e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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þ |
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2006
OR
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o |
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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 1-3473
TESORO CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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95-0862768
(I.R.S. Employer
Identification No.) |
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300 Concord Plaza Drive
San Antonio, Texas
(Address of principal executive offices)
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78216-6999
(Zip Code) |
Registrants telephone number, including area code:
210-828-8484
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
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Name of each exchange on which registered |
Common Stock, $0.16 2/3 par value
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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 Noþ
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 the 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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2
of the Act).
Yes o Noþ
At June 30, 2006, the aggregate market value of the voting common stock held by non-affiliates
of the registrant was approximately $5,069,518,000 based upon the closing price of its common stock
on the New York Stock Exchange Composite tape. At February 21, 2007, there were 68,215,252 shares
of the registrants common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Proxy Statement to be filed pursuant to Regulation 14A pertaining
to the 2007 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. The
Company intends to file such Proxy Statement no later than 120 days after the end of the fiscal
year covered by this Form 10-K.
TESORO CORPORATION
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
This Annual Report on Form 10-K (including documents incorporated by reference herein)
contains statements with respect to our expectations or beliefs as to future events. These types of
statements are forward-looking and subject to uncertainties. See Forward-Looking Statements on
page 45.
When used in this Annual Report on Form 10-K, the terms Tesoro, we, our and us, except
as otherwise indicated or as the context otherwise indicates, refer to Tesoro Corporation and its
subsidiaries.
1
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Tesoro Corporation (Tesoro) is based in San Antonio, Texas. We were incorporated in Delaware
in 1968 under the name Tesoro Petroleum Corporation, which was subsequently changed in 2004 to
Tesoro Corporation. We are one of the largest independent petroleum refiners and marketers in the
United States with two operating segments (1) refining crude oil and other feedstocks at our six
refineries in the western and mid-continental United States and selling refined products in bulk
and wholesale markets (refining) and (2) selling motor fuels and convenience products in the
retail market (retail) through our 460 branded retail stations in 18 states. Through our refining
segment, we produce refined products, primarily gasoline and gasoline blendstocks, jet fuel, diesel
fuel and heavy fuel oils for sale to a wide variety of commercial customers in the western and
mid-continental United States. Our retail segment distributes motor fuels through a network of
retail stations, primarily under the Tesoro® and Mirastar® brands. See Notes C and N in our
consolidated financial statements in Item 8 for additional information on our operating segments
and properties.
Our principal executive offices are located at 300 Concord Plaza Drive, San Antonio, Texas
78216-6999 and our telephone number is (210) 828-8484. We file reports with the SEC, including
annual reports on Form 10-K, quarterly reports on Form 10-Q and other reports from time to time.
The public may read and copy any materials that we file with the SEC at the SECs Public Reference
Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the
operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our SEC filings are
also available to the public on the SECs Internet site at http://www.sec.gov and our website at
http://www.tsocorp.com as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the SEC. You may receive a copy of our Annual Report on Form 10-K,
including the financial statements, free of charge by writing to Tesoro Corporation, Attention:
Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999. We also post our
corporate governance guidelines, code of business conduct, code of ethics for senior financial
officers and our Board of Director committee charters on our website. Our governance documents are
available in print by writing to the address above. We submitted to the New York Stock Exchange on
May 25, 2006 our annual certification concerning corporate governance pursuant to Section 303A.12
(a) of the New York Stock Exchange Listed Company Manual.
PENDING ACQUISITIONS
On January 29, 2007, we entered into agreements with Shell Oil Products US (Shell) to
purchase a 100,000 barrel per day (bpd) refinery and a 42,000 bpd refined products terminal
located south of Los Angeles, California along with approximately 250 Shell-branded retail stations
located throughout Southern California (collectively, the Los Angeles Assets). The purchase
includes a long-term agreement allowing us to continue to operate the retail stations under the
Shell® brand. The purchase price for the Los Angeles Assets is $1.63 billion, plus the
value of petroleum inventories at the time of closing, which is estimated to be $180 million to
$200 million based on January 2007 prices. Upon closing of the acquisitions, Shell has agreed,
subject to certain limitations, to retain certain obligations, responsibilities, liabilities, costs
and expenses, including environmental matters arising out of the pre-closing operations of the
assets. We have agreed to assume certain obligations, responsibilities, liabilities, costs and
expenses arising out of or incurred in connection with decrees, orders and settlements the seller
entered into with governmental and non-governmental entities prior to closing. The transaction,
which will require regulatory approval from the Federal Trade Commission and the Attorney General
of the State of California, is expected to be completed in the second quarter of 2007.
On January 26, 2007, we entered into an agreement with USA Petroleum to purchase 140 retail
stations located primarily in California and a terminal located in New Mexico. The purchase price
of the assets and the USA® brand is $277 million, plus the value of inventories at the
time of closing which is estimated to be $10 million to $15 million based on January 2007 prices.
Tesoro will assume the obligations under the sellers leases, contracts, permits or other
agreements arising after the closing date. USA Petroleum will retain certain pre-closing
liabilities, including environmental matters. The transaction requires regulatory
approval from the Federal Trade Commission and the Attorney General of the State of California and
is expected to be completed in the second quarter of 2007.
The acquisitions of the Los Angeles Assets and USA Petroleum retail stations will be paid with
a combination of debt and cash on-hand, which at December 31, 2006 was $986 million. The exact
amount of debt and cash is yet to be determined.
2
REFINING
We currently own and operate six petroleum refineries, located in California (the Golden Eagle
refinery in the California region), Alaska and Washington (Pacific Northwest region), Hawaii
(Mid-Pacific region) and North Dakota and Utah (Mid-Continent region), and sell refined
products to a wide variety of customers in the western and mid-continental United States. Our
refineries produce a high proportion of our refined product sales volumes, and we purchase the
remainder from other refiners and suppliers. Our six refineries have a combined crude oil capacity
of 563,000 bpd. We operate the largest refineries in Hawaii and Utah, the second largest refineries
in northern California and Alaska, and the only refinery in North Dakota. Capacity and throughput
rates of crude oil and other feedstocks by refinery are as follows:
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Crude Oil |
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Capacity (a) |
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Throughput (bpd) |
Refinery |
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(bpd) |
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2006 |
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2005 |
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2004 |
California |
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Golden Eagle |
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166,000 |
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164,900 |
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164,600 |
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152,800 |
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Pacific Northwest |
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Washington |
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115,000 |
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111,300 |
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110,500 |
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117,200 |
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Alaska |
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72,000 |
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55,800 |
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60,200 |
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57,200 |
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Mid-Pacific |
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Hawaii |
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94,000 |
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84,600 |
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82,700 |
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84,500 |
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Mid-Continent |
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North Dakota |
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58,000 |
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56,300 |
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58,100 |
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56,200 |
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Utah |
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58,000 |
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56,100 |
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53,500 |
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52,500 |
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Total |
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563,000 |
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529,000 |
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529,600 |
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520,400 |
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(a) |
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Crude oil capacity by refinery is obtained from the Oil and Gas Journal. |
We experienced reduced throughput during scheduled refinery maintenance (turnarounds)
at our Golden Eagle, Washington and Alaska refineries in 2006, our Golden Eagle, Washington and
Hawaii refineries in 2005 and our Golden Eagle refinery in 2004. Throughput exceeded our Washington
refinerys crude oil capacity in 2004 due to processing other feedstocks in addition to crude oil.
Feedstock Supply. We purchase crude oil and other feedstocks for our refineries from a
diversified supply of domestic and foreign sources through term agreements with renewal provisions
and in the spot market. Prices under the term agreements generally fluctuate with market prices.
We purchase approximately 43% of our crude oil supplies under term contracts, which are primarily
short-term agreements with market-related prices, and we purchase the remainder in the spot market.
In 2006, we received 53% of our crude oil input from domestic sources (including 16% from Alaskas
North Slope) and 47% from foreign sources (including 14% from Canada). Actual throughput volumes
by feedstock type are summarized below (in thousand bpd):
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2006 |
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2005 |
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2004 |
|
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Volume |
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% |
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Volume |
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% |
|
Volume |
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% |
California |
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Heavy crude (a) |
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153 |
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93 |
% |
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151 |
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91 |
% |
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128 |
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|
84 |
% |
Light crude |
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3 |
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2 |
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6 |
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4 |
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14 |
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9 |
|
Other feedstocks |
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9 |
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5 |
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8 |
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5 |
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11 |
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7 |
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Total |
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165 |
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100 |
% |
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165 |
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100 |
% |
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153 |
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100 |
% |
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Pacific Northwest |
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Heavy crude (a) |
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81 |
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|
49 |
% |
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|
85 |
|
|
|
50 |
% |
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|
89 |
|
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|
51 |
% |
Light crude |
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|
81 |
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|
49 |
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|
78 |
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|
45 |
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|
81 |
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|
|
47 |
|
Other feedstocks |
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5 |
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2 |
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8 |
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|
5 |
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|
4 |
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2 |
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|
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|
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Total |
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167 |
|
|
|
100 |
% |
|
|
171 |
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|
|
100 |
% |
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|
174 |
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|
|
100 |
% |
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3
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|
2006 |
|
2005 |
|
2004 |
|
|
Volume |
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% |
|
Volume |
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% |
|
Volume |
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% |
Mid-Pacific |
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|
|
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|
Heavy crude (a) |
|
|
27 |
|
|
|
32 |
% |
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|
29 |
|
|
|
35 |
% |
|
|
42 |
|
|
|
50 |
% |
Light crude |
|
|
58 |
|
|
|
68 |
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|
|
54 |
|
|
|
65 |
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|
|
42 |
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|
50 |
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Total |
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85 |
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|
100 |
% |
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83 |
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|
100 |
% |
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|
84 |
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|
100 |
% |
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Mid-Continent |
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|
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|
|
|
|
|
|
|
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Light crude |
|
|
108 |
|
|
|
96 |
% |
|
|
107 |
|
|
|
96 |
% |
|
|
104 |
|
|
|
95 |
% |
Other feedstocks |
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|
4 |
|
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|
4 |
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|
4 |
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|
4 |
|
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|
5 |
|
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|
5 |
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|
|
|
|
|
|
|
|
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Total |
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|
112 |
|
|
|
100 |
% |
|
|
111 |
|
|
|
100 |
% |
|
|
109 |
|
|
|
100 |
% |
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|
Total Refining Throughput |
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|
|
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Heavy crude (a) |
|
|
261 |
|
|
|
49 |
% |
|
|
265 |
|
|
|
50 |
% |
|
|
259 |
|
|
|
50 |
% |
Light crude |
|
|
250 |
|
|
|
47 |
|
|
|
245 |
|
|
|
46 |
|
|
|
241 |
|
|
|
46 |
|
Other feedstocks |
|
|
18 |
|
|
|
4 |
|
|
|
20 |
|
|
|
4 |
|
|
|
20 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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Total |
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|
529 |
|
|
|
100 |
% |
|
|
530 |
|
|
|
100 |
% |
|
|
520 |
|
|
|
100 |
% |
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(a) |
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We define heavy crude oil, which generally is sold at a
discount to lighter crudes, as Alaska North Slope or crude oil
with an American Petroleum Institute gravity of 32 degrees or
less. |
Refined Products. Refining yield represents production volumes of refined products
consisting primarily of gasoline and gasoline blendstocks, jet fuel, diesel fuel and heavy fuel
oils. We also manufacture other refined products, including liquefied petroleum gas, petroleum coke
and asphalt. Our refining yields, in volumes, are summarized below (in thousand bpd):
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|
|
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|
|
2006 |
|
2005 |
|
2004 |
|
|
Volume |
|
% |
|
Volume |
|
% |
|
Volume |
|
% |
California |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
96 |
|
|
|
55 |
% |
|
|
93 |
|
|
|
54 |
% |
|
|
96 |
|
|
|
59 |
% |
Diesel fuel |
|
|
49 |
|
|
|
28 |
|
|
|
49 |
|
|
|
28 |
|
|
|
38 |
|
|
|
24 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
30 |
|
|
|
17 |
|
|
|
31 |
|
|
|
18 |
|
|
|
28 |
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
175 |
|
|
|
100 |
% |
|
|
173 |
|
|
|
100 |
% |
|
|
162 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pacific Northwest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Gasoline and gasoline blendstocks |
|
|
67 |
|
|
|
39 |
% |
|
|
74 |
|
|
|
42 |
% |
|
|
74 |
|
|
|
42 |
% |
Jet fuel |
|
|
31 |
|
|
|
18 |
|
|
|
31 |
|
|
|
18 |
|
|
|
31 |
|
|
|
17 |
|
Diesel fuel |
|
|
27 |
|
|
|
16 |
|
|
|
25 |
|
|
|
14 |
|
|
|
27 |
|
|
|
15 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
47 |
|
|
|
27 |
|
|
|
46 |
|
|
|
26 |
|
|
|
47 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
172 |
|
|
|
100 |
% |
|
|
176 |
|
|
|
100 |
% |
|
|
179 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Pacific |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
20 |
|
|
|
23 |
% |
|
|
20 |
|
|
|
24 |
% |
|
|
21 |
|
|
|
25 |
% |
Jet fuel |
|
|
26 |
|
|
|
30 |
|
|
|
26 |
|
|
|
31 |
|
|
|
24 |
|
|
|
28 |
|
Diesel fuel |
|
|
13 |
|
|
|
15 |
|
|
|
12 |
|
|
|
14 |
|
|
|
15 |
|
|
|
17 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
27 |
|
|
|
32 |
|
|
|
26 |
|
|
|
31 |
|
|
|
26 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
86 |
|
|
|
100 |
% |
|
|
84 |
|
|
|
100 |
% |
|
|
86 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
Volume |
|
% |
|
Volume |
|
% |
|
Volume |
|
% |
Mid-Continent |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
62 |
|
|
|
53 |
% |
|
|
61 |
|
|
|
53 |
% |
|
|
60 |
|
|
|
53 |
% |
Jet fuel |
|
|
11 |
|
|
|
10 |
|
|
|
11 |
|
|
|
9 |
|
|
|
11 |
|
|
|
10 |
|
Diesel fuel |
|
|
32 |
|
|
|
27 |
|
|
|
32 |
|
|
|
28 |
|
|
|
30 |
|
|
|
27 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
11 |
|
|
|
10 |
|
|
|
12 |
|
|
|
10 |
|
|
|
12 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
116 |
|
|
|
100 |
% |
|
|
116 |
|
|
|
100 |
% |
|
|
113 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Refining Yield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
245 |
|
|
|
45 |
% |
|
|
248 |
|
|
|
45 |
% |
|
|
251 |
|
|
|
47 |
% |
Jet fuel |
|
|
68 |
|
|
|
12 |
|
|
|
68 |
|
|
|
12 |
|
|
|
66 |
|
|
|
12 |
|
Diesel fuel |
|
|
121 |
|
|
|
22 |
|
|
|
118 |
|
|
|
22 |
|
|
|
110 |
|
|
|
20 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
115 |
|
|
|
21 |
|
|
|
115 |
|
|
|
21 |
|
|
|
113 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
549 |
|
|
|
100 |
% |
|
|
549 |
|
|
|
100 |
% |
|
|
540 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Terminals. To optimize the transportation of crude oil and refined
products within our refinery system and secure shipping capacity, we currently term-charter five
U.S. flag tankers and five foreign-flag tankers, nine of which are double-hulled and one of which
is double-bottomed. Our term charters expire between 2007 and 2010. We have also entered into
term-charters for four U.S. flag tankers beginning in 2009 and 2010 with three year terms and
options to renew. For our Hawaii and Washington operations, we charter several tugs and product
barges over varying terms ending in 2007 through 2015, with options to renew. We also have
arrangements to transport crude oil in double-hulled tankers from certain regions. Other tankers
and ocean-going barges are also chartered on a short-term basis to transport crude oil and refined
products. We also receive crude oils and ship refined products through owned and third-party
pipelines as further described below.
We operate refined products terminals at our refineries and at several other locations in
California, Hawaii, Alaska, Washington and Idaho. We also distribute products through third-party
terminals, truck racks and rail cars, which are supplied by our refineries and through purchases
and exchange agreements with other refining and marketing companies.
Golden Eagle Refinery
Refining. Our Golden Eagle refinery, located in Martinez, California on 2,206 acres about 30
miles east of San Francisco, is a highly complex refinery with a crude oil capacity of 166,000 bpd.
We source our Golden Eagle refinerys crude oil from California, Alaska and foreign locations.
Major refined product upgrading units at the refinery include fluid catalytic cracking (FCC),
fluid coking, hydrocracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation
units. These units enable the refinery to produce a high proportion of motor fuels, including
cleaner-burning California Air Resources Board (CARB) gasoline and CARB diesel, as well as
conventional gasoline and diesel. The refinery also produces heavy fuel oils, liquefied petroleum
gas and petroleum coke. We have commenced a project at the refinery to modify the existing fluid
coking unit into a delayed coking unit which will enable us to comply with the terms of an
abatement order to lower emissions while also enhancing the refinerys capabilities in terms of
reliability, lengthening turnaround cycles and reducing operating costs. We anticipate this
project will be substantially completed during the first quarter of 2008.
Transportation. Our Golden Eagle refinery has waterborne access through the San Francisco Bay
that enables us to receive crude oil and ship refined products through our marine terminals. In
addition, the refinery can receive crude oil through a third-party marine terminal at Martinez. We
also receive California crude oils and ship refined products from the refinery through third-party
pipeline systems.
Terminals. We operate a refined products terminal at Stockton, California and a refined
products terminal at the refinery. We also distribute refined products through third-party
terminals, which are supplied by our refinery and through purchases and exchange arrangements with
other refining and marketing companies. We also lease approximately 800,000 barrels of storage
capacity with waterborne access in southern California.
5
Pacific Northwest Refineries
Washington
Refining. Our Washington refinery, located in Anacortes on the Puget Sound on 917 acres about
60 miles north of Seattle, has a total crude oil capacity of 115,000 bpd. We source our Washington
refinerys crude oil from Alaska, Canada and other foreign locations. The Washington refinery also
processes intermediate feedstocks, primarily heavy vacuum gas oil, provided by some of our other
refineries and by spot-market purchases from third-parties. Major refined product upgrading units
at the refinery include the FCC, alkylation, hydrotreating, vacuum distillation, deasphalting and
naphtha reforming units, which enable our Washington refinery to produce a high proportion of light
products, such as gasoline (including CARB gasoline and components for CARB gasoline), diesel and
jet fuel. The refinery also produces heavy fuel oils, liquefied petroleum gas and asphalt. In the
first quarter of 2006, we completed the modification of a 25,000 bpd diesel desulfurizer unit,
which allows our Washington refinery to manufacture ultra-low sulfur diesel pursuant to regulations
mandated by the EPA.
Transportation. Our Washington refinery receives Canadian crude oil through a third-party
pipeline originating in Edmonton, Alberta, Canada. We receive other crude oil through our
Washington refinerys marine terminal. Our Washington refinery ships products (gasoline, jet fuel
and diesel) through a third-party pipeline system, which serves western Washington and Portland,
Oregon. We also deliver gasoline and diesel fuel through a neighboring refinerys truck rack and
distribute diesel fuel through a truck rack at our refinery. We deliver refined products, including
CARB gasoline and components for CARB gasoline, through our marine terminal to ships and barges and
sell liquefied petroleum gas and asphalt at our refinery.
Terminals. We operate refined products terminals at Anacortes, Port Angeles and Vancouver,
Washington, supplied primarily by our Washington refinery. We also distribute refined products
through third-party terminals in our market areas, supplied by our refinery and through purchases
and exchange arrangements with other refining and marketing companies.
Alaska
Refining. Our Alaska refinery is located near Kenai on the Cook Inlet on 488 acres
approximately 70 miles southwest of Anchorage. Our Alaska refinery processes crude oil from Alaska
and, to a lesser extent, foreign locations. The refinery has a total crude oil capacity of 72,000
bpd, and its refined product upgrading units include vacuum distillation, distillate hydrocracking,
hydrotreating, naphtha reforming and light naphtha isomerization units. Our Alaska refinery
produces gasoline and gasoline blendstocks, jet fuel, diesel fuel, heating oil, heavy fuel oils,
liquefied petroleum gas and asphalt. We are installing a 10,000 bpd diesel desulfurizer unit at the
refinery, which will allow us to manufacture ultra-low sulfur diesel to meet the increasing demand
for cleaner fuels in Alaska. We anticipate that this project will be substantially completed in the
second quarter of 2007.
Transportation. We receive crude oil by tanker and through our owned and operated crude oil
pipeline at our marine terminal. Our crude oil pipeline is a 24-mile common carrier pipeline, which
is connected to the Eastside Cook Inlet oil field. We also own and operate a common-carrier refined
products pipeline that runs from the Alaska refinery to our terminal facilities in Anchorage and to
the Anchorage airport. This 71-mile pipeline has the capacity to transport approximately 40,000 bpd
of refined products and allows us to transport gasoline, diesel and jet fuel to the terminal
facilities. Both of our owned pipelines are subject to regulation by various federal, state and
local agencies, including the Federal Energy Regulatory Commission (FERC). Refined products are
also distributed by tankers and barges from our marine terminal.
Terminals. We operate refined products terminals at Kenai and Anchorage, which are supplied
by our Alaska refinery. We also distribute refined products through a third-party terminal near
Fairbanks, which is supplied through a purchase and exchange arrangement with another refining
company.
6
Mid-Pacific Refinery
Hawaii
Refining. Our 94,000 bpd Hawaii refinery is located at Kapolei on 131 acres about 22 miles
west of Honolulu. We supply the Hawaii refinery with crude oil from Southeast Asia, the Middle East
and other foreign sources. Major refined product upgrading units include the vacuum distillation,
hydrocracking, hydrotreating, visbreaking and naphtha reforming units. The Hawaii refinery produces
gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy fuel oils, liquefied petroleum gas
and asphalt.
Transportation. We transport crude oil to Hawaii by tankers, which discharge through our
single-point mooring terminal, 1.5 miles offshore from our refinery. Three underwater pipelines
from the single-point mooring terminal allow crude oil and refined products to be transferred to
and from the refinerys storage tanks. We distribute refined products to customers on the island of
Oahu through owned and third-party pipeline systems. Our refined products pipelines also connect
the Hawaii refinery to Barbers Point Harbor, 2.5 miles away, where refined products are transferred
to ships and barges.
Terminals. We also distribute refined products from our refinery to customers through
third-party terminals at Honolulu International Airport and Honolulu Harbor and by barge to our
owned and third-party terminal facilities on the islands of Oahu, Maui, Kauai and Hawaii.
Mid-Continent Refineries
North Dakota
Refining. Our 58,000 bpd North Dakota refinery is located near Mandan on 960 acres. We supply
our North Dakota refinery primarily with Williston Basin sweet crude oil. The refinery also can
access other supplies, including Canadian crude oil. Major refined product upgrading units at the
refinery include the FCC, naphtha reforming, hydrotreating and alkylation units. The North Dakota
refinery produces gasoline, diesel fuel, jet fuel, heavy fuel oils and liquefied petroleum gas.
Transportation. We own a crude oil pipeline system, consisting of over 700 miles of pipeline
that delivers all of the crude oil to our North Dakota refinery. Our crude oil pipeline system
gathers crude oil from the Williston Basin and adjacent production areas in North Dakota and
Montana and transports it to our refinery and has the capability to transport crude oil to other
regional points where there is additional demand. Our crude oil pipeline system is a common carrier
subject to regulation by various federal, state and local agencies, including the FERC. We
distribute approximately 85% of our refinerys production through a third-party refined products
pipeline system which serves various areas from Bismarck, North Dakota to Minneapolis, Minnesota.
All gasoline and distillate products from our refinery, with the exception of railroad-spec diesel
fuel, can be shipped through that pipeline to third-party terminals.
Terminals. We operate a refined products terminal at the North Dakota refinery. We also
distribute refined products through a third-party refined products pipeline system which connects
to third-party terminals located in North Dakota and Minnesota. We distribute refined products from
our refinery to customers primarily through these third-party terminals.
Utah
Refining. Our 58,000 bpd Utah refinery is located in Salt Lake City on 145 acres. Our Utah
refinery processes crude oils from Utah, Colorado, Wyoming and Canada. Major refined product
upgrading units include the FCC, naphtha reforming, alkylation and hydrotreating units. The Utah
refinery produces gasoline, diesel fuel, jet fuel, heavy fuel oils and liquefied petroleum gas.
Transportation. Our Utah refinery receives crude oil primarily by third-party pipelines from
fields in Utah, Colorado, Wyoming and Canada. We distribute the refinerys production through a
system of both owned and third-party terminals and third-party pipeline connections, primarily in
Utah, Idaho and eastern Washington, with some refined product delivered in Nevada and Wyoming.
Terminals. In addition to sales at the refinery, we distribute refined products to customers
through a third-party pipeline to our owned terminals in Boise and Burley, Idaho and to third-party
terminals in Pocatello, Idaho and Pasco, Washington.
7
Wholesale Marketing and Refined Product Distribution
We sell refined products including gasoline and gasoline blendstocks, jet fuel, diesel fuel,
heavy fuel oils and residual products in both the bulk and wholesale markets. The majority of our
wholesale volumes are sold in 10 states to independent unbranded distributors that sell refined
products purchased through our owned and third-party terminals. Our bulk volumes are primarily sold
to independent and other oil companies, electric power producers, railroads, airlines and marine
and industrial end-users, which are distributed by pipelines, ships, railcars and trucks. In
addition, we sell refined products that we manufacture, purchase or receive on exchange from third
parties. Exchange agreements provide for the delivery of our refined products primarily to
third-party terminals in exchange for the delivery of refined products from the third parties at
specific locations. Our refined product sales, including intersegment sales to our retail
operations, consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Refined Product Sales (thousand bpd) (a) |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
280 |
|
|
|
294 |
|
|
|
300 |
|
Jet fuel |
|
|
91 |
|
|
|
101 |
|
|
|
90 |
|
Diesel fuel |
|
|
128 |
|
|
|
139 |
|
|
|
133 |
|
Heavy oils, residual products and other |
|
|
87 |
|
|
|
75 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
Total Refined Product Sales |
|
|
586 |
|
|
|
609 |
|
|
|
604 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Total refined product sales were reduced by 23 Mbpd in 2006, as
a result of recording certain purchases and sales transactions
with the same counterparty on a net basis beginning in the 2006
first quarter upon adoption of EITF Issue No. 04-13 (see Note A
of the consolidated financial statements in Item 8 for further
information). |
Gasoline and Gasoline Blendstocks. We sell gasoline and gasoline blendstocks in both the
bulk and wholesale markets in the western and mid-continental United States. The demand for
gasoline is seasonal in many of our markets, with lowest demand during the winter months. We also
sell gasoline to wholesale customers and several major independent and other oil companies under
various supply agreements. We sell, at wholesale, to unbranded distributors and high-volume
retailers, and we distribute refined product through owned and third party terminals. Gasoline also
is delivered to refiners and marketers in exchange for refined product received at other locations
in our markets.
Jet Fuel. We supply jet fuel to passenger and cargo airlines at airports in Alaska, Hawaii,
California, Washington, Utah and other western states. We also supply jet fuel to the U.S. military
in certain of our markets.
Diesel Fuel. We sell our diesel fuel production primarily on a wholesale basis for marine,
transportation, industrial and agricultural use. We sell lesser amounts to end-users through marine
terminals and for power generation in Hawaii and Washington. Upon completion of certain capital
projects in 2007 at our Alaska refinery, we will be able to manufacture ultra-low sulfur diesel
(ULSD) at all of our refineries and become the sole producer of ULSD in both Alaska and Hawaii.
Heavy Fuel Oils and Residual Products. We sell heavy fuel oils to other refineries,
third-party resellers, electric power producers and marine and industrial end-users. Our refineries
supply substantially all of the marine fuels that we sell through leased facilities at Port Angeles
and Seattle, Washington, and Portland, Oregon, and through owned and leased facilities in Alaska
and Hawaii. Our Golden Eagle refinery produces petroleum coke that we sell to industrial end-users.
Sales of Purchased Products. In the normal course of business to meet local market demands,
we purchase refined products manufactured by others for resale to our customers. We purchase these
refined products, primarily gasoline, jet fuel, diesel fuel and industrial and marine fuel
blendstocks, mainly in the spot market. We conduct our gasoline and diesel fuel purchase and resale
activity primarily on the U.S. West Coast. Our jet fuel activity primarily consists of supplying
markets in Alaska, California and Hawaii. We also purchase a lesser amount of gasoline and other
refined products that are sold outside of our refineries local markets.
8
RETAIL
Through our network of retail stations, we sell gasoline and diesel fuel in the western and
mid-continental United States. The demand for gasoline is seasonal in a majority of our markets,
with highest demand for gasoline during the summer driving season. We sell gasoline and diesel to
retail customers through company-operated retail stations and agreements with third-party branded
distributors (or jobber/dealers). As of December 31, 2006, our retail segment included a network
of 460 branded retail stations (under the Tesoro® and Mirastar® brands), comprising 194
company-operated retail stations and 266 jobber/dealer retail stations. Our retail network provides
a committed outlet for a portion of the motor fuels produced by our refineries. Most of our
company-operated retail stations include 2-Go Tesoro® brand convenience stores that sell
a wide variety of merchandise items. The following table summarizes our retail operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Branded Retail Stations (end of period) |
|
|
|
|
|
|
|
|
|
|
|
|
Tesoro® |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
117 |
|
|
|
133 |
|
|
|
137 |
|
Jobber/dealer |
|
|
266 |
|
|
|
268 |
|
|
|
292 |
|
Mirastar® |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
77 |
|
|
|
77 |
|
|
|
78 |
|
Total Branded Retail Stations |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated(a) |
|
|
194 |
|
|
|
210 |
|
|
|
215 |
|
Jobber/dealer(b) |
|
|
266 |
|
|
|
268 |
|
|
|
292 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
460 |
|
|
|
478 |
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of Branded Retail Stations (during year) |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
204 |
|
|
|
213 |
|
|
|
222 |
|
Jobber/dealer |
|
|
261 |
|
|
|
281 |
|
|
|
316 |
|
|
|
|
|
|
|
|
|
|
|
Total Average Retail Stations |
|
|
465 |
|
|
|
494 |
|
|
|
538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fuel Volume (millions of gallons) |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
248 |
|
|
|
258 |
|
|
|
290 |
|
Jobber/dealer |
|
|
186 |
|
|
|
191 |
|
|
|
220 |
|
|
|
|
|
|
|
|
|
|
|
Total Fuel Volumes |
|
|
434 |
|
|
|
449 |
|
|
|
510 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Fuel Volume Per Month Per Retail Station (thousands of gallons) |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
101 |
|
|
|
101 |
|
|
|
109 |
|
Jobber/dealer |
|
|
60 |
|
|
|
57 |
|
|
|
58 |
|
Total retail stations |
|
|
78 |
|
|
|
76 |
|
|
|
79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel Revenues (in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
$ |
674 |
|
|
$ |
609 |
|
|
$ |
566 |
|
Jobber/dealer |
|
|
386 |
|
|
|
335 |
|
|
|
297 |
|
|
|
|
|
|
|
|
|
|
|
Total Fuel Revenues |
|
$ |
1,060 |
|
|
$ |
944 |
|
|
$ |
863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Merchandise and Other Revenues (in millions) |
|
$ |
144 |
|
|
$ |
141 |
|
|
$ |
131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Merchandise Margin (percent of revenues) |
|
|
27 |
% |
|
|
26 |
% |
|
|
28 |
% |
|
|
|
(a) |
|
Company-operated retail stations included 39 in Utah, 33 in
Hawaii, 29 in Alaska, 26 in Washington and 67 in other western
and mid-continental states at December 31, 2006. |
|
(b) |
|
At December 31, 2006, the jobber/dealer retail stations included
69 in North Dakota, 67 in Alaska, 38 in Utah, 27 in Washington,
23 in Idaho, 23 in Minnesota, 13 in California and 6 in other
western states. |
9
COMPETITION AND OTHER
We compete on a global basis with a number of major integrated oil companies who produce crude
oil for use in their refining operations and other companies that may have greater financial and
other resources. The availability and cost of crude oil is affected by global supply and demand
dynamics. Similarly, the supply and prices of refined products are impacted by global dynamics.
Our Golden Eagle and Washington refineries compete with several refineries on the U.S. West Coast.
In addition, products flow into the West Coast from the Gulf Coast and other parts of the world.
Our Hawaii refinery competes primarily with one other refinery in Hawaii, owned by a major
integrated oil company that also is located at Kapolei and has a crude oil capacity of 54,000 bpd.
The Alaska refinery competes with other refineries in Alaska and on the U.S. West Coast. Our
refining competition in Alaska includes two refineries near Fairbanks and a refinery near Valdez.
We estimate that the other Alaska refineries have a combined capacity to process approximately
270,000 bpd of crude oil. Our North Dakota refinery is the only refinery in North Dakota.
Refineries in Wyoming, Montana, the Midwest and the United States Gulf Coast region are the primary
competitors with our North Dakota refinery. Our Utah refinery is the largest of five refineries
located in Utah. We estimate that these other refineries have a combined capacity to process
approximately 107,500 bpd of crude oil. These five refineries collectively supply a high proportion
of the gasoline and distillate products consumed in the states of Utah and Idaho, with additional
supplies provided from refineries in surrounding states. Our Golden Eagle, Washington, Hawaii and
Alaska refineries also compete with companies that import refined products from other parts of the
world, including the Far East and Europe.
Our jet fuel sales in Alaska are concentrated in Anchorage, where we are one of the principal
suppliers to the Anchorage International Airport, a major hub for air cargo traffic between
manufacturing regions in the Far East and markets in the United States and Europe. In Hawaii, jet
fuel sales are concentrated in Honolulu, where we are the principal supplier to the Honolulu
International Airport. We also serve four airports on other islands in Hawaii. In Washington, jet
fuel sales are concentrated at the Seattle/Tacoma International Airport. We also supply jet fuel to
customers in Portland, Oregon; Los Angeles, San Francisco and San Diego, California; Las Vegas and
Reno, Nevada; and Phoenix, Arizona. Other suppliers compete for sales at all of these airports. In
Utah, our jet fuel sales are concentrated in Salt Lake City, and we also supply jet fuel to
customers in Boise, Burley and Pocatello, Idaho. The North Dakota refinery supplies jet fuel to
customers in Minneapolis/St. Paul and Moorhead, Minnesota and in Bismarck and Jamestown, North
Dakota. We compete with other suppliers for U.S. military contracts in Alaska, Hawaii and North
Dakota. Both the Alaska and Hawaii markets periodically require additional jet fuel supplies from
outside the state to meet demand.
We sell our diesel fuel production primarily on a wholesale basis, competing with other
suppliers in all of our market areas. Refined products from foreign sources, including Canada, also
compete for distillate customers in our market areas.
We sell gasoline in Alaska, California, Hawaii, North Dakota, Utah, Washington and other
western and mid-continental states through a network of company-operated retail stations and
branded and unbranded jobber/dealers. From time-to-time we also sell refined product to other
refiners. Competitive factors that affect retail marketing include price, station appearance,
location and brand awareness. Our retail marketing operations compete with other independent
marketing companies, integrated oil companies and high-volume retailers.
GOVERNMENT REGULATION AND LEGISLATION
Environmental Controls and Expenditures
All of our operations, like those of other companies engaged in similar businesses, are
subject to extensive and frequently changing federal, state, regional and local laws, regulations
and ordinances relating to the protection of the environment, including those governing emissions
or discharges to the air and water, the handling and disposal of solid and hazardous wastes and the
remediation of contamination. While we believe our facilities are in substantial compliance with
current requirements, our facilities will continue to be engaged in meeting new requirements
promulgated by the U.S. Environmental Protection Agency (EPA) and the states and local
jurisdictions in which we operate as described below.
10
Changes in fuel standards, including those related to gasoline and diesel fuel sulfur
concentrations, also affect our operations. EPA regulations related to the Clean Air Act require
reductions in the sulfur content in gasoline. Our Golden Eagle, Washington, Hawaii, Alaska and
North Dakota refineries will not require additional capital spending to meet the low sulfur
gasoline standards. We are currently evaluating alternative projects that will satisfy the
requirements to meet the regulations at our Utah refinery.
EPA regulations related to the Clean Air Act also require reductions in the sulfur content in
diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards
became effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content
of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become
effective in phases between 2007 and 2010. We spent $61 million in 2006 to meet the revised diesel
fuel standards, and we have budgeted an additional $18 million in 2007 to complete our diesel
desulfurizer unit to manufacture additional ultra-low sulfur diesel at our Alaska refinery. Our
Golden Eagle, Washington and Hawaii refineries will not require additional capital spending to meet
the new diesel fuel standards. We are currently evaluating alternative projects that will satisfy
the future requirements under existing regulations at both our North Dakota and Utah refineries.
In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro
assumed the sellers obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co. (BP), Amoco Oil Company and Atlantic Richfield Company. BP entered into
this consent decree for both the North Dakota and Utah refineries for various alleged violations.
As the owner of these refineries, Tesoro is required to address issues to reduce air emissions. We
spent $3 million during 2006 and we have budgeted an additional $18 million through 2009 to comply
with this consent decree. We also agreed to indemnify the sellers for all losses of any kind
incurred in connection with the consent decree.
In connection with the 2002 acquisition of our Golden Eagle refinery, subject to certain
conditions, we assumed the sellers obligations pursuant to settlement efforts with the EPA
concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any
potential monetary penalties, which the seller retains. In November 2005, the Consent Decree was
entered by the District Court for the Western District of Texas in which we agreed to undertake
projects at our Golden Eagle refinery to reduce air emissions. To satisfy the requirements of the
Consent Decree, we spent $3 million during 2006 and we have budgeted an additional $25 million
through 2010.
In December 2006, we proposed an alternative monitoring plan and a schedule for removing
atmospheric blowdown towers at the Golden Eagle refinery to the Bay Area Air Quality Management
District in response to a notice of violation (NOV) received from that agency in August 2006. We
have budgeted $88 million through 2010 to remove the atmospheric blowdown towers.
During the fourth quarter of 2005, we received approval by the Hearing Board for the Bay Area
Air Quality Management District to modify our existing fluid coker unit to a delayed coker at our
Golden Eagle refinery which is designed to lower emissions while also enhancing the refinerys
capabilities in terms of reliability, lengthening turnaround cycles and reducing operating costs.
We negotiated the terms and conditions of the Second Conditional Abatement Order with the District
in response to the January 2005 mechanical failure of the fluid coker boiler at the Golden Eagle
refinery. The total capital budget for this project is $503 million, which includes budgeted
spending of $231 million in 2007 and $145 million in 2008. The project is currently scheduled to be
substantially completed during the first quarter of 2008, with spending through the first half of
2008. We have spent $127 million from inception of the project, of which $124 million was spent in
2006.
We will also spend capital at the Golden Eagle refinery for reconfiguring and replacing
above-ground storage tank systems and upgrading piping within the refinery. We spent $26 million
during 2006 and we have budgeted an additional $110 million through 2011 to complete the project.
Our capital budget also includes spending of $29 million through 2010 to upgrade a marine oil
terminal at the Golden Eagle refinery to meet engineering and maintenance standards issued by the
State of California in February 2006.
Conditions may develop that cause increases or decreases in future expenditures for our
various sites, including, but not limited to, our refineries, tank farms, retail stations
(operating and closed locations) and refined products terminals, and for compliance with the Clean
Air Act and other federal, state and local requirements. We cannot currently determine the amounts
of such future expenditures. For further information on environmental matters and other
contingencies, see Note N in our consolidated financial statements in Item 8.
11
Environmental Controls and Expenditures Pending Acquisition of the Los Angeles Assets
The Los Angeles Assets are subject to extensive environmental requirements. If we consummate
the purchase of the Los Angeles Assets, we anticipate spending approximately $375 million to $400
million between 2007 and 2011 for various environmental projects at the refinery primarily to lower
air emissions. These cost estimates will be further reviewed and analyzed after the transaction is
completed and we acquire additional information through the operation of the assets.
Oil Spill Prevention and Response
We operate in environmentally sensitive coastal waters, where tanker, pipeline and refined
product transportation operations are closely regulated by federal, state and local agencies and
monitored by environmental interest groups. The transportation of crude oil and refined product
over water involves risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990
and related state regulations, which require that most oil refining, transport and storage
companies maintain and update various oil spill prevention and oil spill contingency plans. We have
submitted these plans and received federal and state approvals necessary to comply with the Federal
Oil Pollution Act of 1990 and related regulations. Our oil spill prevention plans and procedures
are frequently reviewed and modified to prevent oil and refined product releases and to minimize
potential impacts should a release occur.
We currently charter tankers to ship crude oil from foreign and domestic sources to our Golden
Eagle, Mid-Pacific and Pacific Northwest refineries. The Federal Oil Pollution Act of 1990
requires, as a condition of operation, that we demonstrate the capability to respond to the worst
case discharge to the maximum extent practicable. As an example, the State of Alaska requires us
to provide spill-response capability to contain or control and cleanup amounts equal to 50,000
barrels of crude oil for a tanker carrying fewer than 500,000 barrels and 300,000 barrels for a
tanker carrying more than 500,000 barrels. To meet these requirements, we have entered into
contracts with various parties to provide spill response services. We have entered into
spill-response agreements with (1) Cook Inlet Spill Prevention and Response, Incorporated (for
which we fund approximately 82% of expenditures) and Alyeska Pipeline Service Company for
spill-response services in Alaska and (2) Clean Islands Council for response services throughout
the State of Hawaii. In addition, for larger spill contingency capabilities, we have entered into
contracts with Marine Spill Response Corporation for Hawaii, the San Francisco Bay and Puget Sound.
We believe these contracts, and those with other regional spill-response organizations that are in
place on a location by location basis, provide the additional services necessary to meet
spill-response requirements established by state and federal law.
Regulation of Pipelines
Our crude oil pipeline system in North Dakota and our pipeline systems in Alaska are common
carriers subject to regulation by various federal, state and local agencies, including the FERC
under the Interstate Commerce Act. The Interstate Commerce Act provides that, to be lawful, the
rates of common carrier petroleum pipelines must be just and reasonable and not unduly
discriminatory.
The intrastate operations of our crude oil pipeline system are subject to regulation by the
North Dakota Public Services Commission. The intrastate operations of our Alaska pipelines are
subject to regulation by the Regulatory Commission of Alaska. Like the FERC, the state regulatory
authorities require that we notify shippers of proposed intrastate tariff increases and they have
an opportunity to protest the increases. The North Dakota Public Services Commission also files
with the state authorities copies of interstate tariff charges filed with the FERC. In addition to
challenges to new or proposed rates, challenges to intrastate rates that have already become
effective are permitted by complaint of an interested person or by independent action of the
appropriate regulatory authority.
EMPLOYEES
At December 31, 2006, we had approximately 3,950 full-time employees 1,125 of whom are
covered by collective bargaining agreements with terms expiring on January 31, 2009. We consider
our relations with our employees to be satisfactory.
12
PROPERTIES
Our principal properties are described above under the captions Refining and Retail. In
addition, we own feedstock and refined product storage facilities at our refinery and terminal
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. We are the lessee under a number
of cancelable and non-cancelable leases for certain properties, including office facilities, retail
facilities, ship charters and equipment used in the storage, transportation and production of
feedstocks and refined products. See Notes D and N in our consolidated financial statements in Item
8.
We conduct our retail business under the Tesoro®, Tesoro Alaska®, Mirastar®, and 2-Go Tesoro®
brands. Our retail marketing system under these brands includes 460 branded retail stations, of
which 194 are company-operated.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of our executive officers, their ages and their positions at Tesoro as
of February 1, 2007.
|
|
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
|
Position Held Since |
Bruce A. Smith
|
|
|
63 |
|
|
Chairman of the Board of
Directors, President and
Chief Executive Officer
|
|
June 1996 |
|
|
|
|
|
|
|
|
|
William J. Finnerty
|
|
|
58 |
|
|
Executive Vice President and
Chief Operating Officer
|
|
February 2006 |
|
|
|
|
|
|
|
|
|
Everett D. Lewis
|
|
|
59 |
|
|
Executive Vice President,
Strategy and Asset
Management
|
|
January 2007 |
|
|
|
|
|
|
|
|
|
Gregory A. Wright
|
|
|
57 |
|
|
Executive Vice President and
Chief Financial Officer
|
|
December 2003 |
|
|
|
|
|
|
|
|
|
W. Eugene Burden
|
|
|
58 |
|
|
Senior Vice President,
Government Affairs
|
|
February 2006 |
|
|
|
|
|
|
|
|
|
Claude A. Flagg
|
|
|
53 |
|
|
Senior Vice President,
Strategy
|
|
January 2007 |
|
|
|
|
|
|
|
|
|
J. William Haywood
|
|
|
54 |
|
|
Senior Vice President,
Refining
|
|
March 2005 |
|
|
|
|
|
|
|
|
|
Joseph M. Monroe
|
|
|
52 |
|
|
Senior Vice President,
Business Development and
Logistics
|
|
January 2007 |
|
|
|
|
|
|
|
|
|
Charles S. Parrish
|
|
|
49 |
|
|
Senior Vice President,
General Counsel and
Secretary
|
|
May 2006 |
|
|
|
|
|
|
|
|
|
Daniel J. Porter
|
|
|
51 |
|
|
Senior Vice President,
Marketing
|
|
April 2005 |
|
|
|
|
|
|
|
|
|
Lynn D. Westfall
|
|
|
54 |
|
|
Senior Vice President,
External Affairs and Chief
Economist
|
|
January 2007 |
|
|
|
|
|
|
|
|
|
Arlen O. Glenewinkel, Jr.
|
|
|
50 |
|
|
Vice President and Controller
|
|
December 2006 |
|
|
|
|
|
|
|
|
|
Susan A. Lerette
|
|
|
48 |
|
|
Vice President, Human
Resources
|
|
May 2005 |
|
|
|
|
|
|
|
|
|
Otto C. Schwethelm
|
|
|
52 |
|
|
Vice President, Finance and
Treasurer
|
|
March 2006 |
|
|
|
|
|
|
|
|
|
Sarah S. Simpson
|
|
|
37 |
|
|
Vice President, Corporate
Communications
|
|
June 2005 |
|
|
|
|
|
|
|
|
|
G. Scott Spendlove
|
|
|
43 |
|
|
Vice President, Strategy and
Long-Term Planning
|
|
December 2006 |
13
There are no family relationships among the officers listed, and there are no arrangements or
understandings pursuant to which any of them were elected as officers. Officers are elected
annually by our Board of Directors at their first meeting following the annual meeting of
stockholders. The term of each office runs until the corresponding meeting of the Board of
Directors in the next year or until a successor has been elected or qualified. Positions
held for at least the past five years for each of our executive officers is described below
(positions, unless otherwise specified, are with Tesoro).
Bruce A. Smith was named Chairman of the Board of Directors, President and Chief Executive
Officer in June 1996.
William J. Finnerty was named Executive Vice President and Chief Operating Officer in February
2006. Prior to that, he served as Executive Vice President, Operations beginning in January 2005
and Senior Vice President, Supply and Distribution of Tesoro Refining and Marketing Company
beginning in February 2004. He joined Tesoro in December 2003 as Vice President, Crude Oil and
Logistics, of Tesoro Refining and Marketing Company. Prior to joining Tesoro, Mr. Finnerty served
as Vice President, Trading North America Crude, for ChevronTexaco from October 2001 to November
2003.
Everett D. Lewis was named Executive Vice President, Strategy and Asset Management in January
2007. Prior to that, he served as Executive Vice President, Strategy beginning in January 2005 and
Senior Vice President, Corporate Strategic Planning from November 2004 to January 2005. Mr. Lewis
served as Senior Vice President, Planning and Optimization from February 2003 to November 2004 and
Senior Vice President, Planning and Risk Management from April 2001 to February 2003.
Gregory A. Wright was named Executive Vice President and Chief Financial Officer in December
2003. Prior to that, he served as Senior Vice President and Chief Financial Officer from April 2001
to December 2003.
W. Eugene Burden was named Senior Vice President, Government Affairs in February 2006. Prior
to that, he served as Senior Vice President, External Affairs from November 2004 to February 2006,
Senior Vice President, Human Resources and Government Relations from June 2002 to November 2004,
President of Tesoro Alaska Company from February 2001 to June 2002, and Senior Vice President and
President, Northwest Region of Tesoro Refining and Marketing Company from September 2001 until June
2002.
Claude A. Flagg was named Senior Vice President, Strategy in January 2007. Prior to that, he
served as Senior Vice President, Supply and Optimization beginning in February 2005. He joined
Tesoro in January 2005 as Senior Vice President, Planning and Optimization. Prior to joining
Tesoro, he served as General Manager of Supply Optimization at Shell Oil Products U.S. from January
2003 to December 2004. From May 2002 to January 2003, Mr. Flagg was General Manager of Supply
Optimization at Equilon Enterprises, LLC. He was General Manager of Equilon Enterprises, LLCs
Bay/Valley Refining Complex from April 1999 to May 2002.
J. William Haywood was named Senior Vice President, Refining in March 2005. He joined Tesoro
in May 2002 as Senior Vice President and also became President of the California Region of Tesoro
Refining and Marketing Company in September 2002. Prior to joining Tesoro, Mr. Haywood served as
Regional Vice President of Ultramar Diamond Shamrock Corporation, responsible for California
refineries from September 2000 to May 2002.
Joseph M. Monroe was named Senior Vice President, Business Development and Logistics in
January 2007. Prior to that, he served as Senior Vice President, Corporate Development beginning
in February 2006, Senior Vice President, Business Integration and Analysis from February 2005 to
February 2006 and Senior Vice President, Organizational Effectiveness from November 2004 to
February 2005. Mr. Monroe served as Senior Vice President, Strategic Planning and Business
Development of Tesoro Petroleum Companies, Inc. from February 2004 to November 2004 and as Senior
Vice President, Supply and Distribution, of Tesoro Refining and Marketing Company from May 2002 to
February 2004. Prior to joining Tesoro, he was Vice President, Pipelines and Terminals of Unocal
Corporation and President of Unocal Pipeline Company from January 1999 through May 2002.
14
Charles S. Parrish was named Senior Vice President, General Counsel and Secretary in May 2006.
Prior to that, he served as Vice President, General Counsel and Secretary beginning in March 2005
and as Vice President, Assistant General Counsel and Secretary beginning in November 2004. Mr.
Parrish served as Vice President, Assistant General Counsel of Tesoro Petroleum Companies, Inc.
from March 2003 to November 2004. From 1995 through March 2003, he served numerous roles in the
Companys legal department, primarily focused on matters related to the Companys capital structure
and Securities Act reporting.
Daniel J. Porter was named Senior Vice President, Marketing in April 2005. Prior to that, he
served as President of the Northwest Region of Tesoro Refining and Marketing Company and Anacortes
Refinery Manager from June 2002 to April 2005. He was also President of the Northern Great Plains
Region and Mandan Refinery Manager from September 2001 to June 2002.
Lynn D. Westfall was named Senior Vice President, External Affairs and Chief Economist in
January 2007. Prior to that, he served as Senior Vice President, Chief Economist beginning in May
2006, Vice President, Chief Economist from August 2005 to May 2006 and as Vice President,
Development and Business Analysis from January 2002 to August 2005.
Arlen O. Glenewinkel, Jr. was named Vice President and Controller in December 2006. Prior to
that, Mr. Glenewinkel served as Vice President, Enterprise Risk beginning in April 2005, Vice
President, Internal Audit, from August 2002 to April 2005 and Director, Business Processes from
July 2001 to August 2002.
Susan A. Lerette was named Vice President, Human Resources in May 2005. Prior to that, she
served as Vice President, Human Resources and Communications from May 2004 to May 2005. From April
2001 to May 2004, she served as Vice President, Communications.
Otto C. Schwethelm was named Vice President, Finance and Treasurer in March 2006. Prior to
that, he served as Vice President and Controller from February 2003 to March 2006 and as Vice
President and Operations Controller from September 2002 to February 2003. From December 2001 to
September 2002, Mr. Schwethelm served as Vice President, Shared Services of Tesoro Petroleum
Companies, Inc.
Sarah S. Simpson was named Vice President of Corporate Communications in June 2005. Prior to
joining Tesoro, she served as Director of Corporate Communications and Community Relations at
Cemex, Inc. from November 2004 to June 2005. From July 2000 to November 2004, she served as
Director of Corporate Communications at Waste Management, Inc.
G. Scott Spendlove was named Vice President, Strategy and Long-Term Planning in December 2006.
Prior to that, he served as Vice President and Controller beginning in March 2006 and Vice
President, Finance and Treasurer from May 2003 to March 2006. Mr. Spendlove also served as Vice
President, Finance from January 2002 to May 2003.
BOARD OF DIRECTORS OF THE REGISTRANT
The following is a list of our Board of Directors:
|
|
|
Bruce A. Smith
|
|
Chairman, President and Chief Executive Officer of Tesoro Corporation |
|
|
|
Steven H. Grapstein
|
|
Lead Director of Tesoro Corporation; Chief Executive Officer of Kuo
Investment Company |
|
|
|
John F. Bookout, III
|
|
Retired Director of McKinsey & Company; Senior Advisor to First
Reserve Corporation |
|
|
|
Rodney F. Chase
|
|
Chairman of Petrofac, Ltd. and Senior Advisor to Lehman Brothers, Inc. |
|
|
|
Robert W. Goldman
|
|
Vice President, Finance for World Petroleum Council; Retired Chief
Financial Officer of Conoco, Inc. |
|
|
|
William J. Johnson
|
|
Petroleum Consultant; President of JonLoc, Inc. |
|
|
|
A. Maurice Myers
|
|
Retired Chairman, President and Chief Executive Officer of Waste
Management, Inc. |
15
|
|
|
Donald H. Schmude
|
|
Retired Vice President of Texaco and President and Chief Executive
Officer of Texaco Refining & Marketing, Inc. |
|
|
|
Patrick J. Ward
|
|
Retired Chairman, President and Chief Executive Officer of Caltex
Petroleum Corporation |
|
|
|
Michael E. Wiley
|
|
Retired Chairman, President and Chief Executive Officer of Baker
Hughes, Inc. |
ITEM 1A. RISK FACTORS
The volatility of crude oil prices, refined product prices and natural gas and electrical power
prices may have a material adverse effect on our cash flow and results of operations.
Our earnings and cash flows from our refining and wholesale marketing operations depend on a
number of factors, including fixed and variable expenses (including the cost of crude oil and other
refinery feedstocks) and the margin above those expenses at which we are able to sell refined
products. In recent years, the prices of crude oil and refined products have fluctuated
substantially. These prices depend on numerous factors beyond our control, including the global
supply and demand for crude oil, gasoline and other refined products, which are subject to, among
other things:
|
|
|
changes in the global economy and the level of foreign and domestic production of crude
oil and refined products; |
|
|
|
|
threatened or actual terrorist incidents, acts of war, and other global political
conditions; |
|
|
|
|
availability of crude oil and refined products and the infrastructure to transport
crude oil and refined products; |
|
|
|
|
weather conditions, hurricanes or other natural disasters; |
|
|
|
|
government regulations; and |
|
|
|
|
local factors, including market conditions, the level of operations of other refineries
in our markets, and the volume of refined products imports. |
Prices for refined products are influenced by the price of crude oil. We do not produce crude
oil and must purchase all of our crude oil, the price of which fluctuates on worldwide market
conditions. Generally, an increase or decrease in the price of crude oil affects the price of
gasoline and other refined products. However, the prices for crude oil and prices for our refined
products can fluctuate in different directions based on global market conditions. In addition, the
timing of the relative movement of the prices (both among different classes of refined products and
among various global markets for similar refined products) as well as the overall change in refined
product prices, can reduce profit margins and could have a significant impact on our refining and
wholesale marketing operations, earnings and cash flow. Also, crude oil supply contracts are
generally term contracts with market-responsive pricing provisions. We purchase our refinery
feedstocks weeks before manufacturing and selling the refined products. Price level changes during
the period between purchasing feedstocks and selling the manufactured refined products from these
feedstocks could have a significant effect on our financial results. We also purchase refined
products manufactured by others for sale to our customers. Price level changes during the periods
between purchasing and selling these refined products also could have a material adverse effect on
our business, financial condition and results of operations.
Volatile prices for natural gas and electrical power used by our refineries and other
operations have affected manufacturing and operating costs. Natural gas and electricity prices have
been and will continue to be affected by supply and demand for fuel and utility services in both
local and regional markets.
Our business is impacted by risks inherent in refining operations.
The operation of refineries, pipelines and refined products terminals is inherently subject to
spills, discharges or other releases of petroleum or hazardous substances. If any of these events
had previously occurred or occurs in the future in connection with any of our refineries, pipelines
or refined products terminals, or in connection with any
16
facilities to which we sent wastes or by-products for treatment or disposal, other than events
for which we are indemnified, we could be liable for all costs and penalties associated with their
remediation under federal, state and local environmental laws or common law, and could be liable
for property damage to third parties caused by contamination from releases and spills. The
penalties and clean-up costs that we may have to pay for releases or spills, or the amounts that we
may have to pay to third parties for damage to their property, could be significant and the payment
of these amounts could have a material adverse effect on our business, financial condition and
results of operations.
We operate in environmentally sensitive coastal waters, where tanker, pipeline and refined
product transportation operations are closely regulated by federal, state and local agencies and
monitored by environmental interest groups. Our Golden Eagle, Mid-Pacific and Pacific Northwest
refineries import crude oil feedstocks by tanker. Transportation of crude oil and refined products
over water involves inherent risk and subjects us to the provisions of the Federal Oil Pollution
Act of 1990 and state laws in California, Hawaii, Washington and Alaska. Among other things, these
laws require us to demonstrate in some situations our capacity to respond to a worst case
discharge to the maximum extent possible. We have contracted with various spill response service
companies in the areas in which we transport crude oil and refined products to meet the
requirements of the Federal Oil Pollution Act of 1990 and state laws. However, there may be
accidents involving tankers transporting crude oil or refined products, and response services may
not respond to a worst case discharge in a manner that will adequately contain that discharge, or
we may be subject to liability in connection with a discharge.
The dangers inherent in our operations and the potential limits on insurance coverage could expose
us to potentially significant liability costs.
Our operations are subject to hazards and risks inherent in refining operations and in
transporting and storing crude oil and refined products, such as fires, natural disasters,
explosions, pipeline ruptures and spills and mechanical failure of equipment at our or third-party
facilities, any of which can result in damage to our properties and the properties of others. A
serious accident could also result in serious injury or death to our employees or contractors and
could expose us to significant liability for personal injury claims and reputational risk. In
addition, we operate six petroleum refineries, any of which could experience a major accident, be
damaged by severe weather or other natural disaster, or otherwise be forced to shut down. Any such
unplanned shutdown could have a material adverse effect on our business, financial condition and
results of operations. While we carry property, casualty and business interruption insurance, we do
not maintain insurance coverage against all potential losses, and we could suffer losses for
uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a material adverse effect
on our business, financial condition and results of operations.
Our operations are subject to general environmental risks, expenses and liabilities which could
affect our results of operations.
From time to time we have been, and presently are, subject to litigation and investigations
with respect to environmental and related matters, including product liability claims related to
the oxygenate MTBE. We may become involved in further litigation or other proceedings, or we may be
held responsible in any existing or future litigation or proceedings, the costs of which could be
material.
We have in the past operated retail stations with underground storage tanks in various
jurisdictions, and currently operate retail stations that have underground storage tanks in 18
states in the mid-continental and western United States. Federal and state regulations and
legislation govern the storage tanks, and compliance with these requirements can be costly. The
operation of underground storage tanks also poses certain other risks, including damages associated
with soil and groundwater contamination. Leaks from underground storage tanks which may occur at
one or more of our retail stations, or which may have occurred at our previously operated retail
stations, may impact soil or groundwater and could result in fines or civil liability for us.
Consistent with the experience of other U.S. refineries, environmental laws and regulations
have raised operating costs and require significant capital investments at our refineries. We
believe that existing physical facilities at our refineries are substantially adequate to maintain
compliance with existing applicable laws and regulatory requirements. However, potentially material
expenditures could be required in the future. For example, we may be required to comply with
evolving environmental, health and safety laws, regulations or requirements that may be
17
adopted or imposed in the future. We also may be required to address information or conditions
that may be discovered in the future and that require a response.
Assembly Bill 32, a California bill that creates a statewide cap on greenhouse gas emissions
and requires that the state return to 1990 emission levels by 2020, was passed by the California
legislature and was signed by Governor Schwarzenegger on September 27, 2006. The bill focuses on
using market mechanisms, such as offsets and cap-and-trade programs, to achieve the targets.
Regulations under the bill have not yet been promulgated. The bill specifies that any established
greenhouse gas allowances will be assigned to the entity regulated under the cap. Implementation is
slated to begin January 1, 2010 with full implementation to occur by 2020. The implementation and
implications of this legislation will take many years to realize, and we cannot predict at this
time what impact, if any, this legislation will have on our business.
Currently, various legislative and regulatory measures to address greenhouse gas emissions
(including carbon dioxide, nitrogen oxides and sulfur dioxide) are in various phases of discussion
or implementation. These include proposed federal legislation and state actions to develop
statewide or regional programs, each of which have imposed or would impose reductions in greenhouse
gas emissions. These actions could result in increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls on our facilities and (iii) administer and manage
any greenhouse gas emissions program. These actions could also impact the consumption of refined
products, thereby affecting our operations.
We are subject to interruptions of supply and increased costs as a result of our reliance on
third-party transportation of crude oil and refined products.
Our Washington refinery receives all of its Canadian crude oil and delivers a high proportion
of its gasoline, diesel and jet fuel through third-party pipelines and the balance through marine
vessels. Our Hawaii and Alaska refineries receive most of their crude oil and transport a
substantial portion of refined products through ships and barges. Our Utah refinery receives
substantially all of its crude oil and delivers substantially all of its refined products through
third-party pipelines. Our North Dakota refinery delivers substantially all of its refined products
through a third-party pipeline system. Our Golden Eagle refinery receives approximately one-third
of its crude oil through pipelines and the balance through marine vessels. Substantially all of our
Golden Eagle refinerys production is delivered through third-party pipelines, ships and barges. In
addition to environmental risks discussed above, we could experience an interruption of supply or
an increased cost to deliver refined products to market if the ability of the pipelines or vessels
to transport crude oil or refined products is upset because of accidents, governmental regulation
or third-party action. A prolonged upset of the ability of a pipeline or vessels to transport crude
oil or refined product could have a material adverse effect on our business, financial condition
and results of operations.
The pending acquisitions of the Los Angeles Assets and of the USA Petroleum retail stations
are subject to regulatory approvals that could delay or prevent us from acquiring the assets.
The consummation of the acquisitions of the Los Angeles Assets and of the USA Petroleum retail
stations are subject to approval by the Federal Trade Commission and the Attorney General of the
State of California. The failure to obtain these approvals could delay or prevent the consummations
of either or both of these acquisitions.
Terrorist attacks and threats or actual war may negatively impact our business.
Our business is affected by global economic conditions and fluctuations in consumer confidence
and spending, which can decline as a result of numerous factors outside of our control, such as
actual or threatened terrorist attacks and acts of war. Terrorist attacks, as well as events
occurring in response to or in connection with them, including future terrorist attacks against
U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies,
or military or trade disruptions impacting our suppliers or our customers or energy markets in
general, may adversely impact our operations. As a result, there could be delays or losses in the
delivery of supplies and raw materials to us, delays in our delivery of refined products, decreased
sales of our refined products and extension of time for payment of accounts receivable from our
customers. Strategic targets such as energy-related assets (which could include refineries such as
ours) may be at greater risk of future terrorist attacks than other targets in the United States.
These occurrences could significantly impact energy prices, including prices for our crude oil and
refined products, and have a material adverse impact on the margins from our refining and wholesale
marketing operations. In addition, disruption or significant increases in energy prices could
result in government-imposed price controls.
18
Any one of, or a combination of, these occurrences could have a material adverse effect on our
business, financial condition and results of operations.
Our operating results are seasonal and generally are lower in the first and fourth quarters of the
year.
Demand for gasoline is higher during the spring and summer months than during the winter
months in most of our markets due to seasonal increases in highway traffic. As a result, our
operating results for the first and fourth quarters are generally lower than for those in the
second and third quarters.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
In the ordinary course of business, we become party to or otherwise involved in lawsuits,
administrative proceedings and governmental investigations, including environmental, regulatory and
other matters. Large and sometimes unspecified damages or penalties may be sought from us in some
matters and some matters may require years for us to resolve. We cannot provide assurance that an
adverse resolution of one or more of the matters described below during a future reporting period
will not have a material adverse effect on our financial position or results of operations in
future periods. However, on the basis of existing information, we believe that the resolution of
these matters, individually or in the aggregate, will not have a material adverse effect on our
financial position or results of operations.
In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging
that Tosco misrepresented, concealed and failed to disclose certain additional environmental
conditions at our Golden Eagle refinery. The court granted Toscos motion to compel arbitration of
our claims for these certain additional environmental conditions. In the arbitration proceedings we
initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable
for investigation and remediation of these certain additional environmental conditions, the amount
of which is currently unknown and therefore a reserve has not been established, and which may not
be covered by the $50 million indemnity for the defined environmental liabilities arising from
pre-acquisition operations. In response to our arbitration claims, Tosco filed counterclaims in the
Contra Costa County Superior Court action alleging that we are contractually responsible for
additional environmental liabilities at our Golden Eagle refinery, including the defined
environmental liabilities arising from pre-acquisition operations. The arbitration is scheduled to
begin during March 2007. We intend to vigorously prosecute our claims against Tosco and to oppose
Toscos claims against us, although we cannot provide assurance that we will prevail. For further
information related to the claims, see Note N in our consolidated financial statements in Item 8.
As previously disclosed, we are a defendant, along with other manufacturing, supply and
marketing defendants, in ten pending cases alleging MTBE contamination in groundwater. The
defendants are being sued for having manufactured MTBE and having manufactured, supplied and
distributed gasoline containing MTBE. The plaintiffs, all in California, are generally water
providers, governmental authorities and private well owners alleging, in part, the defendants are
liable for manufacturing or distributing a defective product. The suits generally seek individual,
unquantified compensatory and punitive damages and attorneys fees, but we cannot estimate the
amount or likelihood of the ultimate resolution of these matters at this time, and accordingly, we
have not established a reserve for these cases. We believe we have defenses to these claims and
intend to vigorously defend the lawsuits.
In October 2005, we received a NOV from the United Stated Environmental Protection Agency
(EPA). The EPA alleges certain modifications made to the fluid catalytic cracking unit at our
Washington refinery prior to our acquisition of the refinery were made in violation of the Clean
Air Act. We have investigated the allegations and believe the ultimate resolution of the NOV will
not have a material adverse effect on our financial position or results of operations.
In September 2006, we reached an agreement with the Bay Area Air Quality Management District
(the District) to settle 28 NOVs issued to Tesoro from January 2004 to September 2004 alleging
violations of various air quality requirements at the Golden Eagle refinery. The settlement
agreement was executed on October 11, 2006 and Tesoro made a cash payment of $200,000 to the
District during the fourth quarter of 2006. Pursuant to the terms of the settlement agreement,
Tesoro will undertake a supplemental project valued at approximately $100,000.
19
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
The following performance graph and related information shall not be deemed soliciting
material or to be filed with the Securities and Exchange Commission, nor shall such information
be incorporated by reference into any future filing under the Securities Act of 1933 or Securities
Exchange Act of 1934, each as amended, except to the extent that Tesoro specifically incorporates
it by reference into such filing.
The performance graph below compares the cumulative total return of our common stock to the
cumulative total return of the S&P Composite Index and to a composite peer group of companies. The
composite peer group (the Peer Group) includes the following: Alon USA Energy, Inc., Frontier Oil
Corporation, Holly Corporation, Marathon Oil Corporation, Sunoco, Inc., and Valero Energy
Corporation. The graph below is for the period of five years commencing December 31, 2001 and
ending December 31, 2006.
Comparison of Five Year Cumulative Total Return*
Among the Company, the S&P 500 Index and Composite Peer Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/31/2001 |
|
12/31/2002 |
|
12/31/2003 |
|
12/31/2004 |
|
12/31/2005 |
|
12/31/2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tesoro |
|
$ |
100 |
|
|
$ |
34 |
|
|
$ |
111 |
|
|
$ |
243 |
|
|
$ |
471 |
|
|
$ |
507 |
|
S&P 500 |
|
$ |
100 |
|
|
$ |
78 |
|
|
$ |
100 |
|
|
$ |
111 |
|
|
$ |
116 |
|
|
$ |
134 |
|
Peer Group |
|
$ |
100 |
|
|
$ |
79 |
|
|
$ |
122 |
|
|
$ |
165 |
|
|
$ |
334 |
|
|
$ |
371 |
|
|
|
|
* |
|
Assumes that the value of the investment in common stock and each index was $100 on December
31, 2001, and that all dividends were reinvested. Investment is weighted on the basis of market
capitalization. |
Note: The stock price performance shown on the graph is not necessarily indicative of future
performance.
20
Our common stock is listed under the symbol TSO on the New York Stock Exchange.
Summarized below are high and low sales prices of and dividends declared on our common stock on the
New York Stock Exchange during 2006 and 2005. Quarterly cash dividends have been declared for each
quarter beginning in June 2005. Prior to June 2005, we had not paid dividends on our common stock
since 1986.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Prices per |
|
Dividends |
|
|
Common Share |
|
Per |
Quarter Ended |
|
High |
|
Low |
|
Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
$ |
73.10 |
|
|
$ |
54.66 |
|
|
$ |
0.10 |
|
September 30, 2006 |
|
$ |
76.80 |
|
|
$ |
52.95 |
|
|
$ |
0.10 |
|
June 30, 2006 |
|
$ |
75.74 |
|
|
$ |
60.32 |
|
|
$ |
0.10 |
|
March 31, 2006 |
|
$ |
73.98 |
|
|
$ |
57.67 |
|
|
$ |
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
$ |
69.30 |
|
|
$ |
52.03 |
|
|
$ |
0.10 |
|
September 30, 2005 |
|
$ |
71.82 |
|
|
$ |
46.11 |
|
|
$ |
0.05 |
|
June 30, 2005 |
|
$ |
49.87 |
|
|
$ |
34.05 |
|
|
$ |
0.05 |
|
March 31, 2005 |
|
$ |
38.20 |
|
|
$ |
28.25 |
|
|
$ |
|
|
On January 26, 2007, our Board of Directors declared a quarterly cash dividend on common stock
of $0.10 per share, payable on March 15, 2007 to shareholders of record on March 1, 2007. At
February 21, 2007, there were approximately 1,849 holders of record of our 68,215,252 outstanding
shares of common stock. For information regarding restrictions on future dividend payments and
stock repurchases, see Managements Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and Notes D and E in our consolidated financial statements in Item 8.
The 2007 annual meeting of stockholders will be held at 5:00 P.M. Pacific Daylight Time on
Tuesday, May 1, 2007, at The Four Seasons Hotel, 1260 Channel Drive, Santa Barbara, California.
Holders of common stock of record at the close of business on March 13, 2007 are entitled to notice
of and to vote at the annual meeting.
The following table summarizes, as of December 31, 2006, certain information regarding equity
compensation to our employees, officers, directors and other persons under our equity compensation
plans.
Equity Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
|
|
|
|
|
|
|
|
|
Remaining Available for |
|
|
|
|
|
|
|
|
|
|
|
Future Issuance under |
|
|
|
Number of Securities to be |
|
|
Weighted-Average Exercise |
|
|
Equity Compensation |
|
|
|
Issued upon Exercise of |
|
|
Price of Outstanding |
|
|
Plans (Excluding |
|
|
|
Outstanding Options, |
|
|
Options, Warrants |
|
|
Securities Reflected in |
|
Plan Category |
|
Warrants and Rights |
|
|
and Rights |
|
|
the Second Column) |
|
Equity
compensation plans
approved by
security holders |
|
|
3,573,004 |
|
|
$ |
26.45 |
|
|
|
1,755,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation
plans not approved
by security
holders(a) |
|
|
190,869 |
|
|
$ |
9.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,763,873 |
|
|
$ |
25.61 |
|
|
|
1,755,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The Key Employee Stock Option Plan was approved by our Board of
Directors in November 1999 and provided for stock option grants
to eligible employees who are not our executive officers. The
options expire ten years after the date of grant. Our Board of
Directors has suspended any future grants under this plan. |
21
The table below provides a summary of all repurchases by Tesoro of its common stock
during the three-month period ended December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate Dollar |
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Value of Shares |
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
That May Yet Be |
|
|
Total Number |
|
Average Price |
|
Part of Publicly |
|
Purchased Under the |
|
|
of Shares |
|
Paid Per |
|
Announced Plans or |
|
Plans or |
Period |
|
Purchased |
|
Share |
|
Programs* |
|
Programs* |
October 2006 |
|
|
240,000 |
|
|
$ |
57.78 |
|
|
|
240,000 |
|
|
$38 million |
November 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$38 million |
December 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$38 million |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
240,000 |
|
|
$ |
57.78 |
|
|
|
240,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Tesoros existing stock repurchase program was publicly announced on November 3, 2005. The
program authorizes Tesoro to purchase up to $200 million aggregate purchase price of shares of
Tesoros common stock. |
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected consolidated financial and operating data of
Tesoro as of and for each of the five years in the period ended December 31, 2006. The selected
consolidated financial information presented below has been derived from our historical financial
statements. Our financial results include the results of our California operations since mid-May
2002. The following table should be read in conjunction with Managements Discussion and Analysis
of Financial Condition and Results of Operations in Item 7 and our consolidated financial
statements in Item 8.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
|
(Dollars in millions except per share amounts) |
Statement of Operations Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues |
|
$ |
18,104 |
|
|
$ |
16,581 |
|
|
$ |
12,262 |
|
|
$ |
8,846 |
|
|
$ |
7,119 |
|
Net Earnings (Loss) (a) |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
|
$ |
76 |
|
|
$ |
(117 |
) |
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
11.78 |
|
|
$ |
7.44 |
|
|
$ |
5.01 |
|
|
$ |
1.18 |
|
|
$ |
(1.93 |
) |
Diluted |
|
$ |
11.46 |
|
|
$ |
7.20 |
|
|
$ |
4.76 |
|
|
$ |
1.17 |
|
|
$ |
(1.93 |
) |
Weighted Shares Outstanding (millions): (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
68.0 |
|
|
|
68.1 |
|
|
|
65.5 |
|
|
|
64.6 |
|
|
|
60.5 |
|
Diluted |
|
|
69.9 |
|
|
|
70.4 |
|
|
|
68.9 |
|
|
|
65.1 |
|
|
|
60.5 |
|
Dividends per share (c) |
|
$ |
0.40 |
|
|
$ |
0.20 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Balance Sheet Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
$ |
2,811 |
|
|
$ |
2,215 |
|
|
$ |
1,393 |
|
|
$ |
1,024 |
|
|
$ |
1,054 |
|
Property, Plant and Equipment, Net |
|
$ |
2,687 |
|
|
$ |
2,467 |
|
|
$ |
2,304 |
|
|
$ |
2,252 |
|
|
$ |
2,303 |
|
Total Assets |
|
$ |
5,904 |
|
|
$ |
5,097 |
|
|
$ |
4,075 |
|
|
$ |
3,661 |
|
|
$ |
3,759 |
|
Current Liabilities |
|
$ |
1,672 |
|
|
$ |
1,502 |
|
|
$ |
993 |
|
|
$ |
687 |
|
|
$ |
608 |
|
Total Debt (d) |
|
$ |
1,046 |
|
|
$ |
1,047 |
|
|
$ |
1,218 |
|
|
$ |
1,609 |
|
|
$ |
1,977 |
|
Stockholders Equity (b) |
|
$ |
2,502 |
|
|
$ |
1,887 |
|
|
$ |
1,327 |
|
|
$ |
965 |
|
|
$ |
888 |
|
Current Ratio |
|
|
1.7:1 |
|
|
|
1.5:1 |
|
|
|
1.4:1 |
|
|
|
1.5:1 |
|
|
|
1.7:1 |
|
Working Capital |
|
$ |
1,139 |
|
|
$ |
713 |
|
|
$ |
400 |
|
|
$ |
337 |
|
|
$ |
446 |
|
Total Debt to Capitalization (b) (d) |
|
|
29 |
% |
|
|
36 |
% |
|
|
48 |
% |
|
|
62 |
% |
|
|
69 |
% |
Common Stock Outstanding (millions of shares)(b) |
|
|
67.9 |
|
|
|
69.3 |
|
|
|
66.8 |
|
|
|
64.8 |
|
|
|
64.6 |
|
Book Value Per Common Share |
|
$ |
36.85 |
|
|
$ |
27.23 |
|
|
$ |
19.87 |
|
|
$ |
14.89 |
|
|
$ |
13.74 |
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
Cash Flows From (Used In) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
$ |
1,139 |
|
|
$ |
758 |
|
|
$ |
681 |
|
|
$ |
447 |
|
|
$ |
58 |
|
Investing Activities |
|
|
(430 |
) |
|
|
(254 |
) |
|
|
(174 |
) |
|
|
(70 |
) |
|
|
(941 |
) |
Financing Activities (b) (c) (d) |
|
|
(163 |
) |
|
|
(249 |
) |
|
|
(399 |
) |
|
|
(410 |
) |
|
|
941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
$ |
546 |
|
|
$ |
255 |
|
|
$ |
108 |
|
|
$ |
(33 |
) |
|
$ |
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures (e) |
|
$ |
453 |
|
|
$ |
262 |
|
|
$ |
179 |
|
|
$ |
101 |
|
|
$ |
204 |
|
Operating Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining Throughput (thousand barrels per day) (f) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Golden Eagle |
|
|
165 |
|
|
|
165 |
|
|
|
153 |
|
|
|
156 |
|
|
|
95 |
|
Pacific Northwest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Washington |
|
|
111 |
|
|
|
111 |
|
|
|
117 |
|
|
|
112 |
|
|
|
104 |
|
Alaska |
|
|
56 |
|
|
|
60 |
|
|
|
57 |
|
|
|
49 |
|
|
|
53 |
|
Mid-Pacific |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hawaii |
|
|
85 |
|
|
|
83 |
|
|
|
84 |
|
|
|
80 |
|
|
|
82 |
|
Mid-Continent |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Dakota |
|
|
56 |
|
|
|
58 |
|
|
|
56 |
|
|
|
48 |
|
|
|
51 |
|
Utah |
|
|
56 |
|
|
|
53 |
|
|
|
53 |
|
|
|
43 |
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Refining Throughput |
|
|
529 |
|
|
|
530 |
|
|
|
520 |
|
|
|
488 |
|
|
|
435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining Yield (thousand barrels per day) (f) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
245 |
|
|
|
248 |
|
|
|
251 |
|
|
|
239 |
|
|
|
204 |
|
Jet fuel |
|
|
68 |
|
|
|
68 |
|
|
|
66 |
|
|
|
58 |
|
|
|
64 |
|
Diesel fuel |
|
|
121 |
|
|
|
118 |
|
|
|
110 |
|
|
|
103 |
|
|
|
87 |
|
Heavy oils, residual products, internally
produced fuel and other |
|
|
115 |
|
|
|
115 |
|
|
|
113 |
|
|
|
107 |
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Refining Yield |
|
|
549 |
|
|
|
549 |
|
|
|
540 |
|
|
|
507 |
|
|
|
450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined Product Sales (thousand barrels per day)
(f) (g) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
280 |
|
|
|
294 |
|
|
|
300 |
|
|
|
280 |
|
|
|
264 |
|
Jet fuel |
|
|
91 |
|
|
|
101 |
|
|
|
90 |
|
|
|
84 |
|
|
|
94 |
|
Diesel fuel |
|
|
128 |
|
|
|
139 |
|
|
|
133 |
|
|
|
121 |
|
|
|
115 |
|
Heavy oils, residual products and other |
|
|
87 |
|
|
|
75 |
|
|
|
81 |
|
|
|
72 |
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Refined Product Sales |
|
|
586 |
|
|
|
609 |
|
|
|
604 |
|
|
|
557 |
|
|
|
545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Fuel Sales (millions of gallons) |
|
|
434 |
|
|
|
449 |
|
|
|
510 |
|
|
|
568 |
|
|
|
790 |
|
Number of Branded Retail Stations (end of period) |
|
|
460 |
|
|
|
478 |
|
|
|
507 |
|
|
|
557 |
|
|
|
593 |
|
|
|
|
(a) |
|
We have incurred charges that affect the comparability of the periods
presented. During 2006, 2005 and 2004, we incurred charges for the
Washington refinery delayed coker project termination, debt prepayment
and refinancing, and retirement benefits (see Results of Operations
in Managements Discussion and Analysis of Financial Condition and
Results of Operations in Item 7 for further information). In 2003, we
incurred charges of $23 million after-tax ($0.35 per share) for the
write-off of unamortized debt issuance costs, $6 million after-tax
($0.09 per share) for losses on the sale of marine services assets and
certain retail asset impairments, $6 million after-tax ($0.09 per
share) for voluntary early retirement benefits and $6 million ($0.08
per share) for the termination of our funded executive security plan.
In 2002, we incurred charges for bridge financing fees associated with
the acquisition of the Golden Eagle refinery of $8 million after-tax
($0.14 per share), losses on asset sales and impairment of goodwill of
$5 million after-tax ($0.08 per share), and severance and integration
costs of $5 million after-tax ($0.08 per share). Our 2002 results also
included income tax refund claims which reduced previously recognized
income tax credits by $6 million ($0.10 per share) and a LIFO
inventory liquidation resulting in decreased costs of sales of $3
million after-tax ($0.05 per share). |
23
|
|
|
(b) |
|
During 2006, we repurchased 2.4 million shares of our common stock for
$148 million in connection with our share repurchase program. |
|
(c) |
|
We paid dividends of $0.10 per quarter during 2006. In both June and
September 2005, we paid a quarterly cash dividend on common stock of
$0.05 per share and in December 2005, we paid a quarterly cash
dividend on common stock of $0.10 per share. Prior to 2005, we had not
paid dividends since 1986. |
|
(d) |
|
During 2005, we voluntarily prepaid the remaining $96 million of
senior secured term loans and refinanced nearly $1 billion of
outstanding senior notes through a $900 million notes offering and a
$92 million prepayment of debt. During 2004, we voluntarily prepaid
the $297.5 million of outstanding senior subordinated notes and $100
million of senior secured term loans. During 2003, we reduced total
debt by $377 million primarily through voluntary prepayments. |
|
(e) |
|
Capital expenditures exclude amounts for refinery turnaround spending
and other maintenance costs and for major acquisitions in the refining
and retail segments during 2002. |
|
(f) |
|
Volumes for 2002 include amounts from the Golden Eagle refinery since
we acquired it on May 17, 2002, averaged over 365 days. Throughput and
yield for the Golden Eagle refinery averaged over the 229 days of
operation that we owned it were 151 Mbpd and 160 Mbpd, respectively. |
|
(g) |
|
Sources of total refined product sales include refined products
manufactured at the refineries and refined products purchased from
third parties. Total refined product sales were reduced by 23 Mbpd
during 2006 as a result of recording certain purchases and sales
transactions with the same counterparty on a net basis upon adoption
of EITF Issue No. 04-13, Accounting for Purchases and Sales of
Inventory with the Same Counterparty effective January 1, 2006 (see
our consolidated financial statements in Item 8 for further
information). |
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Those statements in this section that are not historical in nature should be deemed
forward-looking statements that are inherently uncertain. See Forward-Looking Statements on page
45 and Risk Factors on page 16 for a discussion of the factors that could cause actual results to
differ materially from those projected in these statements.
BUSINESS STRATEGY AND OVERVIEW
Our strategy is to create a value-added refining and marketing business that has (i) economies
of scale, (ii) a low-cost structure, (iii) effective management information systems and (iv)
outstanding employees focused on achieving operational excellence in a global market in order to
provide stockholders with competitive returns in any economic environment.
Our goals are focused on: (i) operating our facilities in a safe, reliable, and
environmentally responsible way; (ii) improving cash flow by achieving greater operational and
administrative efficiencies; and (iii) using excess cash flows from operations in a balanced way to
create further shareholder value. During 2006, we achieved the following significant results
relative to our goals, which are further described below under Results of Operations and Capital
Resources & Liquidity:
|
|
|
We had record net earnings of $801 million, or $11.46 per diluted share, compared to
2005 net earnings of $507 million, or $7.20 per diluted share. |
|
|
|
|
Our cash flows from operating activities were $1.1 billion, an increase of $381 million
from 2005. |
|
|
|
|
We achieved average throughput of 529,000 barrels per day (bpd), which was just below
the 529,600 bpd record set in 2005. |
|
|
|
|
Our capital and turnaround spending totaled $570 million, including $225 million for
economic projects, and $68 million for safety and reliability projects. |
|
|
|
|
We posted the lowest recordable OSHA incident rate in our history. |
24
|
|
|
We paid cash dividends on common stock totaling $27 million or $0.40 per share. |
|
|
|
|
We repurchased 2.4 million shares of common stock under our share repurchase program
for $148 million. |
Pending Acquisitions
On January 29, 2007, we entered into agreements with Shell Oil Products US (Shell) to
purchase a 100,000 bpd refinery and a 42,000 bpd refined products terminal located south of Los
Angeles, California along with approximately 250 Shell-branded retail stations located throughout
Southern California (collectively, the Los Angeles Assets). The purchase includes a long-term
agreement allowing us to continue to operate the retail stations under the Shell® brand. The
purchase price of the Los Angeles Assets is $1.63 billion, plus the value of petroleum inventories
at the time of closing, which is estimated to be $180 million to $200 million based on January 2007
prices. Upon closing of the acquisitions Shell has agreed, subject to certain limitations, to
retain certain obligations, responsibilities, liabilities, costs and expenses, including
environmental matters arising out of the pre-closing operations of the assets. We have agreed to
assume certain obligations, responsibilities, liabilities, costs and expenses arising out of or
incurred in connection with decrees, orders and settlements the seller entered into with
governmental and non-governmental entities prior to closing . This transaction, which will
require regulatory approval from the Federal Trade Commission and the Attorney General of the State
of California, is expected to be completed in the second quarter of 2007.
We expect to realize synergies by optimizing the output of our refineries to maximize the
production of clean fuel products for the California market as well as through our crude oil
purchasing and unique shipping logistics. In addition, we expect to increase reliability,
throughput levels and the production of clean products at the refinery by spending approximately
$325 million to $350 million between 2007 and 2011. We also plan to lower air emissions as well as
improve fuel efficiency at the refinery by spending an additional $375 million to $400 million
between 2007 and 2011. These cost estimates will be further reviewed and analyzed after the
transaction is completed and we acquire additional information through operation of the assets.
On January 26, 2007, we entered into an agreement to purchase 140 USA Petroleum retail
stations located primarily in California and a terminal located in New Mexico. The purchase price
of the assets and the USA® brand is $277 million, plus the value of inventory at the
time of closing, which is estimated to be $10 million to $15 million based on January 2007 prices.
Tesoro will assume the obligations under the sellers leases, contracts, permits or other
agreements arising after the closing date. USA Petroleum will retain certain pre-closing
liabilities, including environmental matters. The acquisition will provide us with retail stations
near our refineries in California that will enable us to run the refineries at full capacity,
invest in refinery improvements and deliver more clean products into the market. This transaction,
which will require regulatory approval from the Federal Trade Commission and the Attorney General
of the State of California, is expected to be completed in the second quarter of 2007.
The acquisitions of the Los Angeles Assets and the USA Petroleum retail stations will be paid
for with a combination of debt and cash on-hand, which at December 31, 2006 was $986 million. The
exact amount of debt and cash is yet to be determined, but our debt-to-capitalization ratio is
expected to be less than 50% at the time of closing. We plan to reduce debt through internally
generated cash flow and have set a goal to reduce our debt-to-capitalization ratio to 40% by the
end of 2007.
Strategic Capital Projects
During 2007 we will continue to focus on capital projects that improve safety and reliability,
enhance our crude oil flexibility, improve clean product yields and increase energy efficiency. In
December 2006, our Board of Directors approved the 2007 capital budget, which is approximately $650
million (including refinery turnarounds and other maintenance costs of approximately $92 million).
The capital budget does not include any capital spending for the pending acquisitions discussed
above. See Capital Resources and Liquidity for additional information related to capital
spending, including the estimated spending in 2007 for each of the capital projects described
below.
Golden Eagle Coker Modification Project
The coker modification project at our Golden Eagle refinery is currently scheduled to be
substantially completed during the first quarter of 2008. The modification of our existing fluid
coker unit to a delayed coker unit will enable
25
us to comply with the terms of an abatement order to lower air emissions while also enhancing
the refinerys capabilities in terms of reliability, lengthening turnaround cycles and reducing
operating costs. By extending the typical coker turnaround cycle from 2.5 years to 5 years, we
will effectively increase clean fuels production and significantly reduce the duration and costs of
coker turnarounds.
Washington Sulfur Handling Projects
Our 2007 capital budget includes sulfur handling projects at our Washington refinery which
will allow us to process a greater percentage of sour crude oils beginning in 2008. The sulfur
handling projects were a component of the 25,000 bpd delayed coker unit project at our Washington
refinery which was cancelled in July 2006. We estimate the sulfur handling projects will allow our
Washington refinery to capture up to 15% of the original benefit of the delayed coker. The delayed
coker unit was designed to process a larger portion of lower-cost heavy crude oils or manufacture a
larger percentage of higher-value refined products. The project, originally estimated to cost
approximately $250 million, had experienced significant cost escalations in engineering, materials
and labor and no longer met our rate of return objectives. The cost escalations were similar to
those that had been announced on other projects both within and outside the energy sector. Our
decision to terminate the project is consistent with our commitment to high return projects. The
termination of the delayed coker project resulted in pretax charges of $28 million in 2006.
Other Strategic Capital Projects
During the 2007 second quarter, we are scheduled to complete the following three strategic
projects: (i) a 10,000 bpd diesel desulfurizer unit at our Alaska refinery; (ii) a process control
modernization project at our Golden Eagle refinery; and (iii) a wharf expansion project also at our
Golden Eagle refinery. The diesel desulfurizer unit will allow us to manufacture ultra-low sulfur
diesel (ULSD) and become the sole producer of ULSD in Alaska. The control modernization project
will convert our older refinery control technologies at the Golden Eagle refinery to a modern
digital system. The wharf expansion project will increase our crude oil flexibility by enabling us
to supply all of the Golden Eagle refinerys crude oil requirements by water.
Industry Overview
The global fundamentals of the refining industry remained strong during 2006. Continued demand
growth in developing areas such as India and China and global political concerns supported high
prices for crude oil and refined products. In the U.S., refining margins remained above historical
levels during 2006 and improved as compared to 2005, in part due to the following:
|
|
|
continued high gasoline and diesel demand coupled with limited production capacity; |
|
|
|
|
higher than normal industry maintenance during the first half of 2006 reflecting
turnarounds which were postponed in 2005 due to hurricanes Katrina and Rita; |
|
|
|
|
the introduction of new lower sulfur requirements for gasoline in January 2006 and
diesel in June 2006 and the removal of MTBE as a blendstock nationwide; |
|
|
|
|
stronger reliance on gasoline imports; |
|
|
|
|
the extended downtime at three refineries damaged by the hurricanes and other incidents; and |
|
|
|
|
extensive industry maintenance and unplanned downtime on the U.S. West Coast during the
fourth quarter. |
Anticipated lower overall crude oil and refined product prices, along with relative price
stability, should lead to increases in refined product demand. With little incremental refining
capacity being added during the year, existing refineries will likely continue to run at high
utilization levels and U.S. refined product imports are expected to increase to meet rising demand
requirements. In addition, higher than normal maintenance schedules are planned during the first
and second quarters, further reducing U.S. supplies. For all of these reasons, our outlook for the
refining industry remains strong.
26
RESULTS OF OPERATIONS
Summary
Our net earnings for 2006 were $801 million ($11.46 per diluted share), compared with net
earnings of $507 million ($7.20 per diluted share) for 2005. The significant increase in net
earnings during 2006 was primarily due to higher refined product margins and lower interest expense
as a result of debt reduction and refinancing in 2005. Net earnings for 2006 included an after-tax
charge of $17 million ($0.24 per share) related to the termination of the delayed coker project at
our Washington refinery. Net earnings for 2005 included charges for debt refinancing and prepayment
costs of $58 million after-tax or $0.82 per share, and executive termination and retirement costs
of $6 million after-tax, or $0.09 per share.
Net earnings for 2005 were $507 million ($7.20 per diluted share), compared with net earnings of
$328 million ($4.76 per diluted share) for 2004. The significant increase in earnings during 2005
was primarily due to higher refined product margins, record high throughput levels and realizing
our operating income improvement initiatives. Net earnings for 2004 included debt prepayment and
financing costs of $14 million after-tax, or $0.20 per share, and charges for executive retirement
costs of $1 million after-tax, or $0.01 per share.
A discussion and analysis of the factors contributing to our results of operations is
presented hereafter. The accompanying consolidated financial statements in Item 8, together with
the following information, are intended to provide investors with a reasonable basis for assessing
our historical operations, but should not serve as the only criteria for predicting our future
performance.
Refining Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in millions except per |
|
|
|
barrel amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Refined products (a) |
|
$ |
17,323 |
|
|
$ |
15,587 |
|
|
$ |
11,633 |
|
Crude oil resales and other |
|
|
564 |
|
|
|
782 |
|
|
|
419 |
|
|
|
|
|
|
|
|
|
|
|
Total Revenues |
|
$ |
17,887 |
|
|
$ |
16,369 |
|
|
$ |
12,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining Throughput (thousand barrels per day) (b) |
|
|
|
|
|
|
|
|
|
|
|
|
California |
|
|
|
|
|
|
|
|
|
|
|
|
Golden Eagle |
|
|
165 |
|
|
|
165 |
|
|
|
153 |
|
Pacific Northwest |
|
|
|
|
|
|
|
|
|
|
|
|
Washington |
|
|
111 |
|
|
|
111 |
|
|
|
117 |
|
Alaska |
|
|
56 |
|
|
|
60 |
|
|
|
57 |
|
Mid-Pacific |
|
|
|
|
|
|
|
|
|
|
|
|
Hawaii |
|
|
85 |
|
|
|
83 |
|
|
|
84 |
|
Mid-Continent |
|
|
|
|
|
|
|
|
|
|
|
|
North Dakota |
|
|
56 |
|
|
|
58 |
|
|
|
56 |
|
Utah |
|
|
56 |
|
|
|
53 |
|
|
|
53 |
|
|
|
|
|
|
|
|
|
|
|
Total Refining Throughput |
|
|
529 |
|
|
|
530 |
|
|
|
520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Heavy Crude Oil of Total Refining Throughput (c) |
|
|
49 |
% |
|
|
50 |
% |
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yield (thousand barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
245 |
|
|
|
248 |
|
|
|
251 |
|
Jet Fuel |
|
|
68 |
|
|
|
68 |
|
|
|
66 |
|
Diesel Fuel |
|
|
121 |
|
|
|
118 |
|
|
|
110 |
|
Heavy oils, residual products, internally produced fuel and other |
|
|
115 |
|
|
|
115 |
|
|
|
113 |
|
|
|
|
|
|
|
|
|
|
|
Total Yield |
|
|
549 |
|
|
|
549 |
|
|
|
540 |
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in millions except per |
|
|
|
barrel amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining Margin ($/throughput barrel) (d) |
|
|
|
|
|
|
|
|
|
|
|
|
California |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin |
|
$ |
19.51 |
|
|
$ |
17.88 |
|
|
$ |
13.98 |
|
Manufacturing cost before depreciation and amortization |
|
$ |
5.57 |
|
|
$ |
5.56 |
|
|
$ |
5.07 |
|
Pacific Northwest |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin |
|
$ |
11.61 |
|
|
$ |
9.68 |
|
|
$ |
7.99 |
|
Manufacturing cost before depreciation and amortization |
|
$ |
2.88 |
|
|
$ |
2.74 |
|
|
$ |
2.38 |
|
Mid-Pacific |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin |
|
$ |
6.59 |
|
|
$ |
6.25 |
|
|
$ |
5.30 |
|
Manufacturing cost before depreciation and amortization |
|
$ |
1.84 |
|
|
$ |
1.85 |
|
|
$ |
1.51 |
|
Mid-Continent |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin |
|
$ |
14.16 |
|
|
$ |
10.10 |
|
|
$ |
7.02 |
|
Manufacturing cost before depreciation and amortization |
|
$ |
2.96 |
|
|
$ |
2.73 |
|
|
$ |
2.28 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin |
|
$ |
13.82 |
|
|
$ |
11.81 |
|
|
$ |
9.12 |
|
Manufacturing cost before depreciation and amortization |
|
$ |
3.57 |
|
|
$ |
3.48 |
|
|
$ |
3.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Operating Income |
|
|
|
|
|
|
|
|
|
|
|
|
Gross refining margin (after inventory changes) (e) |
|
$ |
2,631 |
|
|
$ |
2,246 |
|
|
$ |
1,706 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Manufacturing costs |
|
|
689 |
|
|
|
673 |
|
|
|
573 |
|
Other operating expenses |
|
|
178 |
|
|
|
182 |
|
|
|
141 |
|
Selling, general and administrative |
|
|
26 |
|
|
|
27 |
|
|
|
22 |
|
Depreciation and amortization(f) |
|
|
221 |
|
|
|
160 |
|
|
|
130 |
|
Loss on asset disposals and impairments |
|
|
41 |
|
|
|
10 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
Segment Operating Income |
|
$ |
1,476 |
|
|
$ |
1,194 |
|
|
$ |
830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined Product Sales (thousand barrels per day) (a) (g) |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline and gasoline blendstocks |
|
|
280 |
|
|
|
294 |
|
|
|
300 |
|
Jet fuel |
|
|
91 |
|
|
|
101 |
|
|
|
90 |
|
Diesel fuel |
|
|
128 |
|
|
|
139 |
|
|
|
133 |
|
Heavy oils, residual products and other |
|
|
87 |
|
|
|
75 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
Total Refined Product Sales |
|
|
586 |
|
|
|
609 |
|
|
|
604 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined Product Sales Margin ($/barrel) (g) |
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price |
|
$ |
81.26 |
|
|
$ |
70.20 |
|
|
$ |
52.65 |
|
Average costs of sales |
|
|
69.42 |
|
|
|
60.28 |
|
|
|
44.74 |
|
|
|
|
|
|
|
|
|
|
|
Refined Product Sales Margin |
|
$ |
11.84 |
|
|
$ |
9.92 |
|
|
$ |
7.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes intersegment sales to our retail segment, at prices which
approximate market of $987 million, $873 million and $784 million in
2006, 2005 and 2004, respectively. Intersegment refined product sales
volumes totaled 16,200 bpd, 16,900 bpd and 19,000 bpd in 2006, 2005
and 2004, respectively. |
|
(b) |
|
We experienced reduced throughput during scheduled turnarounds for the
following refineries: the Golden Eagle, Washington and Alaska
refineries during 2006; the Golden Eagle, Washington and Hawaii
refineries during 2005; and the Golden Eagle refinery during 2004. |
28
|
|
|
(c) |
|
We define heavy crude oil as Alaska North Slope or crude oil with an
American Petroleum Institute gravity of 32 degrees or less. |
|
(d) |
|
Management uses gross refining margin per barrel to evaluate
performance, allocate resources and compare profitability to other
companies in the industry. Gross refining margin per barrel is
calculated by dividing gross refining margin before inventory changes
by total refining throughput and may not be calculated similarly by
other companies. Management uses manufacturing costs per barrel to
evaluate the efficiency of refinery operations and allocate resources.
Manufacturing costs per barrel is calculated by dividing manufacturing
costs by total refining throughput and may not be comparable to
similarly titled measures used by other companies. Investors and
analysts use these financial measures to help analyze and compare
companies in the industry on the basis of operating performance. These
financial measures should not be considered as alternatives to segment
operating income, revenues, costs of sales and operating expenses or
any other measure of financial performance presented in accordance
with accounting principles generally accepted in the United States of
America. |
|
(e) |
|
Gross refining margin is calculated as revenues less costs of
feedstocks, purchased refined products, transportation and
distribution. Gross refining margin approximates total refining
segment throughput times gross refining margin per barrel, adjusted
for changes in refined product inventory due to selling a volume and
mix of refined product that is different than actual volumes
manufactured. The adjustment for changes in refined product inventory
resulted in a decrease in gross refining margin of $37 million in both
2006 and 2005 and $30 million in 2004. Gross refining margin also
includes the effect of intersegment sales to the retail segment at
prices which approximate market. |
|
(f) |
|
Includes manufacturing depreciation and amortization per throughput
barrel of approximately $1.06, $0.75 and $0.61 for 2006, 2005 and
2004, respectively. |
|
(g) |
|
Sources of total refined product sales included refined products
manufactured at the refineries and refined products purchased from
third parties. Total refined product sales margin includes margins on
sales of manufactured and purchased refined products and the effects
of inventory changes. Total refined product sales were reduced by 23
thousand barrels per day (Mbpd) in 2006 as a result of recording
certain purchase and sales transactions with the same counterparty on
a net basis beginning in the 2006 first quarter upon adoption of EITF
Issue No. 04-13 (see Note A of the consolidated financial statements
in Item 8 for further information.) |
2006 Compared to 2005 Operating income from our refining segment was $1.5 billion in 2006
compared to $1.2 billion in 2005. The increase in operating income of $282 million was primarily
due to increased gross refining margins, partially offset by higher depreciation expense and an
increased loss on asset disposals and impairments. Total gross refining margins increased 17% to
$13.82 per barrel in 2006 compared to $11.81 per barrel in 2005 reflecting higher industry margins
in all of our regions. The higher industry margins reflect continued strong demand for refined
products, limited production capacity in the U.S., a stronger reliance on gasoline imports and
strong global economic growth. During 2006, certain factors further impacted industry refining
margins, including the introduction of new sulfur requirements for gasoline and diesel, the
elimination of MTBE, increased turnaround activity during the first half of 2006 and extensive
turnaround activity on the U.S. West Coast in the fourth quarter. See Business Strategy and
Overview for additional information and other factors impacting industry refining margins.
Industry margins during the second half of 2005 were impacted due to production and supply
disruptions on the U.S. Gulf Coast caused by hurricanes Katrina and Rita.
On an aggregate basis, our total gross refining margins increased to $2.6 billion in 2006 from
$2.2 billion in 2005, reflecting higher per barrel gross refining margins in all of our regions,
particularly in our Mid-Continent and Pacific Northwest regions. In our Mid-Continent region, gross
refining margins increased 40% to $14.16 per barrel during 2006 from $10.10 per barrel during 2005,
reflecting lower feedstock costs due to higher local crude production and strong diesel demand.
During 2005, margins in our Mid-Continent region were negatively impacted by certain factors
primarily during the first quarter, including higher crude oil costs due to Canadian production
constraints and a depressed market in the Salt Lake City area due to record high first quarter
production in PADD IV. Gross refining margins in our Pacific Northwest region increased 20% to
$11.61 per barrel in 2006 versus $9.68 per barrel in 2005 despite a scheduled turnaround at our
Washington refinery during the fourth quarter. Margins were positively impacted by continued strong
demand on the U.S. West Coast along with higher than normal industry maintenance and unscheduled
refining industry downtime. By comparison, certain factors negatively impacted our gross refining
margins in 2005. During the 2005 first quarter, margins in our Pacific Northwest region were
negatively impacted as our Washington refinery completed a scheduled turnaround of the crude and
naphtha
29
reforming units and incurred unscheduled downtime of certain processing equipment. In
addition, our gross refining margins in our Pacific Northwest region during the first half of 2005
were negatively impacted as the increased differential between light and heavy crude oil depressed
the margins for heavy fuel oils.
Total refining throughput averaged 529 Mbpd in 2006 compared to 530 Mbpd during 2005. During
2006, we continued to achieve near record throughput levels reflecting on-going reliability and
operating efficiencies due to recent scheduled turnarounds. In addition, our on-going process
controls modernization programs at our Golden Eagle and Washington refineries contributed to higher
throughput during the second half of 2006. During 2006, we experienced scheduled refinery
turnarounds at our Golden Eagle, Alaska, and Washington refineries and unscheduled downtime at our
North Dakota refinery. We also experienced reduced throughput at our Alaska refinery during the
2006 first quarter as a result of the grounding of our time-chartered vessel which impacted our
supply of feedstocks to the refinery. During 2005, we experienced scheduled refinery turnarounds at
our Golden Eagle, Washington and Hawaii refineries and other unscheduled downtime.
Revenues from sales of refined products increased 11% to $17.3 billion in 2006 from $15.6
billion in 2005, primarily due to significantly higher average refined product sales prices,
partially offset by lower refined product sales volumes. Our average refined product prices
increased 16% to $81.26 per barrel reflecting the continued strength in market fundamentals. Total
refined product sales averaged 586 Mbpd in 2006, a decrease of 23 Mbpd from 2005, reflecting
recording certain purchases and sales transactions on a net basis as described in note (g) in the
table above. Our average costs of sales increased 15% to $69.42 per barrel during 2006, reflecting
significantly higher average feedstock prices. Manufacturing and other operating expenses increased
to $867 million in 2006, compared with $855 million in 2005, primarily due to increased employee
costs of $23 million, higher repairs and maintenance of $11 million and increased catalyst and
chemical costs of $8 million. The increase was partially offset by reclassifying certain pipeline
and terminal costs of $37 million in 2006 from other operating costs to costs of sales.
Depreciation and amortization increased to $221 million in 2006, compared to $160 million in 2005
due in part to additional depreciation of $50 million due to shortening the estimated lives and
recording asset retirement obligations of certain assets at our Golden Eagle refinery beginning in
the fourth quarter of 2005. The increase in depreciation and amortization also reflects increasing
capital expenditures. Loss on asset disposals and impairments increased to $41 million in 2006 from
$10 million in 2005, primarily due to pretax charges of $28 million related to the termination of
the delayed coker project at our Washington refinery.
2005 Compared to 2004 Operating income from our refining segment was $1.2 billion in 2005
compared to $830 million in 2004. The increase in operating income of $364 million was primarily
due to higher gross refining margins, combined with higher throughput levels, partially offset by
higher operating expenses. Total gross refining margins increased 29% to $11.81 per barrel in 2005
compared to $9.12 per barrel in 2004, reflecting higher per-barrel gross refining margins in all
our regions. Industry margins on a national basis improved during 2005 compared to 2004, primarily
due to the continued increased demand for refined products due to improved global economic
performance, an active hurricane season and higher than normal industry maintenance particularly in
the western United States during the first half of 2005. Industry margins were also impacted by
unplanned industry downtime on the U.S. West Coast during the 2005 third quarter.
On an aggregate basis, our total gross refining margins increased to $2.2 billion in 2005 from
$1.7 billion in 2004, reflecting higher per-barrel gross refining margins and increased total
refining throughput. Total refining throughput averaged 530 Mbpd in 2005 compared to 520 Mbpd
during 2004, reflecting record high throughput during the 2005 third and fourth quarters. Our
record high throughput during the last half of 2005 reflects improved operational efficiencies
resulting from scheduled turnarounds at our three largest refineries during the first half of 2005.
We estimate that our refining operating income was reduced by approximately $75 million as a result
of both scheduled and unscheduled downtime at our Golden Eagle and Washington refineries during the
2005 first quarter. During the 2004 third and fourth quarters, our Golden Eagle refinery
experienced reduced throughput during a scheduled turnaround, in which we estimate that our
refining operating income was reduced by approximately $99 million. In addition, our gross refining
margins in our Pacific Northwest region during the first half of 2005 and the 2004 third and fourth
quarters were negatively impacted as the increased differential between light and heavy crude oil
depressed the margins for heavy fuel oils.
Revenues from sales of refined products increased 34% to $15.6 billion in 2005 from $11.6
billion in 2004, primarily due to significantly higher average refined product sales prices
combined with slightly higher refined product sales volumes. Our average refined product prices
increased 33% to $70.20 per barrel reflecting the continued strength in market fundamentals and the
active hurricane season. Total refined product sales averaged 609
30
Mbpd in 2005, compared to 604 Mbpd in 2004. Our average costs of sales increased 35% to $60.28
per barrel during 2005, reflecting significantly higher average feedstock prices and increased
purchases of refined products due to scheduled and unscheduled downtime at certain refineries.
Expenses, excluding depreciation and amortization, increased to $892 million in 2005, compared with
$746 million in 2004, primarily due to higher utilities of $48 million, higher employee costs of
$13 million, increased maintenance costs of $12 million and increased insurance costs of $8 million
primarily due to property insurance premium surcharges resulting from hurricanes Katrina and Rita.
Expenses included the allocation of certain information technology costs totaling $24 million that
were previously classified as corporate and unallocated costs. Depreciation and amortization
increased to $160 million in 2005, compared to $130 million in 2004, primarily reflecting
increasing capital expenditures. In addition, during the fourth quarter of 2005, we shortened the
estimated lives of the fluid coker unit and certain tanks at our Golden Eagle refinery and recorded
asset retirement obligations, resulting in additional depreciation of $12 million.
Retail Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(Dollars in millions except |
|
|
|
per gallon amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
$ |
1,060 |
|
|
$ |
944 |
|
|
$ |
863 |
|
Merchandise and other (a) |
|
|
144 |
|
|
|
141 |
|
|
|
131 |
|
|
|
|
|
|
|
|
|
|
|
Total Revenues |
|
$ |
1,204 |
|
|
$ |
1,085 |
|
|
$ |
994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel Sales (millions of gallons) |
|
|
434 |
|
|
|
449 |
|
|
|
510 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel Margin ($/gallon) (b) |
|
$ |
0.17 |
|
|
$ |
0.16 |
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Merchandise Margin (in millions) |
|
$ |
38 |
|
|
$ |
36 |
|
|
$ |
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Merchandise Margin (percent of revenues) |
|
|
27 |
% |
|
|
26 |
% |
|
|
28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of Retail Stations (during the period) |
|
|
|
|
|
|
|
|
|
|
|
|
Company-operated |
|
|
204 |
|
|
|
213 |
|
|
|
222 |
|
Branded jobber/dealer |
|
|
261 |
|
|
|
281 |
|
|
|
316 |
|
|
|
|
|
|
|
|
|
|
|
Total Average Retail Stations |
|
|
465 |
|
|
|
494 |
|
|
|
538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Operating Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margins |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel (c) |
|
$ |
72 |
|
|
$ |
71 |
|
|
$ |
79 |
|
Merchandise and other non-fuel margin |
|
|
41 |
|
|
|
39 |
|
|
|
39 |
|
|
|
|
|
|
|
|
|
|
|
Total gross margins |
|
|
113 |
|
|
|
110 |
|
|
|
118 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
87 |
|
|
|
90 |
|
|
|
76 |
|
Selling, general and administrative |
|
|
25 |
|
|
|
25 |
|
|
|
26 |
|
Depreciation and amortization |
|
|
16 |
|
|
|
17 |
|
|
|
18 |
|
Loss on asset disposals and impairments |
|
|
6 |
|
|
|
9 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
Segment Operating Loss |
|
$ |
(21 |
) |
|
$ |
(31 |
) |
|
$ |
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Merchandise and other includes other revenues of $3 million in both
2006 and 2005 and $4 million in 2004. |
|
(b) |
|
Management uses fuel margin per gallon to compare profitability to
other companies in the industry. Fuel margin per gallon is calculated
by dividing fuel gross margin by fuel sales volumes and may not be
calculated similarly by other companies. Investors and analysts use
fuel margin per gallon to help analyze and compare companies in the
industry on the basis of operating performance. This financial measure
should not be considered as an alternative to segment operating income
and revenues or any other financial measure of financial performance
presented in accordance with accounting principles generally accepted
in the United States of America. |
|
(c) |
|
Includes the effect of intersegment purchases from our refining
segment at prices which approximate market. |
31
2006 Compared to 2005 The operating loss for our retail segment was $21 million during
2006, compared to an operating loss of $31 million in 2005. Total gross margins increased to $113
million during 2006 from $110 million during 2005 reflecting slightly higher fuel margins, partly
offset by lower sales volumes. Total gallons sold decreased to 434 million from 449 million,
reflecting the decrease in average retail station count to 465 in 2006 from 494 in 2005. The
decrease in average retail station count reflects our continued rationalization of our retail
assets, including the sale of 13 company-operated retail stations in August 2006.
Revenues on fuel sales increased to $1.1 billion in 2006 from $944 million in 2005, reflecting
higher sales prices, partly offset by lower sales volumes. Costs of sales increased in 2006 due to
higher average prices of purchased fuel, partly offset by lower sales volumes.
2005 Compared to 2004 The operating loss for our retail segment was $31 million in 2005,
compared to an operating loss of $6 million in 2004. Total gross margins decreased to $110 million
during 2005 from $118 million in 2004 due to lower sales volumes. Total gallons sold decreased to
449 million from 510 million, reflecting the decrease in average retail station count to 494 in
2005 from 538 in 2004. The decrease in average retail station count reflects our continued
rationalization of our retail assets.
Revenues on fuel sales increased to $944 million in 2005, from $863 million in 2004,
reflecting increased sales prices, partly offset by lower sales volumes. Costs of sales increased
in 2005 due to higher average prices of purchased fuel, partly offset by lower sales volumes.
Operating expenses for 2005 included the allocation of certain information technology costs of $5
million that were previously classified as corporate and unallocated costs and higher insurance
costs of $2 million. The increase in loss on asset disposals and impairments to $9 million in 2005
from $4 million in 2004 primarily reflects charges for the impairment of certain retail stations.
Selling, General and Administrative Expenses
Selling, general and administrative expenses of $176 million in 2006 decreased from $179
million in 2005. The decrease during 2006 was primarily due to charges totaling $11 million for the
termination and retirement of certain executive officers during 2005 and lower contract labor
expenses of $8 million, partially offset by higher employee expenses of $15 million.
Selling, general and administrative expenses of $179 million in 2005 increased from $152
million in 2004. Beginning in 2005, we allocated certain information technology costs previously
reported as selling, general and administrative expenses to costs of sales and operating expenses
totaling $29 million (see Notes A and C of the condensed consolidated financial statements in Item
8). The increase during 2005 was primarily due to increased employee and contract labor expenses of
$28 million, charges for the termination and retirement of certain executive officers of $11
million and additional stock-based compensation expenses of $8 million. The increase in employee
and contract labor expenses during 2005 primarily reflects costs associated with implementing and
supporting systems and process improvements.
Interest and Financing Costs
Interest and financing costs were $77 million in 2006 compared to $211 million in 2005. During
2005, we incurred debt refinancing and prepayment costs totaling $92 million associated with the
refinancing of our 8% senior secured notes and 95/8% senior subordinated
notes, and charges of $3 million in connection with voluntary debt prepayments. Excluding these
refinancing and prepayment costs, interest and financing costs decreased by $39 million during
2006, primarily due to lower interest expense associated with the refinancing and debt reduction
during 2005 totaling $191 million.
Interest and financing costs were $211 million in 2005 compared to $171 million in 2004. The
increase was due to debt refinancing and prepayment costs discussed above. During 2004, debt
prepayment and financing costs totaled $23 million, primarily associated with voluntary debt
prepayments. Excluding these refinancing and prepayment costs, interest and financing costs
decreased by $32 million during 2005, primarily due to lower interest expense associated with debt
reduction totaling $401 million during 2004 and $191 million during 2005.
32
Interest Income and Other
Interest income and other increased to $46 million during 2006 from $15 million in 2005. The
increase reflects the significant increase in invested cash balances along with higher interest
rates and a $5 million gain associated with the sale of our leased corporate headquarters by a
limited partnership in which we were a 50% partner. The increase in 2005 of $10 million from 2004
also reflects an increase in invested cash balances.
Income Tax Provision
The income tax provision amounted to $485 million in 2006 compared to $324 million in 2005 and
$219 million in 2004. The increases reflect significantly higher earnings before income taxes. The
combined federal and state effective income tax rates were approximately 38%, 39% and 40% in 2006,
2005 and 2004, respectively. The decrease in our effective income tax rate during 2006 was
primarily a result of a slight decrease in our state effective tax rate. The decrease in our
effective income tax rate during 2005 was primarily a result of a new federal tax deduction for
domestic manufacturing activities, which became available in 2005.
CAPITAL RESOURCES AND LIQUIDITY
Overview
We operate in an environment where our capital resources and liquidity are impacted by changes
in the price of crude oil and refined products, availability of trade credit, market uncertainty
and a variety of additional factors beyond our control. These risks include, among others, the
level of consumer product demand, weather conditions, fluctuations in seasonal demand, governmental
regulations, geo-political conditions and overall market and global economic conditions. See
Forward-Looking Statements on page 45 and Risk Factors on page 16 for further information
related to risks and other factors. Future capital expenditures, as well as borrowings under our
credit agreement and other sources of capital, may be affected by these conditions.
Our primary sources of liquidity have been cash flows from operations and borrowing
availability under revolving lines of credit, although we have not borrowed on our revolving credit
facility since June 2005. We ended 2006 with $986 million of cash and cash equivalents, no
borrowings under our revolving credit facility, and $626 million in available borrowing capacity
under our credit agreement after $124 million in outstanding letters of credit. We also have a
separate letters of credit agreement of which we had $140 million available after $110 million in
outstanding letters of credit as of December 31, 2006. We believe available capital resources will
be adequate to meet our capital expenditures, working capital and debt service requirements.
As previously described, in January 2007 we entered into purchase agreements to acquire the
Los Angeles Assets and USA Petroleum retail stations. The purchase price for the Los Angeles Assets
is $1.63 billion plus the value of petroleum inventories at the time of closing, which is estimated
to be $180 million to $200 million based on January 2007 prices. The purchase price for the USA
Petroleum retail stations is $227 million plus the value of inventories at the time of closing
which is estimated to be $10 million to $15 million based on January 2007 prices. The acquisitions,
which are subject to federal and state approvals, are anticipated to close in the 2007 second
quarter. We intend to finance the acquisitions using a combination of cash on-hand and debt. The
exact amount of debt and cash is yet to be determined, but the debt to capitalization ratio is
expected to be less than 50% at the time of closing. We plan to reduce debt through internally
generated cash flow and have set a goal to reduce our debt-to-capitalization ratio to 40% by the
end of 2007. We do not plan to finance the acquisitions with public or private equity.
33
Capitalization
Our capital structure at December 31, 2006 was comprised of (in millions):
|
|
|
|
|
Debt, including current maturities: |
|
|
|
|
Credit Agreement Revolving Credit Facility |
|
$ |
|
|
61/4% Senior Notes Due 2012 |
|
|
450 |
|
65/8% Senior Notes Due 2015 |
|
|
450 |
|
95/8% Senior Subordinated Notes Due 2012 |
|
|
14 |
|
Junior subordinated notes due 2012 |
|
|
104 |
|
Capital lease obligations |
|
|
28 |
|
|
|
|
|
Total debt |
|
|
1,046 |
|
Stockholders equity |
|
|
2,502 |
|
|
|
|
|
Total Capitalization |
|
$ |
3,548 |
|
|
|
|
|
At December 31, 2006, our debt to capitalization ratio was 29%, compared to 36% at year-end
2005, reflecting an increase in retained earnings primarily due to net earnings of $801 million
during 2006. We will incur additional indebtedness to consummate the pending acquisitions of the
Los Angeles Assets and USA Petroleum retail stations. On February 15, 2007, we committed to
voluntarily prepay the remaining $14 million outstanding balance of the 95/8%
senior subordinated notes in April 2007 at a redemption price of 104.8%.
Our credit agreement and senior notes impose various restrictions and covenants as described
below that could potentially limit our ability to respond to market conditions, raise additional
debt or equity capital, or take advantage of business opportunities.
Credit Agreement
In July 2006, we amended our credit agreement to extend the term by one year to June 2009 and
reduce letters of credit fees and revolver borrowing interest by 0.25%. Our credit agreement
currently provides for borrowings (including letters of credit) up to the lesser of the agreements
total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base
($1.4 billion as of December 31, 2006), consisting of Tesoros eligible cash and cash equivalents,
receivables and petroleum inventories, as defined. As of December 31, 2006, we had no borrowings
and $124 million in letters of credit outstanding under the revolving credit facility, resulting in
total unused credit availability of $626 million or 83% of the eligible borrowing base. Borrowings
under the revolving credit facility bear interest at either a base rate (8.25% at December 31,
2006) or a eurodollar rate (5.33% at December 31, 2006), plus an applicable margin. The applicable
margin at December 31, 2006 was 1.25% in the case of the eurodollar rate, but varies based upon our
credit facility availability and credit ratings. Letters of credit outstanding under the revolving
credit facility incur fees at an annual rate tied to the eurodollar rate applicable margin (1.25%
at December 31, 2006). We also incur commitment fees for the unused portion of the revolving credit
facility at an annual rate of 0.25% as of December 31, 2006.
We also have a separate letters of credit agreement for the purchase of foreign crude oil. In
July 2006, we increased the capacity under the separate letters of credit agreement to $250 million
from $165 million. The agreement is secured by the crude oil inventories supported by letters of
credit issued under the agreement and will remain in effect until terminated by either party.
Letters of credit outstanding under this agreement incur fees at an annual rate of 1.25% to 1.38%.
As of December 31, 2006, we had $110 million in letters of credit outstanding under this agreement,
resulting in total unused credit availability of $140 million or 56% of total capacity under this
credit agreement.
The credit agreement contains covenants and conditions that, among other things, limit our
ability to pay cash dividends, incur indebtedness, create liens and make investments. Tesoro is
also required to maintain specified levels of fixed charge coverage and tangible net worth. We are
not required to maintain the fixed charge coverage ratio if unused credit availability exceeds 15%
of the eligible borrowing base. For the year ended December 31, 2006, we satisfied all of the
financial covenants under the credit agreement. The credit agreement is guaranteed by substantially
all of Tesoros active subsidiaries and is secured by substantially all of Tesoros cash and cash
equivalents, petroleum inventories and receivables.
34
61/4% Senior Notes Due 2012
In November 2005, Tesoro issued $450 million aggregate principal amount of
61/4% senior notes due November 1, 2012. The notes have a seven-year maturity
with no sinking fund requirements and are not callable. We have the right to redeem up to 35% of
the aggregate principal amount at a redemption price of 106% with proceeds from certain equity
issuances through November 1, 2008. The indenture for the notes contains covenants and restrictions
that are customary for notes of this nature and are identical to the covenants in the indenture for
Tesoros 65/8% senior notes due 2015. Substantially all of these covenants
will terminate before the notes mature if one of two specified ratings agencies assigns the notes
an investment grade rating and no events of default exist under the indenture. The terminated
covenants will not be restored even if the credit rating assigned to the notes subsequently falls
below investment grade. The notes are unsecured and are guaranteed by substantially all of Tesoros
active domestic subsidiaries.
65/8% Senior Notes Due 2015
In November 2005, Tesoro issued $450 million aggregate principal amount of
65/8% senior notes due November 1, 2015. The notes have a ten-year maturity
with no sinking fund requirements and are subject to optional redemption by Tesoro beginning
November 1, 2010 at premiums of 3.3% through October 31, 2011, 2.2% from November 1, 2011 to
October 31, 2012, 1.1% from November 1, 2012 to October 31, 2013, and at par thereafter. We have
the right to redeem up to 35% of the aggregate principal amount at a redemption price of 106% with
proceeds from certain equity issuances through November 1, 2008. The indenture for the notes
contains covenants and restrictions that are customary for notes of this nature and are identical
to the covenants in the indenture for Tesoros 61/4% senior notes due 2012.
Substantially all of these covenants will terminate before the notes mature if one of two specified
ratings agencies assigns the notes an investment grade rating and no events of default exist under
the indenture. The terminated covenants will not be restored even if the credit rating assigned to
the notes subsequently falls below investment grade. The notes are unsecured and are guaranteed by
substantially all of Tesoros active domestic subsidiaries.
The indentures for our senior notes contain covenants and restrictions which are customary for
notes of this nature. These covenants and restrictions limit, among other things, our ability to:
|
|
|
pay dividends and other distributions with respect to our capital stock and purchase,
redeem or retire our capital stock; |
|
|
|
|
incur additional indebtedness and issue preferred stock; |
|
|
|
|
sell assets unless the proceeds from those sales are used to repay debt or are reinvested in our business; |
|
|
|
|
incur liens on assets to secure certain debt; |
|
|
|
|
engage in certain business activities; |
|
|
|
|
engage in certain merger or consolidations and transfers of assets; and |
|
|
|
|
enter into transactions with affiliates. |
The indentures also limit our subsidiaries ability to create restrictions on making certain
payments and distributions.
95/8% Senior Subordinated Notes Due 2012
In April 2002, Tesoro issued $450 million principal amount of 95/8%
senior subordinated notes due April 1, 2012. In November 2005, Tesoro repurchased $415 million of
the outstanding $429 million notes, in connection with the issuance of the
61/4% and 65/8% senior notes described above. In
addition, the indenture for the notes was amended to remove substantially all of the covenants. The
notes are guaranteed by substantially all of Tesoros active domestic subsidiaries. On February 15,
2007, we committed to voluntarily prepay the remaining $14 million outstanding balance of the
95/8% senior subordinated notes in April 2007 at a redemption price of
104.8%.
35
8% Senior Secured Notes Due 2008
In April 2006, we voluntarily prepaid the remaining $9 million outstanding principal balance
of our 8% senior secured notes at a prepayment premium of 4%.
Junior Subordinated Notes Due 2012
In connection with our acquisition of the Golden Eagle refinery, Tesoro issued to the seller
two ten-year junior subordinated notes with face amounts totaling $150 million. The notes consist
of: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing
through May 16, 2007, and carries a 7.5% interest rate thereafter, and (ii) a $50 million junior
subordinated note, due July 2012, which bears interest at 7.47% from May 17, 2003 through May 16,
2007 and 7.5% thereafter. We initially recorded these two notes at a combined present value of
approximately $61 million, discounted at rates of 15.625% and 14.375%, respectively. We are
amortizing the discount over the term of the notes.
Common Stock Repurchase Program
In November 2005, our Board of Directors authorized a $200 million share repurchase program,
which represented approximately 5% of our common stock then outstanding. Under the program, we will
repurchase our common stock from time to time in the open market. Purchases will depend on price,
market conditions and other factors. Under the program, we repurchased 2.4 million shares of common
stock for $148 million in 2006, or an average cost per share of $62.33, and 240,000 shares for $14
million in 2005, or an average cost per share of $58.83. As of December 31, 2006, $38 million
remained available for future repurchases under the program. Due to the pending acquisitions we do
not anticipate repurchasing additional shares in 2007 under the program.
Cash Dividends
On January 26, 2007, our Board of Directors declared a quarterly cash dividend on common stock
of $0.10 per share, payable on March 15, 2007 to shareholders of record on March 1, 2007. During
2006, we paid cash dividends on common stock totaling $0.40 per share.
Cash Flow Summary
Components of our cash flows are set forth below (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Cash Flows From (Used In): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
$ |
1,139 |
|
|
$ |
758 |
|
|
$ |
681 |
|
Investing Activities |
|
|
(430 |
) |
|
|
(254 |
) |
|
|
(174 |
) |
Financing Activities |
|
|
(163 |
) |
|
|
(249 |
) |
|
|
(399 |
) |
|
|
|
|
|
|
|
|
|
|
Increase in Cash and Cash Equivalents |
|
$ |
546 |
|
|
$ |
255 |
|
|
$ |
108 |
|
|
|
|
|
|
|
|
|
|
|
Net cash from operating activities during 2006 totaled $1.1 billion, compared to $758 million
from operating activities in 2005. This increase was primarily due to higher cash earnings and
slightly lower working capital requirements. Net cash used in investing activities of $430 million
in 2006 was primarily for capital expenditures. Net cash used in financing activities primarily
reflects repurchases of our common stock totaling $151 million (including $148 million under our
common stock repurchase program) and dividend payments of $27 million. We did not have any
borrowings or repayments under the revolving credit facility during 2006. Working capital totaled
$1.1 billion at December 31, 2006 compared to $713 million at December 31, 2005, primarily due to
the increase in cash during the year.
Net cash from operating activities during 2005 totaled $758 million, compared to $681 million
from operating activities in 2004. The increase was primarily due to significantly improved
earnings, partly offset by increased working capital requirements. Net cash used in investing
activities of $254 million in 2005 was primarily for capital expenditures. Net cash used in
financing activities primarily reflects our voluntary prepayment of the senior secured term loans,
prepayments of our outstanding 8% senior secured notes and 95/8% senior
subordinated notes in connection with the refinancing, and associated debt refinancing and
prepayment costs. We also repurchased $15
36
million of common stock (including $14 million associated with the common stock repurchase
program) and paid $14 million of dividends to stockholders. Gross borrowings and repayments under
the revolving credit facility each amounted to $463 million during 2005. Working capital totaled
$713 million at December 31, 2005 compared to $400 million at December 31, 2004, primarily as a
result of the $255 million increase in cash and cash equivalents.
Net cash from operating activities during 2004 totaled $681 million. Net cash used in
investing activities of $174 million in 2004 was primarily for capital expenditures. Net cash used
in financing activities of $399 million in 2004 primarily reflects our voluntary debt prepayments
made during the year. Gross borrowings and repayments under the revolving credit facility each
amounted to $112 million during 2004, all of which occurred during the 2004 first quarter.
Historical EBITDA
EBITDA represents earnings before interest and financing costs, interest income and other,
income taxes, and depreciation and amortization. We present EBITDA because we believe some
investors and analysts use EBITDA to help analyze our cash flow including our ability to satisfy
principal and interest obligations with respect to our indebtedness and to use cash for other
purposes, including capital expenditures. EBITDA is also used by some investors and analysts to
analyze and compare companies on the basis of operating performance. EBITDA is also used by
management for internal analysis and as a component of the fixed charge coverage financial covenant
in our credit agreement. EBITDA should not be considered as an alternative to net earnings,
earnings before income taxes, cash flows from operating activities or any other measure of
financial performance presented in accordance with accounting principles generally accepted in the
United States of America. EBITDA may not be comparable to similarly titled measures used by other
entities. Our annual historical EBITDA reconciled to net cash from operating activities was (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Net Cash from Operating Activities |
|
$ |
1,139 |
|
|
$ |
758 |
|
|
$ |
681 |
|
Changes in Assets and Liabilities |
|
|
84 |
|
|
|
67 |
|
|
|
(45 |
) |
Excess Tax Benefits from Stock-based Compensation Arrangements |
|
|
17 |
|
|
|
27 |
|
|
|
4 |
|
Deferred Income Taxes |
|
|
(105 |
) |
|
|
(77 |
) |
|
|
(103 |
) |
Stock-based Compensation |
|
|
(22 |
) |
|
|
(26 |
) |
|
|
(14 |
) |
Loss on Asset Disposals and Impairments |
|
|
(50 |
) |
|
|
(19 |
) |
|
|
(14 |
) |
Amortization and Write-off of Debt Issuance Costs and Discounts |
|
|
(15 |
) |
|
|
(37 |
) |
|
|
(27 |
) |
Depreciation and Amortization |
|
|
(247 |
) |
|
|
(186 |
) |
|
|
(154 |
) |
|
|
|
|
|
|
|
|
|
|
Net Earnings |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
Add Income Tax Provision |
|
|
485 |
|
|
|
324 |
|
|
|
219 |
|
Less Interest Income and Other |
|
|
(46 |
) |
|
|
(15 |
) |
|
|
(5 |
) |
Add Interest and Financing Costs |
|
|
77 |
|
|
|
211 |
|
|
|
171 |
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
1,317 |
|
|
|
1,027 |
|
|
|
713 |
|
Add Depreciation and Amortization |
|
|
247 |
|
|
|
186 |
|
|
|
154 |
|
Add Gain on Partnership Sale |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
1,569 |
|
|
$ |
1,213 |
|
|
$ |
867 |
|
|
|
|
|
|
|
|
|
|
|
Historical EBITDA as presented above differs from EBITDA as defined under our credit
agreement. The primary differences are non-cash postretirement benefit costs and loss on asset
disposals and impairments, which are added to net earnings under the credit agreement EBITDA
calculations.
Capital Expenditures and Refinery Turnaround Spending
Our capital expenditures and refinery turnaround spending totaled $570 million during 2006,
compared to $327 million in 2005 as discussed below.
37
Capital Expenditures
During 2006, our capital expenditures, including accruals, totaled $570 million, including
refinery turnarounds and other maintenance spending of $117 million. Capital expenditures at our
Golden Eagle refinery included $124 million for the delayed coker modification project, $26 million
for reconfiguring and replacing above-ground storage tank systems and upgrading piping, and $14
million for control systems modernization. During 2006, we also spent $38 million for the diesel
desulfurizer unit at our Alaska refinery, $26 million for the cancelled delayed coker unit at our
Washington refinery and $11 million for the sulfur handling projects at our Washington refinery.
Our 2007 capital budget is approximately $650 million, including refinery turnarounds and
other maintenance costs of approximately $92 million. The capital budget does not include any
capital spending for the pending acquisitions. The capital budget includes spending of $231
million for the delayed coker modification project at our Golden Eagle refinery, $18 million for
the diesel desulfurizer unit at our Alaska refinery and $18 million for the sulfur handling
projects at our Washington refinery.
If the pending acquisition of the Los Angeles Assets is consummated, we expect to spend
approximately $325 million to $350 million between 2007 and 2011 to increase reliability,
throughput levels and the production of clean products at this refinery. We also plan to spend an
additional $375 million to $400 million for various environmental projects at the refinery
primarily to lower air emissions between 2007 and 2011. These cost estimates will be further
reviewed and analyzed after the transaction is completed and we acquire additional information
through the operation of the assets.
See Business Strategy and Overview and Environmental Capital Expenditures for additional
information.
Refinery Turnaround and Other Maintenance
During 2006, we spent $93 million for refinery turnarounds, primarily at our Golden Eagle,
Washington and Alaska refineries, and an additional $24 million for other maintenance. In 2007, we
expect to spend approximately $72 million for refinery turnarounds, primarily at our Golden Eagle
and Utah refineries, and an additional $20 million for other maintenance. Refining throughput and
yields in 2007 will be affected by scheduled turnarounds at our Golden Eagle and Utah refineries
during the first quarter.
Long-Term Commitments
Unless the context otherwise indicates, the following discussion of our long-term commitments
does not include any commitments we may incur as a result of the pending acquisitions of the Los
Angeles Assets or the USA Petroleum retail stations.
Contractual Commitments
We have numerous contractual commitments for purchases associated with the operation of our
refineries, debt service and leases (see Notes D and N in our consolidated financial statements in
Item 8). We also have minimum contractual spending requirements for certain capital projects. The
following table summarizes our annual contractual commitments as of December 31, 2006 (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual Obligation |
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
Thereafter |
|
Long-term debt obligations (1) |
|
$ |
81 |
|
|
$ |
69 |
|
|
$ |
69 |
|
|
$ |
69 |
|
|
$ |
69 |
|
|
$ |
1,203 |
|
Capital lease obligations (2) |
|
|
5 |
|
|
|
4 |
|
|
|
5 |
|
|
|
5 |
|
|
|
3 |
|
|
|
27 |
|
Operating lease obligations (2) |
|
|
185 |
|
|
|
150 |
|
|
|
128 |
|
|
|
126 |
|
|
|
115 |
|
|
|
233 |
|
Crude oil supply obligations (3) |
|
|
4,301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other purchase obligations (4) |
|
|
54 |
|
|
|
26 |
|
|
|
24 |
|
|
|
24 |
|
|
|
24 |
|
|
|
43 |
|
Capital expenditure obligations (5) |
|
|
80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected pension contributions (6) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations |
|
$ |
4,706 |
|
|
$ |
249 |
|
|
$ |
226 |
|
|
$ |
224 |
|
|
$ |
211 |
|
|
$ |
1,506 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
|
(1) |
|
Includes maturities of principal and interest payments, excluding capital lease obligations.
Amounts and timing may be different from our estimated commitments due to potential voluntary
debt prepayments and borrowings. |
|
(2) |
|
Capital lease obligations include amounts classified as interest. Operating lease obligations
represent our future minimum lease commitments. Operating lease commitments for 2007 include
lease arrangements with initial terms of less than one year. |
|
(3) |
|
Represents an estimate of our contractual purchase commitments for the supply of crude oil
feedstocks, with remaining terms ranging from 9 to 12 months. Prices under these term
agreements generally fluctuate with market-responsive pricing provisions. To estimate our
annual commitments under these contracts, we estimated crude oil prices using actual market
prices as of December 31, 2006, ranging from $45 per barrel to $57 per barrel, and volumes
based on the contracts minimum purchase requirements. We also purchase additional crude oil
feedstocks under short-term renewable contracts and in the spot market, which are not included
in the table above. |
|
(4) |
|
Represents primarily long-term commitments to purchase chemical supplies and power at our
refineries. These purchase obligations are based on the contracts minimum volume
requirements. We estimated our commitments to purchase power at our Golden Eagle refinery,
which has variable pricing provisions, using estimated future market prices. This contracts
minimum volume purchase requirement expires in July 2007. Actual purchases of electricity at
our Golden Eagle refinery typically exceed the required minimum volumes. |
|
(5) |
|
Capital expenditure obligations represent minimum contractual payments for certain capital
projects. |
|
(6) |
|
Although we have no minimum required contribution obligation to our pension plan under
applicable laws and regulations, we currently project to voluntarily contribute approximately
$25 million in 2007. Amounts are subject to change based on the performance of the assets in
the plan, the discount rate used to determine the obligation, and other actuarial assumptions.
See Critical Accounting Policies for further information related to our pension plan. We are
unable to project benefit contributions beyond 2011. |
Environmental and Other
Tesoro is subject to extensive federal, state and local environmental laws and regulations.
These laws, which change frequently, regulate the discharge of materials into the environment and
may require us to remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites, install additional controls, or make other
modifications or changes in use for certain emission sources.
Conditions may develop that cause increases or decreases in future expenditures for our
various sites, including, but not limited to, our refineries, tank farms, retail stations
(operating and closed locations) and refined products terminals, and for compliance with the Clean
Air Act and other federal, state and local requirements. We cannot currently determine the amounts
of such future expenditures. For further information on environmental matters and other
contingencies, see Note N in our consolidated financial statements in Item 8.
Environmental Liabilities
We are currently involved in remedial responses and have incurred and expect to continue to
incur cleanup expenditures associated with environmental matters at a number of sites, including
certain of our previously owned properties. At December 31, 2006, our accruals for environmental
expenses totaled $23 million. Our accruals for environmental expenses include retained liabilities
for previously owned or operated properties, refining, pipeline and terminal operations and retail
stations. We believe these accruals are adequate, based on currently available information,
including the participation of other parties or former owners in remediation action.
We have completed an investigation of environmental conditions at certain active wastewater
treatment units at our Golden Eagle refinery. This investigation is driven by an order from the San
Francisco Bay Regional Water Quality Control Board that names us as well as two previous owners of
the Golden Eagle refinery. We are evaluating certain improvements to the wastewater treatment units
as a result of this investigation. A reserve for this matter is included in the environmental
accruals referenced above.
39
In October 2005, we received a Notice of Violation (NOV) from the United Stated
Environmental Protection Agency (EPA). The EPA alleges certain modifications made to the fluid
catalytic cracking unit at our Washington refinery prior to our acquisition of the refinery were
made in violation of the Clean Air Act. We have investigated the allegations and believe the
ultimate resolution of the NOV will not have a material adverse effect on our financial position or
results of operations. A reserve for our response to the NOV is included in the environmental
accruals referenced above.
In September 2006, we reached an agreement with the Bay Area Air Quality Management District
(the District) to settle 28 NOVs issued to Tesoro from January 2004 to September 2004 alleging
violations of various air quality requirements at the Golden Eagle refinery. The settlement
agreement was executed on October 11, 2006 and Tesoro made a cash payment of $200,000 to the
District during the fourth quarter of 2006. Pursuant to the terms of the settlement agreement,
Tesoro will undertake a supplemental project valued at approximately $100,000. A reserve for the
supplemental project is included in the environmental accruals referenced above.
Other Environmental Matters
In the ordinary course of business, we become party to or otherwise involved in lawsuits,
administrative proceedings and governmental investigations, including environmental, regulatory and
other matters. Large and sometimes unspecified damages or penalties may be sought from us in some
matters for which the likelihood of loss may be reasonably possible but the amount of loss is not
currently estimable, and some matters may require years for us to resolve. As a result, we have not
established reserves for these matters. On the basis of existing information, we believe that the
resolution of these matters, individually or in the aggregate, will not have a material adverse
effect on our financial position or results of operations. However, we cannot provide assurance
that an adverse resolution of one or more of the matters described below during a future reporting
period will not have a material adverse effect on our financial position or results of operations
in future periods.
We are a defendant, along with other manufacturing, supply and marketing defendants, in ten
pending cases alleging MTBE contamination in groundwater. The defendants are being sued for having
manufactured MTBE and having manufactured, supplied and distributed gasoline containing MTBE. The
plaintiffs, all in California, are generally water providers, governmental authorities and private
well owners alleging, in part, the defendants are liable for manufacturing or distributing a
defective product. The suits generally seek individual, unquantified compensatory and punitive
damages and attorneys fees, but we cannot estimate the amount or the likelihood of the ultimate
resolution of these matters at this time, and accordingly have not established a reserve for these
cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.
Soil and groundwater conditions at our Golden Eagle refinery may require substantial
expenditures over time. In connection with our acquisition of the Golden Eagle refinery from
Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar
had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and
contractually indemnified us for up to $50 million for certain environmental liabilities arising
from operations at the refinery prior to August of 2000, which are identified prior to August 31,
2010 (Pre-Acquisition Operations). Based on existing information, we currently estimate that the
known environmental liabilities arising from Pre-Acquisition Operations including soil and
groundwater conditions at the refinery will exceed the $50 million indemnity. We expect to be
reimbursed for excess liabilities under certain environmental insurance policies that provide $140
million of coverage in excess of the $50 million indemnity. Because of Toscos indemnification and
the environmental insurance policies, we have not established a reserve for these defined
environmental liabilities arising out of the Pre-Acquisition Operations.
In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging
that Tosco misrepresented, concealed and failed to disclose certain additional environmental
conditions at our Golden Eagle refinery related to the soil and groundwater conditions referenced
above. The court granted Toscos motion to compel arbitration of our claims for these certain
additional environmental conditions. In the arbitration proceedings we initiated against Tosco in
December 2003, we are also seeking a determination that Tosco is liable for investigation and
remediation of these certain additional environmental conditions, the amount of which is currently
unknown and therefore a reserve has not been established, and which may not be covered by the $50
million indemnity for the defined environmental liabilities arising from Pre-Acquisition
Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa
County Superior Court action alleging that we are contractually responsible for additional
environmental liabilities at our Golden Eagle refinery, including the defined environmental
liabilities arising from Pre-Acquisition Operations. The arbitration is scheduled to begin during
March 2007. We intend to vigorously prosecute our claims against Tosco and to oppose Toscos claims
against us,
40
and although we cannot provide assurance that we will prevail, we believe that the resolution
of the arbitration will not have a material adverse effect on our financial position or results of
operations.
Environmental Capital Expenditures
EPA regulations related to the Clean Air Act require reductions in the sulfur content in
gasoline. Our Golden Eagle, Washington, Hawaii, Alaska and North Dakota refineries will not
require additional capital spending to meet the low sulfur gasoline standards. We are currently
evaluating alternative projects that will satisfy the requirements to meet the regulations at our
Utah refinery.
EPA regulations related to the Clean Air Act also require reductions in the sulfur content in
diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards
became effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content
of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become
effective in phases between 2007 and 2010. We spent $61 million in 2006 to meet the revised diesel
fuel standards, and we have budgeted an additional $18 million in 2007 to complete our diesel
desulfurizer unit to manufacture additional ultra-low sulfur diesel at our Alaska refinery. Our
Golden Eagle, Washington and Hawaii refineries will not require additional capital spending to meet
the new diesel fuel standards. We are currently evaluating alternative projects that will satisfy
the future requirements under existing regulations at both our North Dakota and Utah refineries.
In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro
assumed the sellers obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co. (BP), Amoco Oil Company and Atlantic Richfield Company. BP entered into
this consent decree for both the North Dakota and Utah refineries for various alleged violations.
As the owner of these refineries, Tesoro is required to address issues to reduce air emissions. We
spent $3 million during 2006 and we have budgeted an additional $18 million through 2009 to comply
with this consent decree. We also agreed to indemnify the sellers for all losses of any kind
incurred in connection with the consent decree.
In connection with the 2002 acquisition of our Golden Eagle refinery, subject to certain
conditions, we assumed the sellers obligations pursuant to settlement efforts with the EPA
concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any
potential monetary penalties, which the seller retains. In November 2005, the Consent Decree was
entered by the District Court for the Western District of Texas in which we agreed to undertake
projects at our Golden Eagle refinery to reduce air emissions. To satisfy the requirements of the
Consent Decree, we spent $3 million during 2006 and we have budgeted an additional $25 million
through 2010.
In December 2006, we proposed an alternative monitoring plan and a schedule for removing
atmospheric blowdown towers at the Golden Eagle refinery to the Bay Area Air Quality Management
District in response to a NOV received from that agency in August 2006. We have budgeted $88
million through 2010 to remove the atmospheric blowdown towers.
During the fourth quarter of 2005, we received approval by the Hearing Board for the Bay Area
Air Quality Management District to modify our existing fluid coker unit to a delayed coker at our
Golden Eagle refinery which is designed to lower emissions while also enhancing the refinerys
capabilities in terms of reliability, lengthening turnaround cycles and reducing operating costs.
We negotiated the terms and conditions of the Second Conditional Abatement Order with the District
in response to the January 2005 mechanical failure of the fluid coker boiler at the Golden Eagle
refinery. The total capital budget for this project is $503 million, which includes budgeted
spending of $231 million in 2007 and $145 million in 2008. The project is currently scheduled to
be substantially completed during the first quarter of 2008, with spending through the first half
of 2008. We have spent $127 million from inception of the project, of which $124 million was spent
in 2006.
We will also spend capital at the Golden Eagle refinery for reconfiguring and replacing
above-ground storage tank systems and upgrading piping within the refinery. We spent $26 million
during 2006 and we have budgeted an additional $110 million through 2011 to complete the project.
Our capital budget also includes spending of $29 million through 2010 to upgrade a marine oil
terminal at the Golden Eagle refinery to meet engineering and maintenance standards issued by the
State of California in February 2006.
The Los Angeles Assets are subject to extensive environmental requirements. If we consummate
the purchase of the Los Angeles Assets, we anticipate spending approximately $375 million to $400
million between 2007 and 2011
41
for various environmental projects at the refinery primarily to lower air emissions. These
estimates will be further reviewed and analyzed after the transaction is completed and we acquire
additional information through the operation of the assets.
Pension Funding
For all eligible employees, we provide a qualified defined benefit retirement plan with
benefits based on years of service and compensation. Our long-term expected return on plan assets
is 8.5%, and our funded employee pension plan assets experienced a return of $30 million in 2006
and $13 million in 2005. Based on a 6% discount rate and fair values of plan assets as of December
31, 2006, the fair value of the assets in our funded employee pension plan were equal to
approximately 98% of the projected benefit obligation as of the end of 2006. However, the funded
employee pension plan was 113% funded based on its current liability, which is a funding measure
defined under applicable pension regulations. Although Tesoro had no minimum required contribution
obligation to its funded employee pension plan under applicable laws and regulations in 2006, we
voluntarily contributed $25 million to improve the funded status of the plan. We currently have no
minimum required contribution obligation to our funded employee pension plan under applicable laws
and regulations in 2007, however, we currently project to contribute approximately $25 million in
2007. Future contributions are affected by returns on plan assets, employee demographics and other
factors. See Note L in our consolidated financial statements in Item 8 for further discussion.
Claims Against Third-Parties
In 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the
transportation of its crude oil through the Trans Alaska Pipeline System (TAPS). Our protest
asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory
Commission of Alaska (RCA) considered our protest of the intrastate rates for the years 1997
through 2000. The RCA set just and reasonable final rates for the years 1997 through 2000, and
held that we are entitled to receive approximately $52 million in refunds, including interest
through the expected conclusion of appeals in December 2007. The RCAs ruling is currently on
appeal to the Alaska Supreme Court, and we cannot give any assurances of when or whether we will
prevail in the appeal.
In 2002, the RCA rejected the TAPS Carriers proposed intrastate rate increases for 2001-2003
and maintained the permanent rate of $1.96 to the Valdez Marine Terminal. That ruling is currently
on appeal to the Alaska Superior Court, and the TAPS Carriers did not move to prevent the rate
decrease. The rate decrease has been in effect since June 2003. The TAPS Carriers attempted to
increase their intrastate rates for 2004, 2005, and 2006 without providing the supporting
information required by the RCAs regulations and in a manner inconsistent with the RCAs prior
decision in Order 151. These filings were rejected by the RCA. The rejection of these filings is
currently on appeal to the Superior Court of Alaska where the decision is being held in abeyance
pending the decision in the appeals of the rates for 1997-2003. If the RCAs decisions are upheld
on appeal, we could be entitled to refunds resulting from our shipments from January 2001 through
mid-June 2003. If the RCAs decisions are not upheld on appeal, we could potentially have to pay
the difference between the TAPS Carriers filed rates from mid-June 2003 through December 31, 2006
(averaging approximately $3.60 per barrel) and the RCAs approved rate for this period ($1.96 per
barrel) plus interest for the approximately 36 million barrels we have transported through TAPS in
intrastate commerce during this period. We cannot give any assurances of when or whether we will
prevail in these appeals. We also believe that, should we not prevail on appeal, the amount of
additional shipping charges cannot reasonably be estimated since it is not possible to estimate the
permanent rate which the RCA could set, and the appellate courts approve, for each year. In
addition, depending upon the level of such rates, there is a reasonable possibility that any
refunds for the period January 2001 through mid-June 2003 could offset some or all of any
additional payments due for the period mid-June 2003 through December 31, 2006.
In January of 2005, Tesoro Alaska Company intervened in a protest before the Federal Energy
Regulatory Commission (FERC), of the TAPS Carriers interstate rates for 2005 and 2006. If Tesoro
Alaska Company prevails and lower rates are set, we could be entitled to refunds resulting from our
interstate shipments for 2005 and 2006. We cannot give any assurances of when or whether we will
prevail in this proceeding. In July 2005, the TAPS Carriers filed a proceeding at the FERC seeking
to have the FERC assume jurisdiction under Section 13(4) of the Interstate Commerce Act and set
future rates for intrastate transportation on TAPS. We have filed a protest in that proceeding,
which has now been consolidated with the other FERC proceeding seeking to set just and reasonable
interstate rates on TAPS for 2005 and 2006. If the TAPS carriers should prevail, then the rates
charged for all shipments of Alaska North Slope crude oil on TAPS could be revised by the FERC, but
any FERC changes to
42
rates for intrastate transportation of crude oil supplies for our Alaska refinery should be
prospective only and should not affect prior intrastate rates, refunds or additional payments.
ACCOUNTING STANDARDS
Critical Accounting Policies
Our accounting policies are described in Note A in our consolidated financial statements in
Item 8. We prepare our consolidated financial statements in conformity with accounting principles
generally accepted in the United States of America, which require us to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the year. Actual results could differ from those estimates. We
consider the following policies to be the most critical in understanding the judgments that are
involved in preparing our financial statements and the uncertainties that could impact our
financial condition and results of operations.
Receivables Our trade receivables are stated at their invoiced amounts, less an allowance
for potentially uncollectible amounts. We monitor the credit and payment experience of our
customers and manage our loss exposure through our credit policies and procedures. The estimated
allowance for doubtful accounts is based on our general loss experience and identified loss
exposures on individual accounts. Although actual losses have not been significant to our results
of operations, global economic conditions and the related credit environment could change, and
actual losses could vary from estimates.
Inventory Our inventories are stated at the lower of cost or market. We use the LIFO method
to determine the cost of our crude oil and refined product inventories. The LIFO cost of these
inventories is usually much less than current market value, however, a significant decline in
market values of crude oil and refined products could impair the carrying values of these
inventories. We had 26 million barrels of crude oil and refined product inventories at December 31,
2006 with an average cost of approximately $29 per barrel on a LIFO basis. If refined product
prices decline below the average cost, then we would be required to write down the value of our
inventories in future periods. The use of LIFO may also result in increases or decreases to costs
of sales in years when inventory volumes decline and result in costs of sales associated with
inventory layers recorded in prior periods.
Property, Plant and Equipment and Acquired Intangibles We calculate depreciation and
amortization using the straight-line method based on estimated useful lives and salvage values of
our assets. When assets are placed into service, we make estimates with respect to their useful
lives that we believe are reasonable. However, factors such as maintenance levels, global economic
conditions impacting the demand for these assets, and regulatory or environmental matters could
cause us to change our estimates, thus impacting the future calculation of depreciation and
amortization. We evaluate these assets for potential impairment by identifying whether indicators
of impairment exist and, if so, assessing whether the assets are recoverable from estimated future
undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to
the amount by which the assets carrying value exceeds its fair value. Fair market value is
generally based on the present values of estimated cash flows in the absence of quoted market
prices. Estimates of future undiscounted cash flows and fair value of assets require subjective
assumptions with regard to several factors, including an assessment of global market conditions,
future operating results and forecasting the remaining useful lives of the assets. Actual results
could differ from those estimates.
Goodwill As of December 31, 2006, we had $89 million of goodwill included in Other
Noncurrent Assets. Goodwill is not amortized, but is tested for impairment annually or more
frequently when indicators of impairment exist. We review the recorded value of our goodwill for
impairment annually during the fourth quarter, or sooner if events or changes in circumstances
indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the
estimated fair value of a reporting unit to the carrying value, including the related goodwill, of
that reporting unit. We use the present value of expected net cash flows and market multiple
analyses to determine the estimated fair value of our reporting units. The impairment test is
susceptible to change from period to period as it requires us to make cash flow assumptions
including, among other things, future margins, volumes, operating costs, capital expenditures and
discount rates. Our assumptions regarding future margins and volumes require significant judgment
as actual margins and volumes have fluctuated in the past and will likely continue to do so.
Changes in market conditions could result in impairment charges in the future.
Contingencies We record an estimated loss from a contingency when information available
before issuing our financial statements indicates that (a) it is probable that an asset has been
impaired or a liability has been incurred at the date of the financial statements and (b) the
amount of the loss can be reasonably estimated. We are required to use our judgment to account for
contingencies such as environmental, legal and income tax matters. While we
43
believe that our accruals for these matters are adequate, the actual loss may differ from our
estimated loss, and we would record the necessary adjustments in future periods. We do not record
the benefits of contingent recoveries or gains until the amount is determinable and recovery is
assured.
Income Taxes As part of the process of preparing consolidated financial statements, we must
assess the likelihood that our deferred income tax assets will be recovered through future taxable
income. To the extent we believe that recovery is not likely, a valuation allowance must be
established. Significant management judgment is required in determining any valuation allowance
recorded against net deferred income tax assets. Based on our estimates of taxable income in each
jurisdiction in which we operate and the period over which deferred income tax assets will be
recoverable, we have not recorded a valuation allowance as of December 31, 2006. In the event that
actual results differ from these estimates or we make adjustments to these estimates in future
periods, we may need to establish a valuation allowance.
Asset Retirement Obligations We record asset retirement obligations in the period in which
the obligations are incurred and a reasonable estimate of fair value can be made. We use the
present value of expected cash flows to estimate fair value. The calculation of fair value is based
on several estimates and assumptions, including, among other things, projected cash flows, a
credit-adjusted risk-free rate, the settlement dates or a range of potential settlement dates and
the probabilities associated with the potential settlement dates. Actual results could differ from
those estimates. Our asset retirement obligations totaled $52 million and $46 million at December
31, 2006 and 2005, respectively. We cannot currently make reasonable estimates of the fair values
of some retirement obligations, principally those associated with our refineries, pipelines and
certain terminals and retail stations, because the related assets have indeterminate useful lives
which preclude development of assumptions about the potential timing of settlement dates. Such
obligations will be recognized in the period in which sufficient information exists to estimate a
range of potential settlement dates.
Pension and Other Postretirement Benefits Accounting for pensions and other postretirement
benefits involves several assumptions and estimates including discount rates, health care cost
trends, inflation, retirement rates and mortality rates. We must also assume a rate of return on
funded pension plan assets in order to estimate our obligations under our defined benefit plans.
Due to the nature of these calculations, we engage an actuarial firm to assist with the
determination of these estimates and the calculation of certain employee benefit expenses. We
record an asset for our plans overfunded status and a liability for our plans underfunded status.
The funded status represents the difference between the fair value our plans assets and its
projected benefit obligations. While we believe that the assumptions used are appropriate,
significant differences in the actual experience or significant changes in assumptions would affect
pension and other postretirement benefits costs and obligations. A one-percentage-point change in
the expected return on plan assets and discount rate for the pension plans would have had the
following effects in 2006 (in millions):
|
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|
|
|
|
|
|
|
|
|
1-Percentage- |
|
1-Percentage- |
|
|
Point Increase |
|
Point Decrease |
Expected Rate of Return |
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|
|
|
|
|
|
Effect on net periodic pension expense |
|
$ |
(2.3 |
) |
|
$ |
2.2 |
|
Discount Rate |
|
|
|
|
|
|
|
|
Effect on net periodic pension expense |
|
$ |
(3.0 |
) |
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$ |
3.2 |
|
Effect on projected benefit obligation |
|
$ |
(27.7 |
) |
|
$ |
29.5 |
|
See Note L in our consolidated financial statements in Item 8 for more information regarding
costs and assumptions.
Stock-Based Compensation We follow the fair value method of accounting for stock-based
compensation. We estimate the fair value of options and other stock-based awards using the
Black-Scholes option-pricing model with assumptions based primarily on historical data. The
assumptions used in the Black-Scholes option-pricing model require estimates of the expected term
the stock-based awards are held until exercised, the estimated volatility of our stock price over
the expected term and the number of options that will be forfeited prior to the completion of their
vesting requirements. Changes in our assumptions may impact the expenses related to our stock
options. The estimated fair value of our stock appreciation rights and phantom stock awards are
revalued at the end of each reporting period, and changes in our assumptions may impact our
liabilities and expenses associated with these awards.
44
New Accounting Standards and Disclosures
See Note A in our consolidated financial statements in Item 8.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. These statements are included throughout this
Form 10-K and relate to, among other things, expectations regarding refining margins, revenues,
cash flows, capital expenditures, turnaround expenses, and other financial items. These statements
also relate to our business strategy, goals and expectations concerning our market position, future
operations, margins and profitability. We have used the words anticipate, believe, could,
estimate, expect, intend, may, plan, predict, project, will and similar terms and
phrases to identify forward-looking statements in this Annual Report on Form 10-K.
Although we believe the assumptions upon which these forward-looking statements are based are
reasonable, any of these assumptions could prove to be inaccurate and the forward-looking
statements based on these assumptions could be incorrect. Our operations involve risks and
uncertainties, many of which are outside our control, and any one of which, or a combination of
which, could materially affect our results of operations and whether the forward-looking statements
ultimately prove to be correct.
Actual results and trends in the future may differ materially from those suggested or implied
by the forward-looking statements depending on a variety of factors including, but not limited to:
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changes in global economic conditions; |
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the timing and extent of changes in commodity prices and underlying demand for our refined products; |
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the availability and costs of crude oil, other refinery feedstocks and refined products; |
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changes in our cash flow from operations; |
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changes in the cost or availability of third-party vessels, pipelines and other means
of transporting crude oil feedstocks and refined products; |
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disruptions due to equipment interruption or failure at our facilities or third-party facilities; |
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actions of customers and competitors; |
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changes in capital requirements or in execution of planned capital projects; |
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direct or indirect effects on our business resulting from actual or threatened
terrorist incidents or acts of war; |
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political developments in foreign countries; |
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changes in our inventory levels and carrying costs; |
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seasonal variations in demand for refined products; |
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changes in fuel and utility costs for our facilities; |
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state and federal environmental, economic, safety and other policies and regulations,
any changes therein, and any legal or regulatory delays or other factors beyond our
control; |
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adverse rulings, judgments, or settlements in litigation or other legal or tax matters,
including unexpected environmental remediation costs in excess of any reserves; |
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weather conditions affecting our operations or the areas in which our refined products are marketed; and |
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earthquakes or other natural disasters affecting operations. |
Many of these factors are described in greater detail in Competition and Other on page 10
and Risk Factors on page 16. All future written and oral forward-looking statements attributable
to us or persons acting on our behalf are expressly qualified in their entirety by the previous
statements. We undertake no obligation to update any information contained herein or to publicly
release the results of any revisions to any forward-looking statements that may be made to reflect
events or circumstances that occur, or that we become aware of, after the date of this Annual
Report on Form 10-K.
45
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ITEM 7A. |
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Our primary source of market risk is the difference between prices received from the sale of
refined products and the prices paid for crude oil and other feedstocks. We have a risk management
committee responsible for, among other things, (i) managing risks arising from transactions and
commitments related to the sale and purchase of crude oil, other feedstocks, refined products and
derivative arrangements and (ii) making recommendations to executive management.
Commodity Price Risks
Our earnings and cash flows from operations depend on the margin above fixed and variable
expenses (including the costs of crude oil and other feedstocks) and the margin above those
expenses at which we are able to sell refined products. The prices of crude oil and refined
products have fluctuated substantially in recent years. These prices depend on many factors,
including the demand for crude oil, gasoline and other refined products, which in turn depend on,
among other factors, changes in the global economy, the level of foreign and domestic production of
crude oil and refined products, geo-political conditions, the availability of imports of crude oil
and refined products, the marketing of alternative and competing fuels and the impact of government
regulations. The prices we receive for refined products are also affected by local factors such as
local market conditions and the level of operations of other suppliers in our markets.
The prices at which we sell our refined products are influenced by the commodity price of
crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding
increase or decrease in the price of gasoline and other refined products. However, the prices for
crude oil and prices for our refined products can fluctuate in different directions based on global
market conditions. In addition, the timing of the relative movement of the prices, as well as the
overall change in refined product prices, can reduce profit margins and could have a significant
impact on our earnings and cash flows. In addition, the majority of our crude oil supply contracts
are short-term in nature with market-responsive pricing provisions. Our financial results can be
affected significantly by price level changes during the period between purchasing refinery
feedstocks and selling the manufactured refined products from such feedstocks. We also purchase
refined products manufactured by others for resale to our customers. Our financial results can be
affected significantly by price level changes during the periods between purchasing and selling
such refined products. Assuming all other factors remained constant, a $1.00 per barrel change in
average gross refining margins, based on our 2006 average throughput of 529 Mbpd, would change
annualized pretax operating income by approximately $193 million.
We maintain inventories of crude oil, intermediate products and refined products, the values
of which are subject to fluctuations in market prices. Our inventories of refinery feedstocks and
refined products totaled 26 million barrels and 28 million barrels at December 31, 2006 and 2005,
respectively. The average cost of our refinery feedstocks and refined products at December 31, 2006
was approximately $29 per barrel on a LIFO basis, compared to market prices of approximately $59
per barrel. If market prices decline to a level below the average cost of these inventories, we
would be required to write down the carrying value of our inventory.
Tesoro periodically enters into non-trading derivative arrangements primarily to manage
exposure to commodity price risks associated with the purchase of feedstocks and blendstocks and
the purchase and sale of manufactured and purchased refined products. To manage these risks, we
typically enter into exchange-traded futures and over-the-counter swaps, generally with durations
of one year or less. We mark to market our non-hedging derivative instruments and recognize the
changes in their fair values in earnings. We include the carrying amounts of our derivatives in
other current assets or accrued liabilities in the consolidated balance sheets. We did not
designate or account for any derivative instruments as hedges during 2006. Accordingly, no change
in the value of the related underlying physical asset is recorded. During 2006, we settled
derivative positions of approximately 138 million barrels of crude oil and refined products, which
resulted in gains of $33 million. At December 31, 2006, we had open derivative positions of
approximately 10 million barrels, which will expire at various times during 2007. We recorded the
fair value of our open positions, which resulted in an unrealized mark-to-market gain of $12
million at December 31, 2006.
We prepared a sensitivity analysis to estimate our exposure to market risk associated with our
derivative instruments. This analysis may differ from actual results. The fair value of each
derivative instrument was based on quoted market prices. Based on our open net short positions of
10 million barrels as of December 31, 2006, a $1.00 per-barrel change in quoted market prices of
our derivative instruments, assuming all other factors remain constant, would change the fair value
of our derivative instruments and pretax operating income by $10 million. As of December 31, 2005,
a $1.00 per-barrel change in quoted market prices for our derivative instruments, assuming all
other factors remain constant, would have changed the fair value of our derivative instruments and
pretax operating income by $7 million.
46
|
|
|
ITEM 8. |
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Tesoro Corporation
We have audited the accompanying consolidated balance sheets of Tesoro Corporation and
subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated
statements of operations, comprehensive income and stockholders equity, and cash flows for each of
the three years in the period ended December 31, 2006. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on the
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). 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, such consolidated financial statements present fairly, in all material
respects, the financial position of Tesoro Corporation and subsidiaries as of December 31, 2006 and
2005, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2006, in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note A to the consolidated financial statements, in 2006 the Company changed
its method of accounting for refined product sales and purchases transactions with the same
counterparty that have been entered into in contemplation of one another, and for its pension and
other postretirement plans.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Companys internal control over financial
reporting as of December 31, 2006, based on the criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated February 22, 2007, expressed an unqualified opinion on managements assessment
of the effectiveness of the Companys internal control over financial reporting and an unqualified
opinion on the effectiveness of the Companys internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
San Antonio, Texas
February 22, 2007
47
TESORO CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(In millions except per share amounts) |
|
REVENUES |
|
$ |
18,104 |
|
|
$ |
16,581 |
|
|
$ |
12,262 |
|
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales and operating expenses |
|
|
16,314 |
|
|
|
15,170 |
|
|
|
11,229 |
|
Selling, general and administrative expenses |
|
|
176 |
|
|
|
179 |
|
|
|
152 |
|
Depreciation and amortization |
|
|
247 |
|
|
|
186 |
|
|
|
154 |
|
Loss on asset disposals and impairments |
|
|
50 |
|
|
|
19 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
|
1,317 |
|
|
|
1,027 |
|
|
|
713 |
|
Interest and financing costs |
|
|
(77 |
) |
|
|
(211 |
) |
|
|
(171 |
) |
Interest income and other |
|
|
46 |
|
|
|
15 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
EARNINGS BEFORE INCOME TAXES |
|
|
1,286 |
|
|
|
831 |
|
|
|
547 |
|
Income tax provision |
|
|
485 |
|
|
|
324 |
|
|
|
219 |
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS PER SHARE: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
11.78 |
|
|
$ |
7.44 |
|
|
$ |
5.01 |
|
Diluted |
|
$ |
11.46 |
|
|
$ |
7.20 |
|
|
$ |
4.76 |
|
WEIGHTED AVERAGE COMMON SHARES: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
68.0 |
|
|
|
68.1 |
|
|
|
65.5 |
|
Diluted |
|
|
69.9 |
|
|
|
70.4 |
|
|
|
68.9 |
|
DIVIDENDS PER SHARE |
|
$ |
0.40 |
|
|
$ |
0.20 |
|
|
$ |
|
|
The accompanying notes are an integral part of these consolidated financial statements.
48
TESORO CORPORATION
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(Dollars in millions |
|
|
|
except per share |
|
|
|
amounts) |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
986 |
|
|
$ |
440 |
|
Receivables, less allowance for doubtful accounts |
|
|
861 |
|
|
|
718 |
|
Inventories |
|
|
872 |
|
|
|
953 |
|
Prepayments and other |
|
|
92 |
|
|
|
104 |
|
|
|
|
|
|
|
|
Total Current Assets |
|
|
2,811 |
|
|
|
2,215 |
|
|
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT |
|
|
|
|
|
|
|
|
Refining |
|
|
3,207 |
|
|
|
2,850 |
|
Retail |
|
|
210 |
|
|
|
223 |
|
Corporate and other |
|
|
144 |
|
|
|
107 |
|
|
|
|
|
|
|
|
|
|
|
3,561 |
|
|
|
3,180 |
|
Less accumulated depreciation and amortization |
|
|
(874 |
) |
|
|
(713 |
) |
|
|
|
|
|
|
|
Net Property, Plant and Equipment |
|
|
2,687 |
|
|
|
2,467 |
|
|
|
|
|
|
|
|
OTHER NONCURRENT ASSETS |
|
|
|
|
|
|
|
|
Goodwill |
|
|
89 |
|
|
|
89 |
|
Acquired intangibles, net |
|
|
112 |
|
|
|
119 |
|
Other, net |
|
|
205 |
|
|
|
207 |
|
|
|
|
|
|
|
|
Total Other Noncurrent Assets |
|
|
406 |
|
|
|
415 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
5,904 |
|
|
$ |
5,097 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
1,270 |
|
|
$ |
1,171 |
|
Accrued liabilities |
|
|
385 |
|
|
|
328 |
|
Current maturities of debt |
|
|
17 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Total Current Liabilities |
|
|
1,672 |
|
|
|
1,502 |
|
|
|
|
|
|
|
|
DEFERRED INCOME TAXES |
|
|
377 |
|
|
|
389 |
|
OTHER LIABILITIES |
|
|
324 |
|
|
|
275 |
|
DEBT |
|
|
1,029 |
|
|
|
1,044 |
|
COMMITMENTS AND CONTINGENCIES (Note N) |
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Common stock, par value $0.162/3; authorized 200,000,000 shares; 71,707,102 shares
issued (70,850,681 in 2005) |
|
|
12 |
|
|
|
12 |
|
Additional paid-in capital |
|
|
841 |
|
|
|
794 |
|
Retained earnings |
|
|
1,876 |
|
|
|
1,102 |
|
Treasury stock, 3,800,446 common shares (1,548,568 in 2005), at cost |
|
|
(159 |
) |
|
|
(19 |
) |
Accumulated other comprehensive loss |
|
|
(68 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
Total Stockholders Equity |
|
|
2,502 |
|
|
|
1,887 |
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
5,904 |
|
|
$ |
5,097 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
49
TESORO CORPORATION
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME AND
STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders' Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
Comprehensive |
|
|
Common Stock |
|
|
Paid-In |
|
|
Retained |
|
|
Treasury Stock |
|
|
Comprehensive |
|
|
|
Income |
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Shares |
|
|
Amount |
|
|
Loss |
|
|
|
(In millions) |
|
AT JANUARY 1, 2004 |
|
|
|
|
|
|
66.5 |
|
|
$ |
11 |
|
|
$ |
691 |
|
|
$ |
281 |
|
|
|
(1.7 |
) |
|
$ |
(17 |
) |
|
$ |
|
|
Net earnings |
|
|
328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares issued for stock
options and benefit plans |
|
|
|
|
|
|
1.1 |
|
|
|
|
|
|
|
21 |
|
|
|
|
|
|
|
0.3 |
|
|
|
6 |
|
|
|
|
|
Excess tax benefits from
stock-based compensation
arrangements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants and
amortization |
|
|
|
|
|
|
0.7 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AT DECEMBER 31, 2004 |
|
|
|
|
|
|
68.3 |
|
|
$ |
11 |
|
|
$ |
718 |
|
|
$ |
609 |
|
|
|
(1.4 |
) |
|
$ |
(11 |
) |
|
$ |
|
|
Net earnings |
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.3 |
) |
|
|
(15 |
) |
|
|
|
|
Shares issued for stock
options and benefit plans |
|
|
|
|
|
|
2.5 |
|
|
|
1 |
|
|
|
47 |
|
|
|
|
|
|
|
0.2 |
|
|
|
7 |
|
|
|
|
|
Excess tax benefits from
stock-based compensation
arrangements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants and
amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum pension liability
adjustment (net of
related tax benefit of $1)
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AT DECEMBER 31, 2005 |
|
|
|
|
|
|
70.8 |
|
|
$ |
12 |
|
|
$ |
794 |
|
|
$ |
1,102 |
|
|
|
(1.5 |
) |
|
$ |
(19 |
) |
|
$ |
(2 |
) |
Net earnings |
|
|
801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.4 |
) |
|
|
(151 |
) |
|
|
|
|
Shares issued for stock
options and benefit plans |
|
|
|
|
|
|
0.8 |
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
0.1 |
|
|
|
11 |
|
|
|
|
|
Excess tax benefits from
stock-based compensation
arrangements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants and
amortization |
|
|
|
|
|
|
0.1 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment to initially
apply FASB Statement No.
158 (net of related tax
benefit of $42) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(66 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AT DECEMBER 31, 2006 |
|
|
|
|
|
|
71.7 |
|
|
$ |
12 |
|
|
$ |
841 |
|
|
$ |
1,876 |
|
|
|
(3.8 |
) |
|
$ |
(159 |
) |
|
$ |
(68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
50
TESORO CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
Adjustments to reconcile net earnings to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
247 |
|
|
|
186 |
|
|
|
154 |
|
Amortization of debt issuance costs and discounts |
|
|
15 |
|
|
|
17 |
|
|
|
18 |
|
Write-off of unamortized debt issuance costs and discount |
|
|
|
|
|
|
20 |
|
|
|
9 |
|
Loss on asset disposals and impairments |
|
|
50 |
|
|
|
19 |
|
|
|
14 |
|
Stock-based compensation |
|
|
22 |
|
|
|
26 |
|
|
|
14 |
|
Deferred income taxes |
|
|
105 |
|
|
|
77 |
|
|
|
103 |
|
Excess tax benefits from stock-based compensation arrangements |
|
|
(17 |
) |
|
|
(27 |
) |
|
|
(4 |
) |
Other changes in non-current assets and liabilities |
|
|
(110 |
) |
|
|
(29 |
) |
|
|
(14 |
) |
Changes in current assets and current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
(143 |
) |
|
|
(190 |
) |
|
|
(114 |
) |
Inventories |
|
|
81 |
|
|
|
(338 |
) |
|
|
(129 |
) |
Prepayments and other |
|
|
(4 |
) |
|
|
(20 |
) |
|
|
(16 |
) |
Accounts payable and accrued liabilities |
|
|
92 |
|
|
|
510 |
|
|
|
318 |
|
|
|
|
|
|
|
|
|
|
|
Net cash from operating activities |
|
|
1,139 |
|
|
|
758 |
|
|
|
681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(436 |
) |
|
|
(258 |
) |
|
|
(179 |
) |
Proceeds from asset sales |
|
|
6 |
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(430 |
) |
|
|
(254 |
) |
|
|
(174 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common stock |
|
|
(151 |
) |
|
|
(15 |
) |
|
|
|
|
Dividend payments |
|
|
(27 |
) |
|
|
(14 |
) |
|
|
|
|
Repayments of debt |
|
|
(12 |
) |
|
|
(191 |
) |
|
|
(401 |
) |
Debt refinanced |
|
|
|
|
|
|
(900 |
) |
|
|
|
|
Proceeds from debt offerings, net of issuance costs of $10 in 2005 |
|
|
|
|
|
|
890 |
|
|
|
|
|
Proceeds from stock options exercised |
|
|
12 |
|
|
|
30 |
|
|
|
13 |
|
Excess tax benefits from stock-based compensation arrangements |
|
|
17 |
|
|
|
27 |
|
|
|
4 |
|
Financing costs and other |
|
|
(2 |
) |
|
|
(76 |
) |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(163 |
) |
|
|
(249 |
) |
|
|
(399 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCREASE IN CASH AND CASH EQUIVALENTS |
|
|
546 |
|
|
|
255 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR |
|
|
440 |
|
|
|
185 |
|
|
|
77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, END OF YEAR |
|
$ |
986 |
|
|
$ |
440 |
|
|
$ |
185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW DISCLOSURES |
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid, net of capitalized interest |
|
$ |
50 |
|
|
$ |
101 |
|
|
$ |
142 |
|
Income taxes paid |
|
$ |
356 |
|
|
$ |
289 |
|
|
$ |
53 |
|
The accompanying notes are an integral part of these consolidated financial statements.
51
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description and Nature of Business
Tesoro Corporation (Tesoro) was incorporated in Delaware in 1968 and is an independent
refiner and marketer of petroleum products. We own and operate six petroleum refineries in the
western and mid-continental United States with a combined crude oil throughput capacity of 563,000
barrels per day (bpd), and we sell refined products to a wide variety of customers. We market
refined products to wholesale and retail customers, as well as commercial end-users. Our retail
business includes a network of 460 branded retail stations operated by Tesoro or independent
dealers.
Tesoros earnings, cash flows from operations and liquidity depend upon many factors,
including producing and selling refined products at margins above fixed and variable expenses. The
prices of crude oil and refined products have fluctuated substantially in our markets. Our
operating results have been significantly influenced by the timing of changes in crude oil costs
and how quickly refined product prices adjust to reflect these changes. These price fluctuations
depend on numerous factors beyond our control, including the demand for crude oil, gasoline and
other refined products, which are subject to, among other things, changes in the global economy and
the level of foreign and domestic production of crude oil and refined products, geo-political
conditions, threatened or actual terrorist incidents or acts of war, availability of crude oil and
refined product imports, the infrastructure to transport crude oil and refined products, weather
conditions, earthquakes and other natural disasters, seasonal variations, government regulations
and local factors, including market conditions and the level of operations of other suppliers in
our markets. As a result of these factors, margin fluctuations during any reporting period can have
a significant impact on our results of operations, cash flows, liquidity and financial position.
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the accounts of Tesoro and its
subsidiaries. All intercompany accounts and transactions have been eliminated. Certain investments
are carried at cost. These investments are not material, either individually or in the aggregate,
to Tesoros financial position, results of operations or cash flows.
Separate financial statements of Tesoros subsidiary guarantors are not included because these
subsidiary guarantors are full and unconditional and jointly and severally liable for Tesoros
outstanding senior notes and senior subordinated notes. In addition, the parent company has no
material independent assets or operations and non-guarantee subsidiaries are minor. Further, net
assets, results of operations and equity of the subsidiary guarantors are substantially equivalent
to Tesoros consolidated net assets, results of operations and equity.
Beginning in 2005, we allocated certain information technology costs, previously reported as
selling, general and administrative expenses, to costs of sales and operating expenses in order to
better reflect costs directly attributable to our segment operations (see Note C).
Use of Estimates
We prepare Tesoros consolidated financial statements in conformity with accounting principles
generally accepted in the United States of America (U.S. GAAP), which requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the year. We review our estimates on an ongoing
basis, based on currently available information. Changes in facts and circumstances may result in
revised estimates and actual results could differ from those estimates.
52
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash and Cash Equivalents
We consider all highly-liquid instruments, such as temporary cash investments, with a maturity
of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated
at cost, which approximates market value.
Financial Instruments
The carrying amounts of financial instruments, including cash and cash equivalents,
receivables, accounts payable and certain accrued liabilities, approximate fair value because of
the short maturities of these instruments. The carrying amounts of Tesoros debt and other
obligations may vary from our estimates of the fair value of such items. We estimate that the fair
market value of our senior notes at December 31, 2006, was approximately $7 million less than its
total book value of $900 million.
Inventories
Inventories are stated at the lower of cost or market. We use last-in, first-out (LIFO) as
the primary method to determine the cost of crude oil and refined product inventories in our
refining and retail segments. We determine the carrying value of inventories of oxygenates and
by-products using the first-in, first-out (FIFO) cost method. We value merchandise and materials
and supplies at average cost.
Property, Plant and Equipment
We capitalize the cost of additions, major improvements and modifications to property, plant
and equipment. We compute depreciation of property, plant and equipment on the straight-line
method, based on the estimated useful life of each asset. The weighted average lives range from 24
to 26 years for refineries, 8 to 16 years for terminals, 11 to 15 years for retail stations, 4 to
27 years for transportation assets and 4 to 16 years for corporate assets. We record property under
capital leases at the present value of minimum lease payments using Tesoros incremental borrowing
rate. We amortize property under capital leases over the term of each lease.
We capitalize interest as part of the cost of major projects during the construction period.
Capitalized interest, which is a reduction to interest and financing costs in the statements of
consolidated operations, totaled $12 million, $8 million and $4 million during 2006, 2005 and 2004,
respectively.
Asset Retirement Obligations
We accrue for asset retirement obligations in the period in which the obligations are incurred
and a reasonable estimate of fair value can be made. We accrue these costs at estimated fair value.
When the related liability is initially recorded, we capitalize the cost by increasing the carrying
amount of the related long-lived asset. Over time, the liability is accreted to its settlement
value and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, we recognize a gain or loss for any difference between the settlement
amount and the liability recorded. We have considered the relevant facts and circumstances
including our past practice, industry practice, managements intent and estimated economic lives to
estimate settlement dates or a range of settlement dates.
53
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We have recorded asset retirement obligations for requirements imposed by certain regulations
pertaining to hazardous materials disposal and other cleanup obligations associated with projects
at our Golden Eagle refinery primarily to retire certain above-ground storage tanks currently
estimated between 2007 and 2012 and to modify our existing coker unit to a delayed coker (see
Environmental Capital Expenditures in Note N). Asset retirement obligations have also been
recorded for certain lease agreements associated with our retail and terminal operations which
generally require that we remove certain improvements, primarily tanks, upon lease termination.
Changes in asset retirement obligations for the years ended December 31, 2006 and 2005 were as
follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Balance at beginning of year |
|
$ |
46 |
|
|
$ |
1 |
|
Additions to accrual |
|
|
1 |
|
|
|
44 |
|
Accretion expense |
|
|
3 |
|
|
|
1 |
|
Settlements |
|
|
(1 |
) |
|
|
|
|
Changes in timing and amount of estimated cash flows |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
$ |
52 |
|
|
$ |
46 |
|
|
|
|
|
|
|
|
We cannot currently make reasonable estimates of the fair values of some retirement
obligations. These retirement obligations primarily include (i) hazardous materials disposal (such
as petroleum manufacturing by-products, chemical catalysts and sealed insulation material
containing asbestos), site restoration, removal or dismantlement requirements associated with the
closure of our refining and terminal facilities or pipelines, (ii) hazardous materials disposal and
other removal requirements associated with the demolition of certain major processing units,
buildings, tanks or other equipment and (iii) removal of underground storage tanks at our owned
retail stations at or near the time of closure. We cannot estimate the fair value for these
obligations primarily because we cannot estimate settlement dates or a range of settlement dates
associated with these assets. Such obligations will be recognized in the period in which sufficient
information exists to determine a reasonable estimate. We believe that these assets have
indeterminate useful lives which preclude development of assumptions about the potential timing of
settlement dates based on the following: (i) there are no plans or expectations of plans to retire
or dispose of these core assets; (ii) we plan on extending these core assets estimated economic
lives through scheduled maintenance projects at our refineries and other normal repair and
maintenance and by continuing to make improvements based on technological advances; (iii) we have
rarely or never retired similar assets in the past; and (iv) industry practice for similar assets
has historically been to extend the economic lives through regular repair and maintenance and
technological advances. Also, we have not historically incurred significant retirement obligations
for hazardous materials disposal or other removal costs associated with our scheduled maintenance
projects.
Environmental Matters
We capitalize environmental expenditures that extend the life or increase the capacity of
facilities, as well as expenditures that mitigate or prevent environmental contamination that is
yet to occur. We charge to expense costs that relate to an existing condition caused by past
operations and that do not contribute to current or future revenue generation. We record
liabilities when environmental assessments and/or remedial efforts are probable and can be
reasonably estimated. Cost estimates are based on the expected timing and the extent of remedial
actions required by applicable governing agencies, experience gained from similar sites on which
environmental assessments or remediation have been completed, and the amount of our anticipated
liability considering the proportional liability and financial abilities of other responsible
parties. Generally, the timing of these accruals coincides with the completion of a feasibility
study or our commitment to a formal plan of action. Estimated liabilities are not discounted to
present value.
Goodwill and Acquired Intangibles
Goodwill represents the excess of cost (purchase price) over the fair value of net assets
acquired. Goodwill acquired in a business combination is not amortized. Acquired intangibles
consist primarily of air emissions
54
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
credits, permits and plans, and customer agreements and contracts, which we recorded at fair
value as of the date acquired. We amortize acquired intangibles on a straight-line basis over
estimated useful lives of 6 to 28 years, and we include the amortization in depreciation and
amortization expense.
Other Assets
We defer turnaround, catalyst and drydocking costs and amortize the costs on a straight-line
basis over the expected periods of benefit, generally ranging from 2 to 10 years. We periodically
shut down refinery processing units for scheduled maintenance or turnarounds. Certain catalysts are
used in refinery process units for periods exceeding one year. Also, we drydock ships, tugs and
barges for periodic maintenance. Amortization for these deferred costs, which is included in
depreciation and amortization expense, amounted to $64 million, $50 million and $34 million in
2006, 2005 and 2004, respectively.
We defer debt issuance costs related to our credit agreement and senior notes and amortize the
costs over the estimated terms of each instrument. We include the amortization in interest and
financing costs in our statements of consolidated operations. We evaluate the carrying value of
debt issuance costs when modifications are made to the related debt instruments (see Note D).
Impairment of Long-Lived Assets
We review property, plant and equipment and other long-lived assets, including acquired
intangible assets for impairment whenever events or changes in business circumstances indicate the
carrying values of the assets may not be recoverable. We would record impairment losses if the
undiscounted cash flows estimated to be generated by those assets were less than the carrying
amount of those assets. Factors that would indicate potential impairment include, but are not
limited to, significant decreases in the market value of a long-lived asset, a significant change
in the long-lived assets physical condition, and operating or cash flow losses associated with the
use of the long-lived asset. We review goodwill for impairment annually or more frequently, if
events or changes in business circumstances indicate the carrying values of the assets may not be
recoverable.
Revenue Recognition
We recognize revenues from petroleum product sales upon delivery to customers, which is the
point at which title is transferred, and when payment has either been received or collection is
reasonably assured. We include certain crude oil and refined product purchases and resales used for
trading purposes in revenues on a net basis. Nonmonetary crude oil and refined product exchange
transactions, which are entered into primarily to optimize our refinery supply requirements, are
included in costs of sales and operating expenses on a net basis. We have also entered into a
limited number of refined product sales and purchases transactions with the same counterparty that
have been entered into in contemplation with one another. On January 1, 2006, we began recording
these transactions on a net basis in costs of sales and operating expenses in connection with the
adoption of the Emerging Issues Task Force (EITF) Issue No. 04-13, Accounting for Purchases and
Sales of Inventory with the Same Counterparty. Prior to our adoption of this standard, we recorded
these purchases and sales on a gross basis in revenues and costs of sales (see New Accounting
Standards and Disclosures for further information). We include transportation fees charged to
customers in revenues, and we include the related costs in costs of sales in our statements of
consolidated operations.
Federal excise and state motor fuel taxes collected from customers in our retail segment and
remitted to governmental agencies are included in revenues and costs of sales. These taxes,
primarily related to sales of gasoline and diesel fuel, totaled $102 million, $108 million and $123
million in 2006, 2005 and 2004, respectively. Excise taxes on sales in our refining segment are not
included in revenues and costs of sales.
55
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
We record deferred tax assets and liabilities for future income tax consequences that are
attributable to differences between financial statement carrying amounts of assets and liabilities
and their income tax bases. We base the measurement of deferred tax assets and liabilities on
enacted tax rates that we expect will apply to taxable income in the year when we expect to settle
or recover those temporary differences. We recognize the effect on deferred tax assets and
liabilities of any change in income tax rates in the period that includes the enactment date. We
provide a valuation allowance for deferred tax assets if it is more likely than not that those
items will either expire before we are able to realize their benefit or their future deductibility
is uncertain.
Stock-Based Compensation
We follow the fair value method of accounting for stock-based compensation prescribed by
Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), Share-Based Payment.
For each of the three years ended December 31, 2006, stock-based compensation was recorded under
the fair value method. We estimate the fair value of certain stock-based awards using the
Black-Scholes option-pricing model. The fair value of our restricted stock awards on the date of
grant is equal to the fair market price of our common stock. We amortize the fair value of our
stock options and restricted stock using the straight-line method. The fair value of our phantom
stock and stock appreciation rights is estimated at the end of each reporting period and is
recorded as a liability in our consolidated balance sheets. See Note M for further information on
Tesoros stock-based compensation plans.
Derivative Instruments
We account for derivative instruments in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended and interpreted. Tesoro periodically
enters into non-trading derivative arrangements primarily to manage exposure to commodity price
risks associated with the purchase of crude oil and the purchase and sale of refined products. To
manage these risks, we typically enter into exchange-traded futures and over-the-counter swaps,
generally with durations of one year or less.
We mark to market our non-hedging derivative instruments and recognize the changes in their
fair values in earnings. We include the carrying amounts of our derivatives in other current assets
or accrued liabilities in the consolidated balance sheets. We did not designate or account for any
derivative instruments as hedges during 2006, 2005 or 2004. Accordingly, no change in the value of
the related underlying physical asset is recorded. During 2006, we settled derivative positions of
approximately 138 million barrels of crude oil and refined products, which resulted in gains of $33
million. Losses on our derivative positions in 2005 and 2004 totaled $23 million and $53 million,
respectively. At December 31, 2006, we had open derivative positions of 10 million barrels, which
will expire at various times during 2007. We recorded the fair value of our open positions, which
resulted in an unrealized mark-to-market gain of $12 million at December 31, 2006.
New Accounting Standards and Disclosures
EITF Issue No. 04-13
In September 2005, the EITF reached a consensus on EITF Issue No. 04-13, Accounting for
Purchases and Sales of Inventory with the Same Counterparty. EITF Issue No. 04-13 requires that
two or more exchange transactions involving inventory with the same counterparty entered into in
contemplation of one another should be reported net in the statement of operations. The provisions
of this EITF issue also require the exchange of refined products for feedstocks or blendstocks
within the same line of business to be accounted for at fair value if the fair value is
determinable within reasonable limits and the transaction has commercial substance as described in
SFAS No. 153, Exchanges of Nonmonetary Assets An Amendment of APB Opinion No. 29, Accounting
for Nonmonetary Transactions. Tesoro has historically not exchanged refined products for
feedstocks and blendstocks. On January 1, 2006, we adopted the provisions of EITF Issue No. 04-13
for new arrangements
56
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
entered into and modifications or renewals of existing arrangements on or after the date of
adoption. The adoption of EITF Issue No. 04-13 did not have a material impact on our financial
position or results of operations. Prior to our adoption of EITF Issue No. 04-13, we had entered
into a limited number of refined product purchases and sales transactions with the same
counterparty which were reported in 2005 and 2004 on a gross basis in revenues and costs of sales
in the statements of consolidated operations. Refined product sales associated with these
arrangements reported on a gross basis totaled approximately $670 million and $620 million in 2005
and 2004, respectively. Related purchases of refined products, reported on a gross basis, totaled
approximately $640 million and $620 million for 2005 and 2004, respectively.
SFAS No. 154
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections which
replaces APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in
Interim Financial Statements. SFAS No. 154 requires retrospective application of a voluntary
change in accounting principle, unless it is impracticable to do so. This statement carries forward
without change the guidance in APB Opinion No. 20 for reporting the correction of an error in
previously issued financial statements and a change in accounting estimate. SFAS No. 154 is
effective for changes in accounting principle made in fiscal years beginning after December 15,
2005. We adopted the provisions of SFAS No. 154 as of January 1, 2006, which had no impact on our
financial position or results of operations.
FIN No. 48
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in
Income Taxes (FIN 48), which prescribes 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. In addition, FIN 48 provides guidance on derecognition, classification, accounting
in interim periods and disclosure requirements for uncertain tax positions. The provisions of FIN
48 are effective beginning January 1, 2007. We are currently completing our analysis of the impact
of adopting FIN 48 and have not yet determined the effect on our financial position or results of
operations.
SFAS No. 157
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which defines fair
value, establishes a framework for measuring fair value and expands disclosures about fair value
measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit
fair value measurements and does not require any new fair value measurements. The provisions of
SFAS No. 157 are effective beginning January 1, 2008. We are currently evaluating the impact this
standard will have on our financial position and results of operations.
SFAS No. 158
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans An Amendment of FASB Statements No. 87, 88, 106 and 132
(R). SFAS No. 158 requires the recognition of an asset for a plans overfunded status or a
liability for a plans underfunded status in the statement of financial position, measurement of
the funded status of a plan as of the date of its year-end statement of financial position and
recognition for changes in the funded status of a defined benefit postretirement plan in the year
in which the changes occur as a component of other comprehensive income. Tesoro measures the funded
status of its defined benefit plans as of the end of each year. See Note L for additional
disclosures required by SFAS No. 158 and the effects of adoption.
57
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FASB Staff Position SFAS 123(R)-3
In November 2005, the FASB issued FASB Staff Position (FSP) SFAS 123(R)-3, Transition
Election Related to Accounting for the Tax Effects of Share-Based Payment Awards. FSP FAS 123(R)-3
provides an alternative transition method for establishing the beginning balance of the pool of
excess tax benefits available to absorb tax deficiencies recognized subsequent to the adoption of
SFAS No. 123(R) (the APIC Pool). Tesoro has elected to adopt the alternative transition method
provided in FSP FAS 123(R)-3 for establishing the beginning balance of the APIC Pool. This method
consists of a computational component that establishes a beginning balance of the APIC Pool related
to employee compensation and a simplified method to determine the subsequent impact on the APIC
Pool of employee awards that are fully vested and outstanding upon the adoption of SFAS No. 123(R).
The adoption of this standard during the 2006 fourth quarter did not have a material impact on our
financial position or results of operations.
NOTE B EARNINGS PER SHARE
We compute basic earnings per share by dividing net earnings by the weighted average number of
common shares outstanding during the period. Diluted earnings per share include the effects of
potentially dilutive shares, principally common stock options and unvested restricted stock
outstanding during the period. Earnings per share calculations are presented below (in millions,
except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
68.0 |
|
|
|
68.1 |
|
|
|
65.5 |
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings Per Share |
|
$ |
11.78 |
|
|
$ |
7.44 |
|
|
$ |
5.01 |
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
801 |
|
|
$ |
507 |
|
|
$ |
328 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
68.0 |
|
|
|
68.1 |
|
|
|
65.5 |
|
Dilutive effect of stock options and unvested restricted stock |
|
|
1.9 |
|
|
|
2.3 |
|
|
|
3.4 |
|
|
|
|
|
|
|
|
|
|
|
Total diluted shares |
|
|
69.9 |
|
|
|
70.4 |
|
|
|
68.9 |
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Share |
|
$ |
11.46 |
|
|
$ |
7.20 |
|
|
$ |
4.76 |
|
|
|
|
|
|
|
|
|
|
|
NOTE C OPERATING SEGMENTS
The Companys revenues are derived from our two operating segments, refining and retail. Our
refining segment owns and operates six petroleum refineries located in California, Washington,
Alaska, Hawaii, North Dakota and Utah. These refineries manufacture gasoline and gasoline
blendstocks, jet fuel, diesel fuel, residual fuel oils and other refined products. We sell these
refined products, together with refined products purchased from third parties, at wholesale through
terminal facilities and other locations, primarily in Alaska, California, Nevada, Hawaii, Idaho,
Minnesota, North Dakota, Utah, Oregon and Washington. Our refining segment also sells refined
products to unbranded marketers and occasionally exports refined products to other markets in the
Asia/Pacific area. Our retail segment sells gasoline, diesel fuel and convenience store items
through company-operated retail stations and branded jobber/dealers in 18 western states from
Minnesota to Alaska and Hawaii. Retail operates under the Tesoro®, Mirastar® and 2-Go Tesoro®
brands. We developed our Mirastar® brand exclusively for use at Wal-Mart stores in an agreement
covering 14 western states.
The operating segments adhere to the accounting policies used for Tesoros consolidated
financial statements, as described in the summary of significant accounting policies in Note A. We
evaluate the performance of our segments and allocate resources based primarily on segment
operating income. Segment operating income includes those revenues and expenses that are directly
attributable to management of the respective segment. Intersegment sales from refining to retail
are made at prevailing market rates. Income taxes, interest and financing
58
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
costs, interest income and other, corporate depreciation and corporate general and administrative
expenses are excluded from segment operating income. Identifiable assets are those utilized by the
segment. Corporate assets are principally cash and other assets that are not associated with a
specific operating segment. Segment information as of and for each of the three years ended
December 31, 2006 is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Refining: |
|
|
|
|
|
|
|
|
|
|
|
|
Refined products |
|
$ |
17,323 |
|
|
$ |
15,587 |
|
|
$ |
11,633 |
|
Crude oil resales and other (a) |
|
|
564 |
|
|
|
782 |
|
|
|
419 |
|
Retail: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
|
1,060 |
|
|
|
944 |
|
|
|
863 |
|
Merchandise and other |
|
|
144 |
|
|
|
141 |
|
|
|
131 |
|
Intersegment sales from Refining to Retail |
|
|
(987 |
) |
|
|
(873 |
) |
|
|
(784 |
) |
|
|
|
|
|
|
|
|
|
|
Total Revenues |
|
$ |
18,104 |
|
|
$ |
16,581 |
|
|
$ |
12,262 |
|
|
|
|
|
|
|
|
|
|
|
Segment Operating Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
Refining (b) (c) |
|
$ |
1,476 |
|
|
$ |
1,194 |
|
|
$ |
830 |
|
Retail (b) |
|
|
(21 |
) |
|
|
(31 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
Total Segment Operating Income |
|
|
1,455 |
|
|
|
1,163 |
|
|
|
824 |
|
Corporate and Unallocated Costs (b) |
|
|
(138 |
) |
|
|
(136 |
) |
|
|
(111 |
) |
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
1,317 |
|
|
|
1,027 |
|
|
|
713 |
|
Interest and Financing Costs |
|
|
(77 |
) |
|
|
(211 |
) |
|
|
(171 |
) |
Interest Income and Other |
|
|
46 |
|
|
|
15 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes |
|
$ |
1,286 |
|
|
$ |
831 |
|
|
$ |
547 |
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
$ |
221 |
|
|
$ |
160 |
|
|
$ |
130 |
|
Retail |
|
|
16 |
|
|
|
17 |
|
|
|
18 |
|
Corporate |
|
|
10 |
|
|
|
9 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
Total Depreciation and Amortization |
|
$ |
247 |
|
|
$ |
186 |
|
|
$ |
154 |
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures (d) |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
$ |
401 |
|
|
$ |
214 |
|
|
$ |
167 |
|
Retail |
|
|
5 |
|
|
|
6 |
|
|
|
3 |
|
Corporate |
|
|
47 |
|
|
|
42 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
Total Capital Expenditures |
|
$ |
453 |
|
|
$ |
262 |
|
|
$ |
179 |
|
|
|
|
|
|
|
|
|
|
|
Identifiable Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
$ |
4,486 |
|
|
$ |
4,204 |
|
|
$ |
3,544 |
|
Retail |
|
|
207 |
|
|
|
222 |
|
|
|
241 |
|
Corporate |
|
|
1,211 |
|
|
|
671 |
|
|
|
290 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
5,904 |
|
|
$ |
5,097 |
|
|
$ |
4,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
To balance or optimize our refinery supply requirements, we sell certain crude oil that
we purchase under our supply contracts. |
59
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(b) |
|
Beginning in 2005, we allocated certain information technology costs, previously reported as
corporate and unallocated costs, to segment operating income in order to better reflect costs
directly attributable to our segment operations. Information technology costs totaling $28
million and $29 million were allocated from corporate and unallocated costs to segment
operating income during 2006 and 2005, respectively. The allocated costs reduced refining
operating income by $23 million and $24 million in 2006 and 2005, respectively, and retail
operating income by $5 million in both 2006 and 2005. |
(c) |
|
Refining operating income for 2006 includes a pretax charge of $28 million related to the
termination of the delayed coker project at our Washington refinery in July 2006. The project
had experienced significant cost escalations in engineering, materials and labor, and no
longer met our rate of return objectives. The charge is included in loss on asset disposals
and impairments in the statements of consolidated operations. |
(d) |
|
Capital expenditures do not include refinery turnaround and other maintenance costs of $117
million, $65 million and $50 million in 2006, 2005 and 2004, respectively. |
NOTE D DEBT
At December 31, 2006 and 2005, debt consisted of (in millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Credit Agreement Revolving Credit Facility |
|
$ |
|
|
|
$ |
|
|
61/4% Senior Notes Due 2012 |
|
|
450 |
|
|
|
450 |
|
65/8% Senior Notes Due 2015 |
|
|
450 |
|
|
|
450 |
|
95/8% Senior Subordinated Notes Due 2012 |
|
|
14 |
|
|
|
14 |
|
8% Senior Secured Notes Due 2008 |
|
|
|
|
|
|
9 |
|
Junior subordinated notes due 2012 (net of unamortized
discount of $46 in 2006 and $57 in 2005) |
|
|
104 |
|
|
|
93 |
|
Capital lease obligations |
|
|
28 |
|
|
|
31 |
|
|
|
|
|
|
|
|
Total debt |
|
|
1,046 |
|
|
|
1,047 |
|
Less current maturities |
|
|
17 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Debt, less current maturities |
|
$ |
1,029 |
|
|
$ |
1,044 |
|
|
|
|
|
|
|
|
On February 15, 2007, we committed to voluntarily prepay the remaining $14 million outstanding
balance of the 95/8% senior subordinated notes in April 2007 at a redemption
price of 104.8%. At December 31, 2006, the notes were included in current maturities of debt. The
aggregate maturities of Tesoros debt for each of the five years following December 31, 2006 were:
2007 $17 million; 2008 $2 million; 2009 $2 million; 2010 $2 million; and 2011 $1
million.
Credit Agreement
In July 2006, we amended our credit agreement to extend the term by one year to June 2009 and
reduce letters of credit fees and revolver borrowing interest by 0.25%. Our credit agreement
currently provides for borrowings (including letters of credit) up to the lesser of the agreements
total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base
($1.4 billion as of December 31, 2006), consisting of Tesoros eligible cash and cash equivalents,
receivables and petroleum inventories, as defined. As of December 31, 2006, we had no borrowings
and $124 million in letters of credit outstanding under the revolving credit facility, resulting in
total unused credit availability of $626 million or 83% of the eligible borrowing base. Borrowings
under the revolving credit facility bear interest at either a base rate (8.25% at December 31,
2006) or a eurodollar rate (5.33% at December 31, 2006), plus an applicable margin. The applicable
margin at December 31, 2006 was 1.25% in the case of the eurodollar rate, but varies based upon our
credit facility availability and credit ratings.
60
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Letters of credit outstanding under the revolving credit facility incur fees at an annual rate tied
to the eurodollar rate applicable margin (1.25% at December 31, 2006). We also incur commitment
fees for the unused portion of the revolving credit facility at an annual rate of 0.25% as of
December 31, 2006.
We also have a separate letters of credit agreement for the purchase of foreign crude oil. In
July 2006, we increased the capacity under the separate letters of credit agreement to $250 million
from $165 million. The agreement is secured by the crude oil inventories supported by letters of
credit issued under the agreement and will remain in effect until terminated by either party.
Letters of credit outstanding under this agreement incur fees at an annual rate of 1.25% to 1.38%.
As of December 31, 2006, we had $110 million in letters of credit outstanding under this agreement,
resulting in total unused credit availability of $140 million or 56% of total capacity under this
credit agreement.
The credit agreement contains covenants and conditions that, among other things, limit our
ability to pay cash dividends, incur indebtedness, create liens and make investments. Tesoro is
also required to maintain specified levels of fixed charge coverage and tangible net worth. We are
not required to maintain the fixed charge coverage ratio if unused credit availability exceeds 15%
of the eligible borrowing base. For the year ended December 31, 2006, we satisfied all of the
financial covenants under the credit agreement. The credit agreement is guaranteed by
substantially all of Tesoros active subsidiaries and is secured by substantially all of Tesoros
cash and cash equivalents, petroleum inventories and receivables.
61/4% Senior Notes Due 2012
In November 2005, Tesoro issued $450 million aggregate principal amount of
61/4% senior notes due November 1, 2012. The notes have a seven-year maturity
with no sinking fund requirements and are not callable. We have the right to redeem up to 35% of
the aggregate principal amount at a redemption price of 106% with proceeds from certain equity
issuances through November 1, 2008. The indenture for the notes contains covenants and restrictions
that are customary for notes of this nature and are identical to the covenants in the indenture for
Tesoros 65/8% senior notes due 2015. Substantially all of these covenants
will terminate before the notes mature if one of two specified ratings agencies assigns the notes
an investment grade rating and no events of default exist under the indenture. The terminated
covenants will not be restored even if the credit rating assigned to the notes subsequently falls
below investment grade. The notes are unsecured and are guaranteed by substantially all of Tesoros
active subsidiaries.
65/8% Senior Notes Due 2015
In November 2005, Tesoro issued $450 million aggregate principal amount of
65/8% senior notes due November 1, 2015. The notes have a ten-year maturity
with no sinking fund requirements and are subject to optional redemption by Tesoro beginning
November 1, 2010 at premiums of 3.3% through October 31, 2011, 2.2% from November 1, 2011 to
October 31, 2012, 1.1% from November 1, 2012 to October 31, 2013, and at par thereafter. We have
the right to redeem up to 35% of the aggregate principal amount at a redemption price of 106% with
proceeds from certain equity issuances through November 1, 2008. The indenture for the notes
contains covenants and restrictions that are customary for notes of this nature and are identical
to the covenants in the indenture for Tesoros 61/4% senior notes due 2012.
Substantially all of these covenants will terminate before the notes mature if one of two specified
ratings agencies assigns the notes an investment grade rating and no events of default exist under
the indenture. The terminated covenants will not be restored even if the credit rating assigned to
the notes subsequently falls below investment grade. The notes are unsecured and are guaranteed by
substantially all of Tesoros active subsidiaries.
95/8% Senior Subordinated Notes Due 2012
In April 2002, Tesoro issued $450 million principal amount of 95/8%
senior subordinated notes due April 1, 2012. On November 16, 2005, Tesoro repurchased $415 million
of the outstanding $429 million notes, in connection with the issuance of the
61/4% and 65/8% senior notes described above. In
addition, the indenture for the
61
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
notes was amended to remove substantially all of the covenants. The
notes are guaranteed by substantially all of Tesoros active domestic subsidiaries. On April 15,
2007, we committed to voluntarily prepay the remaining $14 million outstanding balance of the
95/8% senior subordinated notes in April 2007 at a redemption price of
104.8%.
8% Senior Secured Notes Due 2008
In April 2006, we voluntarily prepaid the remaining $9 million outstanding principal balance
of our 8% senior secured notes at a prepayment premium of 4%.
Junior Subordinated Notes Due 2012
In connection with our acquisition of the Golden Eagle refinery, Tesoro issued to the seller
two ten-year junior subordinated notes with face amounts totaling $150 million. The notes consist
of: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing
through May 16, 2007, and carries a 7.5% interest rate thereafter, and (ii) a $50 million junior
subordinated note, due July 2012, which bears interest at 7.47% from May 17, 2003 through May 16,
2007 and 7.5% thereafter. We initially recorded these two notes at a combined present value of
approximately $61 million, discounted at rates of 15.625% and 14.375%, respectively. We are
amortizing the discount over the term of the notes.
Capital Lease Obligations
Our capital lease obligations are comprised primarily of 30 retail stations that we sold and
leased-back in 2002 with initial terms of 17 years, with four 5-year renewal options. The portions
of the leases attributable to land are classified as operating leases, and the portions
attributable to depreciable buildings and equipment are classified as capital leases. The combined
present value of minimum lease payments related to the leased buildings and equipment totaled $22
million at December 31, 2006. Tesoro also has capital leases for tugs and barges used to transport
refined products, over varying terms ending in 2007 through 2010, in which the combined present
value of minimum lease payments totaled $6 million at December 31, 2006. At December 31, 2006 and
2005, the total cost of assets under capital leases was $39 million gross (accumulated amortization
of $16 million) and $41 million gross (accumulated amortization of $14 million), respectively. We
include amortization of the cost of assets under capital leases in depreciation and amortization.
Future minimum annual lease payments, including interest, as of December 31, 2006 for capital
leases were (in millions):
|
|
|
|
|
2007 |
|
$ |
5 |
|
2008 |
|
|
4 |
|
2009 |
|
|
5 |
|
2010 |
|
|
5 |
|
2011 |
|
|
3 |
|
Thereafter |
|
|
27 |
|
|
|
|
|
Total minimum lease payments |
|
|
49 |
|
Less amount representing interest |
|
|
21 |
|
|
|
|
|
Capital lease obligations |
|
$ |
28 |
|
|
|
|
|
NOTE E STOCKHOLDERS EQUITY
Our credit agreement and 61/4% and 65/8% senior
notes each limit our ability to pay cash dividends or repurchase stock. The limitation in each of
our debt agreements is based on limits on restricted payments (as defined in our debt agreements),
which include dividends, stock repurchases or voluntary prepayments of
62
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
subordinate debt. The aggregate amount of restricted payments cannot exceed an amount defined in
each of the debt agreements. We do not believe that the limitations will restrict our ability to
pay dividends or repurchase stock under our current programs.
Common Stock Repurchase Program
In November 2005, our Board of Directors authorized a $200 million share repurchase program,
which represented approximately 5% of our common stock then outstanding. Under the program, we
repurchase our common stock from time to time in the open market. Purchases will depend on price,
market conditions and other factors. Under the program, we repurchased 2.4 million shares of common
stock for $148 million in 2006, or an average cost per share of $62.33, and 240,000 shares for $14
million in 2005, or an average cost per share of $58.83. As of December 31, 2006, $38 million
remained available for future repurchases under the program.
Cash Dividends
On January 26, 2007, our Board of Directors declared a quarterly cash dividend on common stock
of $0.10 per share, payable on March 15, 2007 to shareholders of record on March 1, 2007. During
2006, we paid cash dividends on common stock totaling $0.40 per share.
Authorized Shares of Common Stock
In May 2006 at our 2006 Annual Meeting, our shareholders approved an increase in the number of
authorized shares of common stock from 100 million to 200 million. The additional 100 million
shares of common stock have the same rights and privileges as the shares previously authorized.
See Note M for information relating to stock-based compensation and common stock reserved for
exercise of options.
NOTE F INCOME TAXES
The income tax provision was comprised of (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
315 |
|
|
$ |
195 |
|
|
$ |
104 |
|
State |
|
|
65 |
|
|
|
52 |
|
|
|
12 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
99 |
|
|
|
71 |
|
|
|
78 |
|
State |
|
|
6 |
|
|
|
6 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
Income Tax Provision |
|
$ |
485 |
|
|
$ |
324 |
|
|
$ |
219 |
|
|
|
|
|
|
|
|
|
|
|
63
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
We provide deferred income taxes and benefits for differences between financial statement
carrying amounts of assets and liabilities and their respective tax bases. Temporary differences
and the resulting deferred tax assets and liabilities at December 31, 2006 and 2005 were (in
millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred Tax Assets: |
|
|
|
|
|
|
|
|
Alternative minimum tax credits |
|
$ |
|
|
|
$ |
56 |
|
Accrued
pension, other postretirement benefits and stock-based compensation |
|
|
124 |
|
|
|
61 |
|
Other accrued employee costs |
|
|
6 |
|
|
|
5 |
|
Accrued environmental remediation liabilities |
|
|
9 |
|
|
|
11 |
|
Other accrued liabilities |
|
|
27 |
|
|
|
33 |
|
Other |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets |
|
$ |
169 |
|
|
$ |
166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred Tax Liabilities: |
|
|
|
|
|
|
|
|
Accelerated depreciation and property related items |
|
$ |
447 |
|
|
$ |
427 |
|
Deferred maintenance costs, including refinery turnarounds |
|
|
60 |
|
|
|
36 |
|
Amortization of intangible assets |
|
|
30 |
|
|
|
27 |
|
LIFO inventory |
|
|
62 |
|
|
|
38 |
|
Other |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities |
|
$ |
599 |
|
|
$ |
533 |
|
|
|
|
|
|
|
|
The net deferred income tax liability is classified in the consolidated balance sheets as
follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
Current Assets |
|
$ |
|
|
|
$ |
22 |
|
Current Liabilities |
|
$ |
53 |
|
|
$ |
|
|
Noncurrent Liabilities |
|
$ |
377 |
|
|
$ |
389 |
|
The realization of deferred tax assets depends on Tesoros ability to generate future taxable
income. Although realization is not assured, we believe it is more likely than not that we will
realize the deferred tax assets, and therefore, we did not record a valuation allowance as of
December 31, 2006 or 2005.
The reconciliation of income tax expense at the U.S. statutory rate to the income tax expense
follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Income Taxes at U.S. Federal Statutory Rate |
|
$ |
450 |
|
|
$ |
291 |
|
|
$ |
191 |
|
Effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
State income taxes, net of federal income tax effect |
|
|
40 |
|
|
|
35 |
|
|
|
24 |
|
Manufacturing activities deduction |
|
|
(11 |
) |
|
|
(7 |
) |
|
|
|
|
Other |
|
|
6 |
|
|
|
5 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
Income Tax Provision |
|
$ |
485 |
|
|
$ |
324 |
|
|
$ |
219 |
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, we had no Federal alternative minimum tax credits or Federal net
operating loss carry-forwards.
64
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
NOTE G RECEIVABLES
Concentrations of credit risk with respect to accounts receivable are influenced by the large
number of customers comprising Tesoros customer base and their dispersion across various industry
groups and geographic areas of operations. We perform ongoing credit evaluations of our customers
financial condition, and in certain circumstances, require prepayments, letters of credit or other
collateral arrangements. We include an allowance for doubtful accounts as a reduction in our trade
receivables, which amounted to $6 million and $5 million at December 31, 2006 and 2005,
respectively.
NOTE H INVENTORIES
Components of inventories at December 31, 2006 and 2005 were (in millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Crude oil and refined products, at LIFO cost |
|
$ |
798 |
|
|
$ |
882 |
|
Oxygenates and by-products, at the lower of FIFO cost or market |
|
|
16 |
|
|
|
14 |
|
Merchandise |
|
|
8 |
|
|
|
9 |
|
Materials and supplies |
|
|
50 |
|
|
|
48 |
|
|
|
|
|
|
|
|
Total Inventories |
|
$ |
872 |
|
|
$ |
953 |
|
|
|
|
|
|
|
|
Inventories valued at LIFO cost were less than replacement cost by approximately $770 million
and $687 million, at December 31, 2006 and 2005, respectively. During 2006, a reduction in
inventory quantities resulted in a liquidation of applicable LIFO inventory quantities carried at
higher costs in the prior year. This LIFO liquidation resulted in an increase in costs of sales of
$5 million and decrease in earnings of $3 million aftertax or $0.04 per share.
NOTE I GOODWILL AND ACQUIRED INTANGIBLES
Goodwill is not amortized but tested for impairment at least annually. We review the recorded
value of goodwill for impairment during the fourth quarter of each year, or sooner if events or
changes in circumstances indicate the carrying amount may exceed fair value. Our annual evaluation
of goodwill impairment requires us to make significant estimates to determine the fair value of our
reporting units. Our estimates may change from period to period because we must make assumptions
about future cash flows, profitability and other matters. It is reasonably possible that future
changes in our estimates could have a material effect on the carrying amount of goodwill. Goodwill
included $84 million in refining and $5 million in retail at both December 31, 2006 and 2005.
All of our acquired intangible assets are subject to amortization. The following table
provides the gross carrying amount and accumulated amortization for each major class of acquired
intangible assets, excluding goodwill (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
December 31, 2005 |
|
|
|
Gross |
|
|
|
|
|
|
Net |
|
|
Gross |
|
|
|
|
|
|
Net |
|
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
|
Amount |
|
|
Amortization |
|
|
Value |
|
|
Amount |
|
|
Amortization |
|
|
Value |
|
Air emissions credits |
|
$ |
99 |
|
|
$ |
17 |
|
|
$ |
82 |
|
|
$ |
99 |
|
|
$ |
13 |
|
|
$ |
86 |
|
Refinery permits and plans |
|
|
11 |
|
|
|
3 |
|
|
|
8 |
|
|
|
11 |
|
|
|
2 |
|
|
|
9 |
|
Customer agreements and contracts |
|
|
39 |
|
|
|
22 |
|
|
|
17 |
|
|
|
39 |
|
|
|
21 |
|
|
|
18 |
|
Other intangibles |
|
|
8 |
|
|
|
3 |
|
|
|
5 |
|
|
|
9 |
|
|
|
3 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
157 |
|
|
$ |
45 |
|
|
$ |
112 |
|
|
$ |
158 |
|
|
$ |
39 |
|
|
$ |
119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The weighted average estimated lives of acquired intangible assets are: air emission credits
28 years; refinery permits and plans 22 years; customer agreements and contracts 14 years;
and other intangible assets 21 years. Amortization expense of acquired intangible assets
amounted to $7 million, $8 million and $11 million for the years ended December 31, 2006, 2005 and
2004, respectively. Amortization expense from 2007 to 2011 is estimated to be $5 million for each
year.
NOTE J OTHER NONCURRENT ASSETS
Other noncurrent assets at December 31, 2006 and 2005 consisted of (in millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred maintenance costs, including
refinery turnarounds, net of amortization |
|
$ |
166 |
|
|
$ |
113 |
|
Debt issuance costs, net of amortization |
|
|
14 |
|
|
|
17 |
|
Prepaid pension costs |
|
|
|
|
|
|
47 |
|
Intangible pension asset |
|
|
|
|
|
|
5 |
|
Notes receivable from employees |
|
|
2 |
|
|
|
2 |
|
Other assets, net of amortization |
|
|
23 |
|
|
|
23 |
|
|
|
|
|
|
|
|
Total Other Assets |
|
$ |
205 |
|
|
$ |
207 |
|
|
|
|
|
|
|
|
Prior to our adoption of SFAS No. 158, we recognized prepaid pension costs to reflect our
contributions made to our pension plan that exceeded amounts that were recognized as pension
expense during 2005 (see Note L). Notes receivable from employees includes two non-interest bearing
notes due from an employee who subsequently became an executive officer with remaining terms of 2
and 4 years. These two notes, which totaled approximately $1 million at both December 31, 2006 and
2005, were assumed in connection with the acquisition of our Golden Eagle refinery in May 2002.
NOTE K ACCRUED LIABILITIES
The Companys current accrued liabilities and noncurrent other liabilities at December 31,
2006 and 2005 included (in millions):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Accrued Liabilities Current: |
|
|
|
|
|
|
|
|
Taxes other than income taxes, primarily excise taxes |
|
$ |
139 |
|
|
$ |
139 |
|
Income taxes payable |
|
|
8 |
|
|
|
7 |
|
Employee costs |
|
|
79 |
|
|
|
70 |
|
Deferred income tax liability |
|
|
53 |
|
|
|
|
|
Interest |
|
|
20 |
|
|
|
16 |
|
Asset retirement obligations |
|
|
18 |
|
|
|
3 |
|
MTBE facility lease termination obligation |
|
|
|
|
|
|
30 |
|
Environmental liabilities |
|
|
6 |
|
|
|
9 |
|
Pension and other postretirement benefits |
|
|
6 |
|
|
|
|
|
Other |
|
|
56 |
|
|
|
54 |
|
|
|
|
|
|
|
|
Total Accrued Liabilities Current |
|
$ |
385 |
|
|
$ |
328 |
|
|
|
|
|
|
|
|
66
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Other Liabilities Noncurrent: |
|
|
|
|
|
|
|
|
Pension and other postretirement benefits |
|
$ |
240 |
|
|
$ |
174 |
|
Asset retirement obligations |
|
|
34 |
|
|
|
43 |
|
Environmental liabilities |
|
|
17 |
|
|
|
23 |
|
Other |
|
|
33 |
|
|
|
35 |
|
|
|
|
|
|
|
|
Total Other Liabilities Noncurrent |
|
$ |
324 |
|
|
$ |
275 |
|
|
|
|
|
|
|
|
On December 31, 2006, we recognized an additional liability for the underfunded status of our
pension and postretirement plans totaling $53 million in connection with the adoption of SFAS No.
158 (see Notes A and L for further information). The MTBE facility lease termination obligation in
2005 represents a final payment which was made in 2006 in connection with the termination of the
lease.
NOTE L BENEFIT PLANS
Pension and Other Postretirement Benefits
Tesoro sponsors four defined benefit pension plans, including a funded employee retirement
plan, an unfunded executive security plan, an unfunded non-employee director retirement plan and an
unfunded restoration retirement plan. The funded employee retirement plan provides to all eligible
employees benefits based on years of service and compensation. Although Tesoro has no minimum
required contribution obligation to its funded employee retirement plan under applicable laws and
regulations in 2007, we expect to voluntarily contribute approximately $25 million to the plan in
2007. We also had no minimum required obligation in 2006, however, we voluntarily contributed $25
million in 2006. Plan assets are primarily comprised of common stock and bond funds.
Tesoros unfunded executive security plan provides certain executive officers and other key
personnel with supplemental death or retirement benefits. These benefits are provided by a
nonqualified, noncontributory plan and are based on years of service and compensation.
Tesoro had previously established an unfunded non-employee director retirement plan that
provided eligible directors retirement payments upon meeting certain age and other requirements. In
1997, that plan was frozen with accrued benefits of current directors transferred to the board of
directors phantom stock plan (see Note M). After the amendment and transfer, only those retired
directors or beneficiaries who had begun to receive benefits remained participants in the previous
plan.
The unfunded restoration retirement plan, which became effective July 1, 2006, provides for
the restoration of retirement benefits to certain executives and other senior employees of Tesoro
that are not available due to the limits imposed by the Internal Revenue Code on our funded
employee retirement plan.
Tesoro provides to retirees who met certain service requirements and were participating in our
group insurance program at retirement, health care benefits and, to those who qualify, life
insurance benefits. Health care is available to qualified dependents of participating retirees.
These benefits are provided through unfunded, defined
benefit plans or through contracts with area health-providers on a premium basis. The health
care plans are contributory, with retiree contributions adjusted periodically, and contain other
cost-sharing features such as deductibles and coinsurance. The life insurance plan is
noncontributory. We fund Tesoros share of the cost of postretirement health care and life
insurance benefits on a pay-as-you go basis.
Our retiree medical plan provides prescription drug benefits, which were affected by the
Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), signed in to law
in December 2003. The Act introduced a prescription drug benefit under Medicare (Medicare Part D),
as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is at least actuarially equivalent to Medicare Part D. We expect to receive
approximately $300,000 to $500,000 annually in federal subsidy receipts for the years 2007 through
2011 and an aggregate $4 million for the years 2012 through 2016.
67
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The combined accumulated benefit obligations for our retirement plans was $252 million and
$209 million at December 31, 2006 and 2005, respectively. Changes in benefit obligations, plan
assets and the funded status of the pension plans and other postretirement benefits as of December
31, 2006 and 2005, were (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
|
Pension Benefits |
|
|
Benefits |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligations at beginning of year |
|
$ |
259 |
|
|
$ |
218 |
|
|
$ |
194 |
|
|
$ |
149 |
|
Service cost |
|
|
21 |
|
|
|
19 |
|
|
|
12 |
|
|
|
9 |
|
Interest cost |
|
|
15 |
|
|
|
13 |
|
|
|
10 |
|
|
|
9 |
|
Actuarial (gain) loss |
|
|
28 |
|
|
|
22 |
|
|
|
(27 |
) |
|
|
30 |
|
Benefits paid |
|
|
(14 |
) |
|
|
(13 |
) |
|
|
(4 |
) |
|
|
(3 |
) |
Curtailments and settlements |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
Plan amendments |
|
|
11 |
|
|
|
4 |
|
|
|
7 |
|
|
|
|
|
Special termination benefits |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligations at end of year |
|
|
320 |
|
|
|
259 |
|
|
|
192 |
|
|
|
194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
224 |
|
|
|
130 |
|
|
|
|
|
|
|
|
|
Actual return on plan assets |
|
|
30 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
Employer contributions |
|
|
26 |
|
|
|
95 |
|
|
|
4 |
|
|
|
3 |
|
Benefits paid |
|
|
(14 |
) |
|
|
(13 |
) |
|
|
(4 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year |
|
|
266 |
|
|
|
225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status |
|
$ |
(54 |
) |
|
$ |
(34 |
) |
|
$ |
(192 |
) |
|
$ |
(194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of pension and postretirement benefit expense included in the consolidated
statements of operations for the years ended December 31, 2006, 2005 and 2004 were (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
|
Pension Benefits |
|
|
Benefits |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Components of net periodic benefit expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
21 |
|
|
$ |
19 |
|
|
$ |
16 |
|
|
$ |
12 |
|
|
$ |
9 |
|
|
$ |
8 |
|
Interest cost |
|
|
15 |
|
|
|
13 |
|
|
|
12 |
|
|
|
10 |
|
|
|
9 |
|
|
|
8 |
|
Expected return on plan assets |
|
|
(19 |
) |
|
|
(11 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized net actuarial loss |
|
|
5 |
|
|
|
4 |
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Special termination benefits |
|
|
|
|
|
|
2 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit expense |
|
$ |
24 |
|
|
$ |
29 |
|
|
$ |
24 |
|
|
$ |
23 |
|
|
$ |
18 |
|
|
$ |
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective December 31, 2006, Tesoro adopted SFAS No. 158, Employers Accounting for Defined
Benefit Pension and Other Postretirement Plans An Amendment of FASB Statements No. 87, 88, 106
and 132 (R). SFAS No. 158 requires the recognition of an asset for a plans overfunded status or
a liability for a plans underfunded status in the statement of financial position, measurement of
the funded status of a plan as of the date of its year-end statement of financial position and
recognition for changes in the funded status of a defined benefit postretirement plan in the year
in which the changes occur as a component of other comprehensive income. No measurement adjustment
was required as Tesoro measures the funded status of its defined benefit pension and
68
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
postretirement
plans as of the end of each year. The amounts included in our consolidated balance sheet related
to our defined benefit pension and postretirement plans before and after adoption of SFAS No. 158
as of December 31, 2006 are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before |
|
|
|
|
|
After |
|
|
Adoption of |
|
SFAS No. 158 |
|
Adoption of |
|
|
SFAS No. 158 |
|
Adjustments |
|
SFAS No. 158 |
Other assets |
|
$ |
55 |
|
|
$ |
(55 |
) |
|
$ |
|
|
Deferred income taxes |
|
|
61 |
|
|
|
42 |
|
|
|
103 |
|
Accrued liabilities |
|
|
|
|
|
|
(6 |
) |
|
|
(6 |
) |
Other liabilities |
|
|
(193 |
) |
|
|
(47 |
) |
|
|
(240 |
) |
Accumulated other comprehensive loss |
|
|
2 |
|
|
|
66 |
|
|
|
68 |
|
Amounts included in accumulated other comprehensive loss before income taxes at December 31,
2006 and 2005 for our defined benefit pension and postretirement plans are presented below (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Pension Benefits |
|
|
Postretirement Benefits |
|
|
Total |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net loss |
|
$ |
69 |
|
|
$ |
3 |
|
|
$ |
12 |
|
|
$ |
|
|
|
$ |
81 |
|
|
$ |
3 |
|
Prior service cost |
|
|
21 |
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
90 |
|
|
$ |
3 |
|
|
$ |
21 |
|
|
$ |
|
|
|
$ |
111 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts included in accumulated other comprehensive loss before income taxes as of December
31, 2006 that are expected to be recognized as components of net periodic benefit cost in 2007 for
our defined benefit pension and postretirement plans was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Pension |
|
|
Postretirement |
|
|
|
|
|
|
Benefits |
|
|
Benefits |
|
|
Total |
|
Net loss |
|
$ |
5 |
|
|
$ |
|
|
|
$ |
5 |
|
Prior service cost |
|
|
4 |
|
|
|
1 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
9 |
|
|
$ |
1 |
|
|
$ |
10 |
|
|
|
|
|
|
|
|
|
|
|
Prior to our adoption of SFAS No. 158, the funded status of our pension and postretirement
plans were adjusted in the consolidated balance sheet by the amount of unrecognized prior service
cost and net actuarial losses. The reconciliation of our funded status for both our defined benefit
pension and postretirement plans to amounts included in our consolidated balance sheet as of
December 31, 2005 was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
|
Pension Benefits |
|
|
Benefits |
|
Funded status |
|
|
(34 |
) |
|
|
(194 |
) |
Unrecognized prior service cost |
|
|
12 |
|
|
|
2 |
|
Unrecognized net actuarial loss |
|
|
56 |
|
|
|
40 |
|
|
|
|
|
|
|
|
Prepaid (accrued benefit) cost |
|
$ |
34 |
|
|
$ |
(152 |
) |
|
|
|
|
|
|
|
Amounts included in consolidated balance sheet (a): |
|
|
|
|
|
|
|
|
Other assets |
|
$ |
48 |
|
|
$ |
|
|
Intangible asset |
|
|
5 |
|
|
|
|
|
Other liabilities |
|
|
(21 |
) |
|
|
(152 |
) |
Accumulated other comprehensive loss |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
Net asset (liability) amount recognized |
|
$ |
34 |
|
|
$ |
(152 |
) |
|
|
|
|
|
|
|
69
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
|
|
|
(a) |
|
At December 31, 2005, our contributions to the funded employee retirement plan exceeded the
plans associated net periodic benefit expense resulting in a prepaid pension cost asset of
$47 million. Further, the accumulated benefit obligation of the executive security plan
exceeded the fair value of plan assets resulting in the recognition of an additional minimum
liability of $8 million, an intangible asset of $5 million and accumulated other comprehensive
loss, net of tax benefit of $2 million. |
Significant assumptions included in estimating Tesoros pension and other postretirement
benefits obligations were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
Pension Benefits |
|
Benefits |
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
Projected Benefit Obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed weighted average % as of
December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
6.00 |
|
|
|
5.50 |
|
|
|
5.75 |
|
|
|
6.00 |
|
|
|
5.50 |
|
|
|
5.75 |
|
Rate of compensation increase |
|
|
3.72 |
|
|
|
3.23 |
|
|
|
3.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Pension Cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed weighted average % as of
December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.52 |
|
|
|
5.75 |
|
|
|
6.25 |
|
|
|
5.50 |
|
|
|
5.75 |
|
|
|
6.25 |
|
Rate of compensation increase |
|
|
3.61 |
|
|
|
3.70 |
|
|
|
3.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected return on plan assets (a) |
|
|
8.50 |
|
|
|
8.50 |
|
|
|
8.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The expected return on plan assets reflects the weighted-average of the expected long term
rates of return for the broad categories of investments held in the plans. The expected
long-term rate of return is adjusted when there are fundamental changes in expected returns on
the plans investments. |
The assumed health care cost trend rates used to determine the projected postretirement
benefit obligation are as follows:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
Health care cost trend rate assumed for next year |
|
|
9.00 |
% |
|
|
10.00 |
% |
Rate to which the cost trend rate is assumed to decline |
|
|
5.00 |
% |
|
|
5.00 |
% |
Year that the rate reaches the ultimate trend rate |
|
|
2011 |
|
|
|
2011 |
|
Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care and life insurance plans. A one-percentage-point change in assumed health care cost
trend rates could have the following effects (in millions):
|
|
|
|
|
|
|
|
|
|
|
1-Percentage-Point |
|
1-Percentage-Point |
|
|
Increase |
|
Decrease |
Effect on total of service and interest cost components |
|
$ |
4 |
|
|
$ |
(3 |
) |
Effect on postretirement benefit obligations |
|
$ |
28 |
|
|
$ |
(23 |
) |
Our pension plans follow an investment return approach in which investments are allocated to
broad investment categories, including equities, debt and real estate, to maximize the long-term
return of the plan assets
70
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
at a prudent level of risk. The 2006 target allocations for the pension plans assets were 68%
equity securities (with sub-category allocation targets), 25% debt securities and 7% real estate.
Our other postretirement benefit plans contained no assets at December 31, 2006 and 2005. The
weighted-average asset allocations in our pension plans at December 31, 2006 and 2005 were:
|
|
|
|
|
|
|
|
|
|
|
Plan Assets |
|
|
|
at |
|
|
|
December 31, |
|
Asset Category |
|
2006 |
|
|
2005 |
|
Equity Securities |
|
|
69 |
% |
|
|
71 |
% |
Debt Securities |
|
|
25 |
|
|
|
25 |
|
Real Estate |
|
|
6 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
The following estimated future benefit payments, which reflect expected future service, as
appropriate, are expected to be paid in the years indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
2007 |
|
$ |
21 |
|
|
$ |
5 |
|
2008 |
|
|
25 |
|
|
|
5 |
|
2009 |
|
|
28 |
|
|
|
7 |
|
2010 |
|
|
30 |
|
|
|
8 |
|
2011 |
|
|
34 |
|
|
|
9 |
|
20122016 |
|
|
208 |
|
|
|
65 |
|
Thrift Plan and Retail Savings Plan
Tesoro sponsors an employee thrift plan that provides for contributions, subject to certain
limitations, by eligible employees into designated investment funds with a matching contribution by
Tesoro. Employees may elect tax-deferred treatment in accordance with the provisions of Section
401(k) of the Internal Revenue Code. Tesoro matches 100% of employee contributions, up to 7% of the
employees eligible earnings, with at least 50% of the matching contribution directed for initial
investment in Tesoros common stock. The maximum matching contribution is 6% for employees covered
by the collective bargaining agreement at the Golden Eagle refinery. Participants with the
exception of executive officers are eligible to transfer out of Tesoros common stock at any time,
on an unlimited basis. Tesoros contributions to the thrift plan amounted to $16 million, $15
million and $13 million during 2006, 2005 and 2004, respectively, of which $11 million, $8 million
and $6 million consisted of treasury stock reissuances in 2006, 2005 and 2004, respectively.
The unfunded executive deferred compensation plan, which became effective January 1, 2007,
provides to certain executives and other employees the ability to defer compensation and receive a
matching contribution by Tesoro that is not available under the employee thrift plan due to salary
deferral limits imposed by the Internal Revenue Code.
Tesoro sponsors a savings plan, in lieu of the thrift plan, for eligible retail employees who
have completed one year of service and have worked at least 1,000 hours within that time. Eligible
employees receive a mandatory employer contribution equal to 3% of eligible earnings. If employees
elect to make pretax contributions, Tesoro also contributes an employer match contribution equal to $0.50 for each $1.00 of employee
contributions, up to 6% of eligible earnings. At least 50% of the matching employer contributions
must be directed for initial investment in Tesoro common stock. Participants are eligible to
transfer out of Tesoros common stock at any
71
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
time, on an unlimited basis. Tesoros contributions amounted to $0.4 million during 2006, 2005
and 2004, of which $0.1 million consisted of treasury stock reissuances in 2006, 2005, and 2004.
NOTE M STOCK-BASED COMPENSATION
Tesoro follows the fair value method of accounting for stock-based compensation prescribed by
SFAS No. 123 (Revised 2004), Share-Based Payment. Stock-based compensation expense for all
stock-based awards for 2006, 2005 and 2004 was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
$ |
13 |
|
|
$ |
15 |
|
|
$ |
8 |
|
Restricted stock |
|
|
5 |
|
|
|
4 |
|
|
|
2 |
|
Stock appreciation rights |
|
|
3 |
|
|
|
|
|
|
|
|
|
Phantom stock |
|
|
1 |
|
|
|
7 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
Total Stock-Based Compensation |
|
$ |
22 |
|
|
$ |
26 |
|
|
$ |
14 |
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation during 2005 included charges totaling $5 million associated with the
termination and retirement of certain executive officers. The income tax benefit realized from tax
deductions associated with option exercises totaled $17 million, $28 million and $6 million during
2006, 2005 and 2004, respectively.
Incentive Stock Plans
We have three employee incentive stock plans, the 2006 Long-Term Incentive Plan, the Amended
and Restated Executive Long-Term Incentive Plan and the Key Employee Stock Option Plan, as amended.
We also have the 1995 Non-Employee Director Stock Option Plan, as amended. At December 31, 2006,
Tesoro had 5,474,873 shares of unissued common stock reserved for these plans.
The 2006 Long-Term Incentive Plan (2006 Plan) permits the grant of options, restricted
stock, deferred stock units, performance stock awards, other stock-based awards and cash-based
awards. The 2006 Plan became effective in May 2006 and no awards may be granted under the 2006 Plan
on or after May 3, 2016. The maximum amount of common stock which may be issued under the 2006
Plan may not exceed 1,500,000 shares of which up to 375,000 shares in the aggregate may be granted
as restricted stock, deferred stock units, performance shares, performance units and other
stock-based awards. Stock options may be granted at exercise prices not less than the
fair market value on the date the options are granted. The options granted become exercisable
after one year in 33% annual increments and expire ten years from the date of grant. At December
31, 2006, Tesoro had 1,500,000 shares available for future grants under this plan.
Under the Amended and Restated Executive Long-Term Incentive Plan, shares of common stock may
be granted in a variety of forms, including restricted stock, nonqualified stock options, stock
appreciation rights and performance share and performance unit awards. Tesoro may grant up to
9,250,000 shares under this plan, of which up to 1,500,000 shares in the aggregate may be granted
as restricted stock, performance shares and performance units. Stock options may be granted at
exercise prices not less than the fair market value on the date the options are granted. The
options granted generally become exercisable after one year in 25% or 33% annual increments and
expire ten years from the date of grant. Options granted under the plan may not be repriced without
stockholder approval. The plan expired as to the issuance of awards in May 2006 upon shareholder
approval of the 2006 Plan. At December 31, 2006, we had 3,422,004 options and 563,404 restricted
shares outstanding under this plan.
The Key Employee Stock Option Plan provided stock option grants to eligible employees who were
not executive officers of Tesoro. We granted stock options to purchase 797,000 shares of common
stock, of which 190,869 shares were outstanding at December 31, 2006, which become exercisable one year after
grant in 25% annual increments. The options expire ten years after the date of grant. Our Board of
Directors has suspended future grants under this plan.
72
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The 1995 Non-Employee Director Stock Option Plan provides for the grant of up to 450,000
nonqualified stock options over the life of the plan to eligible non-employee directors of Tesoro.
These automatic, non-discretionary stock options are granted at an exercise price equal to the fair
market value per share of Tesoros common stock at the date of grant. The term of each option is
ten years, and an option becomes exercisable six months after it is granted. This plan will expire,
unless earlier terminated, as to the issuance of awards in February 2010. At December 31, 2006,
Tesoro had 151,000 options outstanding and 211,000 shares available for future grants under this
plan.
A summary of stock option activity for all plans is set forth below (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
Aggregate |
|
|
|
Number of |
|
|
Weighted-Average |
|
|
Remaining |
|
|
Intrinsic Value |
|
|
|
Options |
|
|
Exercise Price |
|
|
Contractual Term |
|
|
(In Millions)__ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2006 |
|
|
4,037 |
|
|
|
17.90 |
|
|
6.3 years |
|
$ |
176 |
|
Granted |
|
|
557 |
|
|
|
67.35 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(797 |
) |
|
|
15.27 |
|
|
|
|
|
|
|
|
|
Forfeited or expired |
|
|
(33 |
) |
|
|
37.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
3,764 |
|
|
$ |
25.61 |
|
|
6.1 years |
|
$ |
151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2006 |
|
|
2,553 |
|
|
$ |
15.25 |
|
|
5.0 years |
|
$ |
129 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimated weighted-average grant-date fair value per share of options granted during 2006,
2005 and 2004 was $32.01, $18.52 and $13.01, respectively. We estimate the fair value using the
Black-Scholes option-pricing model. The total intrinsic value for options exercised during 2006,
2005 and 2004 was $44 million, $70 million and $15 million, respectively. Total unrecognized
compensation cost related to non-vested stock options totaled $18 million as of December 31, 2006,
which is expected to be recognized over a weighted-average period of 1.7 years.
We estimated the fair value of each option on the date of grant using the Black-Scholes
option-pricing model. We amortize the estimated fair value of stock options granted over the
vesting period using the straight-line method. Expected volatilities are based on the historical
volatility of our stock. We use historical data to estimate option exercise and employee
termination within the valuation model. The expected life of options granted is based on historical
data and represents the period of time that options granted are expected to be outstanding. The
risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury
yield curve in effect at the time of grant. Tesoros weighted average assumptions are presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
Expected life (years) |
|
|
6 |
|
|
|
7 |
|
|
|
7 |
|
Expected volatility |
|
|
46% - 48 |
% |
|
|
45% - 49 |
% |
|
|
42% - 43 |
% |
Expected dividend yield (a) |
|
|
0.63% - 0.79 |
% |
|
|
0.16% - 0.24 |
% |
|
|
|
|
Weighted average volatility |
|
|
48 |
% |
|
|
48 |
% |
|
|
43 |
% |
Risk-free interest rate |
|
|
4.6 |
% |
|
|
4.0 |
% |
|
|
4.3 |
% |
|
|
|
(a) |
|
In June 2005, we began paying a quarterly cash dividend on common stock of $0.05 per share
which was increased to $0.10 per share in December 2005. |
Restricted Stock
We amortize the estimated fair value of our restricted stock granted over the vesting period
using the straight-line method. The fair value of each restricted share on the date of grant is
equal to its fair market price. Our
73
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
restricted shares vest in three and five year increments assuming continued employment at the
vesting dates. A summary of our restricted stock activity is set forth below (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
Number of |
|
Grant-Date |
|
|
Restricted Shares |
|
Fair Value |
Nonvested at January 1, 2006 |
|
|
627 |
|
|
$ |
20.75 |
|
Granted |
|
|
63 |
|
|
|
66.61 |
|
Vested |
|
|
(119 |
) |
|
|
23.67 |
|
Forfeited |
|
|
(8 |
) |
|
|
31.05 |
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2006 |
|
|
563 |
|
|
$ |
25.13 |
|
|
|
|
|
|
|
|
|
|
Total unrecognized compensation cost related to non-vested restricted stock totaled $8 million
as of December 31, 2006, which is expected to be recognized over a weighted-average period of 1.8
years. The total fair value of restricted shares vested was $8 million in 2006 and $4 million in
2005. We did not have any restricted shares that vested in 2004.
Director Compensation Plan
The 2005 Director Compensation Plan was approved at Tesoros annual meeting of stockholders
held in May 2005. The plan provides for the grant of up to 50,000 shares of common stock to our
eligible non-employee directors as payment for a portion of director retainer fees. We granted
3,684 shares of common stock during 2006 at a weighted-average grant-date price per share of
$68.38.
Non-Employee Director Phantom Stock Plan
Under the Non-Employee Director Phantom Stock Plan, a yearly credit of $7,250 is made in units
to an account of each non-employee director, based upon the closing market price of Tesoros common
stock on the date of credit, which vests with three years of service. A director also may elect to
have the value of his cash retainer fee deposited quarterly into the account as units that are
immediately vested. Retiring directors who are committee chairpersons receive an additional $5,000
credit to their accounts. Certain non-employee directors also received a credit in their accounts
in 1997, arising from the transfer of their lump-sum accrued benefit under the frozen Director
Retirement Plan. The value of each vested account balance, which is a function of changes in market
value of Tesoros common stock, is payable in cash commencing at termination or at retirement,
death or disability. Payments may be made as a total distribution or in annual installments, not to
exceed ten years.
Phantom Stock Options
Pursuant to our Amended and Restated Executive Long-Term Incentive Plan, Tesoros chief
executive officer also holds 175,000 phantom stock options, which were granted in 1997 with a term
of ten years at 100% of the fair value of Tesoros common stock on the grant date, or $16.9844 per
share. At December 31, 2006, all of the phantom stock options were exercisable. Upon exercise, the
chief executive officer would be entitled to receive, in cash, the difference between the fair
market value of the common stock on the date of the phantom stock option grant and the fair market
value of common stock on the date of exercise. At the discretion of the Compensation Committee of
the Board of Directors, these phantom stock options may be converted to traditional stock options
under the Amended and Restated Executive Long-Term Incentive Plan. The fair value of each phantom
stock option is estimated at the end of each reporting period using the Black-Scholes
option-pricing model. At December 31, 2006 and 2005, the liability associated with our phantom
stock awards recorded in accrued liabilities in the consolidated balance sheets totaled $9 million
and $8 million, respectively.
2006 Long-Term Stock Appreciation Rights Plan
In February 2006, our Board of Directors approved the 2006 Long-Term Stock Appreciation Rights
Plan (the SAR Plan). The SAR Plan permits the grant of stock appreciation rights (SARs) to key
managers and other
74
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
employees of Tesoro. A SAR granted under the SAR Plan entitles an employee to
receive cash in an amount equal to the excess of the fair market value of one share of common stock
on the date of exercise over the grant price of the SAR. Unless otherwise specified, all SARs under
the SAR Plan vest ratably during a three-year period following the date of grant. The term of a SAR
granted under the SAR Plan shall be determined by the Compensation Committee provided that no SAR
shall be exercisable on or after the tenth anniversary date of its grant. During 2006, we granted
328,610 SARs at 100% of the fair value of Tesoros common stock with a weighted average grant price
of $66.61 per SAR. The estimated weighted-average grant-date fair value was $32.18 per SAR, using
the Black-Scholes option-pricing model. The fair value of each SAR is estimated at the end of each
reporting period using the Black-Scholes option-pricing model. The option-pricing model
weighted-average assumptions used to calculate the fair value of SARS are similar to those used to
calculate the fair value of options as described above. At December 31, 2006, the liability
associated with our SARs recorded in accrued liabilities in the consolidated balance sheet totaled
$3 million.
NOTE N COMMITMENTS AND CONTINGENCIES
Operating Leases
Tesoro has various cancellable and noncancellable operating leases related to land, office and
retail facilities, ship charters and equipment and other facilities used in the storage,
transportation, production and sale of crude oil feedstocks and refined products. These leases have
remaining primary terms up to 37 years, with terms of certain rights-of-way extending up to 24
years, and generally contain multiple renewal options. Total rental expense for all operating
leases, excluding marine charters, amounted to approximately $45 million in 2006, $52 million in
2005 and $44 million in 2004. Total marine charter expense for
our time charters was $148 million in 2006,
$117 million in 2005 and $68 million in 2004. See Note D for information related to capital leases.
As of December 31, 2006, we term-chartered five U.S. flagged ships and five foreign-flagged
ships, used to transport crude oil and refined products with remaining terms up through July 2010.
Most of our time charters contain terms of three to eight years with renewal options. We have also
entered into term-charters for four U.S. flag tankers to be built and delivered between 2009 and
2010, each with three-year terms. All four time charters have options to renew. We have also
entered into various lease agreements for tugs and barges at our Hawaii and Washington refineries
to transport our refined products. We also have leases for several tugs and barges with terms
remaining up through September 2015 with options to renew. Our annual lease commitments for these
leases range from $16 million to $27 million over the next five years.
Tesoro has operating leases for most of its retail stations with primary remaining terms up to
37 years, and generally containing renewal options. Our aggregate annual lease commitments for the
retail stations total approximately $8 million to $9 million over the next five years. These leases
include the 30 retail stations that we sold and leased back in 2002 with initial terms of 17 years
and four five-year renewal options. We classified the portion of each lease attributable to land as
an operating lease, and the portion attributable to depreciable buildings and equipment as a
capital lease (See Note D). Tesoro also has an agreement with Wal-Mart to build and operate retail
stations at selected existing and future Wal-Mart stores in the western United States. Under the
agreement, each site is subject to a lease with a ten-year primary term and an option, exercisable
at our discretion, to extend a sites lease for two additional five-year options.
As of December 31, 2005, we leased Tesoros corporate headquarters from a limited partnership,
in which we owned a 50% limited interest. In February 2006, the limited partnership sold the
building to a third-party resulting in a gain to Tesoro of $5 million. We continue to lease our
corporate headquarters from the third-party with an initial lease term through 2014 and two
five-year renewal options. Our total rent expense includes lease payments and operating costs paid
to the partnership totaling $4 million in 2005 and $3 million in 2004. In 2005, we accounted for
Tesoros interest in the partnership using the equity method of accounting, and our consolidated
balance sheets did not include the partnerships assets, primarily land and buildings,
totaling approximately $16 million and debt of approximately $13 million.
75
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Tesoros minimum annual lease payments as of December 31, 2006, for operating leases having
initial or remaining noncancellable lease terms in excess of one year were (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ship |
|
|
|
|
|
|
Charters |
|
Other |
|
Total |
2007 |
|
$ |
99 |
|
|
$ |
72 |
|
|
$ |
171 |
|
2008 |
|
|
86 |
|
|
|
64 |
|
|
|
150 |
|
2009 |
|
|
70 |
|
|
|
58 |
|
|
|
128 |
|
2010 |
|
|
81 |
|
|
|
45 |
|
|
|
126 |
|
2011 |
|
|
75 |
|
|
|
40 |
|
|
|
115 |
|
Thereafter |
|
|
63 |
|
|
|
170 |
|
|
|
233 |
|
Purchase Obligations and Other Commitments
Tesoros contractual purchase commitments consist primarily of crude oil supply contracts for
our refineries from several suppliers with noncancellable remaining terms ranging up to 12 months
with renewal provisions. Prices under the term agreements generally fluctuate with market prices.
Assuming actual market crude oil prices as of December 31, 2006, ranging from $45 per barrel to $57
per barrel, our minimum crude oil supply commitments for the next year would approximate $4.3
billion. We also purchase crude oil at market prices under short-term renewable agreements and in
the spot market. In addition to these purchase commitments, we also have minimum contractual
capital spending commitments, totaling approximately $80 million in 2007. We do not have any
purchase commitments related to these obligations beyond 2007.
We also have long-term take-or-pay commitments to purchase chemical supplies and power
associated with the operation of our refineries. We have a power supply agreement through 2012 at
the Golden Eagle refinery, which requires minimum payments through July 2007 that vary based on
market prices for electricity. Assuming estimated future market prices of electricity, minimum
payments would approximate $28 million through July 2007. The minimum annual payments under these
take-or-pay agreements, including the power supply agreement, are estimated to total $54 million in
2007, $26 million in 2008, $24 million in 2009, $24 million in 2010, and $24 million in 2011. The
remaining minimum commitments total approximately $43 million over 14 years. Tesoro paid
approximately $125 million, $90 million and $92 million in 2006, 2005 and 2004, respectively, under
these take-or-pay contracts.
Environmental and Other Matters
We are a party to various litigation and contingent loss situations, including environmental
and income tax matters, arising in the ordinary course of business. Where required, we have made
accruals in accordance with SFAS No. 5, Accounting for Contingencies, in order to provide for
these matters. We cannot predict the ultimate effects of these matters with certainty, and we have
made related accruals based on our best estimates, subject to future developments. We believe that
the outcome of these matters will not result in a material adverse effect on our liquidity and
consolidated financial position, although the resolution of certain of these matters could have a
material adverse impact on interim or annual results of operations.
Tesoro is subject to audits by federal, state and local taxing authorities in the normal
course of business. It is possible that tax audits could result in claims against Tesoro in excess
of recorded liabilities. We believe, however, that when these matters are resolved, they will not
materially affect Tesoros consolidated financial position or results of operations.
Tesoro is subject to extensive federal, state and local environmental laws and regulations.
These laws, which change frequently, regulate the discharge of materials into the environment and
may require us to remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites, install additional controls, or make other
modifications or changes in use for certain emission sources.
76
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Conditions may develop that cause increases or decreases in future expenditures for our
various sites, including, but not limited to, our refineries, tank farms, retail stations
(operating and closed locations) and refined products terminals, and for compliance with the Clean
Air Act and other federal, state and local requirements. We cannot currently determine the amounts
of such future expenditures.
Environmental Liabilities
We are currently involved in remedial responses and have incurred and expect to continue to
incur cleanup expenditures associated with environmental matters at a number of sites, including
certain of our previously owned properties. At December 31, 2006, our accruals for environmental
expenses totaled $23 million. Our accruals for environmental expenses include retained liabilities
for previously owned or operated properties, refining, pipeline and terminal operations and retail
stations. We believe these accruals are adequate, based on currently available information,
including the participation of other parties or former owners in remediation action.
We have completed an investigation of environmental conditions at certain active wastewater
treatment units at our Golden Eagle refinery. This investigation is driven by an order from the San
Francisco Bay Regional Water Quality Control Board that names us as well as two previous owners of
the Golden Eagle refinery. We are evaluating certain improvements to the wastewater treatment units
as a result of this investigation. A reserve for this matter is included in the environmental
accruals referenced above.
In October 2005, we received a Notice of Violation (NOV) from the United Stated
Environmental Protection Agency (EPA). The EPA alleges certain modifications made to the fluid
catalytic cracking unit at our Washington refinery prior to our acquisition of the refinery were
made in violation of the Clean Air Act. We have investigated the allegations and believe the
ultimate resolution of the NOV will not have a material adverse effect on our financial position or
results of operations. A reserve for our response to the NOV is included in the environmental
accruals referenced above.
In September 2006, we reached an agreement with the Bay Area Air Quality Management District
(the District) to settle 28 NOVs issued to Tesoro from January 2004 to September 2004 alleging
violations of various air quality requirements at the Golden Eagle refinery. The settlement
agreement was executed on October 11, 2006 and Tesoro made a cash payment of $200,000 to the
District during the fourth quarter of 2006. Pursuant to the terms of the settlement agreement,
Tesoro will undertake a supplemental project valued at approximately $100,000. A reserve for the
supplemental project is included in the environmental accruals referenced above.
Other Environmental Matters
In the ordinary course of business, we become party to or otherwise involved in lawsuits,
administrative proceedings and governmental investigations, including environmental, regulatory and
other matters. Large and sometimes unspecified damages or penalties may be sought from us in some
matters for which the likelihood of loss may be reasonably possible but the amount of loss is not
currently estimable, and some matters may require years for us to resolve. As a result, we have not
established reserves for these matters. On the basis of existing information, we believe that the
resolution of these matters, individually or in the aggregate, will not have a material adverse
effect on our financial position or results of operations. However, we cannot provide assurance
that an adverse resolution of one or more of the matters described below during a future reporting
period will not have a material adverse effect on our financial position or results of operations
in future periods.
We are a defendant, along with other manufacturing, supply and marketing defendants, in ten
pending cases alleging MTBE contamination in groundwater. The defendants are being sued for having
manufactured MTBE and having manufactured, supplied and distributed gasoline containing MTBE. The
plaintiffs, all in California, are generally water providers, governmental authorities and private
well owners alleging, in part, the defendants are liable for manufacturing or distributing a
defective product. The suits generally seek individual, unquantified
compensatory and punitive damages and attorneys fees, but we cannot estimate the amount or
the likelihood of the ultimate resolution of these matters at this time, and accordingly have not
established a reserve for these cases. We believe we have defenses to these claims and intend to
vigorously defend the lawsuits.
77
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Soil and groundwater conditions at our Golden Eagle refinery may require substantial
expenditures over time. In connection with our acquisition of the Golden Eagle refinery from
Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar
had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and
contractually indemnified us for up to $50 million for certain environmental liabilities arising
from operations at the refinery prior to August of 2000, which are identified prior to August 31,
2010 (Pre-Acquisition Operations). Based on existing information, we currently estimate that the
known environmental liabilities arising from Pre-Acquisition Operations including soil and
groundwater conditions at the refinery will exceed the $50 million indemnity. We expect to be
reimbursed for excess liabilities under certain environmental insurance policies that provide $140
million of coverage in excess of the $50 million indemnity. Because of Toscos indemnification and
the environmental insurance policies, we have not established a reserve for these defined
environmental liabilities arising out of the Pre-Acquisition Operations.
In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging
that Tosco misrepresented, concealed and failed to disclose certain additional environmental
conditions at our Golden Eagle refinery related to the soil and groundwater conditions referenced
above. The court granted Toscos motion to compel arbitration of our claims for these certain
additional environmental conditions. In the arbitration proceedings we initiated against Tosco in
December 2003, we are also seeking a determination that Tosco is liable for investigation and
remediation of these certain additional environmental conditions, the amount of which is currently
unknown and therefore a reserve has not been established, and which may not be covered by the $50
million indemnity for the defined environmental liabilities arising from Pre-Acquisition
Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa
County Superior Court action alleging that we are contractually responsible for additional
environmental liabilities at our Golden Eagle refinery, including the defined environmental
liabilities arising from Pre-Acquisition Operations. The arbitration is scheduled to begin during
March 2007. We intend to vigorously prosecute our claims against Tosco and to oppose Toscos claims
against us, and although we cannot provide assurance that we will prevail, we believe that the
resolution of the arbitration will not have a material adverse effect on our financial position or
results of operations.
Environmental Capital Expenditures
EPA regulations related to the Clean Air Act require reductions in the sulfur content in
gasoline. Our Golden Eagle, Washington, Hawaii, Alaska and North Dakota refineries will not require
additional capital spending to meet the low sulfur gasoline standards. We are currently evaluating
alternative projects that will satisfy the requirements to meet the regulations at our Utah
refinery.
EPA regulations related to the Clean Air Act also require reductions in the sulfur content in
diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards
became effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content
of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become
effective in phases between 2007 and 2010. We spent $61 million in 2006 to meet the revised diesel
fuel standards, and we have budgeted an additional $18 million in 2007 to complete our diesel
desulfurizer unit to manufacture additional ultra-low sulfur diesel at our Alaska refinery. Our
Golden Eagle, Washington and Hawaii refineries will not require additional capital spending to meet
the new diesel fuel standards. We are currently evaluating alternative projects that will satisfy
the future requirements under existing regulations at both our North Dakota and Utah refineries.
In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro
assumed the sellers obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co. (BP), Amoco Oil Company and Atlantic Richfield Company. BP entered into
this consent decree for both the North Dakota and Utah refineries for various alleged violations.
As the owner of these refineries, Tesoro is required to address issues to reduce air emissions. We
spent $3 million during 2006 and we have budgeted an additional $18
million through 2009 to comply with this consent decree. We also agreed to indemnify the
sellers for all losses of any kind incurred in connection with the consent decree.
78
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
In connection with the 2002 acquisition of our Golden Eagle refinery, subject to certain
conditions, we assumed the sellers obligations pursuant to settlement efforts with the EPA
concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any
potential monetary penalties, which the seller retains. In November 2005, the Consent Decree was
entered by the District Court for the Western District of Texas in which we agreed to undertake
projects at our Golden Eagle refinery to reduce air emissions. To satisfy the requirements of the
Consent Decree, we spent $3 million during 2006 and we have budgeted an additional $25 million
through 2010.
In December 2006, we proposed an alternative monitoring plan and a schedule for removing
atmospheric blowdown towers at the Golden Eagle refinery to the Bay Area Air Quality Management
District in response to a NOV received from that agency in August 2006. We have budgeted $88
million through 2010 to remove the atmospheric blowdown towers.
During the fourth quarter of 2005, we received approval by the Hearing Board for the Bay Area
Air Quality Management District to modify our existing fluid coker unit to a delayed coker at our
Golden Eagle refinery which is designed to lower emissions while also enhancing the refinerys
capabilities in terms of reliability, lengthening turnaround cycles and reducing operating costs.
We negotiated the terms and conditions of the Second Conditional Abatement Order with the District
in response to the January 2005 mechanical failure of the fluid coker boiler at the Golden Eagle
refinery. The total capital budget for this project is $503 million, which includes budgeted
spending of $231 million in 2007 and $145 million in 2008. The project is currently scheduled to
be substantially completed during the first quarter of 2008, with spending through the first half
of 2008. We have spent $127 million from inception of the project, of which $124 million was spent
in 2006. .
We will also spend capital at the Golden Eagle refinery for reconfiguring and replacing
above-ground storage tank systems and upgrading piping within the refinery. We spent $26 million
during 2006 and we have budgeted an additional $110 million through 2011 to complete the project.
Our capital budget also includes spending of $29 million through 2010 to upgrade a marine oil
terminal at the Golden Eagle refinery to meet engineering and maintenance standards issued by the
State of California in February 2006.
Claims Against Third-Parties
In 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the
transportation of its crude oil through the Trans Alaska Pipeline System (TAPS). Our protest
asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory
Commission of Alaska (RCA) considered our protest of the intrastate rates for the years 1997
through 2000. The RCA set just and reasonable final rates for the years 1997 through 2000, and
held that we are entitled to receive approximately $52 million in refunds, including interest
through the expected conclusion of appeals in December 2007. The RCAs ruling is currently on
appeal to the Alaska Supreme Court, and we cannot give any assurances of when or whether we will
prevail in the appeal.
In 2002, the RCA rejected the TAPS Carriers proposed intrastate rate increases for 2001-2003
and maintained the permanent rate of $1.96 to the Valdez Marine Terminal. That ruling is currently
on appeal to the Alaska Superior Court, and the TAPS Carriers did not move to prevent the rate
decrease. The rate decrease has been in effect since June 2003. The TAPS Carriers attempted to
increase their intrastate rates for 2004, 2005, and 2006 without providing the supporting
information required by the RCAs regulations and in a manner inconsistent with the RCAs prior
decision in Order 151. These filings were rejected by the RCA. The rejection of these filings is
currently on appeal to the Superior Court of Alaska where the decision is being held in abeyance
pending the decision in the appeals of the rates for 1997-2003. If the RCAs decisions are upheld
on appeal, we could be entitled to refunds resulting from our shipments from January 2001 through
mid-June 2003. If the RCAs decisions are not upheld on appeal, we could potentially have to pay
the difference between the TAPS Carriers filed rates from mid-June 2003 through December 31, 2006
(averaging approximately $3.60 per barrel) and the
RCAs approved rate for this period ($1.96 per barrel) plus interest for the approximately 36
million barrels we have transported through TAPS in intrastate commerce during this period. We
cannot give any assurances of when or whether we will prevail in these appeals. We also believe
that, should we not prevail on appeal, the amount of
79
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
additional shipping charges cannot reasonably
be estimated since it is not possible to estimate the permanent rate which the RCA could set, and
the appellate courts approve, for each year. In addition, depending upon the level of such rates,
there is a reasonable possibility that any refunds for the period January 2001 through mid-June
2003 could offset some or all of any additional payments due for the period mid-June 2003 through
December 31, 2006.
In January of 2005, Tesoro Alaska Company intervened in a protest before the Federal Energy
Regulatory Commission (FERC), of the TAPS Carriers interstate rates for 2005 and 2006. If Tesoro
Alaska Company prevails and lower rates are set, we could be entitled to refunds resulting from our
interstate shipments for 2005 and 2006. We cannot give any assurances of when or whether we will
prevail in this proceeding. In July 2005, the TAPS Carriers filed a proceeding at the FERC seeking
to have the FERC assume jurisdiction under Section 13(4) of the Interstate Commerce Act and set
future rates for intrastate transportation on TAPS. We have filed a protest in that proceeding,
which has now been consolidated with the other FERC proceeding seeking to set just and reasonable
interstate rates on TAPS for 2005 and 2006. If the TAPS carriers should prevail, then the rates
charged for all shipments of Alaska North Slope crude oil on TAPS could be revised by the FERC, but
any FERC changes to rates for intrastate transportation of crude oil supplies for our Alaska
refinery should be prospective only and should not affect prior intrastate rates, refunds or
additional payments.
NOTE O QUARTERLY FINANCIAL DATA (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters |
|
Total |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Year |
|
|
(In millions except per share amounts) |
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,877 |
|
|
$ |
4,929 |
|
|
$ |
5,278 |
|
|
$ |
4,020 |
|
|
$ |
18,104 |
|
Costs of sales and operating expenses |
|
$ |
3,689 |
|
|
$ |
4,276 |
|
|
$ |
4,697 |
|
|
$ |
3,652 |
|
|
$ |
16,314 |
|
Operating Income |
|
$ |
81 |
|
|
$ |
543 |
|
|
$ |
446 |
|
|
$ |
247 |
|
|
$ |
1,317 |
|
Net Earnings |
|
$ |
43 |
|
|
$ |
326 |
|
|
$ |
274 |
|
|
$ |
158 |
|
|
$ |
801 |
|
Net Earnings Per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.63 |
|
|
$ |
4.79 |
|
|
$ |
4.02 |
|
|
$ |
2.35 |
|
|
$ |
11.78 |
|
Diluted |
|
$ |
0.61 |
|
|
$ |
4.66 |
|
|
$ |
3.92 |
|
|
$ |
2.28 |
|
|
$ |
11.46 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,171 |
|
|
$ |
4,033 |
|
|
$ |
5,017 |
|
|
$ |
4,360 |
|
|
$ |
16,581 |
|
Costs of sales and operating expenses |
|
$ |
2,997 |
|
|
$ |
3,601 |
|
|
$ |
4,536 |
|
|
$ |
4,036 |
|
|
$ |
15,170 |
|
Operating Income |
|
$ |
78 |
|
|
$ |
337 |
|
|
$ |
392 |
|
|
$ |
220 |
|
|
$ |
1,027 |
|
Net Earnings |
|
$ |
28 |
|
|
$ |
184 |
|
|
$ |
226 |
|
|
$ |
69 |
|
|
$ |
507 |
|
Net Earnings Per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.41 |
|
|
$ |
2.69 |
|
|
$ |
3.29 |
|
|
$ |
1.00 |
|
|
$ |
7.44 |
|
Diluted |
|
$ |
0.40 |
|
|
$ |
2.62 |
|
|
$ |
3.20 |
|
|
$ |
0.97 |
|
|
$ |
7.20 |
|
NOTE P SUBSEQUENT EVENT
On January 29, 2007, we entered into agreements with Shell Oil Products US (Shell) to
purchase a 100,000 barrel per day (bpd) refinery and a 42,000 bpd refined products terminal
located south of Los Angeles, California along with approximately 250 Shell-branded retail stations
located throughout Southern California (collectively, the Los Angeles Assets). The purchase
includes a long-term agreement allowing us to continue to operate the retail stations under the
Shell® brand. The purchase price of the Los Angeles Assets is $1.63 billion, plus the value of
petroleum inventories at the time of closing, which is estimated to be $180 million to $200 million
based on January 2007 prices. Upon closing of the acquisitions, Shell has agreed, subject to
certain limitations, to retain certain obligations, responsibilities, liabilities, costs and
expenses, including environmental matters arising out of the pre-closing operations of the assets.
We have agreed to assume certain obligations, responsibilities, liabilities, costs
and expenses arising out of or incurred in connection with decrees, orders and
settlements the seller entered into with governmental and non-governmental
entities prior to closing. This
80
TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
transaction, which will require regulatory approval from
the Federal Trade Commission and the Attorney General of the State of California, is expected to be
completed in the second quarter of 2007.
On January 26, 2007, we entered into an agreement to purchase 140 USA Petroleum retail
stations located primarily in California and a terminal located in New Mexico. The purchase price
of the assets and the USA® brand is $277 million, plus the value of inventory at the time of
closing, which is estimated to be $10 million to $15 million based on January 2007 prices. Tesoro
will assume the obligations under the sellers leases, contracts, permits or other agreements
arising after the closing date. USA Petroleum will retain certain pre-closing liabilities,
including environmental matters. This transaction, which will require regulatory approval from the
Federal Trade Commission and the Attorney General of the State of California, is expected to be
completed in the second quarter of 2007.
The acquisitions of the Los Angeles Assets and the USA Petroleum retail stations will be paid
for with a combination of debt and cash on-hand, which at December 31, 2006 was $986 million. The
exact amount of debt and cash is yet to be determined.
81
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We carried out an evaluation required by the Securities Exchange Act of 1934, as amended (the
Exchange Act), under the supervision and with the participation of our management, including the
Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act
as of the end of the year. Based upon that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and procedures are effective. During the
fourth quarter of 2006, there have been no changes in our internal control over financial reporting
that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
Management Report on Internal Control over Financial Reporting
We, as management of Tesoro Corporation and its subsidiaries (the Company), are responsible
for establishing and maintaining adequate internal control over financial reporting as defined in
the Securities Exchange Act of 1934, Rule 13a-15(f). The Companys internal control system is
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 in the United States of America.
Due to its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of internal controls over financial reporting as of
December 31, 2006, using the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission in Internal Control Integrated Framework. Based on such assessment, we
believe that as of December 31, 2006, the Companys internal control over financial reporting is
effective. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors
of the Companys consolidated financial statements, has issued an attestation report on
managements assessment of the effectiveness of the Companys internal control over financial
reporting, included herein.
82
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Tesoro Corporation
We have audited managements assessment, included in the accompanying Management Report on
Internal Control over Financial Reporting, that Tesoro Corporation and subsidiaries (the Company)
maintained effective internal control over financial reporting as of December 31, 2006, based on
the criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. 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. Our responsibility is to express an
opinion on managements assessment and an opinion on the effectiveness of 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). 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, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions.
A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel 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 the inherent limitations of internal control over financial reporting, including
the possibility of collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the 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, managements assessment that the Company maintained effective internal control
over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based
on the criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of December 31,
2006, based on the criteria established in Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements as of and for the year ended
December 31, 2006 of the Company and our report dated February 22, 2007, expressed an unqualified
opinion on those financial statements and included an explanatory paragraph relating to a change in
the Companys method of accounting for refined product sales and purchases transactions with the
same counterparty that have been entered into in contemplation of one another, and for its pension
and other postretirement plans.
/s/ DELOITTE & TOUCHE LLP
San Antonio, Texas
February 22, 2007
83
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this Item will be contained in the Companys 2007 Proxy Statement,
incorporated herein by reference. See also Executive Officers of the Registrant under Business in
Item 1 hereof.
You can access our code of business conduct and ethics for senior financial executives on our
website at www.tsocorp.com, and you may receive a copy, free of charge by writing to Tesoro
Corporation, Attention: Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this Item will be contained in the Companys 2007 Proxy Statement,
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Information required under this Item will be contained in the Companys 2007 Proxy Statement,
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required under this Item will be contained in the Companys 2007 Proxy Statement,
incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required under this Item will be contained in the Companys 2007 Proxy Statement,
incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)1. Financial Statements
The following consolidated financial statements of Tesoro Corporation and its subsidiaries are
included in Part II, Item 8 of this Form 10-K:
2. Financial Statement Schedules
No financial statement schedules are submitted because of the absence of the conditions under
which they are required, the required information is insignificant or because the required
information is included in the consolidated financial statements.
84
3. Exhibits
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Exhibit |
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Number |
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Description of Exhibit |
2.1
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Stock Sale Agreement, dated March 18, 1998, among the Company, BHP Hawaii Inc.
and BHP Petroleum Pacific Islands Inc. (incorporated by reference herein to
Exhibit 2.1 to Registration Statement No. 333-51789). |
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2.2
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Stock Sale Agreement, dated May 1, 1998, among Shell Refining Holding Company,
Shell Anacortes Refining Company and the Company (incorporated by reference
herein to the Companys Quarterly Report on Form 10-Q for the period ended March
31, 1998, File No. 1-3473). |
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2.3
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Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP
Corporation North America Inc. and Amoco Oil Company (incorporated by reference
herein to Exhibit 2.1 to the Companys Current Report on Form 8-K filed on
September 21, 2001, File No. 1-3473). |
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2.4
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Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP
Corporation North America Inc. and Amoco Oil Company (incorporated by reference
herein to Exhibit 2.2 to the Companys Current Report on Form 8-K filed on
September 21, 2001, File No. 1-3473). |
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2.5
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Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP
Corporation North America Inc. and BP Pipelines (North America) Inc.
(incorporated by reference herein to Exhibit 2.1 to the Companys Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 2001, File No.
1-3473). |
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2.6
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Sale and Purchase Agreement for Golden Eagle Refining and Marketing Assets, dated
February 4, 2002, by and among Ultramar Inc. and Tesoro Refining and Marketing
Company, including First Amendment dated February 20, 2002 and related Purchaser
Parent Guaranty dated February 4, 2002, and Second Amendment dated May 3, 2002
(incorporated by reference herein to Exhibit 2.12 to the Companys Annual Report
on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-3473, and
Exhibit 2.1 to the Companys Current Report on Form 8-K filed on May 9, 2002,
File No. 1-3473). |
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2.7
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Asset Purchase Agreement by and between the Company and Shell Oil Products US
dated as of January 29, 2007 (incorporated by reference herein to Exhibit 2.1 to
the Companys Current Report on Form 8-K filed on February 1, 2007, File No.
1-3473). |
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2.8
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Asset Purchase and Sale Agreement by and between the Company and Shell Oil
Products US dated as of January 29, 2007 (incorporated by reference herein to
Exhibit 2.2 to the Companys Current Report on Form 8-K filed on February 1,
2007, File No. 1-3473). |
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2.9
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Purchase and Sale Agreement and Joint Escrow Instructions by and among the
Company and USA Petroleum Corporation, USA Gasoline Corporation, Palisades Gas
and Wash, Inc. and USA San Diego LLC dated as of January 26, 2007 (incorporated
by reference herein to Exhibit 2.3 to the Companys Current Report on Form 8-K
filed on February 1, 2007, File No. 1-3473). |
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3.1
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Restated Certificate of Incorporation of the Company (incorporated by reference
herein to Exhibit 3 to the Companys Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473). |
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3.2
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By-Laws of the Company, as amended through February 2, 2005 (incorporated by
reference herein to Exhibit 3.1 to the Companys Current Report on Form 8-K filed
on February 8, 2005, File No. 1-3473). |
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3.3
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Amendment to the By-Laws of the Company, effective March 6, 2006 (incorporated by
reference herein to Exhibit 3.3 to the Companys Annual Report on Form 10-K for
the fiscal year ended December 31, 2005, File No. 1-3473). |
85
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Exhibit |
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Number |
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Description of Exhibit |
3.4
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Amendment to Restated Certificate of Incorporation of the Company adding a new
Article IX limiting Directors Liability (incorporated by reference herein to
Exhibit 3(b) to the Companys Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473). |
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3.5
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Certificate of Amendment, dated as of May 4, 2006, to Certificate of
Incorporation of the Company, amending Article IV, increasing the number of
authorized shares of common stock from 100 million to 200 million (incorporated
by reference herein to Exhibit 3.1 to the Companys Quarterly Report on Form 10-Q
for the period ended March 31, 2006, File No. 1-3473). |
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3.6
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Certificate of Designation Establishing a Series A Participating Preferred Stock,
dated as of December 16, 1985 (incorporated by reference herein to Exhibit 3(d)
to the Companys Annual Report on Form 10-K for the fiscal year ended December
31, 1993, File No. 1-3473). |
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3.7
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Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate
of Incorporation of the Company amending Article IV, Article V, Article VII and
Article VIII (incorporated by reference herein to Exhibit 3(e) to the Companys
Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No.
1-3473). |
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3.8
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Certificate of Amendment, dated as of August 3, 1998, to Certificate of
Incorporation of the Company, amending Article IV, increasing the number of
authorized shares of Common Stock from 50 million to 100 million (incorporated by
reference herein to Exhibit 3.1 to the Companys Quarterly Report on Form 10-Q
for the period ended September 30, 1998, File No. 1-3473). |
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3.9
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Certificate of Ownership of Merger merging Tesoro Merger Corp. into Tesoro
Petroleum Corporation and changing the name of Tesoro Petroleum Corporation to
Tesoro Corporation, dated November 8, 2004 (incorporated by reference herein to
Exhibit 3.1 to the Current Report on Form 8-K filed on November 9, 2004). |
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4.1
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Form of Coastwide Energy Services, Inc. 8% Convertible Subordinated Debenture
(incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No.
1 to Registration No. 333-00229). |
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4.2
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Debenture Assumption and Conversion Agreement dated as of February 20, 1996,
between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp.
(incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No.
1 to Registration No. 333-00229). |
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4.3
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Form of Indenture relating to the 61/4% Senior Notes due
2012, dated as of November 16, 2005, among Tesoro Corporation, certain subsidiary
guarantors and U.S. Bank National Association, as Trustee (including form of
note) (incorporated by reference herein to Exhibit 4.1 to the Companys Current
Report on Form 8-K filed on November 17, 2005, File No. 1-3473). |
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4.4
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Form of Indenture relating to the 65/8% Senior Notes due
2015, dated as of November 16, 2005, among Tesoro Corporation, certain subsidiary
guarantors and U.S. Bank National Association, as Trustee (including form of
note) (incorporated by reference herein to Exhibit 4.2 to the Companys Current
Report on Form 8-K filed on November 17, 2005, File No. 1-3473). |
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4.5
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Form of Registration Rights Agreement relating to the 61/4%
Senior Notes due 2012, dated as of November 16, 2005, among Tesoro Corporation,
certain subsidiary guarantors and Lehman Brothers Inc., Goldman, Sachs & Co. and
J.P. Morgan Securities, Inc. (incorporated by reference herein to Exhibit 4.3 to
the Companys Current Report on Form 8-K filed on November 17, 2005, File No.
1-3473). |
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4.6
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Form of Registration Rights Agreement relating to the 65/8%
Senior Notes due 2015, dated as of November 16, 2005, among Tesoro Corporation,
certain subsidiary guarantors and Lehman Brothers, Inc., Goldman, Sachs & Co. and
J.P. Morgan Securities, Inc. (incorporated by reference herein to Exhibit 4.4 to
the Companys Current Report on Form 8-K filed on November 17, 2005, File No.
1-3473). |
86
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Exhibit |
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Number |
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Description of Exhibit |
10.1
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Third Amended and Restated Credit Agreement, dated as of May 25, 2004, among the
Company, Bank of America, N.A. (the syndication agent), Wells Fargo Foothill,
LLC (the documentation agent), Bank One, NA (the administrative agent) and a
syndicate of banks, financial institutions and other entities (incorporated by
reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2004, File No. 1-3473). |
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10.2
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Amendment No. 1 to the Third Amended and Restated Credit Agreement, dated as of
September 29, 2004 among the Company, Bank One N.A. (the administrative agent)
and a syndicate of banks, financial institutions and other entities (incorporated
by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September
30, 2004, File No. 1-3473). |
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10.3
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Affirmation of Loan Documents dated as of September 29, 2004, by and between the
Company, certain of its subsidiary parties thereto and Bank One N.A. as
administrative agent (incorporated by reference herein to Exhibit 10.2 to the
Current Report on Form 8-K filed on September 30, 2004, File No. 1-3473). |
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10.4
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Amendment No. 2 to the Third Amended and Restated Credit Agreement, dated as of
May 17, 2005 among Tesoro, J.P. Morgan Chase Bank, N.A. as administrative agent
and a syndicate of banks, financial institutions and other entities (incorporated
by reference to Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2005, File No. 1-3473). |
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10.5
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Affirmation of Loan Documents dated as of May 17, 2005, by and between Tesoro,
certain of its subsidiary parties thereto and J.P. Morgan Chase Bank N.A. as
administrative agent (incorporated by reference to Exhibit 10.2 to the Companys
Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005, File
No. 1-3473). |
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10.6
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Amendment No. 3 to the Third Amended and Restated Credit Agreement, dated as of
July 31, 2006 among Tesoro, J.P. Morgan Chase Bank, N.A. as administrative agent
and a syndicate of banks, financial institutions and other entities (incorporated
by reference to Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for
the period ended June 30, 2006, File No. 1-3473). |
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10.7
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$100 million Promissory Note, dated as of May 17, 2002, payable by the Company to
Ultramar Inc. (incorporated by reference to Exhibit 10.1 to the Companys
Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473). |
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10.8
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$50 million Promissory Note, dated as of May 17, 2002, payable by the Company to
Ultramar Inc. (incorporated by reference to Exhibit 10.2 to the Companys
Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473). |
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10.9
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Amended and Restated Executive Security Plan effective as January 1, 2005
(incorporated by reference to Exhibit 10.2 to the Companys Current Report on
Form 8-K filed February 8, 2006, File No. 1-3473). |
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10.10
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Amended and Restated Executive Long-Term Incentive Plan effective as of February
2, 2006 (incorporated by reference herein to Exhibit 10.3 to the Companys
Current Report on Form 8-K filed on February 8, 2006, File No. 1-3473). |
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10.11
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2006 Executive Long-Term Incentive Plan dated as of May 3, 2006 (incorporated by
reference herein to Exhibit A to the Companys Proxy Statement for the Annual
Meeting of Stockholders held on May 3, 2006). |
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10.12
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First Amendment to the 2006 Executive Long-Term Incentive Plan dated as of August
1, 2006 (incorporated by reference herein to Exhibit 10.1 to the Companys
Quarterly Report on Form 10-Q for the period ended June 30, 2006, File No.
1-3473). |
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10.13
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Amended and Restated Employment Agreement between the Company and Bruce A. Smith
dated December 3, 2003 (incorporated by reference herein to Exhibit 10.14 to the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2003,
File No. 1-3473). |
87
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Exhibit |
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Number |
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Description of Exhibit |
10.14
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Form of First Amendment to Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated as of February 2, 2006 (incorporated by
reference herein to Exhibit 10.4 to the Companys Current Report on Form 8-K
filed on February 8, 2006, File No. 1-3473). |
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10.15
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Second Amendment to the Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated as of November 1, 2006 (incorporated by
reference herein to Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q
for the period ended September 30, 2006, File No. 1-3473). |
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10.16
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Agreement between the Company and Bruce A. Smith as of November 1, 2006
(incorporated by reference herein to Exhibit 10.3 to the Companys Quarterly
Report on Form 10-Q for the period ended September 30, 2006, File No. 1-3473). |
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10.17
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Employment Agreement between the Company and William J. Finnerty dated as of
February 2, 2005 (incorporated by reference herein to Exhibit 10.1 to the
Companys Current Report on Form 8-K/A filed on February 8, 2005, File No.
1-3473). |
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10.18
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Form of First Amendment to Employment Agreement between the Company and William
J. Finnerty dated as of February 2, 2006 (incorporated by reference herein to
Exhibit 10.5 to the Companys Current Report on Form 8-K filed on February 8,
2006, File No. 1-3473). |
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10.19
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Employment Agreement between the Company and Everett D. Lewis dated as of
February 2, 2005 (incorporated by reference herein to Exhibit 10.2 to the
Companys Current Report on Form 8-K/A filed on February 8, 2005, File No.
1-3473). |
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10.20
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Form of First Amendment to Employment Agreement between the Company and Everett
D. Lewis dated as of February 2, 2006 (incorporated by reference herein to
Exhibit 10.6 to the Companys Current Report on Form 8-K filed on February 8,
2006, File No. 1-3473). |
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10.21
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Employment Agreement between the Company and Gregory A. Wright dated as of
August 26, 2004 (incorporated by reference herein to Exhibit 10.4 to the
Companys Current Report on Form 8-K filed on August 31, 2004, File No. 1-3473). |
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10.22
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Form of First Amendment to Employment Agreement between the Company and Gregory
A. Wright dated as of February 2, 2006 (incorporated by reference herein to
Exhibit 10.7 to the Companys Current Report on Form 8-K filed on February 8,
2006, File No. 1-3473). |
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10.23
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Management Stability Agreement between the Company and W. Eugene Burden dated
November 8, 2002 (incorporated by reference herein to Exhibit 10.23 to the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2002,
File No. 1-3473). |
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10.24
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Management Stability Agreement between the Company and Claude A. Flagg dated
February 2, 2005 (incorporated by reference herein to Exhibit 10.1 to the
Companys Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473). |
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10.25
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Amended and Restated Management Stability Agreement between the Company and J.
William Haywood dated August 2, 2005 (incorporated by reference herein to Exhibit
10.1 to the Companys Current Report on Form 8-K filed on August 8, 2005, File
No. 1-3473). |
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10.26
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Management Stability Agreement between the Company and Joseph M. Monroe dated
November 6, 2002 (incorporated by reference herein to Exhibit 10.30 to the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2002,
File No. 1-3473). |
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10.27
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Amended and Restated Management Stability Agreement between the Company and
Daniel J. Porter dated August 2, 2005 (incorporated by reference herein to
Exhibit 10.2 to the Companys Current Report on Form 8-K filed on August 8, 2005,
File No. 1-3473). |
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*10.28
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Management Stability Agreement between the Company and Arlen O. Glenewinkel, Jr.
dated August 2, 2005. |
88
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Exhibit |
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Number |
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Description of Exhibit |
10.29
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Amended and Restated Management Stability Agreement between the Company and Susan
A. Lerette dated February 2, 2005 (incorporated by reference herein to Exhibit
10.2 to the Companys Current Report on Form 8-K filed on February 8, 2005, File
No. 1-3473). |
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10.30
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Amended and Restated Management Stability Agreement between the Company and
Charles S. Parrish dated May 3, 2006 (incorporated by reference herein to
Exhibit 10.1 to the Companys Current Report on Form 8-K filed on May 25, 2006,
File No. 1-3473). |
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10.31
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|
Amended and Restated Management Stability Agreement between the Company and Otto
C. Schwethelm dated February 2, 2005 (incorporated by reference herein to
Exhibit 10.4 to the Companys Current Report on Form 8-K filed on February 8,
2005, File No. 1-3473). |
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*10.32
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Management Stability Agreement between the Company and Sarah S. Simpson dated
August 2, 2005. |
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10.33
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Management Stability Agreement between the Company and G. Scott Spendlove dated
January 24, 2002 (incorporated by reference herein to Exhibit 10.1 to the
Companys Quarterly Report on Form 10-Q for the quarterly period ended March 31,
2002, File No. 1-3473). |
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10.34
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Amended and Restated Management Stability Agreement between the Company and Lynn
D. Westfall dated as of May 3, 2006 (incorporated by reference herein to Exhibit
10.2 to the Companys Current Report on Form 8-K filed on May 25, 2006, File No.
1-3473). |
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10.35
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Tesoro Corporation Restoration Retirement Plan dated as of August 9, 2006
(incorporated by reference herein to Exhibit 10.1 to the Companys Current Report
on Form 8-K filed on August 10, 2006, File No. 1-3473). |
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10.36
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Tesoro Corporation 2006 Executive Deferred Compensation Plan dated November 2,
2006 (incorporated by reference herein to Exhibit 10.1 to the Companys Quarterly
Report on Form 10-Q for the period ended September 30, 2006, File No. 1-3473). |
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10.37
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Copy of the Companys Key Employee Stock Option Plan dated November 12, 1999
(incorporated by reference herein to Exhibit 10.3 to the Companys Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2002, File No.
1-3473). |
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10.38
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2006 Long-Term Stock Appreciation Rights Plan of Tesoro Corporation (incorporated
by reference herein to Exhibit 10.1 to the Companys Current Report on Form 8-K
filed on February 8, 2006, File No. 1-3473). |
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10.39
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Copy of the Companys Non-Employee Director Retirement Plan dated December 8,
1994 (incorporated by reference herein to Exhibit 10(t) to the Companys Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No.
1-3473). |
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10.40
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Amended and Restated 1995 Non-Employee Director Stock Option Plan, as amended
through March 15, 2000 (incorporated by reference herein to Exhibit 10.2 to the
Companys Quarterly Report on Form 10-Q for the quarterly period ended March 31,
2002, File No. 1-3473). |
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10.41
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Amendment to the Companys Amended and Restated 1995 Non-Employee Director Stock
Option Plan (incorporated by reference herein to Exhibit 10.41 to the Companys
Registration Statement No. 333-92468). |
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10.42
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Amendment to the Companys 1995 Non-Employee Director Stock Option Plan effective
as of May 11, 2004 (incorporated by reference herein to Exhibit 4.19 to the
Companys Registration Statement No. 333-120716). |
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10.43
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Copy of the Companys Board of Directors Deferred Compensation Plan dated
February 23, 1995 (incorporated by reference herein to Exhibit 10(u) to the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 1994,
File No. 1-3473). |
89
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Exhibit |
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Number |
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Description of Exhibit |
10.44
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Copy of the Companys Board of Directors Deferred Compensation Trust dated
February 23, 1995 (incorporated by reference herein to Exhibit 10(v) to the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 1994,
File No. 1-3473). |
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10.45
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Copy of the Companys Board of Directors Deferred Phantom Stock Plan
(incorporated by reference herein to Exhibit 10 to the Companys Quarterly Report
on Form 10-Q for the quarterly period ended March 31, 1997, File No. 1-3473). |
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10.46
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2005 Director Compensation Plan (incorporated by reference herein to Exhibit A to
the Companys Proxy Statement for the Annual Meeting of Stockholders held on May
4, 2005, File No. 1-3473). |
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10.47
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Phantom Stock Option Agreement between the Company and Bruce A. Smith dated
effective October 29, 1997 (incorporated by reference herein to Exhibit 10.20 to
the Companys Annual Report on Form 10-K for the fiscal year ended December 31,
1997, File No. 1-3473). |
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10.48
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Form of Indemnification Agreement between the Company and its officers and
directors (incorporated by reference herein to Exhibit B to the Companys Proxy
Statement for the Annual Meeting of Stockholders held on February 25, 1987, File
No. 1-3473). |
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14.1
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Code of Business Conduct and Ethics for Senior Financial Executives (incorporated
by reference herein to Exhibit 14.1 to the Companys Annual Report on Form 10-K
for the fiscal year ended December 31, 2003, File No. 1-3473). |
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*21.1
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Subsidiaries of the Company. |
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*23.1
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Consent of Independent Registered Public Accounting Firm. |
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*31.1
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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*31.2
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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*32.1
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Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. |
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*32.2
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Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. |
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* |
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Filed herewith. |
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Identifies management contracts or compensatory plans or arrangements required to be filed as
an exhibit hereto pursuant to Item 15(a)(3) of Form 10-K. |
Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record
at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate
Secretary, Tesoro Corporation, 300 Concord Plaza Drive, San Antonio, Texas, 78216-6999.
90
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized
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TESORO CORPORATION
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By
/s/ BRUCE A. SMITH
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Bruce A. Smith |
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Chairman of the Board of Directors,
President and Chief Executive Officer |
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Dated: February 23, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
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Signature |
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Title |
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Date |
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/s/ BRUCE A, SMITH
Bruce A. Smith
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Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)
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February 23, 2007 |
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/s/ GREGORY A. WRIGHT
Gregory A. Wright
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Executive Vice President and Chief
Financial Officer
(Principal Financial Officer)
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February 23, 2007 |
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/s/ ARLEN O. GLENEWINKEL, JR.
Arlen O. Glenewinkel, Jr.
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Vice President and Controller
(Principal Accounting Officer)
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February 23, 2007 |
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/s/ STEVEN H. GRAPSTEIN
Steven H. Grapstein
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Lead Director
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February 23, 2007 |
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/s/ JOHN F. BOOKOUT, III
John F. Bookout, III
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Director
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February 23, 2007 |
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/s/ RODNEY F. CHASE
Rodney F. Chase
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Director
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February 23, 2007 |
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/s/ ROBERT W. GOLDMAN
Robert W. Goldman
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Director
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February 23, 2007 |
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/s/ WILLIAM J. JOHNSON
William J. Johnson
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Director
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February 23, 2007 |
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/s/ A. MAURICE MYERS
A. Maurice Myers
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Director
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February 23, 2007 |
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/s/ DONALD H. SCHMUDE
Donald H. Schmude
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Director
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February 23, 2007 |
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/s/ PATRICK J. WARD
Patrick J. Ward
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Director
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February 23, 2007 |
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/s/ MICHAEL E. WILEY
Michael E. Wiley
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Director
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February 23, 2007 |
91