
) |
|
$ |
(469 |
) |
|
$ |
(144 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The above changes in current assets and current liabilities differ from changes between amounts
reflected in the applicable consolidated balance sheets for the respective periods for the
following reasons:
|
|
|
the amounts shown above exclude changes in cash and temporary cash investments, deferred
income taxes, and current portion of debt and capital lease obligations, as well as the
effect of certain noncash investing and financing activities discussed below; |
|
|
|
|
previously accrued capital expenditures, deferred turnaround and catalyst costs, and
contingent earn-out payments are reflected in investing activities in the consolidated
statements of cash flows; |
|
|
|
|
amounts accrued for common stock purchases in the open market that are not settled as of
the balance sheet date are reflected in financing activities in the consolidated statements
of cash flows when the purchases are settled and paid; |
|
94
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
changes in assets held for sale and liabilities related to assets held for sale
pertaining to the operations of the Krotz Springs Refinery and the Lima Refinery prior to
their sales are reflected in the line items to which the changes relate in the table above;
and |
|
|
|
certain differences between consolidated balance sheet changes and consolidated
statement of cash flow changes reflected above result from translating foreign currency
denominated amounts at different exchange rates. |
Noncash investing activities for the year ended December 31, 2008 included the contingent
consideration received in the form of the earn-out agreement related to the sale of the Krotz
Springs Refinery discussed in Note 2. Noncash investing activities for the years ended
December 31, 2008 and 2007 included adjustments to goodwill and certain noncurrent liabilities
resulting from adjustments to the purchase price allocations related to the Premcor and UDS
Acquisitions (as discussed in Note 8).
Noncash investing and financing activities for the year ended December 31, 2006 included:
|
|
|
the recognition of $158 million (pre-tax) of SAB 51 credits related to our investment in
NuStar Energy L.P. (as discussed in Note 9); |
|
|
|
adjustments to property, plant and equipment, goodwill, and certain current and
noncurrent assets and liabilities resulting from adjustments to the purchase price
allocations related to the Premcor and UDS Acquisitions; |
|
|
|
the conversion of 3,164,151 shares of preferred stock into 6,271,327 shares of our
common stock as discussed in Note 14; and |
|
|
|
the recording of a $39 million capital lease obligation and related capital lease asset
pertaining to certain facilities at the Lima Refinery. |
Cash flows related to the discontinued operations of the Lima Refinery have been combined with the
cash flows from continuing operations within each category in the consolidated statements of cash
flows for the years ended December 31, 2007 and 2006. Cash provided by operating activities
related to our discontinued operations was $260 million and $215 million for the years ended
December 31, 2007 and 2006, respectively. Cash used in investing activities related to the Lima
Refinery was $14 million and $133 million for the years ended December 31, 2007 and 2006,
respectively.
Cash flows related to interest and income taxes were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid (net of amount capitalized) |
|
$ |
351 |
|
|
$ |
331 |
|
|
$ |
261 |
|
Income taxes paid, net of tax refunds received |
|
|
1,428 |
|
|
|
2,014 |
|
|
|
2,349 |
|
17. FAIR VALUE MEASUREMENTS
As discussed in Note 1, we adopted Statement No. 159 effective
January 1, 2008, but have not made any significant fair value elections with respect to any of our
eligible assets or liabilities. Also as discussed in Note 1,
effective January 1, 2008, we adopted Statement No. 157, which defines fair value, establishes a
consistent framework for measuring fair value, establishes a fair value hierarchy (Level 1, Level
2, or Level 3) based on the quality of inputs used to measure fair value, and expands disclosure
requirements for fair value measurements.
95
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Pursuant to the provisions of Statement No. 157, fair values determined by Level 1 inputs utilize
quoted prices in active markets for identical assets or liabilities. Fair values determined by
Level 2 inputs are based on quoted prices for similar assets or liabilities in active markets, and
inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are
unobservable inputs for the asset or liability, and include situations where there is little, if
any, market activity for the asset or liability. We use appropriate valuation techniques based on
the available inputs to measure the fair values of our applicable assets and liabilities. When
available, we measure fair value using Level 1 inputs because they
generally provide the most reliable evidence of fair value.
The table below presents information (dollars in millions) about our assets and liabilities
measured and recorded at fair value on a recurring basis and indicates the fair value hierarchy of
the inputs utilized by us to determine the fair values as of December 31, 2008. These assets and
liabilities have previously been measured and recorded at fair value in accordance with existing
GAAP, and our accounting for these assets and liabilities was not impacted by our adoption of
Statement No. 157 and Statement No. 159.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted Prices |
|
Significant Other |
|
Significant |
|
|
|
|
in Active |
|
Observable |
|
Unobservable |
|
Total as of |
|
|
Markets |
|
Inputs |
|
Inputs |
|
December 31, |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
|
$ |
40 |
|
|
$ |
610 |
|
|
$ |
|
|
|
$ |
650 |
|
Nonqualified benefit plans |
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
98 |
|
Alon earn-out agreement |
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
13 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Certain nonqualified benefit plans |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
The valuation methods used to measure our financial instruments at fair value are as follows:
|
|
|
Commodity derivative contracts, consisting primarily of exchange-traded futures and
swaps, are measured at fair value using the market approach pursuant to the provisions of
Statement No. 157. Exchange-traded futures are valued based on quoted prices from the
exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced
using third-party broker quotes, industry pricing services, and exchange-traded curves, but
since they have contractual terms that are not identical to exchange-traded futures
instruments with a comparable market price, these financial instruments are categorized in
Level 2 of the fair value hierarchy. |
|
|
|
|
Nonqualified benefit plan assets and certain nonqualified benefit plan liabilities are
measured at fair value using a market approach based on quotations from national securities
exchanges and are categorized in Level 1 of the fair value hierarchy. |
|
|
|
|
The Alon earn-out agreement, which we received as partial consideration for the sale of
our Krotz Springs Refinery as discussed in Note 2, is
measured at fair value using a discounted cash flow model and is categorized in Level 3 of
the fair value hierarchy. Significant inputs to the model include expected payments and
discount rates that consider the effects of both credit risk and the time value of money. |
96
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
An $86 million obligation to pay cash collateral to brokers under master netting arrangements is
netted against the fair value of the commodity derivatives reflected in Level 1. Certain of our
commodity derivative contracts under master netting arrangements include both asset and liability
positions. Under the guidance of FASB Staff Position No. FIN 39-1, Amendment of FASB
Interpretation No. 39, we have elected to offset the fair value amounts recognized for multiple
derivative instruments executed with the same counterparty, including any related cash collateral
asset or obligation.
The following is a reconciliation of the beginning and ending balances (in millions) for fair value
measurements developed using significant unobservable inputs for the year ended December 31, 2008.
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
|
|
Alon earn-out agreement (see Note 2) |
|
|
171 |
|
Net unrealized losses included in earnings |
|
|
(158 |
) |
Transfers in and/or out of Level 3 |
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
$ |
13 |
|
|
|
|
|
|
Unrealized losses for the year ended December 31, 2008, which relate to a Level 3 asset still held
at the reporting date, are reported in other income, net in the consolidated statement of income.
These unrealized losses were more than offset by the recognition in other income, net of gains
on derivative instruments entered into to hedge the risk of changes in the fair value of the Alon
earn-out agreement as discussed in Note 2. These derivative
instruments are included in the commodity derivative contracts amounts reflected in the fair
value table above.
18. PRICE RISK MANAGEMENT ACTIVITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices,
as well as volatility in the price of natural gas used in our refining operations. To reduce the
impact of this price volatility, we use derivative commodity instruments (swaps, futures, and
options) to manage our exposure to:
|
|
|
changes in the fair value of a portion of our refinery feedstock and refined product
inventories and a portion of our unrecognized firm commitments to purchase these
inventories (fair value hedges); |
|
|
|
|
changes in cash flows of certain forecasted transactions such as forecasted feedstock
and product purchases, natural gas purchases, and refined product sales (cash flow hedges);
and |
|
|
|
|
price volatility on a portion of our refinery feedstock and refined product inventories
and on certain forecasted feedstock and product purchases, refined product sales, and
natural gas purchases that are not designated as either fair value or cash flow hedges
(economic hedges). |
In addition, we use derivative commodity instruments for trading purposes based on our fundamental
and technical analysis of market conditions.
Interest Rate Risk
We are exposed to market risk for changes in interest rates related to certain of our debt
obligations. We sometimes use interest rate swap agreements to manage our fixed to floating
interest rate position by converting certain fixed-rate debt to floating-rate debt. As of
December 31, 2008 and 2007, we did not have any interest rate swap agreements.
97
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2005, we had interest rate swap agreements with a notional amount of
$1.0 billion and interest rates ranging from 5.6% to 6.0%. All of these swaps were accounted for
as fair value hedges. During the first quarter of 2006, $125 million of these interest rate swaps
were settled on their scheduled maturity date. Effective May 1, 2006, we terminated the remaining
$875 million of interest rate swap contracts outstanding at that date for a payment of $54 million.
Substantially all of this payment was deferred and is being amortized to interest expense over the
remaining lives of the debt instruments that were being hedged.
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian operations.
To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and
purchase contracts. These contracts are not designated as hedging instruments. As of December 31,
2008, we had commitments to purchase $280 million of U.S. dollars. These commitments matured on or
before January 30, 2009, resulting in a 2009 gain of $2 million.
Current Period Disclosures
The net gain (loss) recognized in income representing the amount of hedge ineffectiveness was as
follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value hedges |
|
$ |
4 |
|
|
$ |
(17 |
) |
|
$ |
(11 |
) |
Cash flow hedges |
|
|
(11 |
) |
|
|
(18 |
) |
|
|
8 |
|
The above amounts were included in cost of sales in the consolidated statements of income. No
component of the derivative instruments gains or losses was excluded from the assessment of hedge
effectiveness. No amounts were recognized in income for hedged firm commitments that no longer
qualify as fair value hedges.
During 2008, 2007, and 2006, we recognized in cost of sales gains of $13 million, $37 million,
and $4 million, respectively, associated with trading activities.
For cash flow hedges, gains and losses reported in accumulated other comprehensive income (loss)
in the consolidated balance sheets are reclassified into cost of sales when the forecasted
transactions affect income. During the years ended December 31, 2008, 2007, and 2006, we
recognized in other comprehensive income (loss) unrealized after-tax gains (losses) of
$85 million, $(11) million, and $70 million, respectively, on certain cash flow hedges, primarily
related to forward sales of gasoline and distillates and associated forward purchases of crude oil,
with $169 million, $17 million, and $45 million of cumulative after-tax gains on cash flow hedges
remaining in accumulated other comprehensive income (loss) as of December 31, 2008, 2007, and
2006, respectively. We expect that substantially all of the deferred gains at December 31, 2008 will be reclassified
into cost of sales over the next 12 months as a result of hedged transactions that are forecasted
to occur. The amount ultimately realized in income, however, will differ as commodity prices
change. For the years ended December 31, 2008, 2007, and 2006, there were no amounts reclassified
from accumulated other comprehensive income (loss) into income as a result of the discontinuance
of cash flow hedge accounting.
98
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Market and Credit Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into
the future. These transactions give rise to market risk, the risk that future changes in market
conditions may make an instrument less valuable. We closely monitor and manage our exposure to
market risk on a daily
basis in accordance with policies approved by our board of directors. Market risks are monitored
by a risk control group to ensure compliance with our stated risk management policy.
Concentrations of customers in the refining industry may impact our overall exposure to credit
risk, in that these customers may be similarly affected by changes in economic or other conditions.
In addition, financial services companies are the counterparties in certain of our price risk
management activities, and such financial services companies may be adversely affected by periods
of uncertainty and illiquidity in the credit and capital markets.
19. INCOME TAXES
Income (loss) from continuing operations before income tax expense from domestic and foreign
operations was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. operations |
|
$ |
(255 |
) |
|
$ |
5,846 |
|
|
$ |
7,290 |
|
Canadian operations |
|
|
605 |
|
|
|
458 |
|
|
|
289 |
|
Aruban operations |
|
|
(14 |
) |
|
|
422 |
|
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
before income tax expense |
|
$ |
336 |
|
|
$ |
6,726 |
|
|
$ |
7,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a reconciliation of income tax expense related to continuing operations to income
taxes computed by applying the statutory federal income tax rate (35% for all years presented) to
income from continuing operations before income tax expense (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax expense
at the U.S. statutory rate |
|
$ |
118 |
|
|
$ |
2,354 |
|
|
$ |
2,764 |
|
U.S. state income tax expense,
net of U.S. federal income tax effect |
|
|
4 |
|
|
|
83 |
|
|
|
46 |
|
U.S. manufacturing deduction |
|
|
(53 |
) |
|
|
(88 |
) |
|
|
(71 |
) |
Canadian operations |
|
|
(27 |
) |
|
|
(48 |
) |
|
|
(45 |
) |
Aruban operations |
|
|
7 |
|
|
|
(144 |
) |
|
|
(108 |
) |
Goodwill impairment |
|
|
1,367 |
|
|
|
|
|
|
|
|
|
Permanent differences |
|
|
26 |
|
|
|
16 |
|
|
|
9 |
|
Other, net |
|
|
25 |
|
|
|
(12 |
) |
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
$ |
1,467 |
|
|
$ |
2,161 |
|
|
$ |
2,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Aruba Refinerys profits are non-taxable in Aruba due to a tax holiday granted by the
Government of Aruba (GOA) through December 31, 2010. The tax holiday had an immaterial effect on
our consolidated results of operations for the years ended December 31, 2008, 2007, and 2006.
99
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Components of income tax expense (benefit) related to continuing operations were as follows (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
732 |
|
|
$ |
1,764 |
|
|
$ |
2,198 |
|
U.S. state |
|
|
13 |
|
|
|
96 |
|
|
|
76 |
|
Canada |
|
|
45 |
|
|
|
202 |
|
|
|
51 |
|
Aruba |
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current |
|
|
792 |
|
|
|
2,065 |
|
|
|
2,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
543 |
|
|
|
155 |
|
|
|
285 |
|
U.S. state |
|
|
(8 |
) |
|
|
31 |
|
|
|
(5 |
) |
Canada |
|
|
140 |
|
|
|
(90 |
) |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred |
|
|
675 |
|
|
|
96 |
|
|
|
283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax
expense |
|
$ |
1,467 |
|
|
$ |
2,161 |
|
|
$ |
2,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The tax effects of significant temporary differences representing deferred income tax assets and
liabilities were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Deferred income tax assets: |
|
|
|
|
|
|
|
|
Tax credit carryforwards |
|
$ |
91 |
|
|
$ |
95 |
|
Net operating losses (NOL) |
|
|
78 |
|
|
|
36 |
|
Compensation and employee
benefit liabilities |
|
|
394 |
|
|
|
175 |
|
Environmental |
|
|
93 |
|
|
|
86 |
|
Inventories |
|
|
72 |
|
|
|
224 |
|
Other assets |
|
|
298 |
|
|
|
360 |
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets |
|
|
1,026 |
|
|
|
976 |
|
Less: Valuation allowance |
|
|
(62 |
) |
|
|
(54 |
) |
|
|
|
|
|
|
|
|
|
Net deferred income tax assets |
|
|
964 |
|
|
|
922 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities: |
|
|
|
|
|
|
|
|
Turnarounds |
|
|
(250 |
) |
|
|
(264 |
) |
Property, plant and equipment |
|
|
(4,530 |
) |
|
|
(4,297 |
) |
Inventories |
|
|
(628 |
) |
|
|
(302 |
) |
Other |
|
|
(106 |
) |
|
|
(126 |
) |
|
|
|
|
|
|
|
|
|
Total deferred income tax
liabilities |
|
|
(5,514 |
) |
|
|
(4,989 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liabilities |
|
$ |
(4,550 |
) |
|
$ |
(4,067 |
) |
|
|
|
|
|
|
|
|
|
100
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2008, we had the following U.S. federal and state income tax credit and loss
carryforwards (in millions):
|
|
|
|
|
|
|
|
|
Amount |
|
Expiration |
|
|
|
|
|
|
|
U.S. state income tax credits |
|
$ |
57 |
|
|
2009 through 2029 |
U.S. state income tax credits |
|
|
36 |
|
|
Unlimited |
Foreign tax credit |
|
|
30 |
|
|
2011 |
U.S. state NOL |
|
|
1,606 |
|
|
2009 through 2028 |
We have recorded a valuation allowance as of December 31, 2008 and 2007, due to uncertainties
related to our ability to utilize some of our deferred income tax assets, primarily consisting of
certain state net operating losses, state income tax credits, and foreign tax credits, before they
expire. The valuation allowance is based on our estimates of taxable income in the various
jurisdictions in which we operate and the period over which deferred income tax assets will be
recoverable. The realization of net deferred income tax assets recorded as of December 31, 2008 is
primarily dependent upon our ability to generate future taxable income in certain states and
foreign source income in the United States.
Subsequently recognized tax benefits related to the valuation allowance for deferred income tax
assets as of December 31, 2008 will be allocated as follows (in millions):
|
|
|
|
|
|
|
|
|
|
Income tax benefit in consolidated statement of income |
|
$ |
57 |
|
Additional paid-in capital |
|
|
5 |
|
|
|
|
|
|
Total |
|
$ |
62 |
|
|
|
|
|
|
Deferred income taxes have not been provided on the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and
the respective tax bases of our foreign subsidiaries based on the determination that such
differences are essentially permanent in duration in that the earnings of these subsidiaries are
expected to be indefinitely reinvested in foreign operations. As of December 31, 2008, the
cumulative undistributed earnings of these subsidiaries were approximately $3.9 billion. If those
earnings were not considered indefinitely reinvested, deferred income taxes would have been
recorded after consideration of foreign tax credits. It is not practicable to estimate the amount
of additional tax that might be payable on those earnings, if distributed.
As discussed in Note 1, we adopted the provisions of FIN 48 on January 1, 2007. We did not
recognize a significant change in our liability for uncertain tax positions as a result of our
implementation of FIN 48; however, certain amounts previously reported in deferred income taxes
were reclassified to other long-term liabilities in the consolidated balance sheet as of January
1, 2007. In accordance with the provisions of FIN 48, prior period amounts were not reclassified.
101
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a reconciliation of the change in unrecognized tax benefits (in millions):
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
Balance as of beginning of year |
|
$ |
164 |
|
|
$ |
160 |
|
Additions based on tax positions related to the current year |
|
|
17 |
|
|
|
32 |
|
Additions for tax positions related to prior years |
|
|
67 |
|
|
|
13 |
|
Reductions for tax positions related to prior years |
|
|
(5 |
) |
|
|
(36 |
) |
Reductions for tax positions related to the lapse of applicable
statute of limitations |
|
|
(5 |
) |
|
|
|
|
Settlements |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
Balance as of end of year |
|
$ |
238 |
|
|
$ |
164 |
|
|
|
|
|
|
|
|
|
|
Included in the balance as of December 31, 2008 and 2007 are $136 million and $65 million,
respectively, of tax benefits that, if recognized, would reduce our annual effective tax rate. We
do not expect our unrecognized tax benefits to change significantly over the next 12 months.
We have elected to classify any interest expense and penalties related to income taxes within
income tax expense in our consolidated statements of income. During the years ended December 31,
2008, 2007, and 2006, we recognized approximately $22 million, $1 million, and $25 million in
interest and penalties. We had accrued approximately $68 million and $46 million for the payment
of interest and penalties as of December 31, 2008 and 2007, respectively.
Our tax years through 1999 and UDSs tax years through 2001 are closed to adjustment by the
Internal Revenue Service. Valeros separate tax years 2000 and 2001 (prior to the UDS Acquisition)
have been settled with the exception of a depreciation method. In addition, our tax years 2002
through 2005 are currently under examination and Premcors separate tax years 2004 through 2005 are
also under examination. During 2007, the Internal Revenue Service proposed adjustments to our 2002
and 2003 taxable income, including adjustments related to inventory and depreciation methods. We
are protesting the proposed adjustments and do not expect that the ultimate disposition of these
findings will result in a material change to our financial position or results of operations.
During 2008, Valero settled Premcors 2002-2003 separate tax year audit. We believe that adequate
provisions for income taxes have been reflected in the consolidated financial statements.
20. SEGMENT INFORMATION
We have two reportable segments, refining and retail. Our refining segment includes refining
operations, wholesale marketing, product supply and distribution, and transportation operations.
The retail segment includes company-operated convenience stores, Canadian dealers/jobbers and
truckstop facilities, cardlock facilities, and home heating oil operations. Operations that are
not included in either of the two reportable segments are included in the corporate category.
The reportable segments are strategic business units that offer different products and services.
They are managed separately as each business requires unique technology and marketing strategies.
Performance is evaluated based on operating income. Intersegment sales are generally derived from
transactions made at prevailing market rates.
102
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
Retail |
|
Corporate |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2008: |
|
(in millions) |
Operating revenues from external customers |
|
$ |
108,586 |
|
|
$ |
10,528 |
|
|
$ |
|
|
|
$ |
119,114 |
|
Intersegment revenues |
|
|
7,703 |
|
|
|
|
|
|
|
|
|
|
|
7,703 |
|
Depreciation and amortization expense |
|
|
1,327 |
|
|
|
105 |
|
|
|
44 |
|
|
|
1,476 |
|
Operating income (loss) |
|
|
797 |
|
|
|
369 |
|
|
|
(603 |
) |
|
|
563 |
|
Total expenditures for long-lived assets |
|
|
2,957 |
|
|
|
104 |
|
|
|
141 |
|
|
|
3,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues from external customers |
|
|
86,443 |
|
|
|
8,884 |
|
|
|
|
|
|
|
95,327 |
|
Intersegment revenues |
|
|
6,298 |
|
|
|
|
|
|
|
|
|
|
|
6,298 |
|
Depreciation and amortization expense |
|
|
1,222 |
|
|
|
90 |
|
|
|
48 |
|
|
|
1,360 |
|
Operating income (loss) |
|
|
7,355 |
|
|
|
249 |
|
|
|
(686 |
) |
|
|
6,918 |
|
Total expenditures for long-lived assets |
|
|
2,483 |
|
|
|
107 |
|
|
|
193 |
|
|
|
2,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
  |