================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Amendment No. 1
to Current Report on
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (Date of earliest event reported): AUGUST 27, 2001
TESORO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 1-3473 95-0862768
(State or other jurisdiction (Commission File Number) (IRS Employer
of incorporation) Identification No.)
300 CONCORD PLAZA DRIVE 78216-6999
SAN ANTONIO, TEXAS (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (210) 828-8484
================================================================================
ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS
On September 6, 2001, Tesoro Petroleum Corporation completed the
acquisition (the "BP Acquisition") of certain refining and marketing assets of
BP p.l.c. and certain of its affiliates, including refineries in Salt Lake City,
Utah and Mandan, North Dakota. We closed the acquisition pursuant to Asset
Purchase Agreements dated July 16, 2001, among the Company, BP Corporation North
America Inc. and Amoco Oil Company, which were filed as Exhibits 2.1 and 2.2 to
our Current Report on Form 8-K dated August 27, 2001 (SEC File No. 1-3473) and
are incorporated herein by reference. The Salt Lake City, Utah refinery has a
crude oil capacity of 55,000 barrels per day ("bpd"). More than half of its
production is gasoline, with principal other products of diesel and jet fuel.
The Mandan refinery, which is located near Bismarck, North Dakota, has a rated
capacity of 60,000 bpd and produces mostly gasoline, with the balance in
distillates, jet fuel and other products. We also acquired 43 retail gasoline
stations and contracts for approximately 290 Amoco-branded stations assigned by
BP to Tesoro that are owned by about 80 jobbers. We intend to utilize the assets
acquired through the BP Acquisition in a similar manner as the sellers.
We paid approximately $666 million in cash for the acquisition,
including $82 million for related hydrocarbon inventories (as adjusted for the
post-closing inventory valuation). We also assumed certain liabilities and
obligations (including costs associated with transferred employees and
environmental matters among others) subject to specified levels of
indemnification. We funded the acquisition with borrowings under a new $1
billion senior secured credit facility. The Company entered into this new senior
secured credit facility on September 6, 2001, with Lehman Brothers Inc. (lead
arranger), Lehman Commercial Paper Inc. (the syndication agent), Bank One, NA
(the administrative agent) and a syndicate of banks, financial institutions and
other entities.
We have also entered into an agreement with BP p.l.c. and certain of
its affiliates to purchase a related North Dakota crude oil pipeline system. We
expect this transaction to close, pending regulatory approval, on or after
November 1, 2001.
The foregoing is qualified by reference to Exhibits 2.1 and 2.2 to our
Current Report on Form 8-K dated August 27, 2001, and are incorporated herein by
reference.
2
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
(a) Financial statements of businesses acquired.
The following financial statements are included in Appendix A
hereto and incorporated herein by reference.
<Table>
FINANCIAL STATEMENTS OF THE NORTH DAKOTA AND UTAH REFINING AND
MARKETING BUSINESS OF BP CORPORATION NORTH AMERICA INC.
Report of Independent Auditors ................................. A-2
Combined Balance Sheets - December 31, 1999 and 2000 and
June 30, 2001 ................................................ A-3
Combined Statements of Income - Years Ended December 31, 1998,
1999 and 2000 and Six Months Ended June 30, 2000 and 2001 .... A-4
Combined Statements of Parent Company Investment - Years Ended
December 31, 1998, 1999 and 2000 and Six Months Ended
June 30, 2001 ................................................ A-5
Combined Statements of Cash Flows - Years Ended
December 31, 1998, 1999 and 2000 and Six Months Ended
June 30, 2000 and 2001 ...................................... A-6
Notes to Combined Financial Statements ......................... A-7
</Table>
(b) Pro forma financial information.
The following pro forma financial information is included in Appendix B
hereto and incorporated herein by reference:
<Table>
PRO FORMA FINANCIAL STATEMENTS
Unaudited Pro Forma Combined Condensed
Balance Sheet as of June 30, 2001 ........................... B-2
Unaudited Pro Forma Combined Condensed Statement of
Operations for the Year Ended December 31, 2000 ............. B-4
Unaudited Pro Forma Combined Condensed Statement of
Operations for the Six Months Ended June 30, 2001 ........... B-5
</Table>
(c) Exhibits.
2.1 Asset Purchase Agreement, dated July 16, 2001, by and
among the Company, BP Corporation North America Inc.
and Amoco Oil Company relating to the purchase and
sale of the Mandan refinery and related assets
(incorporated by reference to Exhibit 2.1 of the
Current Report on Form 8-K dated August 27, 2001,
SEC File No. 1-3473). Pursuant to Item 601(b)(2) of
Regulation S-K, certain schedules and similar
attachments to this Asset Purchase Agreement have not
been filed with this exhibit. The schedules contain
various items relating to the assets acquired and the
representations and warranties made by the parties to
the Asset Purchase Agreement. The Company agrees to
furnish supplementally any omitted schedule to the
SEC upon request.
2.2 Asset Purchase Agreement, dated July 16, 2001, by and
among the Company, BP Corporation North America Inc.
and Amoco Oil Company relating to the purchase and
sale of the Salt Lake City refinery and related
assets (incorporated by reference to Exhibit 2.2 of
the Current Report on Form 8-K dated August 27,
2001, SEC File No. 1-3473). Pursuant to Item
601(b)(2) of Regulation S-K, certain schedules and
similar attachments to this Asset Purchase Agreement
have not been filed with this exhibit. The schedules
contain various items relating to the assets acquired
and the representations and warranties made by the
parties to the Asset Purchase Agreement. The Company
agrees to furnish supplementally any omitted schedule
to the SEC upon request.
23.1 Consent of Ernst & Young LLP, Independent Auditors,
dated October 22, 2001.
ITEM 9. REGULATION FD DISCLOSURE
An updated management's discussion and analysis of financial condition
and results of operations - Tesoro is included in Appendix C hereto and
incorporated herein by reference.
3
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this report to be signed on its behalf
by the undersigned hereunto duly authorized.
Date: October 24, 2001
TESORO PETROLEUM CORPORATION
By: /s/ JAMES C. REED, JR.
--------------------------------
James C. Reed, Jr.
Executive Vice President,
General Counsel and Secretary
4
APPENDIX A
<Table>
FINANCIAL STATEMENTS OF THE NORTH DAKOTA AND UTAH REFINING AND
MARKETING BUSINESS OF BP CORPORATION NORTH AMERICA INC.
Report of Independent Auditors ................................. A-2
Combined Balance Sheets - December 31, 1999 and 2000 and
June 30, 2001 ................................................ A-3
Combined Statements of Income - Years Ended December 31, 1998,
1999 and 2000 and Six Months Ended June 30, 2000 and 2001 .... A-4
Combined Statements of Parent Company Investment - Years Ended
December 31, 1998, 1999 and 2000 and Six Months Ended
June 30, 2001 ................................................ A-5
Combined Statements of Cash Flows - Years Ended
December 31, 1998, 1999 and 2000 and Six Months Ended
June 30, 2000 and 2001 ....................................... A-6
Notes to Combined Financial Statements ......................... A-7
</Table>
A-1
REPORT OF INDEPENDENT AUDITORS
Board of Directors
BP Corporation North America Inc.
We have audited the accompanying combined balance sheets of The North Dakota and
Utah Refining and Marketing Business of BP Corporation North America Inc. (the
Business) as of December 31, 2000 and 1999, and the related combined statements
of income, parent company investment and cash flows for each of the three years
in the period ended December 31, 2000. These financial statements are the
responsibility of BP Corporation North America Inc.'s management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the combined financial position of the Business at
December 31, 2000 and 1999, and the combined results of its operations and its
cash flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States of
America.
/s/ Ernst & Young LLP
Chicago, Illinois
October 12, 2001
A-2
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
COMBINED BALANCE SHEETS
(DOLLARS IN MILLIONS)
<Table>
<Caption>
DECEMBER 31,
----------------- JUNE 30,
1999 2000 2001
------- ------- -----------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Accounts receivable....................................... $ 39.7 $ 62.1 $ 56.5
Inventories............................................... 25.6 24.2 39.8
Prepayments and other..................................... 5.3 4.2 2.5
------- ------- -------
Total Current Assets................................... 70.6 90.5 98.8
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment -- gross.................... 567.3 567.2 571.5
Accumulated depreciation and amortization................. (294.9) (299.9) (311.6)
------- ------- -------
Net Property, Plant and Equipment...................... 272.4 267.3 259.9
OTHER ASSETS
Deferred charges and other assets......................... 9.1 8.0 6.5
------- ------- -------
Total Assets...................................... $ 352.1 $ 365.8 $ 365.2
======= ======= =======
LIABILITIES AND PARENT COMPANY INVESTMENT
LIABILITIES
CURRENT LIABILITIES
Accounts payable.......................................... $ 10.5 $ 16.8 $ 16.3
Accounts payable -- affiliates............................ 79.6 92.1 95.1
Accrued expenses.......................................... 14.1 11.6 6.5
Taxes other than income taxes............................. 12.0 12.6 11.3
------- ------- -------
Total Current Liabilities.............................. 116.2 133.1 129.2
LONG TERM LIABILITIES
Environmental accruals.................................... 11.8 10.6 10.5
Deferred income taxes..................................... 40.4 41.5 42.0
------- ------- -------
Total Long Term Liabilities............................ 52.2 52.1 52.5
PARENT COMPANY INVESTMENT................................... 183.7 180.6 183.5
------- ------- -------
Total Liabilities and Parent Company Investment... $ 352.1 $ 365.8 $ 365.2
======= ======= =======
</Table>
See accompanying notes to combined financial statements.
A-3
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
COMBINED STATEMENTS OF INCOME
(DOLLARS IN MILLIONS)
<Table>
<Caption>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------- -----------------
1998 1999 2000 2000 2001
------ -------- -------- ------- -------
(UNAUDITED)
REVENUES
Sales and other revenues...................... $838.2 $1,006.3 $1,483.8 $656.9 $725.7
COSTS AND EXPENSES
Cost of products sold......................... 575.1 786.5 1,233.8 567.6 561.2
Operating expenses............................ 109.4 101.2 108.5 52.8 61.3
Selling, general and administrative........... 10.8 15.8 9.8 5.1 6.4
Corporate overhead allocations................ 24.6 18.2 16.1 8.3 7.9
Depreciation and amortization................. 23.4 22.9 23.2 11.4 11.2
------ -------- -------- ------ ------
Total Costs and Expenses................... 743.3 944.6 1,391.4 645.2 648.0
INCOME BEFORE INCOME TAXES...................... 94.9 61.7 92.4 11.7 77.7
Income tax provision............................ 37.0 24.2 35.9 4.6 30.5
------ -------- -------- ------ ------
NET INCOME...................................... $ 57.9 $ 37.5 $ 56.5 $ 7.1 $ 47.2
====== ======== ======== ====== ======
</Table>
See accompanying notes to combined financial statements.
A-4
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
COMBINED STATEMENTS OF PARENT COMPANY INVESTMENT
(DOLLARS IN MILLIONS)
<Table>
BALANCE AT JANUARY 1, 1998.................................. $215.6
Net income............................................. 57.9
Net distributions to parent............................ (53.4)
------
BALANCE AT DECEMBER 31, 1998................................ 220.1
Net income............................................. 37.5
Net distributions to parent............................ (73.9)
------
BALANCE AT DECEMBER 31, 1999................................ 183.7
Net income............................................. 56.5
Net distributions to parent............................ (59.6)
------
BALANCE AT DECEMBER 31, 2000................................ 180.6
Net income (a)......................................... 47.2
Net distributions to parent (a)........................ (44.3)
------
BALANCE AT JUNE 30, 2001 (a)................................ $183.5
======
</Table>
(a) Unaudited
See accompanying notes to combined financial statements.
A-5
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
COMBINED STATEMENTS OF CASH FLOWS
(DOLLARS IN MILLIONS)
<Table>
<Caption>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------ -----------------
1998 1999 2000 2000 2001
------ ------ ------ ------- -------
(UNAUDITED)
OPERATING ACTIVITIES
Net income................................... $ 57.9 $ 37.5 $ 56.5 $ 7.1 $ 47.2
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization.............. 23.4 22.9 23.2 11.4 11.2
Provision for deferred income taxes........ 1.1 (1.2) 2.3 1.2 2.2
Loss on sale of assets..................... .6 1.5 2.3 1.5 .3
Change in operating assets and liabilities:
(Increase) decrease in accounts
receivable............................ 3.7 (8.4) (22.4) (30.3) 5.6
(Increase) decrease in inventories...... 3.9 (1.5) 1.4 1.8 (15.6)
(Increase) decrease in prepayments and
other................................. (.4) 3.1 .8 1.6 1.6
Increase (decrease) in accounts
payable............................... (9.9) 42.7 18.8 24.1 2.5
Increase (decrease) in accrued
expenses.............................. (.4) 5.3 (3.7) (6.4) (5.2)
Increase (decrease) in taxes other than
income taxes.......................... 2.8 (.7) .6 (2.7) (1.3)
Other................................... -- (.2) .2 (.4) (.1)
------ ------ ------ ------ ------
Cash provided by operating
activities....................... 82.7 101.0 80.0 8.9 48.4
INVESTING ACTIVITIES
Capital expenditures......................... (29.3) (27.1) (20.4) (11.1) (4.1)
------ ------ ------ ------ ------
Cash used in investing
activities....................... (29.3) (27.1) (20.4) (11.1) (4.1)
FINANCING ACTIVITIES
Net (distributions to) contributions by
parent..................................... (53.4) (73.9) (59.6) 2.2 (44.3)
------ ------ ------ ------ ------
Net cash (used in) provided by
financing activities............. (53.4) (73.9) (59.6) 2.2 (44.3)
CASH AND CASH EQUIVALENTS -- BEGINNING OF
PERIOD.......................................... -- -- -- -- --
------ ------ ------ ------ ------
CASH AND CASH EQUIVALENTS -- END OF PERIOD........ $ -- $ -- $ -- $ -- $ --
====== ====== ====== ====== ======
</Table>
See accompanying notes to combined financial statements.
A-6
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000 AND
(UNAUDITED) SIX MONTHS ENDED JUNE 30, 2000 AND 2001
NOTE A -- BASIS OF PRESENTATION
On July 16, 2001, BP Corporation North America Inc. (the Company), an
indirect wholly owned subsidiary of BP p.l.c., and Tesoro Petroleum Corporation
(Tesoro) entered into agreements (the Agreements) providing for the purchase by
Tesoro of substantially all of the Company's North Dakota and Utah refining and
marketing business (the Business). The Business principally comprises the
Company's Mandan, North Dakota and Salt Lake City, Utah refineries, associated
crude oil and product pipelines, bulk storage, eight product distribution
terminals and forty-three retail gasoline stations. The Agreements also include
an assignment of supply agreements for certain retail gasoline stations located
in the mid-continental and western United States. Except for a crude oil
pipeline system, the acquisition of the Business by Tesoro was completed on
September 6, 2001. The acquisition of the crude oil pipeline system, subject to
regulatory approval, is expected to be completed in the fourth quarter of 2001.
The effects of the acquisition of the Business are not reflected in the
accompanying special-purpose combined financial statements, which are intended
to reflect the specific assets, liabilities and related operations of the
Business being purchased by Tesoro pursuant to the Agreements on a historical
cost basis. As such, the accompanying combined financial statements are not
intended to be a complete presentation of the assets, liabilities or the results
of operations of the Company or of the Business on a stand alone basis.
The Business has certain shared assets and incurs certain common costs
which relate to both the Business and other Company operations. As such, for
purposes of preparing these special-purpose combined financial statements,
management of the Company has made certain allocations of assets, liabilities
and expenses to the Business. While the basis for allocating such costs is
considered reasonable by management, amounts allocated to the Business could
differ significantly from amounts that would otherwise be determined if the
Business were operated on a stand alone basis.
The parent company investment reflects the Company's investment in the
Business, accumulated earnings and losses of the Business and intercompany
balances with the Company and other affiliates which are not settled on a
current basis.
The financial information included herein may not necessarily reflect the
financial position, results of operations or cash flows of the Business in the
future or what the financial position, results of operations or cash flows of
the Business would have been if it had been a separate stand alone entity during
the periods presented.
NOTE B -- ACCOUNTING POLICIES
INTERIM FINANCIAL INFORMATION
The interim financial information as of June 30, 2001 and for the six
months ended June 30, 2000 and 2001 is unaudited and reflects all adjustments
which management considers necessary for a fair presentation.
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect reported amounts and
disclosures in the notes to combined financial statements. Actual results could
differ from the estimates and assumptions used.
A-7
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE B -- ACCOUNTING POLICIES -- (CONTINUED)
INVENTORIES
Inventories are stated at cost, but not in excess of net realizable value.
The cost of inventories is determined primarily by the last-in, first-out method
(LIFO), except for materials and supplies and merchandise, for which cost is
determined using the first-in, first-out method or average cost method.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at cost. Depreciation is computed
using the straight-line method based on estimated useful lives of the
depreciable assets. These lives average 20 years for refining facilities, 30
years for pipelines, 45 years for administrative buildings and 15 years for
service stations. Expenditures for renewals and improvements that extend the
useful life of an asset are capitalized. Expenditures for routine repairs and
maintenance, including those for refinery turnarounds, are charged to operations
when incurred. Property items retired or otherwise disposed of are removed from
the property and related accumulated depreciation accounts. Any profit or loss
is included in operations.
IMPAIRMENT OF LONG-LIVED ASSETS
Carrying amounts of long-lived assets are reviewed when events or
circumstances indicate that such carrying amounts may not be recoverable. Assets
that are to be held and used with recorded values that are not expected to be
recovered through future cash flows are written down to current fair value. Fair
value is generally determined from estimated discounted future net cash flows.
Assets that are held for sale are reported at the lower of carrying amount or
fair value less cost to sell.
ENVIRONMENTAL LIABILITIES
The Business has provided in its accounts for the reasonably estimable
future costs of probable environmental remediation obligations relating to
current and past activities, including obligations for previously disposed
assets. In the case of long-lived cleanup projects, the effects of inflation and
other factors, such as improved application of known technologies and
methodologies, are considered in determining the amount of estimated
liabilities. The liability is undiscounted and primarily consists of costs such
as site assessment, monitoring, equipment, utilities and soil and ground water
treatment and disposal.
REVENUE RECOGNITION
Revenues from product sales and services are generally recognized upon
delivery to customers. Transactions by and among units of the Business are
eliminated in combination. Sales to affiliates are made at prices that reflect
market prices.
SHIPPING, HANDLING AND OTHER TRANSPORTATION COSTS
Shipping, handling and other transportation costs are included in costs and
expenses.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of receivables and payables, which is based on
historical cost, approximates their fair value.
BUSINESS SEGMENTS
The Business operates in one business segment, the refining and marketing
of petroleum products.
A-8
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE B -- ACCOUNTING POLICIES -- (CONTINUED)
NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, the Business adopted Financial Accounting
Standards Board (FASB) Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The
adoption of SFAS 133 did not have a significant effect on the combined results
of operations or financial position of the Business.
In June 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143
requires companies to record liabilities equal to the fair value of their asset
retirement obligations when they are incurred. When the liability is initially
recorded, companies capitalize an equivalent amount as part of the cost of the
asset. Over time, the liability is accreted for the change in its present value
each period, and the initial capitalized cost is depreciated over the useful
life of the related asset. SFAS 143 is effective for accounting periods
beginning after June 15, 2002.
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
144). SFAS 144 retains the requirement to recognize an impairment loss only
where the carrying value of a long-lived asset is not recoverable from its
undiscounted cash flows and to measure such loss as the difference between the
carrying amount and fair value of the asset. SFAS 144, among other things,
changes the criteria that have to be met to in order to classify an asset as
held-for-sale and requires that operating losses from discontinued operations be
recognized in the period that the losses are incurred rather than as of the
measurement date. SFAS 144 is effective for accounting periods beginning after
December 15, 2001.
The Business has not yet determined the effect of adopting SFAS 143 and
SFAS 144 on its results of operations and financial condition.
NOTE C -- INVENTORIES
As a result of the use of the LIFO inventory valuation method, certain
inventories are reported in the balance sheet at amounts less than current cost.
Inventories valued under the LIFO method were approximately 74%, 72%, and 84% of
total inventories in the balance sheet at December 31, 1999, December 31, 2000
and June 30, 2001, respectively. The following is information about the current
cost of inventories, determined primarily using the first-in, first-out method
(in millions).
<Table>
<Caption>
DECEMBER 31,
----------------- JUNE 30,
1999 2000 2001
------- ------- -----------
(UNAUDITED)
Crude oil and other feedstocks.............................. $ 38.8 $ 50.1 $ 50.9
Refined and other finished products......................... 92.2 109.6 108.0
Materials and supplies...................................... 5.9 6.0 6.1
Merchandise................................................. .8 .8 .4
------- ------- -------
137.7 166.5 165.4
Excess of current cost over reported balance sheet
amounts................................................... (112.1) (142.3) (125.6)
------- ------- -------
Reported balance sheet amounts.............................. $ 25.6 $ 24.2 $ 39.8
======= ======= =======
</Table>
In 1998 and 2000, inventory volumes decreased resulting in a liquidation of
LIFO inventory quantities carried at lower costs prevailing in prior years as
compared with the cost of 1998 and 2000 purchases. The effect of this
liquidation was to increase 1998 and 2000 income before income taxes by $7.9
million and $3.1 million, respectively.
A-9
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE D -- PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment are as follows (in
millions).
<Table>
<Caption>
DECEMBER 31,
----------------- JUNE 30,
1999 2000 2001
------- ------- -----------
(UNAUDITED)
Refining.................................................... $ 420.8 $ 419.2 $ 421.6
Marketing................................................... 89.5 90.7 91.7
Crude oil supply and transportation......................... 57.0 57.3 58.2
------- ------- -------
567.3 567.2 571.5
Accumulated depreciation and amortization................... (294.9) (299.9) (311.6)
------- ------- -------
$ 272.4 $ 267.3 $ 259.9
======= ======= =======
</Table>
NOTE E -- RELATED PARTY TRANSACTIONS
The Business is part of a centralized cash management system whereby all
cash disbursements of the Business are funded by, and all cash receipts are
transferred to, the Company.
The Business enters into transactions with the Company and its affiliates.
Such transactions are made at prices that approximate market. The sale of
petroleum products amounted to $131.8 million, $144.8 million, $227.1 million,
$104.4 million and $110.0 million during the years ended December 31, 1998, 1999
and 2000 and the six months ended June 30, 2000 and 2001, respectively.
Purchases of crude oil and other feedstocks amounted to $431.9 million, $639.5
million, $1,038.0 million, $500.7 million and $454.1 million during the years
ended December 31, 1998, 1999 and 2000 and the six months ended June 30, 2000
and 2001, respectively.
The Company provides the Business with various financial and administrative
services for which the Business was charged associated direct costs and an
allocation of certain centrally incurred costs. These services include, among
others, tax, treasury, legal and employee benefit administration. For these
services, the Business receives an allocation which amounted to $24.6 million,
$18.2 million, $16.1 million, $8.3 million and $7.9 million during the years
ended December 31, 1998, 1999 and 2000 and the six months ended June 30, 2000
and 2001, respectively. It is the policy of the Company to allocate centrally
incurred costs primarily on the basis of usage or on estimated time spent. In
the opinion of management, these allocations and charges have been made on a
reasonable basis; however, they are not necessarily indicative of the level of
expenses which might have been incurred had the Business been operating as a
separate stand alone entity.
NOTE F -- RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
The Business participates in defined benefit retirement plans sponsored by
the Company. The Company's master defined benefit retirement plans cover
substantially all domestic employees of the Company. The assets of these plans
are held in U.S. and foreign equity securities, fixed income securities,
interest bearing cash and real estate. Net pension expense (income) allocated to
the Business amounted to $2.6 million, $.9 million, $(.9) million, $(.5) million
and $(.8) million during the years ended December 31, 1998, 1999 and 2000 and
six months ended June 30, 2000 and 2001, respectively. Amounts allocated are
principally determined based on payroll.
The Business participates in postretirement benefit plans sponsored by the
Company. Through these plans, the Company provides certain health care and life
insurance benefits for retired employees who meet eligibility requirements.
These benefits are provided through insured and self-insured arrangements. Net
postretirement benefit expense allocated to the Business amounted to $1.8
million, $1.9 million, $1.5 million,
A-10
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE F -- RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS -- (CONTINUED)
$.7 million and $1.2 million during the years ended December 31, 1998, 1999 and
2000 and six months ended June 30, 2000 and 2001, respectively. Amounts
allocated are principally determined based on payroll.
NOTE G -- INCOME TAXES
The results of operations of the Business are included in the consolidated
income tax returns filed by its parent. The Business' provision for income taxes
is computed as if the Business filed its annual tax returns on a separate
company basis. The current portion of the income tax provision is satisfied by
the Business through a charge or credit to parent company investment.
The provision for income taxes consists of the following (in millions).
<Table>
<Caption>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------ --------------
1998 1999 2000 2000 2001
------ ------ ------ ----- ------
(UNAUDITED)
Current
Federal.......................................... $ 30.6 $ 21.7 $ 28.5 $ 3.0 $ 24.0
State............................................ 5.3 3.7 5.1 .4 4.3
------ ------ ------ ----- ------
35.9 25.4 33.6 3.4 28.3
Deferred
Federal.......................................... .9 (1.0) 2.0 1.0 1.9
State............................................ .2 (.2) .3 .2 .3
------ ------ ------ ----- ------
1.1 (1.2) 2.3 1.2 2.2
------ ------ ------ ----- ------
$ 37.0 $ 24.2 $ 35.9 $ 4.6 $ 30.5
====== ====== ====== ===== ======
</Table>
The provision for income taxes differs from the amount computed by applying
the statutory federal income tax rate as follows (in millions).
<Table>
<Caption>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------ --------------
1998 1999 2000 2000 2001
------ ------ ------ ----- ------
(UNAUDITED)
Income tax provision at statutory rate............. $ 33.2 $ 21.6 $ 32.3 $ 4.1 $ 27.2
State income taxes, net of federal benefit......... 3.6 2.3 3.5 .4 3.0
Other.............................................. .2 .3 .1 .1 .3
------ ------ ------ ----- ------
$ 37.0 $ 24.2 $ 35.9 $ 4.6 $ 30.5
====== ====== ====== ===== ======
</Table>
A-11
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE G -- INCOME TAXES -- (CONTINUED)
The major components of deferred tax assets and liabilities were as follows
(in millions).
<Table>
<Caption>
DECEMBER 31,
------------- JUNE 30,
1999 2000 2001
----- ----- -----------
(UNAUDITED)
Deferred tax liabilities
Property, plant and equipment............................. $45.0 $45.8 $46.2
Deferred tax assets
Accrued expenses.......................................... (9.7) (8.2) (6.4)
----- ----- -----
Net deferred tax liability.................................. $35.3 $37.6 $39.8
===== ===== =====
Balance sheet classification
Prepayments and other..................................... $(5.1) $(3.9) $(2.2)
Deferred income taxes..................................... 40.4 41.5 42.0
----- ----- -----
$35.3 $37.6 $39.8
===== ===== =====
</Table>
NOTE H -- DERIVATIVE FINANCIAL INSTRUMENTS
The Company enters into futures contracts to manage the commodity price
risk associated with certain crude oil acquisition costs of the Business. These
contracts are marked to market with gains (losses) included in cost of product
sold and amounted to $nil, $(.1) million, $(6.6) million, $(5.4) million and
$nil for the years ended December 31, 1998, 1999 and 2000 and for the six months
ended June 30, 2000 and 2001, respectively.
The notional amount of outstanding contracts at December 31, 1999, December
31, 2000, and June 30, 2001 amounted to 12,000 barrels, 124,000 barrels and
93,000 barrels, respectively. All of the open futures contracts at December 31,
2000 and June 30, 2001 were closed in January 2001 and July 2001, respectively.
NOTE I -- COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
The Business rents certain land, machinery and equipment under various
operating leases. Total rental expense for the years ended December 31, 1998,
1999 and 2000 and the six months ended June 30, 2000 and 2001 amounted to $1.3
million, $1.7 million, $2.4 million, $1.2 million and $1.4 million,
respectively. Future minimum lease payments for all non-cancelable operating
leases having a remaining term in excess of one year as of December 31, 2000
amounted to $2.4 million in 2001, $2.2 million in 2002, $.8 million in 2003, $.8
million in 2004, $.7 million in 2005 and $1.4 million thereafter.
RECEIVABLES
Financial instruments that potentially subject the Business to
concentration of credit risk consist principally of trade receivables.
Substantially all of the Business' non-affiliate accounts receivable are due
from companies operating in various industries located in the mid-continental
and western United States. Credit is extended based on an evaluation of the
customer's financial condition, and collateral or other forms of security are
generally not required.
ENVIRONMENTAL MATTERS
In the normal course of business, the Business is required to comply with
the environmental standards and regulations of various regulatory agencies.
Under these standards and regulations, the Business is subject
A-12
THE NORTH DAKOTA AND UTAH REFINING AND MARKETING
BUSINESS OF BP CORPORATION NORTH AMERICA INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE I -- COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
to possible obligations to remove or mitigate the effects on the environment
resulting from the placement, storage, disposal or release of certain chemical
or petroleum substances by the Business or other parties.
The Business is currently participating in the cleanup of several sites.
The reasonably estimable future costs of probable environmental obligations,
including the Business' probable costs for obligations for which the Business is
jointly and severally liable, have been provided for in the Business' results of
operations. The accrued liability, which amounted to $14.2 million at December
31, 2000 and June 30, 2001, represents a reasonable best estimate of the
expenditures expected to be incurred in the future to remediate sites with known
environmental obligations. As the scope of the obligations becomes better
defined, there may be changes in the estimated future costs, which could result
in charges against the Business' future operations.
LITIGATION
Results of operations for 1999 included a charge of $4.7 million relating
to a personal injury claim. This claim was settled during the six months ended
June 30, 2001. The Business is engaged in various other litigation and
proceedings with private parties and governmental authorities and has a number
of unresolved claims pending. While the amounts claimed in the aggregate are
substantial and the ultimate liability in respect of such litigation,
proceedings and claims cannot be determined at this time, management of the
Business is of the opinion that the aggregate amount of any such liability will
not have a material effect on the financial position of the Business or the
results of its operations.
A-13
APPENDIX B
<Table>
PRO FORMA FINANCIAL STATEMENTS
Unaudited Pro Forma Combined Condensed
Balance Sheet as of June 30, 2001 ........................... B-2
Unaudited Pro Forma Combined Condensed Statement of
Operations for the Year Ended December 31, 2000 ............. B-4
Unaudited Pro Forma Combined Condensed Statement of
Operations for the Six Months Ended June 30, 2001 ........... B-5
</Table>
PRO FORMA FINANCIAL STATEMENTS
The following unaudited pro forma combined condensed financial statements
give effect to the BP Acquisition and the pending acquisition of the North
Dakota crude oil pipeline system (together "the Acquisitions") and the recent
financing of the Company's new senior secured credit facility, as amended, to
fund the Acquisitions (together "the Transactions").
These unaudited pro forma combined condensed statements have been prepared
from, and should be read in conjunction with the historical Consolidated
Financial Statements of Tesoro Petroleum Corporation filed on the Company's Form
10-K for the year December 31, 2000 and Form 10-Q for June 30, 2001 and the
Financial Statements of The North Dakota and Utah Refining and Marketing
Business of BP Corporation North America Inc. included in Appendix A to this
Form 8-K/A.
The Unaudited Pro Forma Combined Condensed Balance Sheet gives effect to
the Transactions, and the conversion of our Premium Income Equity Securities
("PIES(SM)") into shares of our common stock on July 1, 2001 as if each had
occurred on June 30, 2001. The Unaudited Pro Forma Combined Condensed Statements
of Operations for the year ended December 31, 2000, and the six months ended
June 30, 2001, give effect to the Transactions and the conversion of our
PIES(SM) into shares of our common stock on July 1, 2001 as if each had occurred
on January 1, 2000. The Acquisitions are being accounted for using the purchase
method of accounting. The estimates of the fair value of the acquired assets and
liabilities, and related estimated useful lives of various intangible assets are
based on valuations that are preliminary. These valuations will likely be
updated with respect to property, plant and equipment, intangible assets and
certain assumed liabilities, and will likely change from the amounts shown. The
unaudited pro forma combined condensed financial statements are based on
assumptions that we believe are reasonable under the circumstances and are
intended for informational purposes only. They are not necessarily indicative of
the future financial position or future results of the combined companies or of
the financial position or the results of operations that would have actually
occurred had the Acquisitions taken place as of the date or for the periods
presented. The Unaudited Pro Forma Combined Condensed Statements of Operations
do not reflect any benefits from potential cost savings or revenue enhancements
resulting from the integration of the operations of Tesoro and the Acquisitions.
B-1
UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET
JUNE 30, 2001
<Table>
<Caption>
HISTORICAL PRO FORMA
----------------------- ------------------------
TESORO ACQUISITIONS ADJUSTMENTS COMBINED
-------- ------------ ----------- --------
(DOLLARS IN MILLIONS)
ASSETS
Current Assets:
Cash and cash equivalents..................... $ 1.9 $ -- $ -- $ 1.9
Receivables................................... 340.5 56.5 (56.5)(a) 340.5
Inventories................................... 307.8 39.8 99.2 (b) 446.8
Prepayments and other......................... 8.2 2.5 (2.5)(a) 8.2
-------- ------ ------- --------
Total Current Assets.................. 658.4 98.8 40.2 797.4
-------- ------ ------- --------
Property, Plant and Equipment:
Refining and Marketing........................ 1,065.8 571.5 (7.2)(c) 1,630.1
Marine Services............................... 51.2 -- -- 51.2
Corporate..................................... 29.3 -- -- 29.3
-------- ------ ------- --------
1,146.3 571.5 (7.2) 1,710.6
Less accumulated depreciation and
amortization............................... 305.6 311.6 (311.6)(c) 305.6
-------- ------ ------- --------
Net Property, Plant and Equipment............. 840.7 259.9 304.4 1,405.0
Goodwill........................................ 61.9 -- 53.3 (d) 115.2
Other Assets.................................... 67.9 6.5 (6.5)(a) 177.4
20.6 (e)
77.6 (f)
11.3 (g)
-------- ------ ------- --------
Total Assets.......................... $1,628.9 $365.2 $ 500.9 $2,495.0
======== ====== ======= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable.............................. $ 265.2 $111.4 $(111.4)(a) $ 265.2
Accrued liabilities........................... 86.1 17.8 (15.3)(h) 88.6
Current maturities of debt and other
obligations................................ 3.7 -- -- 3.7
-------- ------ ------- --------
Total Current Liabilities............. 355.0 129.2 (126.7) 357.5
-------- ------ ------- --------
Deferred Income Taxes........................... 120.7 42.0 (42.0)(a) 120.7
Other Liabilities............................... 78.5 10.5 20.4 (h) 109.4
Debt and Other Obligations...................... 352.6 -- 833.2 (i) 1,185.8
Parent Company Investment....................... -- 183.5 (183.5)(j) --
Stockholders' Equity:
Preferred stock............................... 165.0 -- (165.0)(k) --
Common stock.................................. 5.4 -- 1.7 (k) 7.1
Additional paid-in capital.................... 285.2 -- 163.3 (k) 448.5
Retained earnings............................. 285.1 -- (0.5)(e) 284.6
Treasury stock................................ (18.6) -- -- (18.6)
-------- ------ ------- --------
Total Stockholders' Equity............ 722.1 -- (0.5) 721.6
-------- ------ ------- --------
Total Liabilities and Stockholders'
Equity.............................. $1,628.9 $365.2 $ 500.9 $2,495.0
======== ====== ======= ========
</Table>
B-2
NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET
JUNE 30, 2001
(a) Represents an adjustment to exclude certain assets and liabilities of BP
that we did not acquire in connection with the Acquisitions, including
cash, receivables, prepayments and other assets, accounts payable and
deferred income taxes.
(b) Represents an adjustment of refined products inventories to net realizable
value, less an allowance for a normal selling margin, and of raw materials
inventories to replacement cost. The inventory acquired included $132.9
million of crude oil, other feedstocks and refined products (including
$47.7 million for inventories acquired subject to agreement referenced
footnote (i) below) and $6.1 million of materials and supplies.
(c) Represents an adjustment of acquired property, plant and equipment from
book value to fair market value.
(d) Represents goodwill, which is the excess purchase price over the fair
market value of net assets acquired.
(e) Represents an adjustment to record debt issuance costs associated with the
new senior secured credit facility totaling $21.4 million net of the
writeoff of debt issuance costs of $0.8 million ($0.5 million net of tax)
related to our prior credit facility.
(f) Represents an adjustment to record intangible assets recorded in connection
with the Acquisitions including jobber agreements, permits and plans,
refinery technology, customer contracts and non-contractual customer
arrangements.
(g) Represents an adjustment to conform the accounting policy for refinery
maintenance turnaround costs to Tesoro's policy. BP expensed refinery
maintenance turnaround costs as incurred while Tesoro's policy is to defer
the costs and amortize them on a straight line basis over the expected
periods of benefit.
(h) Represents an adjustment for certain employee benefit and environmental
liabilities we assumed in connection with the Acquisitions.
(i) Represents an adjustment of $833.2 million to aggregate borrowings to
finance the Acquisitions, to finance our existing indebtedness and to pay
related fees, expenses and debt issuance costs as follows:
<Table>
<Caption>
Cash purchase price (including direct costs of
acquisition).............................................. $764.1
Inventories acquired subject to an agreement*............... 47.7
Debt issuance costs......................................... 21.4
------
$833.2
======
</Table>
---------------
* In connection with the Acquisitions, we acquired certain refined
product inventories at the North Dakota refinery subject to an
agreement. Under this agreement, instead of paying cash for these
inventories, we agreed to deliver an equal amount of refined
products to BP.
(j) Represents the elimination of historical equity related to the BP assets.
(k) Represents an adjustment for the conversion of our Premium Income Equity
Securities ("PIES(SM)") into shares of our common stock on July 1, 2001.
B-3
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000
<Table>
<Caption>
HISTORICAL PRO FORMA
-------------------------- -----------------------
TESORO ACQUISITIONS ADJUSTMENTS COMBINED
-------- --------------- ----------- --------
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues:
Refining and Marketing...................... $4,917.6 $1,483.8(a) $ -- $6,401.4
Marine Services............................. 186.8 -- -- 186.8
-------- -------- ------ --------
Total Revenues...................... 5,104.4 1,483.8 -- 6,588.2
-------- -------- ------ --------
Cost of Sales and Operating Expenses:
Refining and Marketing...................... 4,688.1 1,368.2 (0.9)(b) 6,055.4
Marine Services............................. 173.7 -- -- 173.7
Depreciation and amortization............... 43.1 23.2 (3.0)(c) 68.1
4.8 (d)
-------- -------- ------ --------
Total Costs of Sales and Operating
Expenses.......................... 4,904.9 1,391.4 0.9 6,297.2
-------- -------- ------ --------
Segment Operating Profit...................... 199.5 92.4 (0.9) 291.0
General and Administrative.................... (40.3) -- -- (40.3)
Interest and Financing Costs, Net of
Capitalized Interest........................ (32.7) -- (55.5)(e) (91.5)
(3.3)(f)
Interest Income............................... 2.8 -- -- 2.8
Other Expenses................................ (5.8) -- -- (5.8)
-------- -------- ------ --------
Earnings Before Income Taxes.................. 123.5 92.4 (59.7) 156.2
Income Tax Provision.......................... 50.2 35.9 (22.7)(g) 63.4
-------- -------- ------ --------
Net Earnings.................................. 73.3 56.5 (37.0) 92.8
Preferred Dividend Requirements............... (12.0) -- 12.0 (h) --
-------- -------- ------ --------
Net Earnings Applicable to Common Stock....... $ 61.3 $ 56.5 $(25.0) $ 92.8
======== ======== ====== ========
Earnings Per Share
Basic ...................................... $ 1.96 $ 2.23
======== ========
Diluted .................................... $ 1.75 $ 2.22
======== ========
Weighted Average Common Shares - Basic(h) .... 31.2 41.6
======== ========
Weighted Average Common Shares and
Potentially Dilutive Common
Shares - Diluted ............................ 41.8 41.8
======== ========
</Table>
B-4
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2001
<Table>
<Caption>
HISTORICAL PRO FORMA
----------------------- -----------------------
TESORO ACQUISITIONS ADJUSTMENTS COMBINED
-------- ------------ ----------- --------
(DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues:
Refining and Marketing......................... $2,433.1 $725.7(a) $ -- $3,158.8
Marine Services................................ 93.8 -- -- 93.8
-------- ------ ------ --------
Total Revenues......................... 2,526.9 725.7 -- 3,252.6
-------- ------ ------ --------
Costs of Sales and Operating Expenses:
Refining and Marketing......................... 2,295.4 636.8 (6.1)(b) 2,926.1
Marine Services................................ 86.4 -- -- 86.4
Depreciation and amortization.................. 21.6 11.2 (1.1)(c) 34.1
2.4 (d)
-------- ------ ------ --------
Total Costs of Sales and Operating
Expenses............................. 2,403.4 648.0 (4.8) 3,046.6
-------- ------ ------ --------
Segment Operating Profit......................... 123.5 77.7 4.8 206.0
General and Administrative....................... (21.3) -- -- (21.3)
Interest and Financing Costs, Net of Capitalized
Interest....................................... (14.1) -- (28.5)(e) (43.8)
(1.2)(f)
Interest Income.................................. 0.5 -- -- 0.5
Other Expenses................................... (3.1) -- -- (3.1)
-------- ------ ------ --------
Earnings Before Income Taxes..................... 85.5 77.7 (24.9) 138.3
Income Tax Provision............................. 34.3 30.5 (9.5)(g) 55.3
-------- ------ ------ --------
Net Earnings..................................... 51.2 47.2 (15.4) 83.0
Preferred Dividend Requirements.................. (6.0) -- 6.0 (h) --
-------- ------ ------ --------
Net Earnings Available to Common Stock........... $ 45.2 $ 47.2 $ (9.4) $ 83.0
======== ====== ====== ========
Earnings Per Share
Basic.......................................... $ 1.46 $ 2.01
======== ========
Diluted........................................ $ 1.22 $ 1.98
======== ========
Weighted Average Common Shares -- Basic(h)....... 31.0 41.4
======== ========
Weighted Average Common Shares and Potentially
Dilutive Common Shares -- Diluted.............. 42.0 42.0
======== ========
</Table>
B-5
NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED
STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE SIX MONTHS ENDED JUNE 30, 2001
(a) In connection with the Acquisitions, we entered into certain offtake
agreements with BP to provide us with a distribution channel for a portion
of our refined products we produce at these refineries. The offtake
agreements commit approximately 37,220 bpd of refined products for a period
ranging from three to five years. Historically, BP has sold these volumes
through its distribution network, which included retail stations and
jobbers. The product sales prices that we will receive under the offtake
agreements may be less than BP historically had realized. A change in
product sales price of 1 cent per gallon would have resulted in a decrease
in revenues of $5.7 million for the year ended December 31, 2000 and $2.8
million for the six months ended June 30, 2001, and a decrease in net
earnings of $3.4 million for the year ended December 31, 2000 and $1.7
million for the six months ended June 30, 2001.
(b) Represents an adjustment to conform the accounting policy for refinery
maintenance turnaround costs to that of Tesoro's policy.
(c) Represents an adjustment in depreciation expense due to the change in
property, plant and equipment from book value to fair value related to the
Acquisitions. Pro forma depreciation is calculated on the straight-line
method over estimated useful lives of 28 years for refinery assets, 22
years for pipeline assets and 16 years for terminals and retail assets.
(d) Represents the amortization of various intangible assets related to the
Acquisitions over their estimated useful lives. The lives are 20 years for
jobber networks, 15 to 28 years for permits and plans, 28 years for
refinery technology, 5 years for refinery software and 10 years for
customer contracts and non-contractual customer arrangements.
(e) Represents additional interest under our new senior secured credit
facility, offset by a decrease in interest related to our prior credit
facility.
(f) Represents the amortization of debt issuance costs related to our new
senior secured credit facility less the amortization of debt issuance costs
related to our prior credit facility.
(g) Represents the tax effect of the adjustments above at a combined statutory
tax rate of 38%.
(h) Represents the elimination of the preferred dividend requirements upon
conversion of our PIES(SM) into shares of our common stock on July 1, 2001.
The increased number of shares of common stock is reflected in the pro
forma weighted average common shares used in the computation of Earnings
Per Share -- Basic.
B-6
APPENDIX C
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- TESORO
We have endeavored to provide a more thorough discussion of our
expectations and goals in this section, and we anticipate that we will continue
to do the same in Management's Discussion and Analysis of Financial Condition
and Results of Operations in the future. However, expectations and goals may
change during interim periods of time. We do not intend to, and you should not
expect that we will, update the information contained herein during any such
interim period.
Unless otherwise indicated, the disclosures in this section do not include
the Acquisitions, as defined below. The following should be read in conjunction
with the Company's Form 10-K for the year December 31, 2000 and the Company's
Form 10-Q for the quarter June 30, 2001.
The term "North Dakota System" refers to the refinery in Mandan, North
Dakota and related storage, pipeline, distribution and gasoline marketing assets
we recently acquired and the Pipeline System (as defined below); the term "Utah
System" refers to the refinery in Salt Lake City, Utah and related storage,
distribution and gasoline marketing assets we recently acquired; and the term
"Pipeline System" refers to a crude oil gathering and transmission system
located in Montana and North Dakota that we expect to acquire in the fourth
quarter of 2001 that provides crude oil to the North Dakota refinery. The term
"Acquisitions" refers collectively to the acquisition of the North Dakota System
(including the Pipeline System) and the Utah system.
This Management's Discussion and Analysis includes certain statements that
are "forward-looking" statements within the meaning of the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995, as codified
in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. These forward-looking statements
include, among other things, projections of revenues, earnings, earnings per
share, cash flows, capital expenditures or other financial items, discussions of
the Acquisitions, discussions of estimated future revenue enhancements and cost
savings. These statements also relate to our business strategy, goals and
expectations concerning our market position, future operations, margins,
profitability, liquidity and capital resources. 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 Management's Discussion and Analysis.
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 those 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. Accordingly, these forward-looking
statements are qualified in their entirety by reference to the factors described
in "Capital Resources and Liquidity" on page C-11 and in "Forward-Looking
Statements," "Risk Factors and Investment Considerations" in our Annual Report
on Form 10-K for the year ended December 31, 2000.
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 in this Management's Discussion and Analysis 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 report (October 24, 2001).
STRATEGY
Our goal is to create value by: (1) maximizing our earnings, cash flows and
return on capital by reducing costs, increasing efficiencies and optimizing
existing assets; and (2) increasing our competitiveness by expanding our size
and market presence through a combination of internal growth initiatives and
selective acquisitions that are accretive to earnings and cash flows and provide
operational synergies. We are also focused on improving profitability in the
Refining and Marketing segment by enhancing processing capabilities,
strengthening its marketing activities and improving supply and transportation
logistics. The Marine Services segment optimizes existing operations through
ongoing development of customer services and cost management. As part of this
strategy, we continue to assess our existing asset base to maximize returns and
financial flexibility through market diversification and related acquisitions.
On August 27, 2001, we announced we are evaluating various strategic
opportunities (including a possible sale of all or a part of this business) to
capitalize on the value of our Marine Services assets.
ACQUISITIONS
We believe the refining and marketing industry has been and will continue
to undergo a significant level of asset redeployment and consolidation. We have
grown and taken advantage of the economies of scale from this consolidation. We
more than tripled our refining capacity in 1998 when we acquired the Hawaii and
Washington refineries and improved our financial condition and performance
through our focus on the refining and marketing business. As a result, we
believe we are positioned for additional growth and improved financial returns.
On September 6, 2001, we acquired two refineries in North Dakota and Utah
and related storage, distribution and retail assets from certain affiliates of
BP p.l.c. We paid approximately $666 million in cash (including $82 million for
hydrocarbon inventories) for the Utah System and the North Dakota System
(excluding the Pipeline System). We financed the purchase price for the North
Dakota System (excluding the Pipeline System) and Utah System acquisitions with
debt under our new senior secured credit facility. We also assumed certain
liabilities and obligations (including costs associated with transferred
employees and environmental matters) subject to specified levels of
indemnification.
The North Dakota System (excluding the Pipeline System) includes:
- a 60,000 barrels per day ("bpd") refinery in Mandan, North Dakota;
- five terminals with an aggregate capacity of 2.8 million barrels
(including refinery tankage);
- approximately 430 miles of refined product pipeline connecting the
refinery to our terminals, including the Minneapolis/St. Paul market;
- 12 retail stations with convenience stores; and
- contracts to supply a jobber (third party retail distributor) network of
over 90 retail stations.
C-1
The Utah System includes:
- a 55,000 bpd refinery in Salt Lake City, Utah;
- five terminals, two of which are leased, with an aggregate capacity of
2.5 million barrels (including refinery tankage);
- 31 retail stations with convenience stores; and
- contracts to supply a jobber network of over 200 retail stations.
In connection with the acquisition of the North Dakota refinery, we agreed
to acquire the Pipeline System, which consists of over 700 miles of pipeline,
from BP Pipelines (North America) Inc. The Pipeline System is configured to
gather crude oil from the local Williston Basin and adjacent production areas in
North Dakota and Montana and transport it to the North Dakota refinery. The
Pipeline System is also configured to move substantial quantities of imported
Canadian crude oil to the North Dakota refinery or transport it either to
Clearbrook, Minnesota to the east or to Guernsey, Wyoming to the south. We will
fund the $90 million purchase price with borrowings under the delayed draw term
loan of our new senior secured credit facility. We expect to close the Pipeline
System acquisition in the fourth quarter of 2001 following the approval of the
Public Services Commission of North Dakota and satisfaction of other customary
conditions.
With the acquisition of the North Dakota System (excluding the Pipeline
System) and the Utah System, we have an asset base consisting of five refineries
with a rated crude oil throughput capacity of 390,000 bpd and over 630 retail
gasoline stations. These acquisitions added approximately 620 employees to our
operations and we expect the acquisition of the Pipeline System to add
approximately 30 employees to our operations.
We believe the Acquisitions enable us to increase the size and scope of our
operations, diversify our earnings and geographic exposure, and build a platform
for additional growth. We further believe the Acquisitions will improve our
ability to supply markets in areas we had previously targeted for commercial and
retail marketing expansion, including our Mirastar program.
MANUFACTURING
Heavy Oil Conversion Project
Our manufacturing strategy focuses on improving refinery reliability and
safety, improving refining processes and controlling manufacturing costs. We
commenced a heavy oil conversion project at our Washington refinery in 2000,
which will enable us to process a larger proportion of lower-cost heavy crude
oils, to manufacture a larger proportion of higher-value gasoline and to reduce
production of lower-value heavy products. We expect to spend approximately $100
million (including capitalized interest) for this project, of which we had spent
$78 million through August 31, 2001. We completed the first stage of the
project, the installation of a de-asphalting unit, in late September 2001. We
expect the upgrade of the fluid catalytic cracking unit, the final major
component of the heavy oil conversion project, to be operational by the end of
the first quarter of 2002.
We originally estimated the total heavy oil conversion project would
increase annual operating profit by $30 million to $40 million. Based upon price
differentials between light and heavy crude oils and between light and heavy
refined products and changes in throughput, yield levels and operating expenses,
we estimate the heavy oil conversion project would have increased annual
operating profit by approximately $41 million for the twelve months ended August
31, 2001, if it had been in operation during that period. The actual profit to
be contributed by the heavy oil conversion project is subject to several
factors, including, among others, refinery throughput, market values of light
and heavy refined products, availability of economic heavy feedstocks, price
differentials between light and heavy crude oils and operating expenses,
including fuel and utility costs.
C-2
Other
In addition to the heavy oil conversion project, we have increased our
asphalt and middle distillate production capabilities at the Washington
refinery. We have also implemented programs to improve refinery reliability and
safety. We have implemented other programs to control manufacturing costs by
upgrading process control systems, consolidating refinery equipment purchasing
and improving our ability to respond to volatile changes in the cost of
utilities at the Washington refinery. Wholesale prices for purchased electricity
at the Washington refinery fluctuated tremendously in the first six months of
2001, from a low of $20 per megawatt-hour to a high of $488 per megawatt-hour.
We installed leased, diesel-fueled generators in late January 2001 to
self-generate most of the Washington refinery's power requirements. We have
acquired natural gas-fired generators with emission control packages to replace
the leased diesel generators. The natural gas-fired generators are capable of
supplying approximately 90% of the Washington refinery's present power
requirements and provide the flexibility to better manage our power costs
between self-generated power and purchased electricity.
RETAIL MARKETING
Our Refining and Marketing business includes a network of over 630 branded
retail stations (under the Tesoro, Mirastar, Tesoro Alaska and Amoco brands),
including 159 Tesoro-owned retail gasoline stations and over 470 jobber stations
(third-party retail distributors) in the mid-continental and western United
States. We developed our Mirastar brand exclusively for Wal-Mart, for which we
build and operate retail fueling facilities on sites at selected Wal-Mart store
locations. Our relationship with Wal-Mart covers 17 western states, including
North Dakota and Utah.
Each of the sites under our agreement with Wal-Mart is subject to a ground
lease with a ten-year primary term and two options, exercisable at our
discretion, to extend a site's lease for additional terms of five years. As of
August 31, 2001, we had 46 Mirastar stations in operation. Though highly
dependent on Wal-Mart's ability to offer sites, we expect to have approximately
60 to 70 Mirastar stations operating by the end of 2001 and expect to construct
an additional 50 to 60 stations in each of 2002 and 2003. Our average cost of
constructing a standard Mirastar station with four fuel dispensers is
approximately $550,000.
We expect the Acquisitions to help us capitalize on the benefits of the
Wal-Mart agreement and expand our current retail platform by providing a source
of proprietary gasoline product to our expanded retail network.
In early September 2001, we entered into a purchase and sale agreement to
acquire 46 retail fueling facilities, including 37 retail stations with
convenience stores and nine commercial card lock facilities, located in
Washington, Oregon and Idaho. We are purchasing these properties from Gull
Industries Inc., a privately-held company based in Seattle, Washington. We
expect the transaction to close in the fourth quarter of 2001.
BUSINESS ENVIRONMENT
We operate in an environment where our results and cash flows are sensitive
to volatile changes in energy prices. Fluctuations in the costs of crude oil and
other refinery feedstocks and the price of refined products can result in
changes in margins from the Refining and Marketing operations, as prices
received for refined products may not keep pace with changes in feedstock costs.
As part of our marketing program, we also purchase refined products for sale to
customers. Changes in price levels of crude oil and refined products can result
in changes in margins on these activities. Energy prices, together with volume
levels, also determine the carrying value of crude oil and refined product
inventory. We use the last-in, first-out method of accounting for inventories of
crude oil and refined products in our Refining and Marketing segment. This
method results in inventory carrying amounts that are less likely to represent
current values and costs of sales that more closely represent current costs.
We maintain inventories of crude oil, intermediate products and refined
products, the values of which are subject to fluctuations in market prices. At
December 31, 2000 and June 30, 2001, our inventories of
C-3
refinery feedstocks and refined products totaled 11.9 million barrels and 13.2
million barrels, respectively. During 2000, inventory levels increased 3.3
million barrels over year-end 1999 levels at an average cost of $29.82 per
barrel. Sales that result in a reduction in inventories below 11.9 million
barrels during 2001 would have a per barrel cost of sales equal to the sum of
$29.82 plus the cost of transportation to market. This amount could exceed the
year-to-date average costs of sales in 2001. The average cost of refinery
throughput in June 2001 was approximately $27.70 per barrel, or approximately
$2.12 per barrel lower than the cost of the 2000 incremental inventory layer.
The average costs of our refinery feedstocks and refined products inventories as
of June 30, 2001 and December 31, 2000 were $21.50 per barrel and $20.79 per
barrel, respectively. If market price levels decline to a level below the
average cost of these inventories, we may be required to write down the carrying
value of our inventory.
Changes in crude oil and natural gas prices also influence the level of
drilling activity in the Gulf of Mexico. Our Marine Services segment, whose
customers include offshore drilling contractors and related industries, can be
impacted by significant fluctuations in crude oil and natural gas prices. The
Marine Services segment uses the first-in, first-out method of accounting for
inventories of fuels. Changes in fuel prices can significantly affect inventory
valuations and costs of sales.
RESULTS OF OPERATIONS
SUMMARY
Our net earnings were $51.2 million ($1.46 per basic share or $1.22 per
diluted share) for the six months ended June 30, 2001, compared with net
earnings of $23.9 million ($0.57 per basic share or $0.56 per diluted share) for
the six months ended June 30, 2000. The increase in earnings during the six
months ended June 30, 2001 reflected improvement in operating profit from our
Refining and Marketing segment due to higher refined product margins, refinery
throughput levels and sales volumes, partially offset by higher expenses.
Our net earnings for the year 2000 were $73.3 million ($1.96 per basic
share or $1.75 per diluted share). On a comparable basis, our earnings from
continuing operations were $32.2 million ($0.62 per basic and diluted share) in
1999 and $7.6 million ($0.05 per basic and diluted share) in 1998. The earnings
improvement during 2000 reflected a record level of operating profit from the
Refining and Marketing segment resulting from higher refined product margins and
increased throughput levels, partly offset by higher operating expenses. The
Marine Services segment's operating profit also reached a record level,
reflecting a recovery in sales volumes from depressed 1999 levels, as well as
effective cost management.
The improvement in 1999 earnings from continuing operations, as compared to
1998, also was due to higher operating profit from our Refining and Marketing
segment. Increased throughput and sales volumes from operations acquired in
mid-1998, refinery efficiency and reliability, and profits from purchasing and
selling products manufactured by others contributed to the Refining and
Marketing results. Partially offsetting these improvements were increased
general and administrative expenses and interest and financing costs during 1999
as compared to 1998.
Our 1999 net earnings of $75.0 million ($1.94 per basic share or $1.92 per
diluted share) and net loss of $19.4 million ($0.86 per basic and diluted share)
in 1998 included results from our former exploration and production operations.
These discontinued operations contributed $42.8 million to net earnings ($1.32
per basic share or $1.30 per diluted share) in 1999, including an aftertax gain
of $39.1 million from the sale of these operations. In 1998, discontinued
operations incurred a net loss of $22.6 million ($0.76 per basic and diluted
share), which included $43.2 million in aftertax write-downs of oil and gas
properties and $13.4 million in aftertax income from receipt of contingency
funds related to these operations. In addition, we incurred an aftertax
extraordinary loss of $4.4 million in 1998 for early extinguishment of debt.
A discussion and analysis of the factors contributing to our results of
operations are presented below. The accompanying Consolidated Financial
Statements, together with the following information, are intended to provide
investors with a reasonable basis for assessing our operations, but should not
serve as the only criteria for predicting our future performance.
C-4
REFINING AND MARKETING
<Table>
<Caption>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------ -------------------
1998 1999 2000 2000 2001
-------- -------- -------- -------- --------
(DOLLARS IN MILLIONS, EXCEPT AS INDICATED)
REVENUES:
Refined Products..................................... $1,198.2 $2,808.6 $4,536.0 $2,022.5 $2,282.8
Other Revenues, Primarily Crude Oil Resales and
Merchandise........................................ 69.8 80.5 381.6 165.7 150.3
-------- -------- -------- -------- --------
Total Revenues.............................. $1,268.0 $2,889.1 $4,917.6 $2,188.2 $2,433.1
======== ======== ======== ======== ========
SEGMENT OPERATING PROFIT:
Gross margins:
Refinery(a)........................................ $ 308.3 $ 500.6 $ 625.2 $ 273.2 $ 354.6
Purchased Product and Crude Oil Resales............ 3.8 38.5 14.4 16.0 5.2
Merchandise and Other.............................. 17.8 23.2 27.2 13.4 11.6
-------- -------- -------- -------- --------
Total Gross Margins......................... 329.9 562.3 666.8 302.6 371.4
Operating Expenses and Other(b)...................... 235.1 399.3 437.3 213.3 233.7
Depreciation and Amortization(c)..................... 25.1 37.9 40.4 18.6 20.2
-------- -------- -------- -------- --------
Segment Operating Profit.................... $ 69.7 $ 125.1 $ 189.1 $ 70.7 $ 117.5
======== ======== ======== ======== ========
Capital Expenditures................................. $ 38.0 $ 72.4 $ 87.5 $ 21.0 $ 76.6
% Heavy Crude Oil of Total Refinery System
Throughput......................................... 43% 35% 43% 44% 51%
Total Refinery System Product Spread ($/barrel)...... $ 5.67 $ 5.79 $ 6.99 $ 6.17 $ 7.73
PRODUCT SALES (thousand bpd)(d)(e):
Gasoline and Gasoline Blendstocks.................... 58.4 123.7 135.0 134.8 139.7
Jet Fuel............................................. 45.9 75.5 76.3 76.6 78.0
Diesel Fuel.......................................... 24.2 47.1 53.6 47.9 59.0
Heavy Oils, Residual Products and Other.............. 39.3 56.5 57.6 59.2 58.7
-------- -------- -------- -------- --------
Total Product Sales......................... 167.8 302.8 322.5 318.5 335.4
======== ======== ======== ======== ========
PRODUCT SALES PRICES ($/barrel):
Gasoline and Gasoline Blendstocks.................... $ 24.22 $ 29.62 $ 41.95 $ 38.33 $ 43.56
Middle Distillates (Jet Fuel and Diesel Fuel)........ 19.79 25.18 39.97 35.60 36.84
Heavy Oils, Residual Products and Other.............. 12.12 16.80 26.88 25.74 24.98
PRODUCT SALES MARGIN ($/barrel)(d):
Average Sales Price.................................. $ 19.56 $ 25.41 $ 38.43 $ 35.04 $ 37.59
Average Costs of Sales............................... 14.49 20.59 33.03 29.69 31.66
-------- -------- -------- -------- --------
Gross Margin................................ $ 5.07 $ 4.82 $ 5.40 $ 5.35 $ 5.93
======== ======== ======== ======== ========
</Table>
---------------
(a) Approximates refinery system throughput times the refinery system product
spread, adjusted for changes in refined product inventory.
(b) Includes manufacturing costs per throughput barrel of $2.73, $2.98 and
$2.85 for 1998, 1999 and 2000, respectively, and $2.83 and $3.19 for the
six months ended June 30, 2000 and 2001, respectively. Manufacturing costs
included non-cash amortization of maintenance turnaround costs of $11.3
million, $14.2 million and $20.1 million in 1998, 1999 and 2000,
respectively, and $10.3 million and $8.6 million for the six months ended
June 30, 2000 and 2001, respectively.
(c) Includes manufacturing depreciation per throughput barrel of approximately
$0.27, $0.32 and $0.26 for 1998, 1999 and 2000, respectively, and $0.26 and
$0.24 for the six months ended June 30, 2000 and 2001, respectively.
(d) Volumes for 1998 include amounts from the Washington refinery (acquired in
August 1998) and the Hawaii operations (acquired in May 1998) since their
dates of acquisition, averaged over the full year.
(e) Sources of total product sales included products manufactured at the
refineries, products drawn from inventory balances and products purchased
from third parties. Gross margins on total product sales included margins
on sales of manufactured and purchased products and the effects of
inventory changes.
C-5
Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 2001
Segment operating profit for the Refining and Marketing segment was $117.5
million in the six months ended June 30, 2001, an increase of more than 65% from
the same period in 2000. The increase was primarily driven by stronger refined
product margins and higher refinery throughput and sales volumes. The
improvement in refinery margins was partially offset by increases in operating
expenses and lower margins from purchased product resales.
Revenues from sales of refined products in the Refining and Marketing
segment increased 10% to $2,283 million in the six months ended June 30, 2001,
as compared to the same period in 2000, due to higher product prices and sales
volumes. Our average product sales prices increased 7% to $37.59 per barrel in
the six months ended June 30, 2001 from $35.04 per barrel in the same period in
2000. Total product sales averaged 335,400 bpd in the six months ended June 30,
2001, an increase of 5% from the same period in 2000. The decrease in other
revenues was primarily due to lower crude oil resales which totaled
approximately $117 million in the six months ended June 30, 2001 compared to
approximately $134 million in the same period in 2000. The increase in costs of
sales reflected primarily higher purchased product prices and increased volumes.
Refinery gross margin increased 30% to $354.6 million in the six months
ended June 30, 2001, reflecting higher volumes and a 25% increase in average
refinery system product spread per barrel to $7.73 in the six months ended June
30, 2001. Industry refining margins remained strong in the western United States
during the six months ended June 30, 2001, reflecting the continued tightness of
supply and refining capacity in the region. We were able to increase refinery
throughput 5% to a record-high first half level of 253,000 bpd in the six months
ended June 30, 2001. Our sales of higher-value California Air Resources Board
quality blendstocks added approximately $13 million to segment operating profit
in the six months ended June 30, 2001 as compared to the values received from
sales of conventional gasoline.
Our margins on purchased product and crude oil resales declined by $10.8
million in the six months ended June 30, 2001, as compared to the same period in
2000. Market conditions during the six months ended June 30, 2000 offered
greater profit opportunities compared to market conditions during the same
period in 2001.
Operating expenses, excluding depreciation, increased by $20.4 million to
$233.7 million in the six months ended June 30, 2001, primarily due to higher
costs for utilities and fuel and increased employee costs.
Year Ended December 31, 1999 Compared to Year Ended December 31, 2000
Segment operating profit for the Refining and Marketing segment increased
51% during 2000 to $189.1 million. This improvement was driven by a combination
of stronger refined product margins and record-high refinery throughput.
Industry product supply concerns and tight product inventories contributed to
strong U.S. west coast margins. We were able to capitalize on these conditions
by operating our refineries at historically high rates. The record level of
refinery throughput reflected high levels of operational reliability without
compromising our safety program. The improvement in refinery margins was
partially offset by higher operating expenses and lower margins from purchased
product resales.
Revenues from sales of refined products in the Refining and Marketing
segment increased 62% in 2000, primarily due to higher product prices and
increases in sales volumes. Our average product sales prices increased 51% to
$38.43 per barrel in 2000 from $25.41 per barrel in 1999. Total product sales
increased to an average of 322,500 bpd during 2000 from 302,800 bpd in 1999.
Other revenues increased during 2000 primarily due to crude oil resales of
$332.4 million in 2000 compared to $16.6 million in 1999.
C-6
This increase in crude oil resales resulted from a term agreement with one of
our crude oil suppliers. The increase in cost of sales reflected higher costs of
refinery feedstocks and purchased products due to higher prices as well as
higher volumes.
Our refinery gross margins improved to $625.2 million in 2000 from $500.6
million in 1999, reflecting a 21% increase in refinery system product spread to
$6.99 per barrel and a 7% increase in refinery throughput to 249,500 bpd. The
improvement in refinery margins was partly due to the higher throughput levels
combined with strong market conditions. In manufacturing, a flexible feedstock
supply enabled us to process a higher percentage of lower-cost heavy crude oil,
which represented 42.5% of refinery throughput in 2000 compared with 34.9% in
1999. This percentage increase in heavy crude oil partly offset the impact of
higher prices for refinery feedstocks, while minimally affecting our yield of
light, higher-value products, which declined less than 2%. The investment in the
distillate treater, which allows us to produce jet fuel and diesel fuel at the
same time and was placed in service at the Washington refinery in December 1999,
was a contributing factor in maintaining those yields. We estimate that this
investment added approximately $12 million of incremental segment operating
profit in 2000. In marketing, we altered our gasoline blending process to market
higher-value California Air Resources Board quality blendstocks, rather than
including these materials in the finished gasoline pool. The flexibility to sell
these products added an estimated $10 million to segment operating profit in
2000, as compared to the values received from sales of conventional gasoline.
Margins on purchased product and crude oil resales declined by $24.1
million during 2000. Market conditions in 2000 offered fewer opportunities for
product resales compared to market conditions in 1999, which were affected by
product supply disruptions. The $4.0 million increase in merchandise and other
margins reflected increased sales volumes and the continued expansion of retail
sites in 2000.
Operating expenses and other, excluding depreciation, increased by 10% to
$437.3 million in 2000 from $399.3 million in 1999. This increase was primarily
attributable to the impact of higher refinery throughput and increased costs for
refinery utilities and fuel. In addition, expenses increased for state and local
taxes because of higher product values, employee costs related to expansion of
the retail marketing team and maintenance turnaround costs. Savings associated
with our cost reduction program partly offset these higher expenses.
Electricity rates at the Washington refinery increased from an average of
$35 per megawatt hour in 1999 to an average of $104 per megawatt hour in 2000
(including an average of $205 per megawatt hour in the fourth quarter of 2000),
resulting in an aggregate increase in electricity costs from approximately $6
million in 1999 to approximately $18 million in 2000.
Operating expenses included non-cash amortization of refinery turnaround
costs of $20.1 million and $14.2 million in 2000 and 1999, respectively. The
increase in 2000 was due, in part, to the accelerated turnaround of certain
refinery units. The Hawaii crude oil unit turnaround was moved from 2001 and
combined with the September 2000 hydrocracker turnaround to avoid a temporary
reduction in throughput in 2001.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1999
Segment operating profit for our Refining and Marketing operations was
$125.1 million in 1999, an increase of $55.4 million from segment operating
profit of $69.7 million in 1998. Contributing to the increase was a full year of
results from the Washington refinery and related marketing operations in 1999,
compared to five months in 1998. Similarly, the Hawaii refinery and operations
contributed to operating profit for the full year in 1999; however, the 1999
results were lower than in the seven months included in 1998 due to rising crude
oil costs and lower product margins.
Segment operating profit increased significantly during the 1999 second
quarter and first half of the 1999 third quarter due primarily to stronger than
normal market conditions on the U.S. west coast. Refining margins during this
period were strong in the western United States due to seasonal demand, product
supply disruptions caused by operating problems at other refineries, and a
rupture of the major
C-7
refined products pipeline that serves the Pacific Northwest region. However, in
the fourth quarter of 1999, margins were adversely impacted as affected U.S.
west coast facilities resumed operations, refined product imports into the U.S.
west coast continued, and crude oil costs escalated rapidly. Our refinery system
product spread, which averaged approximately $8.07 per barrel in the month of
July 1999 and $7.16 per barrel in the month of August 1999, dropped
precipitously during the 1999 fourth quarter to approximately $4.30 per barrel
in the month of December 1999. In addition, during the 1999 fourth quarter,
lower refinery throughputs, caused primarily by the scheduled turnaround of the
Washington refinery's crude oil distillation and catalytic reformer units for
25 days in October, reduced overall system throughput to an average of 208,100
bpd.
Revenues from sales of refined products in the Refining and Marketing
segment increased in 1999, primarily due to the higher sales volumes from the
Washington and Hawaii refineries, acquired in mid-1998, higher product prices
and increased sales volumes of purchased product. The increase in other revenues
during 1999 included higher retail merchandise sales, primarily from the Hawaii
acquisition, and $4.5 million in revenues from the sub-charter of vessels to
third parties, partially offset by lower crude oil resales. The increase in
costs of sales reflected higher volumes associated with the 1998 acquisitions,
increased prices for feedstocks and products, and higher purchased product
volumes. During 1999, we reduced inventory levels by approximately 2.5 million
barrels from the prior year-end level, resulting in a liquidation of last-in,
first-out inventory quantities carried at lower costs prevailing in previous
years. This last-in, first-out liquidation resulted in a decrease in costs of
sales of $8.4 million in 1999.
During 1999, the Refining and Marketing segment benefited from our focus on
manufacturing efficiency and reliability, as well as distribution costs and
marketing flexibility. We maintained a flexible supply of crude oils and other
feedstocks and operated the refineries at economic rates, which all contributed
to the improvement in operating profit. Overall refinery gross margin increased
to $500.6 million in 1999 due to the higher throughput volumes and an increase
in average refinery system product spread to $5.79 per barrel in 1999 compared
to $5.67 per barrel in 1998.
Margins from purchased product and crude oil resales increased to $38.5
million in 1999 from $3.8 million in 1998, due primarily to stronger than normal
market conditions on the U.S. west coast. Operating expenses and depreciation
and amortization increased in 1999 primarily due to the acquisitions of the
Washington and Hawaii refineries in 1998.
MARINE SERVICES
<Table>
<Caption>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------ -----------------
1998 1999 2000 2000 2001
------ ------ ------ ------ ------
(DOLLARS IN MILLIONS)
Revenues:
Fuels........................................... $ 91.1 $ 86.5 $156.9 $70.2 $78.3
Lubricants and other............................ 15.9 13.0 15.0 7.6 7.8
Services........................................ 11.6 11.7 13.3 6.3 7.9
Other income.................................... -- -- 1.6 1.2 (0.2)
------ ------ ------ ----- -----
Total Revenues.......................... 118.6 111.2 186.8 85.3 93.8
Cost of Sales..................................... 79.0 74.8 143.6 63.0 70.9
------ ------ ------ ----- -----
Gross Profit............................ 39.6 36.4 43.2 22.3 22.9
Operating Expenses and Other...................... 28.6 27.9 30.1 15.3 15.5
Depreciation and Amortization..................... 2.4 2.6 2.7 1.2 1.4
------ ------ ------ ----- -----
Segment Operating Profit................ $ 8.6 $ 5.9 $ 10.4 $ 5.8 $ 6.0
====== ====== ====== ===== =====
Sales Volumes (millions of gallons):
Fuels, primarily diesel......................... 180.8 148.3 170.0 84.0 87.4
Lubricants...................................... 2.3 2.0 2.1 1.1 1.0
Capital Expenditures.............................. $ 4.2 $ 1.5 $ 3.2 $ 1.9 $ 1.0
</Table>
C-8
Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 2001
Segment operating profit for Marine Services improved by $0.2 million
during the six months ended June 30, 2001, primarily due to higher fuel sales
volumes and service revenues. Included in the six month period ended June 30,
2000 was other income of $1.2 million from settlement of a service contract.
Excluding this income, operating profit for the six months ended June 30, 2001
improved by 30%, or $1.4 million.
Revenues increased $8.5 million from the six month period ended June 30,
2000, reflecting higher fuel prices, fuel sales volumes, and services revenues.
Sales volumes and services revenues increased from the six month period ended
June 30, 2000, reflecting an increase in customer exploration and development
activities in the U.S. Gulf of Mexico. The increase in costs of sales also
reflected higher fuel sales volumes and prices.
The Marine Services segment's business is largely dependent upon the volume
of oil and gas drilling, workover and construction and the level of seismic
activity in the U.S. Gulf of Mexico.
Year Ended December 31, 1999 Compared to Year Ended December 31, 2000
Segment operating profit for Marine Services improved 76% to a record $10.4
million in 2000 from $5.9 million in 1999, primarily due to higher fuel sales
volumes and service revenues. The Marine Services business was positively
impacted in 2000 by the recovery in drilling activity during the latter half of
1999. The higher fuel sales volumes and service revenues reflected increased
customer exploration and development activities in the U.S. Gulf of Mexico,
compared with 1999. The average number of drilling rigs served by our terminals
increased from 22 rigs in 1999 to 29 rigs in 2000. Operating revenues increased
67% to $185.2 million in 2000 from $111.2 million in 1999, reflecting higher
fuel volumes and prices, and service revenues. The increase in cost of sales
also reflected higher fuel sales volumes and prices. In 2000, we realized other
income of $1.2 million from settlement of a service contract and $0.4 million
from the sale of excess real estate. Operating expenses in 2000, as compared to
1999, increased due mainly to the higher sales activities.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1999
Segment operating profit decreased $2.7 million to $5.9 million during
1999. The lower operating profit for 1999 was primarily due to the 18% decrease
in fuel sales volumes to 148.3 million gallons in 1999. The segment's operations
were negatively impacted by the low level of drilling activity in the U.S. Gulf
of Mexico during the first half of 1999. However, the business climate improved
during the latter half of 1999 with the number of drilling rigs served by our
terminals increasing to a high of 35 as compared to eight in March 1999. Our
recovery in the last half of 1999 was due in part to the increased drilling
activity and better cost management.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses increased by $3.7 million during the
six months ended June 30, 2001, as compared to the same period in 2000. The
increase was primarily due to higher employee costs and professional fees.
General and administrative expenses were $40.3 million in 2000, compared
with $34.1 million in 1999 and $19.7 million in 1998. The $6.2 million increase
in 2000 was primarily due to higher employee costs associated with business
development and growth. The $14.4 million increase in 1999 was primarily due to
costs related to the implementation of an integrated enterprise-wide information
system and higher employee costs.
INTEREST AND FINANCING COSTS
Interest and financing costs, net of capitalized interest, decreased by
$3.8 million during the six months ended June 30, 2001, as compared to the same
period in 2000, reflecting the impact of capitalized
C-9
interest on major projects during the six months ended June 30, 2001.
Capitalized interest amounted to $2.5 million in the six months ended June 30,
2001, while interest capitalized in the same period in 2000 was less than
$0.1 million. Before capitalized interest, interest and financing costs
decreased $1.3 million during the six months ended June 30, 2001 reflecting
lower interest rates on floating rate debt.
Interest and financing costs were $32.7 million in 2000, compared with
$37.6 million in 1999 and $25.2 million in 1998. The $4.9 million decrease in
2000 primarily reflected lower borrowings. Proceeds from the sales of our
exploration and production operations were used to repay debt in December 1999
and in March 2000. The benefits from these debt repayments were partly offset by
higher interest rates on variable-rate debt and additional borrowings to finance
an increase in working capital. We financed the increases in inventories and
receivables, which arose from higher crude oil and product inventory volumes,
petroleum prices and sales activities, by borrowings and trade payables.
Interest and financing costs increased in 1999, as compared to 1998, primarily
due to a full year's interest on the senior subordinated notes that we issued to
finance the Washington and Hawaii refinery acquisitions in 1998.
Corporate interest expense allocated to discontinued operations was based
on net assets and amounted to $10.6 million and $7.8 million in 1999 and 1998,
respectively (see Note E of Notes to Consolidated Financial Statements of Tesoro
Petroleum Corporation in the Company's Form 10-K for the year December 31,
2000). Interest and financing costs reported in our Statements of Consolidated
Operations are after the allocation to discontinued operations.
INTEREST INCOME
Interest income for the six months ended June 30, 2001 decreased by $1.3
million from the six month period ended June 30, 2000 when a portion of the
proceeds from the December 1999 sales of exploration and production operations
was temporarily invested. A substantial portion of those proceeds was used to
repay debt in March 2000.
Interest income totaled $2.8 million in 2000, compared with $1.2 million in
1999 and $2.0 million in 1998. The $1.6 million increase in 2000 primarily
reflected the temporary investment of a portion of the proceeds from the
December 1999 sales of exploration and production operations.
OTHER EXPENSES
Other expenses totaled $5.8 million in 2000, compared with $9.3 million in
1999 and $23.3 million in 1998. The $3.5 million decrease in 2000 primarily
reflected a $3.0 million provision for settlement of claims by the State of
Hawaii in 1999. The $14.0 million decrease in 1999 was primarily due to the
$19.1 million charge recorded in 1998 for special incentive compensation
resulting from our common stock market price achieving a specific performance
target (see Note L of Notes to Consolidated Financial Statements of Tesoro
Petroleum Corporation in the Company's Form 10-K for the year December 31,
2000).
INCOME TAX PROVISION
The increase of $18.8 million in the income tax provision during the six
months ended June 30, 2001, as compared to the same period in 2000, primarily
reflected the increase in pretax earnings. The combined federal and state
effective income tax rate was approximately 40% in the six months ended June 30,
2001 and approximately 39% in the same period in 2000.
Income taxes on continuing operations increased to $50.2 million in 2000,
from $19.0 million in 1999 and $4.5 million in 1998, primarily due to the higher
pretax earnings from continuing operations. Our combined federal and state
effective income tax rate increased to 40% in 2000 from 37% in both 1999 and
1998. The effective state tax rate increased from 1% in 1998 to 3% in 1999 and
2000 due to a larger apportionment of taxable income to states with higher
income tax rates. The 1999 tax rate benefited from amendments to prior year
returns. See Note G of Notes to Consolidated Financial Statements of Tesoro
Petroleum Corporation for further information on income taxes and Note E for
income taxes related to discontinued operations in the Company's Form 10-K for
the year December 31, 2000.
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DISCONTINUED OPERATIONS
Earnings from discontinued operations in 1999 of $42.8 million (net of
income tax expense of $29.6 million), or $1.30 per diluted share, included $3.7
million of aftertax operating results and a $39.1 million aftertax gain on the
sale of these operations. In 1998, discontinued operations had a net loss of
$22.6 million, or $0.76 per diluted share, which included aftertax write-downs
of oil and gas properties of $43.2 million and aftertax income of $13.4 million
for the receipt of contingency funds from the entity operating a field in which
we owned an interest. See Note E of Notes to Consolidated Financial Statements
of Tesoro Petroleum Corporation in the Company's Form 10-K for the year December
31, 2000 for further information related to discontinued operations.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
Our primary sources of liquidity are our cash flows from operations and
borrowing availability under revolving lines of credit, including the
acquisition debt discussed below. We expect capital requirements to include
capital expenditures, working capital and debt service. We believe available
capital resources will be adequate to meet our capital requirements.
We operate in an environment where our liquidity and capital resources are
impacted by changes in the supply of and demand for crude oil and refined
petroleum products, market uncertainty and a variety of additional factors
beyond our control. These factors include:
- changes in general economic conditions;
- the timing and extent of changes in commodity prices and underlying
demand for our products;
- the availability and costs of crude oil, other refinery feedstocks and
refined products;
- the direct or indirect effects on our business resulting from recent
terrorist incidents;
- political developments in foreign countries;
- changes in our inventory levels;
- changes in the cost or availability of third-party vessels, pipelines and
other means of transporting feedstocks and products;
- changes in fuel and utility costs for our facilities;
- disruptions due to equipment interruption or failure at our or
third-party facilities;
- execution of planned capital projects;
- our ability to successfully integrate acquisitions, including the
recently acquired North Dakota System (excluding the Pipeline System) and
Utah System, as well as to acquire and then successfully integrate the
Pipeline System;
- adverse changes in the credit ratings assigned to our trade credit and
debt instruments;
- 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;
- adverse rulings, judgments, or settlements in litigation or other legal
or tax matters, including unexpected environmental remediation costs in
excess of any reserves;
- actions of customers and competitors;
- weather conditions affecting our operations or the areas in which our
products are marketed;
- earthquakes or other natural disasters affecting operations; and
- the condition of the capital markets.
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Our future capital expenditures, as well as borrowings under our new senior
secured credit facility and other sources of capital, will be affected by these
conditions.
CAPITALIZATION
At June 30, 2001, our debt to capitalization ratio was 33% compared with
32% at year-end 2000, reflecting increased borrowings under our prior credit
facility we used primarily to fund working capital and capital expenditures. Pro
forma for the Acquisitions and borrowings under our new senior secured credit
facility, our debt to capitalization ratio at June 30, 2001 was 62%.
Our new senior secured credit facility and our senior subordinated notes
impose various restrictions and covenants on us that could potentially limit our
ability to respond to market conditions, to raise additional debt or equity
capital, or to take advantage of business opportunities. Our new senior secured
credit facility and our existing senior subordinated notes are guaranteed by
substantially all of our active domestic subsidiaries.
The indenture for our senior subordinated notes contain covenants that
restrict, 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;
- enter into asset sales;
- enter into transactions with affiliates;
- incur liens on assets to secure certain debt;
- engage in certain business activities; and
- engage in certain mergers or consolidations and transfers of assets.
The indenture limits our restricted subsidiaries' ability to create restrictions
on making certain payments and distributions. In addition, our new senior
secured credit facility contains other and more restrictive covenants, including
the prohibition on making voluntary or optional prepayments of certain of our
indebtedness, including the notes. Under our new senior secured credit facility,
we are required to comply with specified financial covenants, including
maintaining specified levels of consolidated leverage and interest and fixed
charge coverages and limiting our debt to capital ratio. These financial ratios
become more restrictive over the life of our new senior secured credit facility.
NEW SENIOR SECURED CREDIT FACILITY
On September 6, 2001, we entered into a new senior secured credit facility,
arranged by Lehman Brothers Inc. in the amount of $1.0 billion, in connection
with the funding of the acquisitions of the North Dakota System and the Utah
System. Our new senior secured credit facility, as amended, consists of a $175
million revolving credit facility (with a $90 million sublimit for letters of
credit), an $85 million tranche A term loan, a $90 million delayed draw term
loan (to be used solely to fund the purchase of the Pipeline System), a $450
million tranche B term loan and a $200 million capital markets term loan. Our
new senior secured credit facility is guaranteed by substantially all of our
active domestic subsidiaries and is secured by substantially all of our material
present and future assets as well as all material present and future assets of
our domestic subsidiaries (with certain exceptions for pipeline, retail and
marine services assets) and is additionally secured by a pledge of all of the
stock of all current active and future domestic subsidiaries and 66% of the
stock of our current and future foreign subsidiaries.
Borrowings under our senior secured credit facility bear interest at either
a base rate or a eurodollar rate, plus an applicable margin. The initial
applicable margin for the tranche A term loan, the delayed draw term loan and
the revolving credit facility is 1.25% in the case of the base rate and 2.25% in
the case
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of the eurodollar rate. Additionally, the tranche B eurodollar rate will not be
deemed to be less than 3.0%. The initial applicable margin for the tranche B
term loan is 1.75% in the case of the base rate and 2.75% in the case of the
eurodollar rate. The initial applicable margin for the capital markets term loan
is 1.50% in the case of the base rate and 2.50% in the case of the eurodollar
rate. These initial applicable margins are the highest margins applicable to the
respective base and eurodollar rates and will vary in relation to ratios of our
consolidated total debt to consolidated EDITDA, as determined under our senior
secured credit facility. In addition, at any time during which the senior
secured credit facility is rated at least BBB- by Standard & Poor's Rating
Services and Baa3 by Moody's Investors Service, Inc., each applicable margin,
other than in one instance with respect to the tranche B term loan, will be
reduced by 0.125%.
Our ability to make scheduled payments of principal of, or to pay the
interest or liquidated damages, if any, on, or to refinance, indebtedness
or to fund planned capital expenditures will depend upon our future performance,
which, in turn, is subject to general economic, financial, competitive and other
factors that are beyond our control. Based on current operations, we expect the
capacity under our new senior secured credit facility, together with
internally-generated cash flows, to be sufficient to fund capital expenditures,
working capital requirements and other corporate purposes for the forseeable
future.
CONVERSION OF PREFERRED STOCK
On July 1, 2001, our Premium Income Equity Securities ("PIES(SM)"),
representing fractional interests of our 7.25% Manditorily Convertible Preferred
Stock, automatically converted into 10,350,000 shares of our common stock.
Following conversion, we had approximately 41.6 million shares of common stock
outstanding. This conversion saves us approximately $12 million in annual
preferred dividends. We paid the final quarterly cash dividends on the PIES(SM)
on July 2, 2001.
COMMON STOCK REPURCHASE PROGRAM
In February 2000, our board of directors authorized the repurchase of up to
3 million shares of our common stock, which represented approximately 9% of the
shares then outstanding. Under the program, we may make repurchases from time to
time in the open market and through privately-negotiated transactions. Purchases
depend on price, market conditions and other factors and have been made
primarily from internally-generated cash flows. We may use the stock to meet
employee benefit plan requirements and other corporate purposes. Through June
30, 2001, we repurchased 1,627,400 shares of common stock. Since that date we
repurchased an additional 304,000 shares of our common stock at an average cost
of $11.50 per share, or an aggregate of approximately $3.5 million.
CAPITAL SPENDING
For the year 2001, our total capital program is approximately $195 million,
primarily for manufacturing improvements and retail marketing expansion.
Refinery projects are planned to total approximately $121 million, including
completion of the heavy oil conversion project and other economic projects,
approximately $28 million for sustaining capital, approximately $8 million for
environmental and approximately $4 million for health, safety and other
projects. We plan to spend approximately $59 million to further expand our
retail marketing, which includes construction of new Mirastar stations under the
agreement with Wal-Mart, construction of Tesoro-owned and operated stations, and
expansion of our branded jobber network. Our Marine Services capital
expenditures are planned to be approximately $5 million. Other capital is
budgeted at $10 million, primarily for information systems to support the
expanded retail program and other upgrades. We plan to fund our capital program
for the remainder of 2001 with internally-generated cash flows from operations
and borrowings under our new senior secured credit facility.
During the six months ended June 30, 2001, our capital expenditures totaled
$82 million, which included $35 million for the heavy oil conversion project and
approximately $13 million for the Mirastar
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and other retail marketing programs. Other capital spending of approximately
$34 million during the six months ended June 30, 2001 was primarily for natural
gas-fueled generators, modernization of refinery control systems and other
system upgrades.
Based on our preliminary projections, our capital expenditures (including
capital expenditures related to assets acquired in the Acquisitions) for 2002
are estimated to range from approximately $150 million to $175 million.
MAJOR MAINTENANCE COSTS
We completed our scheduled turnaround of the Alaska refinery in the second
quarter of 2001 at a cost of approximately $10 million. We have scheduled a
turnaround of certain processing units at the Washington refinery with an
estimated cost of approximately $20 million in the first quarter of 2002.
Amortization of turnaround costs, other major maintenance projects and catalysts
totaled $11 million in the six months ended June 30, 2001. Amortization of these
costs are projected to total approximately $22 million in 2001, including
approximately $1 million for the Acquisitions.
CASH FLOW SUMMARY
Components of our cash flows are set forth below:
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30,
----------------------
2000 2001
---------- ---------
(DOLLARS IN MILLIONS)
CASH FLOWS FROM (USED IN):
Operating Activities........................................ $ (22.7) $ 23.2
Investing Activities........................................ (21.9) (79.4)
Financing Activities........................................ (88.6) 44.0
------- ------
Decrease in Cash and Cash Equivalents............. $(133.2) $(12.2)
======= ======
</Table>
Net cash from operating activities during the six months ended June 30,
2001 totaled $23 million, compared to $23 million used in operating activities
in the same period in 2000. This improvement was primarily due to higher
earnings before depreciation and amortization as well as a reduction in
operating cash flows used for working capital. Net cash used in investing
activities of $79 million in the six months ended June 30, 2001 included capital
expenditures of $82 million, partly offset by proceeds from sales of assets. Net
cash from financing activities of $44 million in the six months ended June 30,
2001 included net borrowings of $49 million under our prior credit facility,
partly offset by payment of $6 million of dividends on PIES(SM). Gross
borrowings under revolving credit lines amounted to $466 million and repayments
amounted to $417 million during the six months ended June 30, 2001. Working
capital totaled $303 million at June 30, 2001 compared to $248 million at
year-end 2000.
ENVIRONMENTAL AND OTHER
Extensive federal, state and local environmental laws and regulations
govern our operations. 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. We are currently
involved in remedial responses and have incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of our owned
properties. At June 30, 2001, our accruals for environmental expenses totaled
approximately $15 million. Including the Acquisitions, our accruals for
environmental expenses have increased to $32 million. Based on currently
available information, including the participation of other parties or former
owners in remediation actions, we believe these accruals are adequate.
C-14
We continue to evaluate certain new revisions to the Clean Air Act
regulations which will require a reduction in the sulfur content in gasoline
starting January 1, 2004. To meet this revised gasoline standard at our
refineries, we expect to make capital improvements (including capital
improvements on assets acquired in the Acquisitions) of approximately $65
million in the aggregate through 2006 and $15 million in years after 2006.
The U.S. Environmental Protection Agency also has announced new standards
that will require a reduction in sulfur content in diesel fuel manufactured for
on-road consumption. In general, the new diesel fuel standards will become
effective on June 1, 2006. We expect to spend approximately $35 million in
capital improvements (including capital improvements on assets acquired in the
Acquisitions) through 2006 and $30 million in years after 2006 to meet the new
diesel fuel standards.
We expect to spend approximately $35 million in the aggregate in capital
improvements at our refineries (including the North Dakota and Utah refineries)
over the next four years to comply with the second phase of Maximum Achievable
Control Technologies ("Refinery MACT II") which was signed into law in January
2001. We expect that the Refinery MACT II regulations will require new emission
controls at certain processing units at several of our refineries. We are
currently evaluating a selection of control technologies to assure operations
flexibility and compatibility with long-term air emission reduction goals. As an
alternative to making capital improvements of $35 million solely to meet the
Refinery MACT II requirements, we are evaluating making capital improvements of
$50 million to meet both the Refinery MACT II requirements and long-term
reduction goals for sulfur emissions.
We anticipate we will make additional capital improvements (including
capital improvements on assets acquired in the Acquisitions) of approximately $8
million in 2001 and $10 million in 2002, primarily for improvements to storage
tanks, tank farm secondary containment and pipelines. During the six months
ended June 30, 2001, we spent approximately $3 million on environmental capital
projects.
Conditions that require additional expenditures may transpire for various
of our sites, including, but not limited to, our refineries, tank farms, retail
gasoline stations (operating and closed locations) and petroleum product
terminals, and for compliance with the Clean Air Act and other state and federal
requirements. We cannot currently determine the amount of these future
expenditures.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, we adopted Statement of Financial Accounting
Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by SFAS No. 138. The adoption of SFAS No. 133 did not
have a significant impact on our financial condition, results of operations or
cash flows.
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Intangible
Assets". SFAS No. 141 requires the purchase method of accounting for all
business combinations initiated after June 30, 2001 and that certain acquired
intangible assets in a business combination be recognized as assets separate
from goodwill. SFAS No. 142 requires that goodwill and other intangibles that
are determined to have an indefinite life are no longer to be amortized but are
to be tested for impairment at least annually. SFAS No. 142 requires an
impairment test related to the carrying values of existing goodwill be completed
within the first six months of 2002. Impairment losses on existing goodwill, if
any, would be recorded as the cumulative effect of a change in accounting
principle as of the beginning of 2002. SFAS Nos. 141 and 142 will apply to the
Acquisitions. We are currently evaluating the impact these standards will have
on our future results of operations and financial condition.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present
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value each period. SFAS No. 143 is effective for us beginning January 1, 2003
with earlier adoption encouraged. We are currently evaluating the impact the
standard will have on our future results of operations and financial condition.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS No. 144 retains the
requirement to recognize an impairment loss only where the carrying value of a
long-lived asset is not recoverable from its undiscounted cash flows and to
measure such loss as the difference between the carrying amount and fair value
of the asset. SFAS No. 144, among other things, changes the criteria that have
to be met to classify an asset as held-for-sale and requires that operating
losses from discontinued operations be recognized in the period that the losses
are incurred rather than as of the measurement date. SFAS No. 144 is effective
for us beginning January 1, 2002 with earlier adoption encouraged. We are
currently evaluating the impact the standard will have on our future results of
operations and financial condition.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary sources of our market risk are changes in commodity prices and
interest rates. We have a risk management committee responsible for overseeing
energy risk management activities.
COMMODITY PRICE RISKS
Our Refining and Marketing earnings and cash flows from operations are
dependent upon the margin above fixed and variable expenses (including the costs
of crude oil and other feedstocks) 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, including the
demand for crude oil, gasoline and other refined products, which in turn depend
on, among other factors, changes in the economy, the level of foreign and
domestic production of crude oil and refined products, worldwide political
conditions, the availability of imports of crude oil and refined products, the
marketing of alternative and competing fuels and the extent of government
regulations. The prices we receive for our refined products are also affected by
local factors such as local market conditions and the level of operations of
other refineries in our markets.
The prices at which we can 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 prices of
gasoline and other refined products. The timing of the relative movement of the
prices, however, can impact profit margins which could significantly affect our
earnings and cash flows. In addition, crude oil supply contracts generally are
short-term in nature with market-responsive pricing provisions. We normally
purchase our refinery feedstocks prior to selling the refined products
manufactured. 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 resale to customers. Price level
changes during the periods between purchasing and selling these products could
have a significant effect on our financial results.
We maintain inventories of crude oil, intermediate products and refined
products, the values of which are subject to fluctuations in market prices. At
June 30, 2001 and December 31, 2000, our inventories of refinery feedstocks and
refined products totaled 13.2 million barrels and 11.9 million barrels,
respectively. During 2000, inventory levels increased 3.3 million barrels over
year-end 1999 levels at an average cost of $29.82 per barrel. Sales that result
in a reduction in inventories below 11.9 million barrels during 2001 would have
a per barrel cost of sales equal to the sum of $29.82 plus the cost of
transportation to market. This amount could exceed the year-to-date average
costs of sales in 2001. The average cost of refinery throughput in June 2001 was
approximately $27.70 per barrel, or $2.12 per barrel lower than the cost of the
2000 incremental inventory layer. The average costs of our refinery feedstocks
and refined product inventories as of June 30, 2001 and December 31, 2000 were
$21.50 per barrel and $20.79 per barrel,
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respectively. If market price levels decline from current levels to a level
below the average cost of these inventories, we may be required to write down
the carrying value of our inventory.
In connection with the Acquisitions, we purchased an aggregate of
approximately 2.6 million barrels of refinery feedstocks and refined products
inventory in the North Dakota System and the Utah System at an average cost of
$31.34 per barrel.
We periodically enter into derivative type arrangements on a limited basis,
as part of our program to acquire refinery feedstocks at reasonable costs and to
manage margins on certain refined product sales. We also engage in limited
non-hedging activities which are marked to market with changes in the fair
market value of the derivatives recognized in earnings. We believe any potential
adverse impact from these activities would not result in a material adverse
effect on our business, financial condition and results of operations. At June
30, 2001, we held exchange traded crude oil futures contracts to purchase
155,000 barrels in August 2001 at a weighted average price of $26.44 per barrel,
or a total of $4 million. We account for the contracts at market prices, and
these contracts had a total fair market value of $4 million at June 30, 2001.
INTEREST RATE RISK
We had $49 million of outstanding floating-rate debt under our new senior
secured credit facility and $307 million of fixed-rate debt at June 30, 2001.
The weighted-average interest rate on the floating-rate debt was 6.75% at June
30, 2001. The impact on annual cash flow of a 10% change in the floating rate
for our new senior secured credit facility (68 basis points) would be
approximately $0.3 million.
The fair market value of our fixed-rate debt at June 30, 2001 was
approximately $12 million less than its book value of $307 million, based on
recent transactions and bid quotes for our senior subordinated notes.
Pro forma for the Transactions, we had approximately $682 million of
outstanding floating-rate debt under our new senior secured credit facility and
$507 million of fixed-rate debt at June 30, 2001. The pro forma weighted-
average interest rate on the floating-rate debt as of October 16, 2001 was
5.4%. The pro forma impact on annual cash flow of a 10% change in the floating-
rate of our new senior secured credit facility (54 basis points) would be
approximately $3.7 million.
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INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
2.1 Asset Purchase Agreement, dated July 16, 2001, by and among
the Company, BP Corporation North America Inc. and Amoco Oil
Company relating to the purchase and sale of the Mandan
refinery and related assets (incorporated by reference to
Exhibit 2.1 of the Current Report on Form 8-K dated August
27, 2001, SEC File No. 1-3473). Pursuant to Item 601(b)(2)
of Regulation S-K, certain schedules and similar attachments
to this Asset Purchase Agreement have not been filed with this
exhibit. The schedules contain various items relating to the
assets acquired and the representations and warranties made by
the parties to the Asset Purchase Agreement. The Company
agrees to furnish supplementally any omitted schedule to the
SEC upon request.
2.2 Asset Purchase Agreement, dated July 16, 2001, by and among
the Company, BP Corporation North America Inc. and Amoco Oil
Company relating to the purchase and sale of the Salt Lake
City refinery and related assets (incorporated by reference to
Exhibit 2.2 of the Current Report on Form 8-K dated August
27, 2001, SEC File No. 1-3473). Pursuant to Item 601(b)(2)
of Regulation S-K, certain schedules and similar attachments
to this Asset Purchase Agreement have not been filed with this
exhibit. The schedules contain various items relating to the
assets acquired and the representations and warranties made by
the parties to the Asset Purchase Agreement. The Company
agrees to furnish supplementally any omitted schedule to the
SEC upon request.
23.1 Consent of Ernst & Young LLP, Independent Auditors, dated
October 22, 2001.
</Table>