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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(MARK ONE)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ........... TO ...........
COMMISSION FILE NUMBER 1-3473
TESORO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-0862768
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 CONCORD PLAZA DRIVE, SAN ANTONIO, TEXAS 78216-6999
(Address of principal executive offices) (Zip Code)
210-828-8484
(Registrant's telephone number, including area code)
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--- ---
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There were 41,356,848 shares of the registrant's Common Stock
outstanding at October 31, 2001.
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TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - September 30, 2001 and December 31, 2000.................. 3
Condensed Statements of Consolidated Operations - Three Months and Nine Months
Ended September 30, 2001 and 2000................................................................. 4
Condensed Statements of Consolidated Cash Flows - Nine Months Ended
September 30, 2001 and 2000....................................................................... 5
Notes to Condensed Consolidated Financial Statements.............................................. 6
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations..................................................................................... 14
Item 3. Quantitative and Qualitative Disclosures About Market Risk........................................ 27
PART II. OTHER INFORMATION
Item 1. Legal Proceedings................................................................................. 28
Item 2. Changes in Securities and Use of Proceeds......................................................... 28
Item 6. Exhibits and Reports on Form 8-K.................................................................. 28
SIGNATURES................................................................................................... 30
EXHIBIT INDEX................................................................................................ 31
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
September 30, December 31,
2001 2000
------------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ........................................................ $ 1.2 $ 14.1
Receivables, less allowance for doubtful accounts ................................ 479.2 334.5
Inventories ...................................................................... 396.6 274.3
Prepayments and other ............................................................ 7.1 7.3
----------- -----------
Total Current Assets ........................................................... 884.1 630.2
----------- -----------
PROPERTY, PLANT AND EQUIPMENT
Refining and Marketing ........................................................... 1,589.9 991.1
Marine Services .................................................................. 52.4 50.3
Corporate ........................................................................ 47.1 25.1
----------- -----------
1,689.4 1,066.5
Less accumulated depreciation and amortization ................................... 317.1 285.1
----------- -----------
Net Property, Plant and Equipment .............................................. 1,372.3 781.4
----------- -----------
GOODWILL ............................................................................ 112.4 63.2
----------- -----------
OTHER ASSETS ........................................................................ 170.5 68.8
----------- -----------
Total Assets ................................................................. $ 2,539.3 $ 1,543.6
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable ................................................................. $ 339.1 $ 281.6
Accrued liabilities .............................................................. 131.1 97.0
Current maturities of debt and other obligations ................................. 16.6 3.8
----------- -----------
Total Current Liabilities ...................................................... 486.8 382.4
----------- -----------
DEFERRED INCOME TAXES ............................................................... 124.6 107.2
----------- -----------
OTHER LIABILITIES ................................................................... 107.4 77.3
----------- -----------
DEBT AND OTHER OBLIGATIONS .......................................................... 1,068.5 306.8
----------- -----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, no par value; authorized 5,000,000 shares; 7.25% Mandatorily
Convertible Preferred Stock, 103,500 shares issued
and outstanding in 2000 ........................................................ -- 165.0
Common stock, par value $0.16-2/3; authorized 100,000,000 shares;
43,371,825 shares issued (32,739,592 in 2000) .................................. 7.2 5.4
Additional paid-in capital ....................................................... 448.5 280.0
Retained earnings ................................................................ 317.9 239.9
Treasury stock, 2,035,836 common shares (1,920,281 in 2000), at cost ............. (21.6) (20.4)
----------- -----------
Total Stockholders' Equity ..................................................... 752.0 669.9
----------- -----------
Total Liabilities and Stockholders' Equity ................................... $ 2,539.3 $ 1,543.6
=========== ===========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
3
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(UNAUDITED)
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
REVENUES
Refining and Marketing ................................... $ 1,366.4 $ 1,347.4 $ 3,799.5 $ 3,535.6
Marine Services .......................................... 45.6 47.2 139.4 132.5
----------- ----------- ----------- -----------
Total Revenues ........................................ 1,412.0 1,394.6 3,938.9 3,668.1
----------- ----------- ----------- -----------
COSTS OF SALES AND OPERATING EXPENSES
Refining and Marketing ................................... 1,268.3 1,275.9 3,563.7 3,374.8
Marine Services .......................................... 41.7 43.6 128.1 121.9
Depreciation and amortization ............................ 12.0 11.0 33.6 30.8
----------- ----------- ----------- -----------
Total Costs of Sales and Operating Expenses ........... 1,322.0 1,330.5 3,725.4 3,527.5
----------- ----------- ----------- -----------
SEGMENT OPERATING PROFIT ................................... 90.0 64.1 213.5 140.6
General and administrative expenses ........................ (16.1) (11.4) (37.4) (29.0)
Interest and financing costs, net of capitalized interest .. (17.3) (7.7) (31.4) (25.6)
Interest income ............................................ 0.1 0.4 0.6 2.2
Other expenses ............................................. (2.0) (2.0) (5.1) (5.4)
----------- ----------- ----------- -----------
EARNINGS BEFORE INCOME TAXES .............................. 54.7 43.4 140.2 82.8
Income tax provision ....................................... 21.9 18.4 56.2 33.9
----------- ----------- ----------- -----------
NET EARNINGS ............................................... 32.8 25.0 84.0 48.9
Preferred dividend requirements ............................ -- 3.0 6.0 9.0
----------- ----------- ----------- -----------
NET EARNINGS APPLICABLE TO COMMON STOCK .................... $ 32.8 $ 22.0 $ 78.0 $ 39.9
=========== =========== =========== ===========
NET EARNINGS PER SHARE
Basic .................................................... $ 0.79 $ 0.71 $ 2.26 $ 1.27
=========== =========== =========== ===========
Diluted .................................................. $ 0.79 $ 0.60 $ 2.00 $ 1.17
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES -
BASIC .................................................... 41.4 30.8 34.5 31.4
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON AND
POTENTIALLY DILUTIVE COMMON SHARES -
DILUTED .................................................. 41.7 41.4 41.9 41.9
=========== =========== =========== ===========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(UNAUDITED)
(IN MILLIONS)
Nine Months Ended
September 30,
--------------------------
2001 2000
----------- -----------
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings ..................................................................... $ 84.0 $ 48.9
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation and amortization .................................................. 35.6 32.6
Amortization of refinery turnarounds and other non-cash charges ................ 24.9 17.0
Deferred income taxes .......................................................... 17.4 13.2
Changes in operating assets and liabilities:
Receivables .................................................................. (136.7) (68.4)
Inventories .................................................................. 0.7 (93.1)
Accounts payable and accrued liabilities ..................................... 57.5 106.9
Other assets and liabilities ................................................. (7.1) (3.6)
----------- -----------
Net cash from operating activities ......................................... 76.3 53.5
----------- -----------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures ............................................................. (151.7) (42.7)
Acquisitions ..................................................................... (669.7) --
Other ............................................................................ (15.4) 1.8
----------- -----------
Net cash used in investing activities ...................................... (836.8) (40.9)
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CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Net borrowings under revolving credit facilities ................................. 43.0 --
Issuance of term loans ........................................................... 735.0 --
Repayments of other debt ......................................................... (0.9) (105.6)
Repurchases of Common Stock ...................................................... (3.5) (15.5)
Payment of dividends on Preferred Stock .......................................... (9.0) (9.0)
Financing costs and other ........................................................ (17.0) 0.2
----------- -----------
Net cash from (used in) financing activities ............................... 747.6 (129.9)
----------- -----------
DECREASE IN CASH AND CASH EQUIVALENTS ............................................... (12.9) (117.3)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ...................................... 14.1 141.8
----------- -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD ............................................ $ 1.2 $ 24.5
=========== ===========
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of capitalized interest of $4.3 in 2001 and $0.2 in 2000 ...... $ 30.0 $ 17.4
=========== ===========
Income taxes paid ................................................................ $ 36.0 $ 13.6
=========== ===========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE A - BASIS OF PRESENTATION
The interim Condensed Consolidated Financial Statements and Notes thereto of
Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company"
or "Tesoro") have been prepared by management without audit pursuant to the
rules and regulations of the Securities and Exchange Commission ("SEC").
Accordingly, the accompanying financial statements reflect all adjustments that,
in the opinion of management, are necessary for a fair presentation of results
for the periods presented. Such adjustments are of a normal recurring nature. As
described in Note B, financial results of newly-acquired assets have been
included in Tesoro's consolidated results since the date of acquisition. The
Consolidated Balance Sheet at December 31, 2000 has been condensed from the
audited Consolidated Financial Statements at that date. Certain information and
notes normally included in financial statements prepared in accordance with
accounting principles generally accepted in the United States of America ("U.S.
GAAP") have been condensed or omitted pursuant to the SEC's rules and
regulations. However, management believes that the disclosures presented herein
are adequate to make the information not misleading. The accompanying Condensed
Consolidated Financial Statements and Notes should be read in conjunction with
the Consolidated Financial Statements and Notes thereto contained in the
Company's Annual Report on Form 10-K for the year ended December 31, 2000.
The preparation of the Company's Condensed Consolidated Financial Statements in
conformity with U.S. GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the periods. Actual results
could differ from those estimates. The results of operations for any interim
period are not necessarily indicative of results for the full year.
NOTE B - ACQUISITIONS
On September 6, 2001, the Company acquired two refineries in North Dakota and
Utah and related storage, distribution and retail assets from certain affiliates
of BP p.l.c. The acquired assets include a 60,000 barrels per day ("bpd")
refinery in Mandan, North Dakota and a 55,000 bpd refinery in Salt Lake City,
Utah. The acquired assets also include related bulk storage facilities, eight
product distribution terminals, and retail assets which consist of 43 retail
stations and contracts to supply a jobber network of over 290 retail stations.
The Company paid $665.8 million in cash (including $82.2 million for hydrocarbon
inventories) for these assets. The purchase price was determined as part of a
competitive bid process. In addition, the Company incurred direct costs related
to this transaction of $3.9 million.
On November 1, 2001, the Company purchased the North Dakota-based,
common-carrier crude oil pipeline and gathering system ("Pipeline System") from
certain affiliates of BP p.l.c. The Pipeline System is the primary crude supply
carrier for the Company's Mandan, North Dakota refinery. The purchase price of
the Pipeline System was $90.1 million. The Pipeline System will be accounted for
as a purchase in the fourth quarter of 2001. The purchase of the Pipeline System
and the September 6, 2001 acquisition of the North Dakota and Utah refineries
and related storage, distribution and retail assets are collectively referred to
as "the Acquisitions." The Acquisitions enable the Company to increase the size
and scope of its operations, diversify its earnings and geographic exposure, and
build a platform for additional growth.
In connection with the Acquisitions, Tesoro assumed certain liabilities and
obligations (including costs associated with transferred employees and
environmental matters) related to the acquired assets, subject to specified
levels of indemnification. This includes, subject to certain exceptions, certain
of the sellers' obligations, liabilities, costs and expenses for violations of
health, safety and environmental laws relating to the assets, including certain
known and unknown obligations, liabilities, costs and expenses arising or
incurred prior to, on or after the closing date. In addition, the Company has
agreed to indemnify the sellers for all losses of any kind incurred in
connection with or related to these assumed liabilities. See Note F for
environmental matters related to the Acquisitions.
Under Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations", the acquisitions of the North Dakota and Utah refineries and
related storage, distribution and retail assets were accounted for as
6
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
purchases, whereby the purchase price was allocated to the assets acquired and
liabilities assumed based upon their respective fair market values at the date
of acquisition. The accompanying financial statements reflect the preliminary
purchase price allocation, which remains subject to change pending completion of
independent appraisals and other evaluations. The accompanying financial
statements include the results of operations of the Acquisitions, excluding the
Pipeline System, since the date of acquisition.
The following unaudited pro forma financial information for the three months and
nine months ended September 30, 2001 and 2000 gives effect to (i) the
Acquisitions, (ii) the recent financing of the Company's new senior secured
credit facility, as amended, and (iii) the issuance of the 9-5/8% Senior
Subordinated Notes (see Note D below), as if each had occurred at the beginning
of the periods presented. This pro forma information is not necessarily
indicative of the results of future operations.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(In millions, except per share amounts)
Revenues .................................... $ 1,658.6 $ 1,807.0 $ 4,911.2 $ 4,737.4
Net earnings ................................ $ 41.2 $ 43.9 $ 125.1 $ 59.4
Net earnings per share:
Basic ................................... $ 1.00 $ 1.33 $ 3.45 $ 1.60
Diluted ................................. $ 0.99 $ 1.06 $ 2.99 $ 1.42
NOTE C - INVENTORIES
Components of inventories were as follows (in millions):
September 30, December 31,
2001 2000
------------ -----------
Crude oil and refined products, at LIFO .......... $ 363.0 $ 248.0
Fuel products, at FIFO ........................... 3.1 4.5
Merchandise and other ............................ 7.6 5.6
Materials and supplies ........................... 22.9 16.2
----------- -----------
Total inventories ............................ $ 396.6 $ 274.3
=========== ===========
NOTE D - CAPITALIZATION
SENIOR SECURED CREDIT FACILITY
In conjunction with the Acquisitions (see Note B), the Company entered into a
new $1.0 billion senior secured credit facility (the "Senior Secured Credit
Facility"). The Senior Secured Credit Facility replaced the Company's previous
unsecured credit facility which provided for $250 million in total commitments.
The Senior Secured Credit Facility, as amended, consists of a five-year $175
million revolving credit facility (with a $90 million sublimit for letters of
credit), a five-year $85 million tranche A term loan, a five-year $90 million
delayed draw term loan (used to fund the purchase of the Pipeline System), a
six-year $450 million tranche B term loan and a $200 million capital markets
term loan. On November 6, 2001, the Company repaid the $200 million capital
markets term loan with the proceeds of the 9-5/8% Senior Subordinated Notes, as
described below. The Senior Secured Credit Facility is guaranteed by
substantially all of the Company's active domestic subsidiaries and is secured
by substantially all of the Company's material present and future assets as well
as all material present and future assets of the Company's 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 the Company's current and
future foreign subsidiaries.
7
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The Senior Secured Credit Facility requires the Company to maintain specified
levels of interest and fixed charge coverages and sets limitations on the
Company's debt-to-capital and leverage ratios. It also contains other covenants
and restrictions customary in credit arrangements of this kind. The terms allow
for payment of cash dividends on the Company's Common Stock and repurchases of
shares of its Common Stock, not to exceed $15 million in any year.
Borrowings under the Senior Secured Credit Facility bear interest at either a
base rate (6.0% at September 30, 2001) or a eurodollar rate, plus an applicable
margin. The applicable margin at September 30, 2001 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 of the eurodollar rate. The
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. Additionally, the tranche B
eurodollar rate is deemed to be no less than 3.0%. The applicable margin for the
capital markets term loan was 1.50% over the base 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 the Company's consolidated total
debt to consolidated EBITDA, as defined in the 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 will be reduced by 0.125%. The
Company is also charged various fees and expenses in connection with the Senior
Secured Credit Facility, including commitment fees and various letter of credit
fees.
At September 30, 2001, the Company had $43 million in borrowings and $1 million
in letters of credit outstanding under the revolving credit facility. Total
unused credit available under the revolving credit facility at September 30,
2001 was $131 million.
DEBT AND MATURITIES
Debt and other obligations consisted of the following (in millions):
September 30, December 31,
2001 2000
------------- -----------
Revolving Credit Facilities ..................................... $ 43.0 $ --
Term Loans ...................................................... 735.0 --
9% Senior Subordinated Notes .................................... 297.5 297.3
Capital leases and other ........................................ 9.6 13.3
----------- -----------
Total debt and other obligations ............................ 1,085.1 310.6
Less current maturities ......................................... 16.6 3.8
----------- -----------
Debt and other obligations, less current maturities ......... $ 1,068.5 $ 306.8
=========== ===========
Aggregate maturities of debt and other obligations, including the delayed draw
term loan which was used to fund the Pipeline System on November 1, 2001 and the
revolving credit facility, for each of the five years following September 30,
2001 were as follows: 2002 - $26.7 million; 2003 - $38.4 million; 2004 - $40.9
million; 2005 - $40.7 million; and 2006 - $90.2 million. These maturities
reflect the refinancing of the capital markets term loan with the proceeds of
the 9-5/8% Senior Subordinated Notes, discussed below.
NOTES OFFERING
On November 6, 2001, the Company issued $215 million aggregate principal amount
of 9-5/8% Senior Subordinated Notes ("9-5/8% Senior Subordinated Notes") due
November 1, 2008 through a private offering eligible for Rule 144A. The 9-5/8%
Senior Subordinated Notes have a seven-year maturity with no sinking fund
requirements and are subject to optional redemption by the Company after four
years at declining premiums. The Company, for the first three years, may redeem
up to 35% of the aggregate principal amount at a redemption price of 109.625%.
The indenture for the 9-5/8% Senior Subordinated Notes contains covenants and
restrictions which are customary for notes of this nature. The proceeds from the
9-5/8% Senior Subordinated Notes were used to repay the indebtedness incurred
under the capital markets term loan, to pay accrued interest on the capital
markets term loan, to pay certain fees and expenses related to the 9-5/8% Senior
Subordinated Notes and for general corporate purposes. The 9-5/8% Senior
Subordinated Notes are guaranteed by substantially all of the Company's active
domestic subsidiaries.
8
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONVERSION OF PREFERRED STOCK
On July 1, 2001, all of the Company's outstanding Premium Income Equity
Securities ("PIES") automatically converted into 10,350,000 shares of Common
Stock. The final quarterly cash dividends on the PIES were paid on July 2, 2001.
COMMON STOCK REPURCHASES
In February 2000, the Company's Board of Directors authorized the repurchase of
up to 3 million shares of Tesoro Common Stock, which represented approximately
9% of the shares then outstanding. During 2001, the Company repurchased 304,000
shares of Common Stock at a weighted average price of $11.50 per share, or an
aggregate of $3.5 million, bringing the cumulative shares repurchased under the
program to 1,931,400. For information concerning restrictions on the repurchase
of Common Stock, see "Senior Secured Credit Facility" and "Notes Offering"
above.
NOTE E - OPERATING SEGMENTS
The Company's revenues are derived from two operating segments: (i) Refining and
Marketing and (ii) Marine Services. Management evaluates its segments based on
segment operating profit and EBITDA. Segment operating profit includes those
revenues and expenses that are directly attributable to management of the
respective segment. Income taxes, interest and financing costs, interest income
and corporate general and administrative expenses are not included in
determining segment operating profit. EBITDA represents earnings before interest
and financing costs, income taxes, and depreciation and amortization. While not
purporting to reflect any U.S. GAAP measurement of the Company's operations or
cash flows, EBITDA is used by management for additional analysis. This measure
may not be comparable to similarly titled measures used by other entities.
Operating segment EBITDA is equal to segment operating profit before
depreciation and amortization related to each segment.
For the periods presented, intersegment revenues were not significant. Segment
information is as follows (in millions):
Three Months Ended Nine Months Ended
September 30 September 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
REVENUES
Refining and Marketing:
Refined products ........................................... $ 1,265.9 $ 1,274.4 $ 3,548.7 $ 3,296.9
Other, primarily crude oil resales and merchandise ......... 100.5 73.0 250.8 238.7
Marine Services .............................................. 45.6 47.2 139.4 132.5
----------- ----------- ----------- -----------
Total Revenues ........................................... $ 1,412.0 $ 1,394.6 $ 3,938.9 $ 3,668.1
=========== =========== =========== ===========
SEGMENT OPERATING PROFIT
Refining and Marketing ....................................... $ 86.8 $ 61.2 $ 204.3 $ 131.9
Marine Services .............................................. 3.2 2.9 9.2 8.7
----------- ----------- ----------- -----------
Total Segment Operating Profit ........................... 90.0 64.1 213.5 140.6
Corporate and Unallocated Costs .............................. (35.3) (20.7) (73.3) (57.8)
----------- ----------- ----------- -----------
Earnings Before Income Taxes ................................. $ 54.7 $ 43.4 $ 140.2 $ 82.8
=========== =========== =========== ===========
9
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30 September 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
EBITDA
Refining and Marketing ............................. $ 98.1 $ 71.5 $ 235.8 $ 160.8
Marine Services .................................... 3.9 3.6 11.3 10.6
----------- ----------- ----------- -----------
Total Segment EBITDA ........................... 102.0 75.1 247.1 171.4
Corporate and Unallocated .......................... (17.3) (12.4) (39.9) (30.4)
----------- ----------- ----------- -----------
Total EBITDA ................................... 84.7 62.7 207.2 141.0
Depreciation and Amortization ...................... (12.7) (11.6) (35.6) (32.6)
Interest and Financing Costs ....................... (17.3) (7.7) (31.4) (25.6)
----------- ----------- ----------- -----------
Earnings Before Income Taxes ....................... $ 54.7 $ 43.4 $ 140.2 $ 82.8
=========== =========== =========== ===========
DEPRECIATION AND AMORTIZATION
Refining and Marketing ............................. $ 11.3 $ 10.3 $ 31.5 $ 28.9
Marine Services .................................... 0.7 0.7 2.1 1.9
Corporate .......................................... 0.7 0.6 2.0 1.8
----------- ----------- ----------- -----------
Total Depreciation and Amortization ............ $ 12.7 $ 11.6 $ 35.6 $ 32.6
=========== =========== =========== ===========
CAPITAL EXPENDITURES
Refining and Marketing ............................. $ 50.7 $ 17.4 $ 127.3 $ 38.4
Marine Services .................................... 1.3 0.3 2.3 2.2
Corporate .......................................... 17.8 1.5 22.1 2.1
----------- ----------- ----------- -----------
Total Capital Expenditures ..................... $ 69.8 $ 19.2 $ 151.7 $ 42.7
=========== =========== =========== ===========
Identifiable assets are those assets utilized by the segment. Corporate assets
include cash and other assets that are not directly associated with the
operations of a business segment.
September 30, December 31,
2001 2000
------------- ------------
IDENTIFIABLE ASSETS
Refining and Marketing ............................. $ 2,378.6 $ 1,405.4
Marine Services .................................... 72.5 76.8
Corporate .......................................... 88.2 61.4
----------- -----------
Total Assets ................................... $ 2,539.3 $ 1,543.6
=========== ===========
The Company is evaluating various strategic opportunities to capitalize on the
value of the Marine Services assets, including the possible sale of all or a
part of this business. Management is in the initial stages of its evaluation.
NOTE F - COMMITMENTS AND CONTINGENCIES
The Company is a party to various litigation and contingent loss situations,
including environmental and income tax matters, arising in the ordinary course
of business. The Company has made accruals in accordance with SFAS No. 5,
"Accounting for Contingencies," in order to provide for these matters. The
ultimate effects of these matters cannot be predicted with certainty, and
related accruals are based on management's best estimates, subject to future
developments. Although the resolution of certain of these matters could have a
material adverse effect on interim or annual results of operations, the Company
believes that the outcome of these matters will not result in a material adverse
effect on its liquidity or consolidated financial position.
ENVIRONMENTAL
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company 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.
10
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The Company is currently involved with the U.S. Environmental Protection Agency
("EPA") regarding a waste disposal site near Abbeville, Louisiana. The Company
has been named a potentially responsible party under the Federal Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund")
at this location. Although the Superfund law may impose joint and several
liability upon each party at the site, the extent of the Company's allocated
financial contributions for cleanup is expected to be de minimis based upon the
number of companies, volumes of waste involved and total estimated costs to
close the site. The Company believes, based on these considerations and
discussions with the EPA, that its liability at the Abbeville site will not
exceed $25,000.
The Company is currently involved in remedial responses and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its owned properties. At September 30, 2001, the Company's
accruals for environmental expenses totaled approximately $34 million, including
assumed known liabilities related to the Acquisitions (excluding the Pipeline
System) discussed in Note B. Based on currently available information, including
the participation of other parties or former owners in remediation actions, the
Company believes these accruals are adequate.
The Company continues 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, the Company
expects 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 EPA 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. The Company expects
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.
The Company expects to spend approximately $35 million in the aggregate in
capital improvements at its 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. Management expects that the Refinery MACT II regulations will
require new emission controls at certain processing units at several of the
Company's refineries. The Company is currently evaluating a selection of control
technologies to assure operations flexibility and compatibility with long-term
air emission reduction goals.
In connection with the Acquisitions, the Company assumed the sellers'
obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield Company. BP
recently entered into this consent decree for both the North Dakota and Utah
refineries for various alleged violations. As the new owner of these refineries,
the Company is required to address issues, including leak detection and repair,
flaring protection and sulfur recovery unit optimization. The Company estimates
it will spend $9 million at each of the North Dakota and Utah refineries to
comply with this consent decree. In addition, the Company has agreed to
indemnify the sellers for all losses of any kind incurred in connection with the
consent decree.
The Company anticipates it 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 nine months
ended September 30, 2001, the Company spent approximately $5 million on
environmental capital projects.
Conditions that require additional expenditures may transpire for various
Company sites, including, but not limited to, the Company's refineries, tank
farms, retail gasoline stations (operating and closed locations) and petroleum
product terminals (including assets acquired in the Acquisitions), and for
compliance with the Clean Air Act and other state, federal and local
requirements. The Company cannot currently determine the amount of such future
expenditures.
11
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
OTHER
In October 1998, the Company's Board of Directors unanimously approved the 1998
Performance Incentive Compensation Plan ("Performance Plan"), which is intended
to advance the best interests of the Company and its stockholders by directly
targeting Company performance to align with the ninetieth percentile historical
stock-price growth rate for the Company's peer group. In addition, the
Performance Plan will provide the Company's employees with additional
compensation, contingent upon achievement of the targeted objectives, thereby
encouraging them to continue in the employ of the Company. Under the Performance
Plan, targeted objectives are comprised of the fair market value of the
Company's Common Stock equaling or exceeding an average of $35 per share ("First
Performance Target") and $45 per share ("Second Performance Target") on any 20
consecutive trading days during a period commencing on October 1, 1998 and
ending on the earlier of September 30, 2002, or the date on which the Second
Performance Target is achieved. No costs will be recorded until the First
Performance Target is reached.
NOTE G - EARNINGS PER SHARE
Basic earnings per share are determined by dividing net earnings applicable to
Common Stock by the weighted average number of common shares outstanding during
the period. The calculation of diluted earnings per share takes into account the
effects of potentially dilutive shares outstanding during the period,
principally the maximum shares which would have been issued assuming conversion
of PIES at the beginning of the period and stock options. In July 2001, the
Company's PIES were converted into 10.35 million shares of Common Stock.
Earnings per share calculations are presented below (in millions except per
share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
BASIC:
Numerator:
Net earnings ......................................... $ 32.8 $ 25.0 $ 84.0 $ 48.9
Less dividends on Preferred Stock .................... -- 3.0 6.0 9.0
----------- ----------- ----------- -----------
Net earnings applicable to common shares ............. $ 32.8 $ 22.0 $ 78.0 $ 39.9
=========== =========== =========== ===========
Denominator:
Weighted average common shares outstanding ........... 41.4 30.8 34.5 31.4
=========== =========== =========== ===========
Basic Earnings Per Share ............................... $ 0.79 $ 0.71 $ 2.26 $ 1.27
=========== =========== =========== ===========
DILUTED:
Numerator:
Net earnings applicable to common shares ............. $ 32.8 $ 22.0 $ 78.0 $ 39.9
Plus impact of assumed conversion of PIES ............ -- 3.0 6.0 9.0
----------- ----------- ----------- -----------
Total .............................................. $ 32.8 $ 25.0 $ 84.0 $ 48.9
=========== =========== =========== ===========
Denominator:
Weighted average common shares outstanding ........... 41.4 30.8 34.5 31.4
Add potentially dilutive securities:
Incremental dilutive shares from assumed exercise of
stock options and other .......................... 0.3 0.3 0.5 0.2
Incremental dilutive shares from assumed conversion
of PIES .......................................... -- 10.3 6.9 10.3
----------- ----------- ----------- -----------
Total diluted shares ........................... 41.7 41.4 41.9 41.9
=========== =========== =========== ===========
Diluted Earnings Per Share ............................. $ 0.79 $ 0.60 $ 2.00 $ 1.17
=========== =========== =========== ===========
12
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE H - NEW ACCOUNTING STANDARDS
SFAS NO. 133 AND SFAS NO. 138
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. SFAS
No. 133, as amended and interpreted, establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. SFAS No. 133 requires
all derivatives to be recorded on the balance sheet at fair value. The
accounting for changes in the fair value of a derivative depends on the intended
use of the derivative and the designation if in a hedging relationship. The
adoption of SFAS No. 133 did not have a significant impact on the Company's
financial condition, results of operations or cash flows.
The Company periodically enters into derivatives arrangements, on a limited
basis, as part of its programs to acquire refinery feedstocks at reasonable
costs and to manage margins on certain refined product sales. The Company also
engages in limited non-hedging derivatives, which are marked to market with
changes in the fair value of the derivatives recognized in earnings in the
Condensed Statements of Consolidated Operations and the carrying amounts
included in other current assets or accrued liabilities in the Condensed
Consolidated Balance Sheets. As of September 30, 2001, the Company did not have
any derivative instruments that were designated and accounted for as hedges. The
Company believes that substantially all of its supply and marketing agreements
are normal purchases and sales and that repricing provisions in other agreements
are not embedded derivatives.
SFAS NO. 141 AND SFAS NO. 142
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,
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 that 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 No. 141 and 142 apply to the
Acquisitions discussed in Note B. The Company is currently evaluating the impact
these standards will have on its future results of operations and financial
condition.
SFAS NO. 143
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 value each period. SFAS No. 143 is effective for the
Company beginning January 1, 2003 with earlier adoption encouraged. The Company
is currently evaluating the impact the standard will have on its future results
of operations and financial condition.
SFAS NO. 144
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 the Company beginning
January 1, 2002 with earlier adoption encouraged. The Company is currently
evaluating the impact the standard may have on its future results of operations
and financial condition.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
THOSE STATEMENTS IN THE MANAGEMENT'S DISCUSSION AND ANALYSIS THAT ARE NOT
HISTORICAL IN NATURE SHOULD BE DEEMED FORWARD-LOOKING STATEMENTS THAT ARE
INHERENTLY UNCERTAIN. SEE "FORWARD-LOOKING STATEMENTS" ON PAGE 26 FOR DISCUSSION
OF THE FACTORS WHICH COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
PROJECTED IN SUCH STATEMENTS.
THE COMPANY HAS ENDEAVORED TO PROVIDE A MORE THOROUGH DISCUSSION OF MANAGEMENT'S
EXPECTATIONS AND GOALS FOR THE COMPANY IN THIS MANAGEMENT'S DISCUSSION AND
ANALYSIS, AND THE COMPANY ANTICIPATES THAT IT WILL CONTINUE TO DO THE SAME IN
MANAGEMENT'S DISCUSSION AND ANALYSIS IN THE FUTURE. HOWEVER, EXPECTATIONS AND
GOALS MAY CHANGE DURING INTERIM PERIODS OF TIME. THE COMPANY DOES NOT INTEND TO,
AND A READER HEREOF SHOULD NOT EXPECT THAT THE COMPANY WILL, UPDATE THE
INFORMATION CONTAINED HEREIN DURING ANY SUCH INTERIM PERIOD.
STRATEGY
Management's goal is to create value by: (i) maximizing the Company's earnings,
cash flows and return on capital by reducing costs, increasing efficiencies and
optimizing existing assets; and (ii) increasing the Company's competitiveness by
expansion in overall size and market presence through a combination of internal
growth initiatives and selective acquisitions which are accretive to earnings
and cash flows and provide operational synergies. The Company is 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, the Company continues to assess its
existing asset base in order to maximize returns and financial flexibility
through market diversification and related acquisitions. The Company is
evaluating various strategic opportunities to capitalize on the value of the
Marine Services assets, including a possible sale of all or a part of this
business. Management is in the initial stages of its evaluation.
ACQUISITIONS
Management believes that the refining and marketing industry has been and will
continue to undergo a significant level of asset redeployment and consolidation.
Tesoro has grown and taken advantage of the economies of scale from this
consolidation. Tesoro more than tripled its refining capacity in 1998 when the
Company acquired the Hawaii and Washington refineries and improved its financial
condition and performance through its focus on the refining and marketing
business. As a result, management believes that the Company is positioned for
additional growth and improved financial returns.
On September 6, 2001, the Company acquired a refinery in Mandan, North Dakota
and related storage, pipeline, distribution, and gasoline marketing assets (the
"North Dakota System") and a refinery in Salt Lake City, Utah and related
storage, distribution and retail assets (the "Utah System") from certain
affiliates of BP p.l.c. The Company paid $665.8 million in cash (including $82.2
million for hydrocarbon inventories) for the Utah System and the North Dakota
System. The acquisitions of the North Dakota System and Utah System were
financed with debt under the Company's new senior secured credit facility
("Senior Secured Credit Facility"). The Company 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 includes:
o a 60,000 barrels per day ("bpd") refinery in Mandan, North Dakota;
o five terminals with aggregate capacity of 2.8 million barrels
(including refinery tankage);
o approximately 430 miles of refined product pipelines connecting the
refinery to the owned terminals, including the Minneapolis/St. Paul
market;
o 12 retail stations with convenience stores; and
o contracts to supply a jobber network of over 90 retail stations.
14
The Utah System includes:
o a 55,000 bpd refinery in Salt Lake City, Utah;
o five terminals, two of which are leased, with aggregate capacity of
2.5 million barrels (including refinery tankage);
o 31 retail stations with convenience stores; and
o contracts to supply a jobber network of over 200 retail stations.
On November 1, 2001, the Company acquired the pipeline system (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. The Company funded the $90.1 million
purchase price with borrowings under the delayed draw term loan of the new
Senior Secured Credit Facility. The purchase of the Pipeline System and the
September 6, 2001 acquisition of the North Dakota System and Utah System are
collectively referred to as "the Acquisitions."
With the Acquisitions, the Company has an asset base consisting of five
refineries with a rated crude oil throughput capacity of 390,000 bpd and a
network of 650 retail gasoline stations. The Acquisitions added approximately
650 employees to the Company's operations.
Management believes the Acquisitions enable the Company to increase the size and
scope of its operations, diversify its earnings and geographic exposure, and
build a platform for additional growth. Management further believes that the
Acquisitions will improve the Company's ability to supply markets in areas that
the Company had previously targeted for commercial and retail marketing
expansion, including the Company's Mirastar program.
For further information related to the Acquisitions, see Note B of Notes to
Condensed Consolidated Financial Statements in Part I, Item 1.
MANUFACTURING
Heavy Oil Conversion Project
The Company's manufacturing strategy focuses on improving refinery reliability
and safety, improving refining processes, and controlling manufacturing costs.
The Company commenced a heavy oil conversion project at its Washington refinery
in 2000, which will enable the Company 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. The Company
expects to spend approximately $100 million (including capitalized interest) for
this project, of which $85 million had been spent through September 30, 2001.
The de-asphalting unit, one of the major components of the heavy oil conversion
project, has been in operation since late September 2001. The upgrade of the
fluid catalytic cracking unit, the final major component of the heavy oil
conversion project, is expected to be fully operational by the end of the first
quarter of 2002.
Management originally estimated that 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, management estimates that 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.
Other
In addition to the heavy oil conversion project, the Company has increased its
asphalt and middle distillate production capabilities at the Washington
refinery. The Company has also implemented programs to improve refinery
reliability and safety. Other programs have been put in place to control
manufacturing costs by upgrading process control systems, consolidating refinery
equipment purchasing and improving the Company's ability to respond to volatile
15
changes in the cost of utilities at the Washington refinery. Wholesale prices
for purchased electricity at the Washington refinery fluctuated tremendously in
the first nine months of 2001, from a low of $14 per megawatt-hour ("MWH") to a
high of $488 per MWH. The Company acquired natural gas-fired generators with
emission control packages capable of supplying approximately 90% of the
Washington refinery's present power requirements and providing the flexibility
to better manage the Company's power costs between self-generated power and
purchased electricity.
RETAIL MARKETING
As of September 30, 2001, the Company's Refining and Marketing business included
a network of 650 branded retail stations (under the Tesoro, Mirastar, Tesoro
Alaska and Amoco brands), including 163 Tesoro-owned retail gasoline stations
and 487 jobber stations (third-party retail distributors) in the mid-continental
and western United States. The Company has completed the rebranding of the
exterior signage for the recently acquired company-owned stations in Utah and
expects to finish rebranding the company-owned North Dakota stores during the
fourth quarter of 2001. In November 2001, the Company acquired 46 retail fueling
facilities, including 37 retail stations with convenience stores and nine
commercial card lock facilities, located in Washington, Oregon and Idaho. The
Company purchased these properties from Gull Industries Inc., a privately-held
company based in Seattle, Washington.
The Company developed its Mirastar brand exclusively for Wal-Mart Stores, Inc.
("Wal-Mart"), for which Tesoro builds and operates retail fueling facilities on
sites at selected Wal-Mart store locations. Tesoro's relationship with Wal-Mart
covers 17 western states, including North Dakota and Utah. Each of the sites
under the Company's agreement with Wal-Mart is subject to a ground lease with a
ten-year primary term and two options, exercisable at Tesoro's discretion, to
extend a site's lease for additional terms of five years. As of September 30,
2001, the Company had 47 Mirastar stations in operation, 5 Mirastar stations
under construction and 54 sites in various stages of development or evaluation.
The availability of future sites is determined solely at Wal-Mart's option, but
decisions concerning the development of a Mirastar station at a site are
determined solely by the Company. Management expects to have approximately 60 to
70 Mirastar stations operating by the end of 2001 and expects to construct an
additional 50 to 60 stations in each of 2002 and 2003. The average cost of
constructing a standard Mirastar station with four fuel dispensers is
approximately $550,000. The average investment in Mirastar stations may increase
in the future as stations with five to eight fuel dispensers are constructed.
Management expects the Acquisitions to create economic benefits for the
Company's current retail platform by providing a source of proprietary gasoline
supply and additional opportunities for its expanded retail network.
BUSINESS ENVIRONMENT
The Company operates in an environment where its 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 its marketing program, the Company also purchases refined
products for sale to customers. Changes in price levels of crude oil and refined
products can result in changes in margins on such activities. Energy prices,
together with volume levels, also determine the carrying value of crude oil and
refined product inventory. The Company uses the last-in, first-out ("LIFO")
method of accounting for inventories of crude oil and refined products in its
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.
Changes in crude oil and natural gas prices also influence the level of drilling
activity in the Gulf of Mexico. The Company's 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 ("FIFO") method of
accounting for inventories of fuels. Changes in fuel prices can significantly
affect inventory valuations and costs of sales.
For information on commodity price and interest rate risks, see Quantitative and
Qualitative Disclosures About Market Risk in Item 3 herein.
16
RESULTS OF OPERATIONS - THREE MONTHS AND NINE MONTHS ENDED SEPTEMBER 30, 2001
COMPARED WITH THREE MONTHS AND NINE MONTHS ENDED SEPTEMBER 30, 2000
SUMMARY
Tesoro's net earnings were $32.8 million ($0.79 per basic and diluted share) for
the three months ended September 30, 2001 ("2001 Quarter"), compared with net
earnings of $25.0 million ($0.71 per basic share or $0.60 per diluted share) for
the three months ended September 30, 2000 ("2000 Quarter"). For the year-to-date
periods, net earnings were $84.0 million ($2.26 per basic share or $2.00 per
diluted share) for the nine months ended September 30, 2001 ("2001 Period"),
compared with net earnings of $48.9 million ($1.27 per basic share or $1.17 per
diluted share) for the nine months ended September 30, 2000 ("2000 Period"). The
increase in earnings during the 2001 Quarter and Period reflected the
newly-acquired operations in North Dakota and Utah, and increased operating
profit due to higher refined product margins, refinery throughput levels and
sales volumes, partially offset by higher operating expenses. Expenses related
to the acquisition financing and integration costs decreased earnings by
approximately $0.13 per share during the 2001 Quarter.
A discussion and analysis of the factors contributing to the Company's results
of operations are presented below. The accompanying Condensed Consolidated
Financial Statements and related Notes, together with the following information,
are intended to provide shareholders and other investors with a reasonable basis
for assessing the Company's operations, but should not serve as the only
criteria for predicting the future performance of the Company.
REFINING AND MARKETING
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
(Dollars in millions except per barrel amounts) 2001 2000 2001 2000
----------- ----------- ----------- -----------
REVENUES
Refined products ........................................ $ 1,265.9 $ 1,274.4 $ 3,548.7 $ 3,296.9
Other, primarily crude oil resales and merchandise ...... 100.5 73.0 250.8 238.7
----------- ----------- ----------- -----------
Total Revenues ...................................... $ 1,366.4 $ 1,347.4 $ 3,799.5 $ 3,535.6
=========== =========== =========== ===========
SEGMENT OPERATING PROFIT
Gross margins:
Refinery (a) .......................................... $ 213.4 $ 175.7 $ 568.0 $ 448.9
Purchased product and crude oil resales .............. 4.5 (0.6) 9.7 15.4
Merchandise and other ................................. 7.5 7.6 19.1 21.0
----------- ----------- ----------- -----------
Total gross margins ................................. 225.4 182.7 596.8 485.3
Operating expenses and other (b) ........................ (127.3) (111.2) (361.0) (324.5)
Depreciation and amortization (c) ....................... (11.3) (10.3) (31.5) (28.9)
----------- ----------- ----------- -----------
Segment Operating Profit ............................ $ 86.8 $ 61.2 $ 204.3 $ 131.9
=========== =========== =========== ===========
REFINERY SYSTEM THROUGHPUT (thousand bpd) (d)
Washington .............................................. 121.8 123.6 120.4 116.9
Hawaii .................................................. 87.5 79.2 87.9 81.9
Alaska .................................................. 58.5 53.6 49.7 47.8
North Dakota ............................................ 14.8 -- 5.0 --
Utah .................................................... 13.9 -- 4.7 --
----------- ----------- ----------- -----------
Total Refinery System Throughput .................... 296.5 256.4 267.7 246.6
=========== =========== =========== ===========
% HEAVY CRUDE OIL OF TOTAL REFINERY SYSTEM
THROUGHPUT .............................................. 43% 42% 48% 43%
=========== =========== =========== ===========
TOTAL REFINERY SYSTEM PRODUCT SPREAD ($/barrel) ............ $ 8.10 $ 7.36 $ 7.87 $ 6.58
=========== =========== =========== ===========
17
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
(Dollars in millions except per barrel amounts) 2001 2000 2001 2000
----------- ----------- ----------- -----------
REFINED PRODUCTS MANUFACTURED (thousand bpd) (d)
Gasoline and gasoline blendstocks .................. 110.9 98.8 97.1 96.6
Jet fuel ........................................... 58.8 56.6 58.3 56.0
Diesel fuel ........................................ 58.8 41.6 46.1 37.8
Heavy oils, residual products and other ............ 75.7 66.2 73.2 63.3
----------- ----------- ----------- -----------
Total Refined Products Manufactured ............ 304.2 263.2 274.7 253.7
=========== =========== =========== ===========
PRODUCT SALES (thousand bpd) (d)(e)
Gasoline and gasoline blendstocks .................. 159.4 141.8 146.3 137.1
Jet fuel ........................................... 82.2 75.2 79.4 76.2
Diesel fuel ........................................ 80.0 60.4 66.1 52.1
Heavy oils, residual products and other ............ 62.0 55.4 59.8 57.9
----------- ----------- ----------- -----------
Total Product Sales .............................. 383.6 332.8 351.6 323.3
=========== =========== =========== ===========
PRODUCT SALES PRICES ($/barrel)
Gasoline and gasoline blendstocks .................. $ 41.59 $ 47.61 $ 42.84 $ 41.55
Jet fuel ........................................... $ 34.26 $ 40.14 $ 35.31 $ 37.15
Diesel fuel ........................................ $ 34.21 $ 42.43 $ 36.56 $ 38.19
Heavy oils, residual products and other ............ $ 24.35 $ 27.74 $ 24.68 $ 26.38
PRODUCT SALES MARGIN ($/barrel) (e)
Average sales price ................................ $ 35.87 $ 41.61 $ 36.96 $ 37.21
Average costs of sales ............................. 29.68 35.91 30.93 31.98
----------- ----------- ----------- -----------
Gross Margin ..................................... $ 6.19 $ 5.70 $ 6.03 $ 5.23
=========== =========== =========== ===========
(a) Approximates refinery system throughput times refinery system product
spread, adjusted for changes in refined product inventory.
(b) Includes manufacturing costs per throughput barrel of $2.86 and $2.82 for
the three months ended September 30, 2001 and 2000, respectively, and $3.06
and $2.83 for the nine months ended September 30, 2001 and 2000,
respectively. Manufacturing costs included non-cash amortization of
maintenance turnaround costs of $4.6 million and $5.3 million for the three
months ended September 30, 2001 and 2000, respectively, and $13.2 million
and $15.6 million for the nine months ended September 30, 2001 and 2000,
respectively. Manufacturing costs also include costs of internally-produced
fuel.
(c) Includes manufacturing depreciation per throughput barrel of approximately
$0.26 and $0.24 for the three months ended September 30, 2001 and 2000,
respectively, and $0.24 and $0.26 for the nine months ended September 30,
2001 and 2000, respectively.
(d) Volumes for 2001 include amounts for North Dakota and Utah operations since
their acquisition on September 6, 2001 averaged over the periods presented.
Refinery throughput for the 25 days of operations in September 2001 was
54,600 bpd and 51,200 bpd for the North Dakota and Utah refineries,
respectively.
(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.
THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH THREE MONTHS ENDED SEPTEMBER
30, 2000. Segment operating profit for the Refining and Marketing segment was
$86.8 million in the 2001 Quarter, a 42% increase from the 2000 Quarter. The
Company's newly-acquired operations in North Dakota and Utah contributed
approximately $13 million to operating profit, representing almost 50% of the
total increase in operating profit from the 2000 Quarter. The increase was also
driven by stronger refined product margins and higher refinery throughput. The
improvement in refinery margins was partially offset by increases in operating
expenses as discussed below.
Revenues from sales of refined products in the Refining and Marketing segment
decreased to $1,265.9 million in the 2001 Quarter, from $1,274.4 million in the
2000 Quarter, reflecting lower sales prices and higher sales volumes. The
Company's average product sales prices decreased 14% to $35.87 per barrel in the
2001 Quarter from $41.61 per barrel in the 2000 Quarter. The decrease in product
sales prices was largely offset by higher sales volumes. Total product sales
averaged 383,600 bpd in the 2001 Quarter, an increase of 15% from the 2000
Quarter. The new
18
operations contributed 20,300 bpd of product sales averaged over the 2001
Quarter, representing approximately 40% of the total increase from the 2000
Quarter. The increase in other revenues was primarily due to higher crude oil
resales which totaled approximately $79 million in the 2001 Quarter compared to
$55 million in the 2000 Quarter. The decrease in costs of sales primarily
reflected lower feedstock and purchased product prices.
Refinery gross margin increased by 21% to $213.4 million in the 2001 Quarter,
reflecting higher volumes and a $0.74 per barrel (10%) increase in average
refinery system product spread per barrel to $8.10 in the 2001 Quarter. The
increase in refinery margin included contributions from the North Dakota and
Utah operations. In addition, the Company benefitted from lower feedstock costs
which included lower foreign-flag shipping rates of approximately $0.30 per
barrel for the 10 million barrels of crude that was shipped to the refineries
during the 2001 Quarter. The Company was able to capitalize on these market
conditions by increasing its refinery throughput, excluding the new operations,
11,400 bpd in the 2001 Quarter as compared to the 2000 Quarter.
The Company's margins on purchased product and crude oil resales increased by
$5.1 million in the 2001 Quarter as compared to the 2000 Quarter. Market
conditions during the 2001 Quarter offered greater profit opportunities compared
to market conditions during the 2000 Quarter.
Operating expenses, excluding depreciation, increased by $16.1 million, or 14%,
to $127.3 million in the 2001 Quarter. The Company's North Dakota and Utah
operations added operating expenses of approximately $8 million, or
approximately 50% of the total 2001 Quarter increase. The remaining increase was
primarily due to higher refinery throughput, increased costs for utilities and
fuel and increased employee costs.
NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH NINE MONTHS ENDED SEPTEMBER
30, 2000. Segment operating profit for the Refining and Marketing segment was
$204.3 million in the 2001 Period, a 55% increase from the 2000 Period. The
increase was primarily driven by stronger refined product margins and higher
refinery throughput and sales volumes. In addition, the Company's new operations
contributed approximately $13 million to operating profit. The improvement in
refinery margins was partially offset by increases in operating expenses and
lower margins from purchased product resales as discussed below.
Revenues from sales of refined products in the Refining and Marketing segment
increased 8% to $3,548.7 million in the 2001 Period, compared to the 2000
Period, due to increased sales volumes. Total product sales averaged 351,600 bpd
in the 2001 Period, an increase of 9% from the 2000 Period. The increase in
other revenues was primarily due to higher crude oil resales which totaled $196
million in the 2001 Period compared to $189 million in the 2000 Period. The
increase in costs of sales reflected primarily increased volumes.
Refinery gross margin increased 27% to $568.0 million in the 2001 Period,
reflecting higher volumes and a $1.29 per barrel, or 20%, increase in average
refinery system product spread per barrel to $7.87 in the 2001 Period. The
increase in refinery margin included contributions from the North Dakota and
Utah operations. The Company increased refinery throughput 5%, or 11,400 bpd,
excluding the new operations, as compared to the 2000 Period.
The Company's margins on purchased product and crude oil resales declined by
$5.7 million in the 2001 Period as compared to the 2000 Period. Market
conditions during the first six months of 2000 offered greater profit
opportunities compared to market conditions during the 2001 Period.
Operating expenses, excluding depreciation, increased by $36.5 million to $361.0
million in the 2001 Period, primarily due to additional operating expenses from
the Company's new operations, increased throughput at the Company's other
refineries, higher costs for utilities and fuel, and increased employee costs.
19
MARINE SERVICES
Three Months Ended Nine Months Ended
(Dollars in millions) September 30, September 30,
---------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Revenues:
Fuels ............................... $ 37.7 $ 40.0 $ 116.0 $ 110.2
Lubricants and other ................ 4.0 3.3 11.8 10.9
Services ............................ 3.9 3.5 11.8 9.8
Other income (loss) ................. -- 0.4 (0.2) 1.6
------------ ------------ ------------ ------------
Total Revenues .................... 45.6 47.2 139.4 132.5
Costs of Sales ......................... 33.8 36.2 104.7 99.2
------------ ------------ ------------ ------------
Gross Profit ...................... 11.8 11.0 34.7 33.3
Operating Expenses and Other ........... (7.9) (7.4) (23.4) (22.7)
Depreciation and Amortization .......... (0.7) (0.7) (2.1) (1.9)
------------ ------------ ------------ ------------
Segment Operating Profit ............ $ 3.2 $ 2.9 $ 9.2 $ 8.7
============ ============ ============ ============
Sales Volumes (millions of gallons):
Fuels, primarily diesel ............. 44.6 41.1 132.0 125.1
Lubricants .......................... 0.6 0.5 1.6 1.6
Segment operating profit for Marine Services improved by $0.3 million and $0.5
million during the 2001 Quarter and 2001 Period, respectively, primarily due to
higher fuel sales volumes and service revenues. Included in the 2000 Period was
other income of $1.2 million from settlement of a service contract. Excluding
this income, operating profit for the 2001 Period improved by 23%, or $1.7
million.
Revenues decreased $1.6 million and increased $6.9 million during the 2001
Quarter and 2001 Period, respectively. The decrease in the 2001 Quarter
reflected lower fuel sales prices, partially offset by increased fuel sales
volumes and services revenues. The increase during the 2001 Period reflected
higher fuel sales volumes and services revenues. Sales volumes and services
revenues increased from the 2000 Quarter and 2000 Period, reflecting an increase
in customer exploration and development activities in the U.S. Gulf of Mexico.
The decrease in costs of sales during the 2001 Quarter reflected the lower fuel
prices, whereas the increase in costs of sales during the 2001 Period reflected
increased fuel sales volumes.
The Marine Services segment's business is largely dependent upon the volume of
oil and gas drilling, workover, construction and seismic activity in the U.S.
Gulf of Mexico.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses increased by $4.7 million and $8.4 million
during the 2001 Quarter and 2001 Period, respectively. The increase was
primarily due to approximately $3 million of acquisition integration costs in
the 2001 Quarter, as well as higher employee costs and other professional fees.
INTEREST AND FINANCING COSTS
Interest and financing costs, net of capitalized interest, increased by $9.6
million and $5.8 million during the 2001 Quarter and 2001 Period, respectively.
The increases were primarily due to one-time cost of approximately $6 million
related to the acquisition financing and increased interest expense due to the
additional debt issued September 6, 2001.
INTEREST INCOME
Interest income decreased by $1.6 million from the 2000 Period 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.
20
INCOME TAX PROVISION
The increases of $3.5 million and $22.3 million in the income tax provision
during the 2001 Quarter and 2001 Period, respectively, primarily reflected the
increase in pretax earnings. The combined federal and state effective income tax
rate was approximately 40% in both the 2001 Quarter and 2001 Period, compared
with 42% and 41% in the 2000 Quarter and 2000 Period, respectively.
OUTLOOK AND OTHER FACTORS
For 2002, management is maintaining its earnings goal of $3.00 per share as a
result of the Company's strong earnings trend, including expected earnings from
the acquired operations and benefits from the heavy oil conversion project. The
earnings goal is primarily based on (i) the impact of the Acquisitions, (ii) the
expected margin improvement from completion of the heavy oil conversion project,
(iii) increased retail sales, and (iv) the potential for margin and other
earnings improvements.
The Company's debt-to-capitalization ratio at September 30, 2001 was 59%.
Management is committed to reducing the Company's debt to capital ratio to 50%
by the end of 2002. The Company achieved its goal to reduce debt after the 1998
refinery acquisitions. The Company used internally-generated cash flow, equity
and asset sales to reduce its debt-to-capital ratio from 56% in June 1998 to 32%
at year-end 2000.
Future profitability will continue to be influenced by market conditions and
other factors that are beyond the control of the Company. Many factors
contribute to the strength of industry margins, including, among others, cost
and availability of crude oil, the general demand for refined products, changes
in product specifications, changes in refining capacity in the Company's
operational regions and other conditions. In addition, industry margins may be
impacted by high-volume retail expansions and strong competition in the industry
due to mergers and acquisitions. See "Forward-looking Statements" on page 26 and
"Business Environment" on page 16 for further information related to these
factors and other factors which could cause results to differ.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
The Company's primary sources of liquidity are its cash flows from operations
and borrowing availability under revolving lines of credit, including the
acquisition debt discussed below. Capital requirements are expected to include
capital expenditures, working capital and debt service. Management believes that
available capital resources will be adequate to meet the Company's capital
requirements.
The Company operates in an environment where its 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 risks that
are beyond the control of the Company. These risks include, among others, the
level of consumer product demand, weather conditions, fluctuations in seasonal
demand, governmental regulations, the price and availability of alternative
fuels and overall market and economic conditions. See "Forward-looking
Statements" on page 26 for further information related to risks and other
factors. The Company's future capital expenditures, as well as borrowings under
its new Senior Secured Credit Facility and other sources of capital, will be
affected by these conditions.
CAPITALIZATION
At September 30, 2001, the Company's debt-to-capitalization ratio was 59%
compared with 32% at year-end 2000, reflecting increased borrowings under the
Senior Secured Credit Facility used to fund the Acquisitions (excluding the
Pipeline System).
The Company's new Senior Secured Credit Facility, existing 9% Senior
Subordinated Notes, and new 9-5/8% Senior Subordinated Notes, described below,
impose various restrictions and covenants on the Company that could potentially
limit its ability to respond to market conditions, to raise additional debt or
equity capital, or to take advantage of business opportunities. The Senior
Secured Credit Facility, existing 9% Senior Subordinated Notes and the new
9-5/8% Senior Subordinated Notes are guaranteed by substantially all of the
Company's active domestic subsidiaries.
21
The indentures relating to the 9% Senior Subordinated Notes and the 9-5/8%
Senior Subordinated Notes contain covenants that restrict, among other things,
the Company's ability to:
o pay dividends and other distributions with respect to Tesoro's capital
stock and purchase, redeem or retire its capital stock;
o incur additional indebtedness and issue preferred stock;
o enter into asset sales;
o enter into transactions with affiliates;
o incur liens on assets to secure certain debt;
o engage in certain business activities; and
o engage in certain mergers or consolidations and transfers of assets.
The indentures limit the Company's restricted subsidiaries' ability to create
restrictions on making certain payments and distributions. In addition, the new
Senior Secured Credit Facility contains other and more restrictive covenants,
including the prohibition on making voluntary or optional prepayments of certain
of the Company's indebtedness, including the 9-5/8% Senior Subordinated Notes.
Under the Senior Secured Credit Facility, the Company is required to comply with
specified financial covenants, including maintaining specified levels of
consolidated leverage and interest and fixed charge coverages and limiting the
Company's debt to capital ratio. These financial ratios become more restrictive
over the life of the new Senior Secured Credit Facility.
NEW SENIOR SECURED CREDIT FACILITY AND 9-5/8% SENIOR SUBORDINATED NOTES
On September 6, 2001, the Company entered into a new Senior Secured Credit
Facility, in the amount of $1.0 billion, in connection with the funding of the
acquisitions of the North Dakota System and the Utah System. The Senior Secured
Credit Facility, as amended, consists of a five-year $175 million revolving
credit facility (with a $90 million sublimit for letters of credit), a five-year
$85 million tranche A term loan, a five-year $90 million delayed draw term loan
(used to fund the purchase of the Pipeline System), a six-year $450 million
tranche B term loan and a $200 million capital markets term loan. On November 6,
2001, the Company repaid the $200 million capital markets term loan with the
proceeds of the 9-5/8% Senior Subordinated Notes, as described below. The Senior
Secured Credit Facility is guaranteed by substantially all of the Company's
active domestic subsidiaries and is secured by substantially all of the
Company's material present and future assets as well as all material present and
future assets of the Company's 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 the Company's current and future foreign
subsidiaries.
The Senior Secured Credit Facility requires the Company to maintain specified
levels of interest and fixed charge coverages and sets limitations on the
Company's debt-to-capital and leverage ratios. It also contains other covenants
and restrictions customary in credit arrangements of this kind. The terms allow
for payment of cash dividends on the Company's Common Stock and repurchases of
shares of its Common Stock, not to exceed $15 million in any year.
Borrowings under the Senior Secured Credit Facility bear interest at either a
base rate (6.0% at September 30, 2001) or a eurodollar rate, plus an applicable
margin. The applicable margin at September 30, 2001 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 of the eurodollar rate. The
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. Additionally, the tranche B
eurodollar rate is deemed to be no less than 3.0%. The applicable margin for the
capital markets term loan was 1.50% over the base 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 the Company's consolidated total
debt to consolidated EBITDA, as defined in the 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, will be reduced by 0.125%. The
Company is also charged various fees and expenses in connection with the Senior
Secured Credit Facility, including commitment fees and various letter of credit
fees.
At September 30, 2001, the Company had $43 million in borrowings and $1 million
in letters of credit outstanding under the revolving credit facility. Total
unused credit available under the revolving credit facility at September 30,
2001 was $131 million.
On November 6, 2001, the Company issued $215 million aggregate principal amount
of 9-5/8% Senior Subordinated Notes ("9-5/8% Senior Subordinated Notes") due
November 1, 2008 through a private offering eligible for Rule 144A. The 9-5/8%
Senior Subordinated Notes have a seven-year maturity with no sinking fund
requirements and
22
are subject to optional redemption by the Company after four years at declining
premiums. The Company, for the first three years, may redeem up to 35% of the
aggregate principal amount at a redemption price of 109.625%. The indenture for
the 9-5/8% Senior Subordinated Notes contains covenants and restrictions which
are customary for notes of this nature. The proceeds from the 9-5/8% Senior
Subordinated Notes were used to repay the indebtedness incurred under the
capital markets term loan, to pay accrued interest on the capital markets term
loan, to pay certain fees and expenses related to the 9-5/8% Senior Subordinated
Notes and for general corporate purposes. The 9-5/8% Senior Subordinated Notes
are guaranteed by substantially all of the Company's active domestic
subsidiaries.
The Company's 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 the Company's' future
performance, which, in turn, is subject to general economic, financial,
competitive and other factors that are beyond the Company's control. Based on
current operations, the Company expects the capacity under the 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 foreseeable future.
CONVERSION OF PREFERRED STOCK
On July 1, 2001, all of the Company's Premium Income Equity Securities ("PIES")
automatically converted into 10,350,000 shares of Common Stock. This conversion
saves the Company approximately $12 million in annual preferred dividends. The
final quarterly cash dividends on the PIES were paid on July 2, 2001.
COMMON STOCK REPURCHASE PROGRAM
In February 2000, the Company's Board of Directors authorized the repurchase of
up to 3 million shares of Tesoro Common Stock, which represented approximately
9% of the shares then outstanding. Under the program, the Company 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. The stock may be used to meet employee benefit plan requirements and
other corporate purposes. During 2001, the Company repurchased 304,000 shares of
Common Stock at a weighted average price of $11.50 per share, or an aggregate of
$3.5 million, bringing the cumulative shares repurchased under the program to
1,931,400.
CAPITAL SPENDING
For the year 2001, the Company's total capital budget 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. The Company plans to spend approximately $59 million to further
expand its retail marketing, which includes construction of new Mirastar
stations under the agreement with Wal-Mart, construction of Company- owned and
operated stations, and expansion of Tesoro's branded jobber network. The
Company's 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. Management
plans to fund its capital program for the remainder of 2001 with
internally-generated cash flows from operations and borrowings under the new
Senior Secured Credit Facility.
During the 2001 Period, the Company's capital expenditures totaled $152 million,
which included $62 million for the heavy oil conversion project and $23 million
for the Mirastar and other retail marketing programs. Other capital spending was
primarily for natural gas-fueled generators, modernization of refinery control
systems and other system upgrades. In the 2001 fourth quarter, the Company
entered into a sale and leaseback agreement for the recently acquired natural
gas-fueled generators at the Washington refinery. The lease agreement is for a
three-year period with a one-year renewal option and purchase options at fair
market value. The equipment was sold at the Company's cost.
Based on management's preliminary projections, the Company's 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.
23
MAJOR MAINTENANCE COSTS
The Company completed a scheduled turnaround of the Alaska refinery in the
second quarter of 2001 at a cost of approximately $10 million. The Company has
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 $5 million and $16 million in the 2001 Quarter and 2001
Period, respectively. 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 the Company's cash flows are set forth below (in millions):
Nine Months Ended
September 30,
--------------------------
2001 2000
----------- -----------
Cash Flows From (Used In):
Operating Activities ........................... $ 76.3 $ 53.5
Investing Activities ........................... (836.8) (40.9)
Financing Activities ........................... 747.6 (129.9)
----------- -----------
Decrease in Cash and Cash Equivalents ............ $ (12.9) $ (117.3)
=========== ===========
Net cash from operating activities during the 2001 Period totaled $76 million,
compared to $54 million from operating activities in the 2000 Period. The
increase was primarily due to higher earnings before depreciation and
amortization, offset by an increase in operating cash flows used for working
capital primarily related to higher sales activities. Net cash used in investing
activities of $837 million in the 2001 Period included $670 million for
acquisitions and $152 million for capital expenditures. Net cash from financing
activities of $748 million in the 2001 Period included net borrowings of $778
million under the Senior Secured Credit Facility partly offset by financing
costs of $17 million and preferred dividend payments of $9 million. Gross
borrowings under revolving credit lines amounted to $916 million and repayments
amounted to $873 million during the 2001 Period. Working capital totaled $397
million at September 30, 2001 compared to $248 million at year-end 2000.
ENVIRONMENTAL AND OTHER
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company 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. The Company is
currently involved in remedial responses and has incurred cleanup expenditures
associated with environmental matters at a number of sites, including certain of
its owned properties. At September 30, 2001, the Company's accruals for
environmental expenses totaled approximately $34 million, including assumed
known liabilities related to the Acquisitions (excluding the Pipeline System).
Based on currently available information, including the participation of other
parties or former owners in remediation actions, the Company believes these
accruals are adequate.
The Company continues 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, the Company
expects 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 has also 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. The Company expects 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.
The Company expects to spend approximately $35 million in the aggregate in
capital improvements at its 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. Management expects that the Refinery MACT II regulations will
require new emission controls at certain processing
24
units at several of the Company's refineries. The Company is currently
evaluating a selection of control technologies to assure operations flexibility
and compatibility with long-term air emission reduction goals.
In connection with the Acquisitions, the Company assumed the sellers'
obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield Company. BP
recently entered into this consent decree for both the North Dakota and Utah
refineries for various alleged violations. As the new owner of these refineries,
the Company is required to address issues including leak detection and repair,
flaring protection and sulfur recovery unit optimization. The Company estimates
it will spend $9 million at each of the North Dakota and Utah refineries to
comply with this consent decree. In addition, the Company has agreed to
indemnify the sellers for all losses of any kind incurred in connection with the
consent decree.
The Company anticipates it 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 2001 Period,
the Company spent approximately $5 million on environmental capital projects.
Conditions that require additional expenditures may transpire for various
Company sites, including, but not limited to, the Company's refineries, tank
farms, retail gasoline stations (operating and closed locations) and petroleum
product terminals (including assets acquired in the Acquisitions), and for
compliance with the Clean Air Act and other state, federal and local
requirements. The amount of such future expenditures cannot currently be
determined by the Company.
For further information on environmental matters and other contingencies, see
Note F of Notes to Condensed Consolidated Financial Statements in Part I, Item
1.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards ("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 the Company's 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,
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 that 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 No. 141 and 142 apply to the
Acquisitions. The Company is currently evaluating the impact these standards
will have on its 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 value each period. SFAS No. 143 is effective for the
Company beginning January 1, 2003 with earlier adoption encouraged. The Company
is currently evaluating the impact the standard will have on its 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 the Company beginning
January 1, 2002 with earlier adoption encouraged. The Company is currently
evaluating the impact the standard may have on its future results of operations
and financial condition.
25
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward-looking statements within
the meaning of the Private Securities Litigation Reform Act of 1995. These
statements include, among other things, projections of revenues, earnings,
earnings per share, capital expenditures or other financial items and
discussions of estimated future revenue enhancements, potential acquisitions and
cost savings. These statements also include the Company's business strategy,
goals and expectations concerning the Company's market position, future
operations, margins, profitability, liquidity and capital resources. The words
"anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan,"
"predict," "project," "will" and similar terms and phrases identify
forward-looking statements.
Although management believes the assumptions upon which these forward-looking
statements contained in this Quarterly Report on Form 10-Q 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. All
phases of the Company's operations involve risks and uncertainties, many of
which are outside the Company's control, and any one of which, or a combination
of which, could materially affect the Company's results of operations and
whether the forward- looking statements ultimately prove to be correct. Actual
results and trends in the future may differ materially depending on a variety of
factors including, but not limited to:
o changes in general economic conditions;
o the timing and extent of changes in commodity prices and underlying
demand for products;
o the availability and costs of crude oil, other refinery feedstocks and
refined products;
o the direct or indirect effects on the Company's business resulting
from the recent terrorist incidents;
o political developments in foreign countries;
o changes in the Company's inventory levels;
o changes in the cost or availability of third-party vessels, pipelines
and other means of transporting feedstocks and products;
o changes in fuel and utility costs for the Company's facilities;
o disruptions due to equipment interruption or failure at Company or
third-party facilities;
o execution of planned capital projects;
o the Company's ability to make acquisitions and successfully integrate
them, including the recently acquired North Dakota System, Utah System
and Pipeline System;
o adverse changes in the credit ratings assigned to the Company's trade
credit and debt instruments;
o state and federal environmental, economic, safety and other policies
and regulations, any changes therein, and any legal or regulatory
delays or other factors beyond the Company's control;
o adverse rulings, judgments, or settlements in litigation or other
legal or tax matters, including unexpected environmental remediation
costs in excess of any reserves;
o actions of customers and competitors;
o weather conditions affecting the Company's operations or the areas in
which the Company's products are marketed;
o earthquakes or other natural disasters affecting operations; and
o the conditions of the capital markets in the period covered by the
forward-looking statements.
Many of these factors are described in greater detail in the Company's other
filings with the SEC. All future written and oral forward-looking statements
attributable to the Company or persons acting on the Company's behalf are
expressly qualified in their entirety by the previous statements. The Company
undertakes no obligation to update any information contained in this Quarterly
Report on Form 10-Q or to publicly release the results of any revisions to any
such forward-looking statements that may be made to reflect events or
circumstances that occur, or which the Company becomes aware of, after the date
hereof.
26
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary sources of market risk to the Company include changes in commodity
prices and interest rates. The Company has a risk management committee
responsible for overseeing energy risk management activities.
COMMODITY PRICE RISKS
The Company's 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 the Company is 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 received by the Company for its refined products are
also affected by local factors such as local market conditions and the level of
operations of other refineries in the Company's markets.
The prices at which the Company can sell its refined products are influenced by
the commodity price of crude oil. Generally, an increase or decrease in the
prices of crude oil results in a corresponding increase or decrease in the
prices of gasoline and other refined products; however, the timing of the
relative movement of the prices can impact profit margins which could
significantly affect the Company's earnings and cash flows. In addition, crude
oil supply contracts generally are short-term in nature with market-responsive
pricing provisions. The Company normally purchases its 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 such feedstocks could have a significant effect on the Company's
financial results. The Company also purchases refined products manufactured by
others for resale to customers. Price level changes during the periods between
purchasing and selling such products could have a significant effect on
financial results.
The Company maintains inventories of crude oil, intermediate products and
refined products, the values of which are subject to fluctuations in market
prices. At September 30, 2001 and December 31, 2000, the Company's inventories
of refinery feedstocks and refined products totaled 15.5 million barrels,
including inventories related to the Acquisitions, and 11.9 million barrels,
respectively. In connection with the Acquisitions approximately 3.8 million
barrels were acquired at an average cost of $31.56 per barrel (market value at
September 6, 2001). 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 liquidation of LIFO inventories at year-end 2001 would have a per
barrel cost of sales in excess of current replacement costs and could exceed the
year-to-date average costs of sales in 2001. The average cost of refinery
throughput in September 2001 was approximately $25.86 per barrel, or
approximately $3.96 per barrel lower than the cost of the 2000 incremental
inventory layer. The average cost of the Company's refinery feedstocks and
refined products inventories as of September 30, 2001 was $23.42 per barrel. If
market price levels decline from current levels to a level below the average
cost of these inventories, the Company may be required to write down the
carrying value of its inventory.
The Company periodically enters into derivative type arrangements on a limited
basis, as part of its programs to acquire refinery feedstocks at reasonable
costs and to manage margins on certain refined product sales. The Company also
engages in limited non-hedging activities which are marked to market with
changes in the fair value of the derivatives recognized in earnings. Management
believes that any potential adverse impact from these activities would not
result in a material adverse effect on the Company's financial results,
financial position or cash flows. At September 30, 2001, the Company did not
hold any exchange traded futures contracts.
INTEREST RATE RISK
The Company had $778 million of outstanding floating-rate debt under the Senior
Secured Credit Facility and $307 million of fixed-rate debt at September 30,
2001. The weighted average interest rate on the floating-rate debt was 7.55% at
September 30, 2001. The impact on annual cash flow of a 10% change in the
floating-rate for the Senior Secured Credit Facility (76 basis points) would be
approximately $6 million.
27
On November 6, 2001, the Company issued $215 million 9-5/8% Senior Subordinated
Notes maturing in 2008, and the proceeds were used to replace $200 million of
floating-rate debt. At November 8, 2001 the Company had $625 million of
outstanding floating-rate debt under the Senior Secured Credit Facility with a
weighted average interest rate of 5.44%. The impact on annual cash flow of a
10% change in the floating-rate (54 basis points) would be approximately $3
million.
The fair market value of the Company's fixed-rate debt at September 30, 2001 was
approximately $19 million less than its book value of $307 million, based on
recent transactions and bid quotes for the Company's 9% Senior Subordinated
Notes, due in 2008.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported, on May 31, 2000, the Company and certain of
its officers were named defendants in a lawsuits filed in the United
States District Court, Western District of Texas, San Antonio
Division, brought by Group One Limited that sought to certify as a
class, all persons or entities who purchased the Company's securities
during the period from January 3, 2000 through May 3, 2000. Three
other identical lawsuits were filed in the same court. The lawsuits,
which were consolidated, alleged that the defendants issued false and
misleading information regarding the Company's financial condition and
operations, which artificially inflated the market price of the
Company's securities during the period from January 3, 2000 through
May 3, 2000. The plaintiffs sought unspecified damages. These claims
were dismissed on September 21, 2001, although the plaintiffs may
replead their case within 60 days of the dismissal order. If the
plaintiffs replead their case, the Company believes the claims will be
without merit and intends to vigorously defend against the claims.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
In September 2001, the Company entered into a Senior Secured Credit
Facility under which the Company is required to maintain specified
levels of interest and fixed charge coverages and sets limitations on
the Company's debt-to-capital and leverage ratios. It also contains
other covenants and restrictions customary in credit arrangements of
this kind. The terms allow for payment of cash dividends on the
Company's Common Stock and repurchases of shares of the Common Stock,
not to exceed $15 million in any year.
In November 2001, the Company issued $215 million aggregate principal
amount of 9-5/8% Senior Subordinated Notes. The indenture for the
notes contains covenants and restrictions which are customary for
notes of this nature.
For further information related to these restrictions and covenants in
the Senior Secured Credit Facility and the 9-5/8% Senior Subordinated
Notes, see Note B of Notes to Condensed Consolidated Financial
Statements in Part I, Item 1, and "Capital Resources and Liquidity" in
Management's Discussion and Analysis of Financial Condition and
Results of Operations in Part I, Item 2, contained herein.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
2.1 Asset Purchase Agreement, dated July 16, 2001, by and among
the Company, BP Corporation North America Inc. and BP
Pipelines (North America) Inc. relating to the purchase and
sale of the North Dakota core pipeline interest and related
assets. 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.
28
(b) REPORTS ON FORM 8-K
On September 4, 2001, a Current Report on Form 8-K was filed
reporting under Item 9, Regulation FD Disclosures,
information related to a presentation and webcast concerning
the Acquisitions. The presentation data and script were
filed as Exhibits under Item 7 of this Form 8-K. In
addition, removal of the Company's indicator margin from its
website was filed under Item 5, Other Events.
On September 21, 2001, a Current Report on Form 8-K was
filed reporting under Item 2, Acquisitions or Dispositions
of Assets, that the Company completed the 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 and entered into an
agreement to purchase the Pipeline System. Asset purchase
agreements for the Salt Lake City refinery and the Mandan
refinery were filed as Exhibits under Item 7 of this Form
8-K. In addition, press releases announcing (i) the Company
is investigating various strategic, value-creating
opportunities for its Gulf of Mexico- based Marine Services
operations and (ii) the Company had entered into a purchase
and sale agreement to acquire approximately 46 retail
fueling facilities were filed under Item 5, Other Events.
Press releases dated August 27, 2001 and September 4, 2001
were filed as Exhibits under Item 7.
On October 24, 2001, a Current Report on Form 8-K was filed
reporting under Item 9, Regulation FD Disclosures,
information related to a presentation concerning the 9-5/8%
Senior Subordinated Notes. The presentation data was filed
as an Exhibit under Item 7 of this Form 8-K.
On October 24, 2001, an Amendment No. 1 to Current Report on
Form 8-K was filed reporting under Item 2, Acquisitions or
Dispositions of Assets, that the Company completed the
acquisition (as adjusted for the post-closing inventory
valuation) 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. Included
under Item 7 of this Form 8-K/A were the following: (i)
Audited Financial Statements of The North Dakota and Utah
Refining and Marketing Business of BP Corporation North
America Inc. as of December 31, 1999 and 2000 and for the
years ended December 31, 1998, 1999 and 2000; (ii) Unaudited
Financial Statements of The North Dakota and Utah Refining
and Marketing Business of BP Corporation North America Inc.
as of June 30, 2001 and for the six months ended June 30,
2000 and 2001; and (iii) Unaudited Pro Forma Combined
Condensed Financial Statements as of June 30, 2001, for the
year ended December 31, 2000 and for the six months ended
June 30, 2001. In addition, an updated management's
discussion and analysis of financial condition and results
of operations was filed under Item 9, Regulation FD
Disclosures.
On November 5, 2001, an Amendment No. 2 to Current Report on
Form 8-K was filed reporting under Item 5, Other Events,
that the Company completed the acquisition of the North
Dakota-based, common-carrier crude oil pipeline and
gathering system of BP p.l.c. Amended pro forma financial
information was filed as an Exhibit under Item 7 of this
Form 8-K/A. In addition, the new $1,000,000,000 Credit
Agreement , Guarantee and Collateral Agreement and First
Amendment to the Credit Agreement were filed as Exhibits
under Item 7 of this Form 8-K/A.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TESORO PETROLEUM CORPORATION
REGISTRANT
Date: November 14, 2001 /s/ BRUCE A. SMITH
--------------------------------------------------
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive Officer
Date: November 14, 2001 /s/ GREGORY A. WRIGHT
--------------------------------------------------
Gregory A. Wright
Senior Vice President and Chief Financial Officer
30
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------ -----------
2.1 Asset Purchase Agreement, dated July 16, 2001, by and among the
Company, BP Corporation North America Inc. and BP Pipelines (North
America) Inc. relating to the purchase and sale of the North Dakota
core pipeline interest and related assets. 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.
31