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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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 1-13514
PREMCOR USA INC.
(Exact name of registrant as specified in its charter)
Delaware 43-1495734
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
8182 Maryland Avenue 63105-3721
St. Louis, Missouri (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (314) 854-9696
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 ( )
Number of shares of registrant's common stock, $.01 par value, outstanding as
of August 7, 2001, 100, all of which were owned by Premcor Inc.
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Premcor USA INC.
Form 10-Q
June 30, 2001
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Independent Accountants' Report........................................................................ 1
Consolidated Balance Sheets as of December 31, 2000 and June 30, 2001.................................. 2
Consolidated Statements of Operations for the Three Months Ended June 30, 2000 and 2001................. 3
Consolidated Statements of Operations for the Six Months Ended June 30, 2000 and 2001................... 4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2000 and 2001................... 5
Notes to Consolidated Financial Statements.............................................................. 6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 12
PART II. OTHER INFORMATION
Item 1. Legal Proceedings....................................................................................... 27
Item 6. Exhibits and Reports on Form 8-K........................................................................ 29
Signature............................................................................................... 32
FORM 10-Q - PART I
ITEM 1. FINANCIAL STATEMENTS
INDEPENDENT ACCOUNTANTS' REPORT
-------------------------------
To the Board of Directors of Premcor USA Inc.:
We have reviewed the accompanying consolidated balance sheet of Premcor USA Inc.
and subsidiaries (the "Company") as of June 30, 2001 and the related
consolidated statements of operations and cash flows for the three-month and
six-month periods ended June 30, 2000 and 2001. These financial statements are
the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the United States of
America, the objective of which is the expression of an opinion regarding the
financial statements taken as a whole. Accordingly, we do not express such an
opinion.
Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements for them to be in conformity
with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of the
Company as of December 31, 2000, and the related consolidated statements of
operations, stockholder's equity, and cash flows for the year then ended (not
presented herein); and in our report dated February 13, 2001, we expressed an
unqualified opinion on those consolidated financial statements.
Deloitte & Touche LLP
St. Louis, Missouri
August 6, 2001
1
PREMCOR USA INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in millions, except share data)
December 31, June 30,
2000 2001
-------- -----------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 253.7 $ 409.3
Short-term investments 1.7 1.7
Accounts receivable 250.5 198.2
Receivable from affiliates 36.9 59.5
Inventories 334.7 293.8
Prepaid expenses and other 34.2 30.8
-------- --------
Total current assets 911.7 993.3
PROPERTY, PLANT AND EQUIPMENT, NET 707.5 638.8
OTHER ASSETS 136.9 127.8
NOTE RECEIVABLE FROM AFFILIATE 4.9 3.9
-------- --------
$1,761.0 $1,763.8
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable $ 418.4 $ 331.3
Payable to affiliates 66.8 85.6
Accrued expenses and other 67.6 53.5
Accrued taxes other than income 37.1 38.6
-------- --------
Total current liabilities 589.9 509.0
LONG-TERM DEBT 971.9 971.3
OTHER LONG-TERM LIABILITIES 65.6 100.7
COMMITMENTS AND CONTINGENCIES -- --
EXCHANGEABLE PREFERRED STOCK
($.01 par value per share; 250,000 shares authorized;
93,176 shares issued) 90.6 95.8
STOCKHOLDER'S EQUITY:
Common stock ($0.01 par value per share;
100 shares authorized, issued and outstanding) -- --
Paid-in capital 206.4 206.4
Retained earnings (deficit) (163.4) (119.4)
-------- --------
Total common stockholder's equity 43.0 87.0
-------- --------
$1,761.0 $1,763.8
======== ========
The accompanying notes are an integral part of these financial statements.
2
PREMCOR USA INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in millions)
For the Three Months
Ended June 30,
------------------
2000 2001
-------- --------
NET SALES AND OPERATING REVENUES $1,720.4 $1,846.1
EXPENSES:
Cost of sales 1,475.1 1,533.9
Operating expenses 109.5 88.9
General and administrative expenses 12.3 15.5
Depreciation 8.3 7.7
Amortization 8.9 10.0
-------- --------
1,614.1 1,656.0
-------- --------
OPERATING INCOME 106.3 190.1
Interest expense and finance income, net 20.0 19.5
-------- --------
EARNINGS BEFORE INCOME TAXES 86.3 170.6
Income tax provision 0.2 62.2
-------- --------
NET EARNINGS 86.1 108.4
Preferred stock dividends 2.4 2.7
-------- --------
NET EARNINGS AVAILABLE TO
COMMON STOCKHOLDER $ 83.7 $ 105.7
======== ========
The accompanying notes are an integral part of these financial statements.
3
PREMCOR USA INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in millions)
For the Six Months
Ended June 30,
--------------------
2000 2001
--------- ---------
NET SALES AND OPERATING REVENUES $3,279.8 $3,563.8
EXPENSES:
Cost of sales 2,899.2 3,084.4
Operating expenses 213.7 180.6
General and administrative expenses 22.7 27.1
Depreciation 17.0 16.0
Amortization 16.4 18.6
Refinery restructuring and other charges -- 164.0
-------- --------
3,169.0 3,490.7
-------- --------
OPERATING INCOME 110.8 73.1
Interest expense and finance income, net 39.6 41.2
-------- --------
EARNINGS BEFORE INCOME TAXES 71.2 31.9
Income tax (provision) benefit (0.4) 17.3
-------- --------
NET EARNINGS 70.8 49.2
Preferred stock dividends 4.7 5.2
-------- --------
NET EARNINGS AVAILABLE TO
COMMON STOCKHOLDER $ 66.1 $ 44.0
======== ========
The accompanying notes are an integral part of these financial statements.
4
PREMCOR USA INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in millions)
For the Six Months
Ended June 30,
-------------------
2000 2001
------- ------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 70.8 $ 49.2
Adjustments
Depreciation 17.0 16.0
Amortization 20.7 22.6
Deferred taxes - 19.2
Refinery restructuring and other charges - 132.1
Other, net 2.5 (2.5)
Cash provided by (reinvested in) working capital -
Accounts receivable, prepaid expenses and other (146.5) 55.7
Inventories (198.8) 40.9
Accounts payable, accrued expenses, taxes other
than income 213.9 (99.7)
Affiliate accounts receivables and payables (0.4) (2.8)
------- ------
Net cash provided by (used in) operating activities (20.8) 230.7
------- ------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (76.2) (34.8)
Expenditures for turnaround (21.7) (38.3)
Proceeds from disposals of property, plant and equipment 0.5 0.5
Purchases of short-term investments (1.5) (1.7)
Sales and maturities of short-term investments 1.5 1.7
------- ------
Net cash used in investing activities (97.4) (72.6)
------- ------
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital lease payments (6.6) (0.7)
Deferred financing costs (1.9) (1.8)
------- ------
Net cash used in financing activities (8.5) (2.5)
------- ------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (126.7) 155.6
CASH AND CASH EQUIVALENTS, beginning of period 306.2 253.7
------- ------
CASH AND CASH EQUIVALENTS, end of period $ 179.5 $409.3
======= ======
The accompanying notes are an integral part of these financial statements.
5
FORM 10-Q - PART I
ITEM 1 FINANCIAL STATEMENTS (continued)
Premcor USA Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
June 30, 2001
(tabular dollar amounts in millions of U.S. dollars)
1. Basis of Preparation and Business Update
The accompanying unaudited consolidated financial statements of Premcor USA
Inc. and subsidiaries (the "Company") are presented in accordance with the
disclosure requirements for Form 10-Q. In the opinion of the management of the
Company, all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the financial statements have been included
therein. Operating results for the three and six months ended June 30, 2001 were
not necessarily indicative of the results that may be expected for the year
ended December 31, 2001. These unaudited financial statements should be read in
conjunction with the audited financial statements and notes included in the
Company's 2000 Annual Report on Form 10-K/A.
On April 10, 2001, Premcor Inc., the Company's parent, announced that it had
retained Credit Suisse First Boston and The Blackstone Group L.P. to serve as
its financial advisors to assist Premcor Inc. in its review of alternatives to
maximize the value of Premcor Inc. No assurance was given that this review would
result in any specific transaction. On August 7, 2001, Premcor Inc. disclosed
that its review of alternatives continued, but that due to developments within
the refining sector and its improved performance a wider range of alternatives
were now being considered.
2. New and Proposed Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 1999, the FASB issued
SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities--
Deferral of the Effective Date of FASB Statement No. 133" which delayed the
effective date of SFAS No. 133 for one year to fiscal years beginning after June
15, 2000. In June 2000, the FASB issued SFAS No. 138 "Accounting for Certain
Derivative Instruments and Hedging Activities" which amended various provisions
of SFAS No. 133. The Company adopted SFAS No. 133, as amended, effective
January 1, 2001. The adoption of SFAS No. 133 did not have a material impact on
the financial position or results of operations because the Company has
historically marked to market all financial instruments used in the
implementation of the Company's hedging strategies.
On July 20, 2001 the FASB issued SFAS No. 141 "Business Combinations" and SFAS
No. 142 "Goodwill and Other Intangible Assets". SFAS No. 141, which became
effective on issuance, requires business combinations initiated after June 30,
2001 to be accounted for using the purchase method of accounting and addresses
the initial recording of intangible assets separate from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite lives will not be
amortized, but will be tested at least annually for impairment. Intangible
assets with finite lives will continue to be amortized. SFAS No. 142 is
effective for
6
fiscal years beginning after December 15, 2001. The Company is in the process of
evaluating the impact of the adoption of these standards on its financial
position and results of operations.
In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset Retirement
Obligations". SFAS No. 143 addresses when a liability should be recorded for
asset retirement obligations and how to measure this liability. The initial
recording of a liability for an asset retirement obligation will require the
recording of a corresponding asset which will be required to be amortized. SFAS
No. 143 is effective for fiscal years beginning after June 15, 2002. The
Company is in the process of evaluating the impact of the adoption of this
standard on its financial position and results of operations.
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants ("AICPA") has issued an exposure draft of a
proposed statement of position ("SOP") entitled "Accounting for Certain Costs
and Activities Related to Property, Plant and Equipment." If adopted as
proposed, this SOP would require companies to expense as incurred turnaround
costs, which it terms as "the non-capital portion of major maintenance costs."
Adoption of the proposed SOP would also require that any existing unamortized
turnaround costs be expensed immediately. A turnaround is a periodically
required standard procedure for maintenance of a refinery that involves the
shutdown and inspection of major processing units and generally occurs every
three to five years. Turnaround costs include actual direct and contract labor
and material costs for the overhaul, inspection, and replacement of major
components of refinery processing and support units performed during turnaround.
Turnaround costs, which are included in the Company's consolidated balance sheet
in "Other Assets," are currently amortized by the Company on a straight-line
basis over the period until the next scheduled turnaround, beginning the month
following completion. The amortization of turnaround costs is presented as
"Amortization" in the Company's consolidated statements of operations.
The proposed SOP requires adoption for fiscal years beginning after June 15,
2002. If this proposed change were in effect at June 30, 2001, the Company
would have been required to write-off unamortized turnaround costs of
approximately $107 million. Unamortized turnaround costs will change throughout
the year as maintenance turnarounds are performed and past maintenance
turnarounds are amortized. If adopted in its present form, charges related to
this proposed change would be taken in the first quarter of 2003 and would be
reported as a cumulative effect of an accounting change, net of tax, in the
consolidated statements of operations.
3. Inventories
The carrying value of inventories consisted of the following:
December 31, June 30,
2000 2001
------------ --------
Crude oil......................... $125.3 $ 43.0
Refined products and blendstocks.. 185.7 228.9
Warehouse stock and other......... 23.7 21.9
------ ------
$334.7 $293.8
====== ======
7
The market value of crude oil, refined products and blendstocks inventories at
June 30, 2001 was approximately $70.3 million (December 31, 2000 - $100.8
million) above carrying value.
4. Other Assets
Other assets consisted of the following:
December 31, June 30,
2000 2001
------------ --------
Deferred turnaround costs............. $ 94.1 $107.1
Deferred financing costs.............. 17.1 14.6
Deferred tax asset.................... 24.2 5.0
Other................................. 1.5 1.1
------ ------
$136.9 $127.8
====== ======
Amortization of deferred financing costs for the three- and six-month periods
ended June 30, 2001 was $2.2 million (2000 - $2.1 million) and $4.4 million
(2000 - $4.2 million), respectively, and was included in "Interest expense and
finance income, net."
5. Related Party Transactions
Port Arthur Coker Company L.P.
The Company and Port Arthur Coker Company L.P. have entered into certain
agreements associated with the operations between the Port Arthur Coker Company
coking, hydrocracking, and sulfur removal facilities and the Company's Port
Arthur refinery. Premcor Inc. holds 100% of the common stock of the Company and
90% of the common stock of the general partner of PACC, Sabine River Holding
Corp. Balances and activity related to a services and supply, product purchase,
and ancillary lease agreement were as follows:
As of June 30, 2001, the Company had an outstanding receivable from Port
Arthur Coker Company of $9.5 million (December 31, 2000 - $28.0 million) and a
payable to Port Arthur Coker Company of $66.8 million (December 31, 2000 - $50.4
million) related to ongoing operations. As of June 30, 2001, the Company had a
note receivable from Port Arthur Coker Company of $7.4 million (December 31,
2000 - $7.0 million) related to construction management services of which $3.9
million (December 31, 2000 - $4.9 million) was accounted for as a long-term
asset and the remainder as a current asset.
The Company generated $29.8 million and $70.6 million in revenues for the
three- and six-month periods ended June 30, 2001, respectively, related to lease
and pipeline tariff fees and to the sale of feedstocks and hydrogen to Port
Arthur Coker Company. The Company incurred $535.9 million and $1,031.9 million
in costs of sales for purchases of finished and intermediate refined products
and crude oil from Port Arthur Coker Company for the three- and six- month
periods ended June 30, 2001, respectively. The company recorded reimbursements
of operating expenses of $2.2 million and $16.8 million for services provided to
Port Arthur Coker Company for the three- and six-month periods ended June 30,
2001. There were no revenues or expenses generated from these agreements in the
first half of 2000.
8
6. Working Capital Facilities
In the second quarter, The Premcor Refining Group Inc. (the "Refining Group")
extended the expiration dates from June 30,2001 to October 31, 2001 of its $625
million working capital facility, cash-collateralized $75 million facility, and
cash-collateralized $20 million facility. In conjunction with this extension,
the $625 million working capital facility was reduced by $40 million at June 30,
2001 and will be further reduced by $30 million at August 31, 2001. The Refining
Group is currently negotiating a renewal of these working capital facilities.
7. Interest Expense and Finance Income, net
Interest expense and finance income, net, included in the statements of
operations, consisted of the following:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------- --------------------
2000 2001 2000 2001
----- ----- ----- -----
Interest expense...... $23.1 $21.9 $46.2 $45.6
Financing costs....... 2.2 2.3 4.3 4.5
Interest income....... (3.6) (3.7) (7.5) (7.2)
----- ----- ----- -----
21.7 20.5 43.0 42.9
Capitalized interest.. (1.7) (1.0) (3.4) (1.7)
----- ----- ----- -----
$20.0 $19.5 $39.6 $41.2
===== ===== ===== =====
Cash paid for interest expense for the three- and six-month periods ended June
30, 2001 was $27.3 million (2000 - $27.2 million) and $46.6 million (2000 -
$46.0 million), respectively.
8. Refinery Restructuring and Other Charges
Refinery restructuring and other charges consisted of $150.0 million related
to the January, 2001 closure of the Blue Island, Illinois refinery and a $14.0
million charge related to the environmental liability for previously-owned
retail properties.
On January 31, 2001, the Company ceased operations at the Blue Island refinery
due to economic factors and a decision that the capital expenditures necessary
to produce low sulfur transportation fuels required by impending Environmental
Protection Agency regulations could not produce an acceptable return on
investment. The Company continues to utilize its petroleum products storage
facility at the refinery site to supply products to the Chicago and other
Midwest markets from the Company's Hartford and Port Arthur refineries.
Management adopted an exit plan that detailed the shutdown of the process
units at the refinery and the subsequent environmental remediation of the site.
The shutdown of the process units was completed during the first quarter of
2001. We are currently in discussions with the Illinois Environmental Protection
Agency concerning an investigation of the site and a remediation program that
would allow for redevelopment of the site for other manufacturing uses at the
earliest possible time. Until the site remediation plan is finalized it is not
possible to estimate the completion date for remediation, but we anticipate that
the remediation activities will continue for an extended period of time.
9
The $150.0 million charge included $102.5 million of net asset write-offs and
reserves of $12.0 million for severance, $26.4 million for the ceasing of
operations, preparation of the plant for permanent closure and equipment
remediation, $19.1 million for environmental remediation and other environmental
matters, and $10.0 million credit for the future sale of air emission credits.
The following schedule summarizes the restructuring reserve balance and net cash
activity as of June 30, 2001:
Initial Net Cash June 30,
Reserve Outlays 2001
------- -------- --------
Employee severance...................... $ 12.0 $10.0 $ 2.0
Plant closure/equipment remediation..... 26.4 11.8 14.6
Site remediation/environmental matters.. 19.1 1.1 18.0
Air emission credits.................... (10.0) - (10.0)
------ ----- ------
$ 47.5 $22.9 $ 24.6
====== ===== ======
The site remediation and environmental reserve takes into account costs that
we can reasonably estimate at this time. As the site remediation plan is
finalized and work performed, an adjustment of the estimate may be necessary.
The Company anticipates that remediation activities will continue for an
extended period of time.
The Blue Island refinery employed 297 employees, both hourly (covered by
collective bargaining agreements) and salaried, approximately 275 of whom were
terminated during the first six months of 2001. The remaining employees are all
salaried employees and the majority of them will terminate employment within the
year as the shutdown progresses.
The retail environmental charge of $14 million represents a change in estimate
relative to the Company's clean up obligation regarding the discontinued retail
division. More complete information concerning site by site clean up plans and
changing postures of state regulatory agencies prompted the change in estimate.
9. Income Taxes
The Company made net cash income tax payments during the three-month and six-
month periods ended June 30, 2001 of $2.4 million (2000 - $0.1 million) and $0.3
million (2000 - net cash income tax refunds of $2.1 million), respectively. The
income tax provision for the three-month period ended June 30, 2001 was $62.2
million, and the income tax benefit for the six-month period ended June 30, 2001
was $17.3 million. The income tax benefit of $17.3 million for the six-month
period ended June 30, 2001 included the effect of the Company's reversal during
the first quarter of 2001 of its remaining deferred tax valuation allowance of
$30.0 million. This reversal resulted from the Company's analysis of the
likelihood of realizing the future tax benefit of its federal and state tax loss
carryforwards, alternative minimum tax credits and federal and state business
tax credits. The income tax provision for the three-month and six-month periods
ended June 30, 2000 was $0.2 million and $0.4 million, respectively, which
represented current state taxes.
10. Commitments and Contingencies
Tier 2 Motor Vehicle Emission Standards. In February 2000, the EPA published
the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger
vehicles, establishing standards
10
for sulfur content in gasoline. The ruling mandates that the sulfur content of
gasoline at any refinery not exceed 30 ppm during any calendar year beginning
January 1, 2006. In 2004, the EPA will begin a program to phase in new low
sulfur gasoline. Modifications will be required at each of our refineries as a
result of the Tier 2 standards. Based on preliminary estimates, we believe that
compliance with the new Tier 2 gasoline specifications will require capital
expenditures in a range of $180 million to $225 million from 2001 - 2005 for our
refineries.
Low Sulfur Diesel Standards. In addition to the new gasoline standards, in
December 2000, the EPA issued its Highway Diesel Fuel Sulfur Control rules,
which require refineries to reduce the sulfur content of diesel fuel sold to
highway consumers by 97%, from 500 ppm to 15 ppm, beginning June 1, 2006, with
full compliance required by June 1, 2010. Refining industry groups have filed
two lawsuits, which may delay implementation of the highway diesel rule beyond
2006. On August 8, 2001 the EPA announced its intention to form a panel of
outside experts to review whether the highway diesel rule should be delayed. The
panel will be comprised of experts from the automobile and oil industries, state
governments, and environmental groups. The EPA has also announced plans to
review the sulfur content of diesel fuel sold to "off-road" consumers, with
proposed regulations to be issued in the fourth quarter of 2001. A final
decision regarding technology and compliance alternatives has not yet been made.
We will pursue the highest efficiency, lowest cost means of compliance, but at
this time no estimate of the cost of compliance can be made due to the
preliminary nature of our work and the fact that the off-road diesel rule has
not been finalized.
Legal and Environmental. As a result of its normal course of business the
Company is a party to a number of environmental proceedings. As of June 30,
2001, the Company had accrued a total of $67 million for legal and
environmental-related obligations including obligations associated with certain
formerly-owned retail sites and the Blue Island refinery closure. The Company is
of the opinion that the ultimate resolution of these claims, to the extent not
previously provided for, will not have a material adverse effect on the
consolidated financial condition, results of operations or liquidity of the
Company. However, an adverse outcome of any one or more of these matters could
have a material effect on quarterly or annual operating results or cash flows
when resolved in a future period.
11
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Forward-Looking Statements
Certain statements in this document are forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. These statements are subject to the safe
harbor provisions of this legislation. Words such as "expects," "intends,"
"plans," "projects," "believes," "estimates," "will" and similar expressions
typically identify such forward-looking statements.
Even though the Company believes its expectations regarding future events are
based on reasonable assumptions, forward-looking statements are not guarantees
of future performance. Important factors that could cause actual results to
differ materially from those contained in the Company's forward-looking
statements include, among others, changes in:
. Industry-wide refining margins;
. Crude oil and other raw material costs, embargoes, industry expenditures for
the discovery and production of crude oil, and military conflicts between, or
internal instability in, one or more oil-producing countries, and
governmental actions;
. Market volatility due to world and regional events;
. Availability and cost of debt and equity financing;
. Labor relations;
. U.S. and world economic conditions;
. Supply and demand for refined petroleum products;
. Reliability and efficiency of the Company's operating facilities which are
effected by such potential hazards as equipment malfunctions, plant
construction/repair delays, explosions, fires, oil spills and the impact of
severe weather;
. Actions taken by competitors which may include both pricing and expansion or
retirement of refinery capacity;
. Civil, criminal, regulatory or administrative actions, claims or proceedings
and regulations dealing with protection of the environment, including refined
petroleum product composition and characteristics;
. Other unpredictable or unknown factors not discussed.
Because of all of these uncertainties, and others, you should not place undue
reliance on the Company's forward-looking statements.
12
Overview
We are the fourth largest independent refiner, pending completion of two
industry mergers, in terms of capacity and one of the largest marketers of
unbranded transportation fuels, heating oil, petrochemicals, petroleum coke and
other petroleum products in the United States. We own and operate three
refineries in Port Arthur, Texas, Lima, Ohio and Hartford, Illinois, with a
combined crude oil throughput capacity of approximately 490,000 barrels per day,
or bpd. The strategic location of our assets allows us to sell petroleum
products in the Midwest, where demand has historically exceeded refining
production, as well as in the eastern and southeastern United States. We sell
our products on an unbranded basis to approximately 600 distributors and chain
retailers through our own product distribution system and an extensive third-
party owned product distribution system, as well as on the spot market.
Our Port Arthur, Texas refinery has a crude oil throughput capacity of
approximately 250,000 bpd. We utilize approximately 50,000 bpd of the crude oil
throughput capacity and lease the remaining 200,000 bpd of capacity to our
affiliate, the Port Arthur Coker Company. At our Port Arthur refinery site, the
Port Arthur Coker Company owns and operates a delayed coking unit, hydrocracker
unit and sulfur complex which are designed to process sour and heavy sour crude
oils. We have agreements with Port Arthur Coker Company whereby we lease
certain of our refinery equipment to them, provide to them certain operating,
maintenance and other services, and purchase from them all of the output of the
Port Arthur Coker Company units. We also lease back a portion of our leased
equipment and utilize a portion of the equipment of Port Arthur Coker Company
through a processing arrangement. As a result of these agreements, Port Arthur
Coker Company is a significant supplier of partially-refined intermediate
products representing approximately 125,000 bpd of our refinery feedstocks. See
"Factors Affecting Operating Results" and "Factors Affecting Comparability"
below.
Factors Affecting Operating Results
Our earnings and cash flow from operations are primarily affected by the
relationship between refined product prices and the prices for crude oil and
other feedstocks. The cost to acquire feedstocks and the price of refined
products ultimately sold depends on numerous factors beyond our control,
including the supply of, and demand for, crude oil, gasoline and other refined
products which, in turn, depend on, among other factors, changes in domestic and
foreign economies, weather conditions, domestic and foreign political affairs,
production levels, the availability of imports, the marketing of competitive
fuels and the extent of government regulation. While our net sales and operating
revenues fluctuate significantly with movements in industry crude oil prices,
such prices do not generally have a direct long-term relationship to net
earnings. Crude oil price movements may impact net earnings in the short term
because of fixed price crude oil purchase commitments. The effect of changes in
crude oil prices on our operating results is influenced by the rate at which the
prices of refined products adjust to reflect such changes. In general, low crude
oil prices indirectly benefit operating results over the longer term due to
increased demand and decreased working capital requirements. Conversely, high
crude oil prices generally result in decreased demand and increased working
capital requirements over the long term.
Feedstock and refined product prices are also affected by other factors,
such as product pipeline capacity, local market conditions and the operating
levels of competing refineries. Crude oil and other feedstock costs and the
price of refined products have historically been
13
subject to wide fluctuation. Expansion of existing facilities and installation
of additional refinery crude distillation and upgrading facilities, price
volatility, international political and economic developments and other factors
beyond our control are likely to continue to play an important role in refining
industry economics. These factors can impact, among other things, the level of
inventories in the market resulting in price volatility and a reduction in
product margins. Moreover, the industry typically experiences seasonal
fluctuations in demand for refined products, such as for gasoline during the
summer driving season and for home heating oil during the winter, primarily in
the Northeast.
In order to assess our operating performance, we compare our gross margin (net
sales and operating revenue less cost of sales) against an industry gross margin
benchmark. The industry gross margin is calculated by assuming that three
barrels of benchmark light sweet crude oil is converted, or cracked, into two
barrels of conventional gasoline and one barrel of high sulfur diesel fuel. This
is referred to as the 3/2/1 crack spread. Since we calculate the benchmark
margin using the market value of U.S. Gulf Coast gasoline and diesel fuel
against the market value of West Texas Intermediate crude oil, we refer to the
benchmark as the Gulf Coast 3/2/1 crack spread, or simply, the Gulf Coast crack
spread. The Gulf Coast crack spread is expressed in dollars per barrel and is a
proxy for the per barrel margin that a sweet crude oil refinery situated on the
Gulf Coast would earn assuming it produced and sold the benchmark production of
conventional gasoline and high sulfur diesel fuel.
Because each of our refineries is unique in configuration and has logistical
advantages as compared to a benchmark refinery, actual gross refining margins
will differ from the benchmark crack spread. Our Port Arthur and Hartford
refineries are able to process heavy sour crude oil that has historically cost
less than West Texas Intermediate crude oil. We measure the cost advantage of
heavy crude oil by calculating the spread between the value of Maya crude oil
produced in Mexico to the value of West Texas Intermediate crude oil because
Maya is our predominate heavy sour crude oil. The cost advantage of sour crude
oil is measured by calculating the spread between the value of West Texas Sour
crude oil to the value of West Texas Intermediate crude oil. In addition, since
we are able to source both domestic pipeline crude oil and foreign tanker crude
oil to each of our three refineries, the relative value of foreign crude oil to
domestic crude oil is also an important factor affecting our operating results.
Since many foreign crude oils are priced relative to the market value of a
benchmark North Sea crude oil known as Dated Brent, we also measure the cost
advantage of foreign crude oil by calculating the spread between the value of
Dated Brent crude oil to the value of West Texas Intermediate crude oil.
As part of the Port Arthur heavy oil upgrade project, we lease our crude,
vacuum and other ancillary units to our affiliate, Port Arthur Coker Company,
and lease back approximately 20%, or 50,000 bpd of crude distillation capacity.
Port Arthur Coker Company also pays us a fee for providing certain services and
supplies. Port Arthur Coker Company produces primarily intermediate feedstocks,
which are sold to us at fair market value for further processing into higher
value finished products. The utilization of intermediate feedstocks purchased
from Port Arthur Coker Company, rather than crude oil, causes a variance from
the benchmark crack spreads because these intermediate feedstocks are generally
more expensive than the benchmark West Texas Intermediate crude oil. However,
this variance is partially offset by lease, service and supply fees paid to us
by Port Arthur Coker Company. These payments, which provide a reliable source
of cash flow that is not market sensitive, increase our revenues and reduce our
operating costs.
14
The sales value of our production is also an important consideration in
understanding our results. We produce a high volume of premium products, such as
premium and reformulated gasoline, low sulfur diesel fuel, jet fuel, and
petrochemical products that carry a sales value significantly greater than that
for the products used to calculate the Gulf Coast crack spread. In addition,
products produced by our Midwest refineries are generally of higher value than
similar products produced on the Gulf Coast due to the fact that the Midwest
consumes more product than it produces, thereby creating a competitive advantage
for Midwest refiners that can produce and deliver refined products at a cost
lower than importers of refined product into the region. This advantage is
measured by the excess of the Chicago crack spread over the Gulf Coast crack
spread. The Chicago crack spread is determined by replacing the published Gulf
Coast product values in the Gulf Coast crack spread with published Chicago
product values.
Another important factor affecting operating results is the relative quantity
of higher value transportation fuels and petrochemical products compared to the
production of residual fuel oil and other by-products such as petroleum coke and
sulfur. Our Midwest refineries produce a product slate that is of significantly
higher value than the products used to calculate the Gulf Coast crack spread. At
our Hartford refinery, this added value is driven primarily by the competitive
location advantage discussed above. Our Lima refinery benefits from its mid-
continental location, in addition to the fact that it produces a greater
percentage of high value transportation fuels as a result of processing a
predominantly sweet crude oil slate.
Our operating cost structure is also important to our profitability. Major
operating costs include energy, employee labor, processing fees paid to Port
Arthur Coker Company, maintenance, including contract labor, and environmental
compliance. By far, the predominant variable cost is energy and the most
important benchmark for energy costs is the value of natural gas. Because the
complexity of the Port Arthur refinery complex and its ability to process
greater volumes of heavy sour crude oil increased significantly as a result of
the heavy oil upgrade project, the complex now has a higher operating cost
structure, primarily related to energy and labor. However, our share of these
operating costs has been reduced due to the lease and service fees paid to us by
Port Arthur Coker Company in accordance with the intercompany agreements.
Consistent, safe and reliable operations at the refineries are a key to our
financial performance. Unplanned downtime of our refinery assets generally
results in lost margin opportunity, increased maintenance expense and a
temporary increase in working capital investment and related inventory position.
If we choose to hedge the incremental inventory position, we are subject to
market and other risks normally associated with hedging activities. The
financial impact of planned downtime, such as major turnaround maintenance, is
mitigated through a diligent planning process that considers such things as
margin environment, availability of resources to perform the needed maintenance
and feedstock logistics.
The nature of our business leads us to maintain a substantial investment in
petroleum inventories. As petroleum feedstocks and products are essentially
commodities, we have no control over the changing market value of our
investment. We manage the impact of commodity price volatility on our
hydrocarbon inventory position by, among other methods, determining a volumetric
exposure level that we consider to be appropriate and consistent with normal
business operations. This target inventory position, which includes both titled
inventory and fixed price purchase and sale commitments, is generally not
hedged. To the extent that our inventory position deviates from the target
level, we consider risk mitigation activities usually through the purchase or
sale of futures contracts on the New York Mercantile Exchange or NYMEX. Our
15
hedging activities carry all of the usual time, location and product grade basis
risks associated with hedging activities generally. Because our titled inventory
is valued under the last-in, first-out costing method, price fluctuations on our
target level of titled inventory have very little effect on our financial
results. However, our financial results are affected by price movements on the
target level of fixed price purchase and sale commitments, which on a net basis
amount to a long inventory position of approximately 6 million barrels.
Factors Affecting Comparability
Our results compared to the comparable period of the prior year are
affected by the following events, which must be understood in order to assess
the comparability of our period to period financial statements.
Port Arthur Heavy Oil Upgrade Project. In January 2001, the operations of
the heavy oil upgrade project at our Port Arthur refinery began. The project,
construction of which began in 1998, included new coking, hydrocracking, and
sulfur removal units and the expansion of the existing crude unit capacity to
250,000 bpd. The heavy oil upgrade project allows the refinery to process
primarily lower-cost, heavy sour crude oil. In the third quarter of 1999, we
sold a portion of the work in progress and certain other assets to our
affiliate, Port Arthur Coker Company L.P. Port Arthur Coker Company financed
and completed the construction of the coking, hydrocracking, and sulfur removal
facilities. We completed the expansion of our crude unit capacity to 250,000
bpd from 232,000 bpd and made certain other improvements to existing facilities.
Start-up of the project occurred in three stages, with the sulfur removal units
beginning operations in November 2000, the coker unit beginning operations in
December 2000 and the hydrocracker unit beginning operations in January 2001.
Performance and reliability testing of the project as a whole is scheduled to be
completed in the third quarter of 2001. Additional information regarding the
heavy oil upgrade project is included in our Annual Report on Form 10-K for the
year ended December 31, 2000.
We entered into four intercompany agreements with Port Arthur Coker Company
associated with the refinery upgrade project and continuing operations as
described in our Annual Report on Form 10-K for the year ended December 31,
2000. These agreements, and other factors, significantly impacted the
comparability of the Company's 2001 results with the results of 2000 as follows:
. Under the agreements, we lease our crude, vacuum and certain other ancillary
units to Port Arthur Coker Company and lease back approximately 20%, or
50,000 bpd, of crude distillation capacity. Port Arthur Coker Company
utilizes approximately 80%, or 200,000 bpd of our leased crude distillation
capacity. Beginning in December 2000, we began receiving quarterly net lease
payments from Port Arthur Coker Company for the lease of our crude, vacuum
and other ancillary units as described above. Port Arthur Coker Company also
pays us a fee for pipeline access and use of our refinery dock. The net
effect of these lease payments is recorded in Net Sales and Operating Revenue
and increases our gross margin accordingly.
16
. Port Arthur Coker Company produces predominately intermediate feedstocks that
are sold to us at their fair market value. The intermediate refined
feedstocks are higher in price than crude oil because they have been
partially refined. In 2000, prior to the start up of Port Arthur Coker
Company, our feedstocks consisted primarily of crude oil.
. In order to efficiently process our crude oil throughput, we utilize a
portion of Port Arthur Coker Company's equipment and pay a monthly processing
fee. Payment of this fee began in December 2000 and is recorded as an
operating expense.
. We also provide certain services and supplies to Port Arthur Coker Company
including employee, maintenance, and energy costs. Beginning in December
2000, Port Arthur Coker Company reimburses us for these services at their
fair market value. These fees are recorded as an offset to our operating
expenses.
Closure of Blue Island Refinery. In January 2001, we ceased operations at the
Blue Island refinery due to economic factors and a decision that the capital
expenditures necessary to produce low sulfur transportation fuels required by
impending Environmental Protection Agency regulations could not produce
acceptable returns on investment. This closure resulted in a pre-tax charge of
$150 million in the first quarter of 2001. We continue to utilize the petroleum
products storage facility at the refinery site to supply products to the Chicago
and other Midwest markets from our Hartford and Port Arthur refineries.
Management adopted an exit plan that detailed the shutdown of the process units
at the refinery and the subsequent environmental remediation of the site. The
shutdown of the process units was completed during the first quarter of 2001. We
are currently in discussions with the Illinois Environmental Protection Agency
concerning an investigation of the site and a remediation program that would
allow for redevelopment of the site for other manufacturing uses at the earliest
possible time. Until the site remediation plan is finalized it is not possible
to estimate the completion date for remediation, but we anticipate that the
remediation activities will continue for an extended period of time.
The $150.0 million charge included $102.5 million of net asset write-offs and
reserves of $12.0 million for severance, $26.4 million for the ceasing of
operations, preparation of the plant for permanent closure and equipment
remediation, $19.1 million for environmental remediation and other environmental
matters, and $10.0 million credit for the future sale of air emission credits.
We expect to spend approximately $25 million in 2001 related to these reserves,
with the remainder to be spent over the next several years. The following
schedule summarizes the restructuring reserve balance and net cash activity as
of June 30, 2001:
Initial Net Cash June 30,
Reserve Outlays 2001
------- -------- --------
Employee severance...................... $ 12.0 $10.0 $ 2.0
Plant closure/equipment remediation..... 26.4 11.8 14.6
Site remediation/environmental matters.. 19.1 1.1 18.0
Air emission credits.................... (10.0) - (10.0)
------ ----- ------
$ 47.5 $22.9 $ 24.6
====== ===== ======
The site remediation and environmental reserve takes into account costs that
we can reasonably estimate at this time. As the site remediation plan is
finalized and work performed,
17
an adjustment of the estimate may be necessary. We anticipate that remediation
activities will continue for an extended period of time.
The Blue Island refinery employed 297 employees, both hourly (covered by
collective bargaining agreements) and salaried, approximately 275 of whom were
terminated during the first six months of 2001. The remaining employees are all
salaried employees and the majority of them will terminate employment within the
year as the shutdown progresses.
Industry Outlook
Our earnings depend largely on refining margins, which have been and continue
to be volatile. The cost of crude oil and intermediate feedstocks we purchase
and the prices of refined products we sell have fluctuated widely in the past.
Crude oil, intermediate feedstocks and refined product prices depend on numerous
factors beyond our control. While it is impossible to predict refining margins
due to the uncertainties associated with global crude oil supply and domestic
demand for refined products, we believe that refining margins over the next
several years will remain above those experienced in the period 1995 through
2000. Reviewing the first half of the year 2001, however, will give some
indication of the volatility that exists in the industry.
Throughout most of the first six months of 2001, the market price of
distillate relative to crude oil was above average due to low industry
inventories and strong consumer demand brought about by the relatively cold
winter weather in the northeast United States and eastern Canada. In addition,
gasoline margins were above average, primarily because substantial scheduled and
unscheduled refinery maintenance turnaround activity in the United States in
late 2000 and early 2001 resulted in inventories that did not increase in a
manner typically experienced during the winter. The increased demand for
refined products due to the relatively cold winter and the decreased supply due
to high turnaround activity, led to increased refining margins during the first
five months of 2001.
During June and July 2001, refining margins declined from the historic highs
experienced earlier in the year. This decline was largely the result of
increasing product inventories due to a short-term oversupply of refined
products that was driven by high refinery production rates, excessive product
import levels and a drop in consumer demand. The healthy refining margins
realized in early 2001 led refiners to postpone scheduled turnarounds in order
to maximize utilization rates. Import levels increased because of high domestic
product margins. Consumer demand dropped as a result of high prices and a
weakening economy. These factors led to a significant decrease in refinery
margins. Despite the recent weakness, we believe that refining margins will
strengthen once again because refiners will undertake delayed maintenance
turnarounds, and that the drop in product prices coupled with the typical
increase in summer demand will drive an increase in demand for refined products
and lower product imports due to the recent reductions in United States product
margins.
Average discounts for sour and heavy sour crude oil increased in the first
half of 2001 from already favorable 2000 levels due to increasing worldwide
supplies of sour and heavy sour crude oil, coupled with the continuing demand
for light sweet crude oil. In April 2001, the discount for heavy sour crude oil
versus West Texas Intermediate widened to more than double historical averages.
Although the heavy sour crude oil discount to West Texas Intermediate crude oil
has narrowed from these record highs, the discount continues to exceed historic
levels. Sweet crude oil continues to trade at a premium to West Texas Sour due
to continued high demand for sweet
18
crude oil resulting from the more stringent fuel specifications implemented in
the United States and Europe and the higher margins for light products.
The cost of natural gas in late 2000 and early 2001 peaked at over $10 per
thousand cubic feet but recently has fallen to approximately $3 per thousand
cubic feet. While certainly more favorable than recent record levels, we expect
the price of natural gas to result in an increase in per-barrel cash operating
costs for 2001. As production rates and inventories of natural gas continue to
increase, we expect prices to remain at levels well below the record highs seen
in the first quarter of 2001.
We expect refined product supply and demand balances to tighten worldwide
as a result of increasing demand and decreased supply. The supply decrease will
likely be driven by more stringent gasoline specifications and refinery closures
resulting from capital requirements to meet Tier 2 gasoline and low-sulfur
diesel specifications. We anticipate that the worldwide supplies of sour and
heavy sour crude oil will continue to increase along with the demand for sweet
crude oil. As a result, we expect the spread between light sweet and heavy sour
crude oil to remain wide.
19
Results of Operations
The following table reflects our financial and operating highlights for the
three- and six-month periods ended June 30, 2000 and 2001.
Financial Results For the Three Months Ended June 30, For the Six Months Ended June 30,
(in millions, except as noted) ------------------------------------- ----------------------------------
2000 2001 2000 2001
----------------- --------------- --------------- --------------
Net sales and operating revenues $1,720.4 $1,846.1 $3,279.8 $3,563.8
Cost of sales 1,475.1 1,533.9 2,899.2 3,084.4
----------------- --------------- --------------- --------------
Gross Margin 245.3 312.2 380.6 479.4
Operating expenses 109.5 88.9 213.7 180.6
General and administrative expenses 12.3 15.5 22.7 27.1
----------------- --------------- --------------- --------------
EBITDA as adjusted (1) 123.5 207.8 144.2 271.7
Depreciation & amortization 17.2 17.7 33.4 34.6
Refinery restructuring and other charges -- -- -- 164.0
----------------- --------------- --------------- --------------
Operating Income 106.3 190.1 110.8 73.1
Interest expense and finance income, net 20.0 19.5 39.6 41.2
Income tax (provision) benefit (0.2) (62.2) (0.4) 17.3
Earnings before dividends 86.1 108.4 70.8 49.2
Preferred stock dividends 2.4 2.7 4.7 5.2
----------------- --------------- --------------- --------------
Net earnings available to common
stockholders $ 83.7 $ 105.7 $ 66.1 $ 44.0
================= =============== =============== ==============
(1) Earnings before interest, income taxes,
depreciation and amortization and excluding
the refinery restructuring and other charges
of $164.0 million in 2001
For the Three Months For the Six Months Ended
Selected Volumetric and Per Barrel Data Ended June 30, June 30,
-------------------------------------- ----------------------------------
(in thousands of barrels per day, except as 2000 2001 2000 2001
noted) ------ ------ ------ ------
Production....................................... 436.9 373.6 445.0 382.5
Crude oil throughput............................. 390.5 254.1 415.2 262.0
PACC intermediate throughput..................... -- 124.7 -- 113.5
----------------- ----------------- --------------- ---------------
Total throughput............................... 390.5 378.8 415.2 375.5
Dollars per barrel of throughput:
Gross margin..................................... $ 6.90 $ 9.06 $ 5.06 $ 7.05
Operating expenses............................... $ 3.08 $ 2.58 $ 2.84 $ 2.66
For the Three Months For the Six Months
Market Indicators Ended June 30, Ended June 30,
- ----------------- -----------------------------------------------
(dollars per barrel, except as noted) 2000 2001 2000 2001
------ ------ ------ ------
West Texas Intermediate, or "WTI,".... $28.93 $27.89 $28.90 $28.35
Crack Spreads (3/2/1):
Gulf Coast crack spread............. $ 5.13 $ 6.52 $ 4.29 $ 5.76
Chicago............................. $ 8.19 $11.97 $ 6.33 $ 8.95
Crude Oil Differentials:
WTI less WTS (sour)................. $ 2.19 $ 3.23 $ 1.98 $ 3.66
WTI less Maya (heavy sour).......... $ 5.95 $10.46 $ 6.05 $10.54
WTI less Dated Brent (foreign)...... $ 2.15 $ 0.49 $ 2.04 $ 1.70
Natural gas (per mmbtu)................ $ 3.45 $ 4.68 $ 2.97 $ 5.84
20
Premcor Refining Group and Premcor USA tables (MD&A)
Three months ended June 30, 2000 Three months ended June 30, 2001
--------------------------------------- ----------------------------------------
Selected Volumetric Data Port Total Port Total
(in thousands of barrels per day) Arthur Midwest Total Percent Arthur Midwest Total Percent
------ ------- ----- ------- ------ ------- ----- -------
Feedstocks:
Crude oil throughput
Sweet 8.1 221.2 229.3 53% -- 143.5 143.5 38%
Light/Medium sour 81.1 41.2 122.3 28% 6.7 61.8 68.5 18%
Heavy sour 20.9 18.0 38.9 9% 34.1 8.0 42.1 11%
----- ----- ----- --- ----- ----- ----- ---
Total crude oil 110.1 280.4 390.5 90% 40.8 213.3 254.1 67%
PACC Intermediate throughput -- -- -- -- 124.7 -- 124.7 32%
Unfinished and blendstocks 47.2 (5.4) 41.8 10% 9.5 (6.6) 2.9 1%
----- ----- ----- --- ----- ----- ----- ---
Total feedstocks 157.3 275.0 432.3 100% 175.0 206.7 381.7 100%
===== ===== ===== === ===== ===== ===== ===
Production:
Light Products:
Conventional gasoline 61.0 126.8 187.8 43% 85.3 98.1 183.4 49%
Premium and reformulated gasoline 21.3 40.8 62.1 14% 28.4 22.5 50.9 14%
Diesel fuel 36.5 59.0 95.5 22% 33.5 42.8 76.3 20%
Jet fuel 11.2 21.0 32.2 8% -- 24.8 24.8 7%
Petrochemical products 21.0 14.9 35.9 8% 9.1 10.7 19.8 5%
----- ----- ----- --- ----- ----- ----- ---
Total Light products 151.0 262.5 413.5 95% 156.3 198.9 355.2 95%
Residual oil 1.8 7.3 9.1 2% 2.5 1.1 3.6 1%
Petroleum coke and sulfur 6.8 7.5 14.3 3% 7.4 7.4 14.8 4%
----- ----- ----- --- ----- ----- ----- ---
Total production 159.6 277.3 436.9 100% 166.2 207.4 373.6 100%
===== ===== ===== === ===== ===== ===== ===
Six months ended June 30, 2000 Six months ended June 30, 2001
--------------------------------------- ----------------------------------------
Selected Volumetric Data Port Total Port Total
(in thousands of barrels per day) Arthur Midwest Total Percent Arthur Midwest Total Percent
------ ------- ----- ------- ------ ------- ----- -------
Feedstocks:
Crude oil throughput
Sweet 4.3 197.9 202.2 46% -- 141.7 141.7 37%
Light/Medium sour 121.0 47.3 168.3 38% 15.2 66.3 81.5 22%
Heavy sour 31.6 13.1 44.7 10% 33.3 5.5 38.8 10%
----- ----- ----- --- ----- ----- ----- ---
Total crude oil 156.9 258.3 415.2 94% 48.5 213.5 262.0 69%
PACC Intermediate throughput -- -- -- --- 113.5 -- 113.5 30%
Unfinished and blendstocks 24.3 0.3 24.6 6% 7.2 (2.7) 4.5 1%
----- ----- ----- --- ----- ----- ----- ---
Total feedstocks 181.2 258.6 439.8 100% 169.2 210.8 380.0 100%
===== ===== ===== === ===== ===== ===== ===
Production:
Light Products:
Conventional gasoline 63.5 115.8 179.3 40% 81.8 99.3 181.1 47%
Premium and reformulated gasoline 22.8 41.1 63.9 14% 24.9 23.6 48.5 13%
Diesel fuel 47.5 57.3 104.8 24% 37.5 46.2 83.7 22%
Jet fuel 15.7 19.2 34.9 8% (1.8) 21.8 20.0 5%
Petrochemical products 23.2 13.0 36.2 8% 13.2 10.4 23.6 6%
----- ----- ----- --- ----- ----- ----- ---
Total Light products 172.7 246.4 419.1 94% 155.6 201.3 356.9 93%
Residual oil 2.8 6.3 9.1 2% 3.8 2.9 6.7 2%
Petroleum coke and sulfur 9.5 7.3 16.8 4% 11.9 7.0 18.9 5%
----- ----- ----- --- ----- ----- ----- ---
Total production 185.0 260.0 445.0 100% 171.3 211.2 382.5 100%
===== ===== ===== === ===== ===== ===== ===
Blue Island refinery (included in data above):
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2000 2001 2000 2001
------ ------ ------ ------
Total feed stocks 74.4 - 67.9 8.8
Production 74.4 - 67.8 8.6
21
Overview. Net earnings increased $22.0 million to $105.7 million in the
second quarter of 2001 from $83.7 in the corresponding period in 2000. Operating
income increased $83.8 million to $190.1 million in the second quarter of 2001
from $106.3 million in the corresponding period in 2000. Net earnings decreased
$22.1 million to $44.0 million in the first six months of 2001 from $66.1
million in the corresponding period in 2000. Net earnings in the first six
months of 2001 included a $164.0 million pre-tax charge, which represents a
$150.0 million restructuring charge for exit costs associated with the closure
of the refining operations at the Blue Island, Illinois refinery and $14.0
million associated with environmental liabilities for the previously
discontinued retail division. Operating income, excluding the refinery
restructuring and other charges, increased $126.3 million to $237.1 million in
the first six months of 2001 from $110.8 million in the corresponding period in
2000. The increases in operating income, excluding the refinery restructuring
and other charges, were principally due to strong market conditions partially
offset by operational issues. The operating results for 2001 compared to 2000
were also affected by the completion and operation of the heavy oil upgrade
project at the Port Arthur refinery. See "Factors Affecting Comparability" and
"Factors Affecting Operating Results" for a detailed discussion of how the heavy
oil upgrade project has affected our results.
Net Sales and Operating Revenue. Net sales and operating revenues increased
$125.7 million, or 7%, to $1.846 billion in the second quarter of 2001 from
$1.720 billion in the corresponding period in 2000. Net sales and operating
revenues increased $284.0 million, or 9%, to $3.564 billion in the first six
months of 2001 from $3.280 billion in the corresponding period in 2000. These
increases were mainly attributable to the leasing of ancillary units at the Port
Arthur, Texas refinery to our affiliate, Port Arthur Coker Company and an
increase in the volume of crude oil sales that we make from time to time to
advantageously optimize our crude oil slate.
Gross Margin. Gross margin increased $66.9 million to $312.2 million in the
second quarter of 2001 from $245.3 million in the corresponding period in 2000.
Gross margin increased $98.8 million to $479.4 million in the first six months
of 2001 from $380.6 million in the corresponding period in 2000. This increase,
over what was considered a strong 2000 market, was principally due to continued
strong market conditions driven by strong demand going into the summer driving
season accompanied by low domestic inventory levels.
The gross margin was favorably impacted by the improvements in the Gulf
Coast and Chicago crack spreads in both the second quarter and first six months
of 2001 compared to the corresponding periods in 2000. Improvements in the Gulf
Coast crack spread contributed approximately $40 million and $94 million to the
second quarter and first six months of 2001, respectively, compared to the
corresponding periods in 2000. The record high Chicago crack spreads also
favorably impacted gross margin at our Lima and Hartford refineries.
Gross margin was also favorably impacted by the improvement in the sour and
heavy sour crude oil discounts for the second quarter and first six months of
2001 compared to the corresponding periods in 2000, but was partially offset by
the use of more expensive intermediate feedstocks for approximately 70% of our
throughput at our Port Arthur refinery. Gross margin also increased due to
lease, supplies and service revenue generated by our intercompany agreements
with Port Arthur Coker Company. Partially offsetting the improvements to gross
margin was the effects of producing less higher-value products at our Port
Arthur refinery due to the changes in product mix as discussed in "Factors
Affecting Operating Results" above.
Our Port Arthur refinery financial results were greatly impacted in the
second quarter and first six months of 2001 compared to 2000 by the completion
of the heavy oil upgrade project. The feedstock throughput rates for our
operations reflected the change in operations due to the completion of the heavy
oil upgrade project and start up of operations at Port Arthur Coker Company.
Feedstock throughput rates were 165,500 bpd and 162,000 bpd for the second
quarter and first six months of 2001, respectively. Of these feedstock
throughput rates 40,800 bpd and 48,500 bpd for the second quarter and first six
months of 2001, respectively were crude oil. The remainder of the feedstock
throughout was intermediate feedstock purchased from Port Arthur Coker Company.
Feedstock throughput rates in the
22
second quarter of 2001 were restricted due to a lightning strike in early May,
which limited the crude unit rate through the balance of the second quarter. The
crude unit was shutdown in early July for 10 days to repair the damage caused by
the lightning strike. Feedstock throughput rates in the first six months of 2001
were restricted due to the lightening strike plus restrictions on the crude unit
as downstream process units were in start-up operations during the first
quarter. In the first quarter of 2001, the Port Arthur refinery performed a
planned maintenance turnaround on its alkylation unit, which had only a minor
impact on production. Crude oil throughput rates at the Port Arthur refinery
were significantly reduced in the second quarter of 2000 by a planned 33-day
maintenance turnaround of the crude unit and subsequent unscheduled 11-day
downtime of the crude unit due to a fire.
In the second quarter, the Lima and Hartford refineries experienced some
minor unplanned downtime, but overall crude oil throughput rates were higher
than prior year rates. In March 2001, the Lima refinery performed a month-long
maintenance turnaround on the coker and isocracker units. Midwest crude oil
throughput rates in the first six months of 2001 were below capacity principally
due to crude oil delivery delays to the Lima refinery caused by bad weather in
the Gulf Coast, unplanned downtime at the Hartford refinery for coker unit
repairs, and the closure of the Blue Island refinery on January 31, 2001. In the
first six months of 2000, Midwest crude oil throughput rates were lowered by
planned restrictions due to weak margin conditions, unplanned downtime at the
Lima refinery due to two electrical outages and a failed compressor, and
unplanned downtime at the Blue Island refinery, which required maintenance on
its vacuum and crude unit.
Operating Expenses. Operating expenses decreased $20.6 million to $88.9
million in the second quarter of 2001 from $109.5 million in the corresponding
period in 2000. Operating expenses decreased $33.1 million to $180.6 million in
the first six months of 2001 from $213.7 million in the corresponding period in
2000. This decrease in the second quarter was principally due to the supply and
service fees collected from Port Arthur Coker Company based on the intercompany
agreements, lower repair and maintenance costs at the Port Arthur refinery, and
the absence of Blue Island refinery expenses in 2001. In 2000, the Port Arthur
refinery had higher repair and maintenance costs due to the unscheduled downtime
of its crude unit. The decrease for the first six months of 2001 was
attributable to these same reasons partially offset by higher repair and
maintenance expense at the Hartford refinery and higher energy costs at the Lima
refinery. The Hartford refinery incurred the additional repair and maintenance
expenses for the above-mentioned coker unit repairs.
As evidenced by the significant increases in the average natural gas price,
energy costs soared in 2001. Our exposure to this increase was limited in 2001
due to the ability to pass on a significant amount of our Port Arthur refinery
energy costs to Port Arthur Coker Company in relation to the intercompany
agreements surrounding the leasing by Port Arthur Coker Company of approximately
80% of our crude unit and other ancillary unit capacity.
General and Administrative Expenses. General and administrative expenses
increased $3.2 million to $15.5 million in the second quarter of 2001 from $12.3
million in the corresponding period in 2000. General and administrative expenses
increased $4.4 million to $27.1 million in the first six months of 2001 from
$22.7 million in the corresponding period in 2000. This increase was principally
due to a higher incentive bonus accrual in 2001.
Refinery restructuring and other charges. The refinery restructuring and
other charges consisted of $150.0 million related to the January, 2001 closure
of the Blue Island, Illinois refinery and a $14.0 million charge related to the
environmental liability for previously-owned retail properties. The retail
environmental charge of $14 million represents a change in estimate relative to
the Company's clean up obligation regarding the discontinued retail division.
More complete information concerning site by site clean up plans and changing
postures of state regulatory agencies prompted the change in estimate.
Depreciation and Amortization. Depreciation and amortization expenses
increased $0.5 million to $17.7 million in the second quarter of 2001 from $17.2
million in the corresponding period in 2000. Depreciation and amortization
expenses increased $1.2 million to $34.6 million in the first six months of
23
2001 from $33.4 million in the corresponding period in 2000. The increases in
both periods are principally attributable to higher amortization associated with
a second quarter 2000 Port Arthur refinery turnaround. Depreciation for both
periods reflected higher depreciation in 2001 due to the completion of the heavy
oil upgrade project offset by the absence of depreciation for the Blue Island
refinery after its January 2001 closure.
Interest Expense and Finance Income, net. Interest expense and finance
income, net decreased $0.5 million to $19.5 million in the second quarter of
2001 from $20.0 million in the corresponding period in 2000. Interest expense
and finance income, net increased $1.6 million to $41.2 million in the first six
months of 2001 from $39.6 million in the corresponding period in 2000. In the
first six months of 2000 a portion of interest expense was capitalized as part
of the heavy oil upgrade project. The first six months of 2001 does not include
any interest capitalization for the heavy oil upgrade project since the project
was substantially in service and operational at the beginning of 2001.
Income Tax Provision. Income tax provision increased $62.0 million to $62.2
million in the second quarter of 2001 from $0.2 million in the corresponding
period in 2000. Income tax provision decreased $17.7 million to a benefit of
$17.3 million in the first six months of 2001 from a provision of $0.4 million
in the corresponding period in 2000. The increase in the provision for the
second quarter was principally due to an increase in pretax earnings. The
decrease for the first six months of 2001 was principally due to an increase in
pretax income together with the complete reversal of our tax valuation allowance
in the first quarter of 2001. Our pretax earnings going forward will generally
be fully subject to income taxes.
Liquidity and Capital Resources
Cash Flows from Operating Activities
Net cash provided by operating activities for the six months ended June 30,
2001 was $236.6 million compared to cash provided of $111.0 million in the year-
earlier period. The improvement in net cash provided by operating activities
principally resulted from improved operating results. Working capital as of June
30, 2001 was $484.3 million, a 1.95-to-1 current ratio, versus $321.8 million as
of December 31, 2000, a 1.55-to-1 current ratio.
In general, our short-term working capital requirements fluctuate with the
price and payment terms of crude oil and refined petroleum products. The
Refining Group has in place a credit agreement (the "Credit Agreement") which
provides for the issuance of letters of credit up to the lesser of $585 million
or the amount of a borrowing base calculated with respect to the Refining
Group's cash and eligible cash equivalents, eligible investments, eligible
receivables, eligible petroleum inventories, paid but unexpired letters of
credit, and net obligations on swap contracts. The Credit Agreement contains a
sublimit for direct cash borrowings up to $50 million. Borrowings under the
Credit Agreement are secured by a lien on substantially all of the Refining
Group's cash and cash equivalents, receivables, crude oil and refined product
inventories and trademarks. The borrowing base associated with such facility at
June 30, 2001 was $842.2 million with $409.4 million of the facility utilized
for letters of credit. As of June 30, 2001, there were no direct cash borrowings
under the Credit Agreement. In January 2001, the Refining Group received a
waiver regarding the maintenance of a tangible net worth covenant which allows
for the exclusion of a $150 million restructuring charge related to the closure
of the Blue Island refinery The Refining Group was in compliance with all
financial covenants as of June 30, 2001.
In addition, the Refining Group had three separate cash-collateralized
facilities with certain lenders: (i) a $75 million letter of credit facility for
hydrocarbon purchases, (ii) a $50 million facility for issuing letters of credit
to Foster Wheeler in connection with the heavy oil upgrade project, and (iii) a
$20 million letter of credit facility for non-hydrocarbon items. There were no
letters of credit issued against the $75 million and $50 million facilities and
$18.6 against the $20 million facility as of June 30, 2001. All facilities and
agreements were due to expire on June 30, 2001 except the $50 million facility,
which expired on April 30, 2001. In the second quarter of 2001, the Refining
Group extended the expiration date of its $585 million, $75 million, and $20
million facilities from June 30, 2001 to October 31, 2001. In conjunction with
this
24
extension, the $585 million working capital facility was reduced from $625
million at June 30, 2001 and will be reduced by another $30 million at August
31, 2001.
In 1999, the we sold crude oil linefill in the pipeline system supplying
the Lima refinery. An agreement is in place that requires the we to repurchase
approximately 2.4 million barrels of crude oil in this pipeline system in
September 2002 at market prices, unless extended by mutual consent.
Cash Flows from Investing Activities
Cash flows used in investing activities in the six months ended June 30,
2001 were $72.6 million as compared to $97.4 million in the year-earlier period.
Capital expenditures were $41.4 million lower than the same period last year,
primarily due to the ramp-down of the heavy oil upgrade project. Turnaround
costs increased $16.6 million over last year, due to expenditures in 2001 for
planned maintenance at the Port Arthur and Lima refineries.
Cash Flows from Financing Activities
Cash flows used in financing activities for the six months ended June 30,
2001 were $2.5 million as compared to $8.5 million for the same period last
year. The six months ended June 30, 2000 included a balloon payment on a
capitalized lease at the Hartford refinery. The Company continues to evaluate
the most efficient use of capital and, from time to time depending upon market
conditions, may seek to purchase certain of the Company's outstanding debt
securities in the open market or by other means, in each case to the extent
permitted by existing covenant restrictions.
Premcor USA Inc. relies on the Refining Group for substantially all of its
liquidity in order to meet its interest and other costs. Premcor USA Inc. is
required to make semi-annual interest payments on its 10 7/8% Notes due 2005 of
$9.5 million on June 1 and December 1 of each year and expects its other
operating costs to total less than $1 million per year. Premcor USA Inc.
currently pays dividends on its 11 1/2% Exchangeable Preferred Stock in kind.
Premcor USA Inc.'s ability to access the Refining Group's cash flows from
operating activities is limited by covenants governing certain of the Refining
Group's outstanding debt securities. Under the most restrictive covenants, the
Refining Group was able to return additional capital of approximately $49
million to Premcor USA Inc. as of June 30, 2001. Cash, cash equivalents, and
short-term investments owned by Premcor USA Inc. amounted to $33 million at June
30, 2001. These amounts are restricted primarily for financing costs.
Funds generated from operating activities together with existing cash, cash
equivalents and short-term investments and proceeds from asset sales are
expected to be adequate to fund existing requirements for working capital and
capital expenditure programs at the Refining Group for the next year. Due to the
commodity nature of its products, the Company's operating results are subject to
rapid and wide fluctuations. While the Company believes the Refining Group's
maintenance of large cash, cash equivalents and short-term investment balances
and its operating philosophies will be sufficient to provide the Refining Group
with adequate liquidity through the next year, there can be no assurance that
market conditions will not be worse than anticipated. Future working capital,
discretionary capital expenditures, environmentally mandated spending and
acquisitions may require additional debt or equity capital.
New and Proposed Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 1999, the FASB issued
SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities--
Deferral of the Effective Date of FASB Statement No. 133" which delayed the
effective date of SFAS No. 133 for one year to fiscal years beginning after June
15, 2000. In June 2000, the FASB issued SFAS No. 138 "Accounting for Certain
Derivative Instruments and Hedging Activities" which amended various provisions
of SFAS No. 133. We adopted SFAS No. 133, as amended, effective January 1, 2001.
25
The adoption of SFAS No. 133 did not have a material impact on the financial
position or results of operations because we have historically marked to market
all financial instruments used in the implementation of our hedging strategies.
On July 20, 2001 the FASB issued SFAS No. 141 "Business Combinations" and
SFAS No. 142 "Goodwill and Other Intangible Assets". SFAS No. 141, which became
effective on issuance, requires business combinations initiated after June 30,
2001 to be accounted for using the purchase method of accounting and addresses
the initial recording of intangible assets separate from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite lives will not be
amortized, but will be tested at least annually for impairment. Intangible
assets with finite lives will continue to be amortized. SFAS No. 142 is
effective for fiscal years beginning after December 15, 2001. We are in the
process of evaluating the impact of the adoption of these standards on our
financial position and results of operations.
In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset
Retirement Obligations". SFAS No. 143 addresses when a liability should be
recorded for asset retirement obligations and how to measure this liability. The
initial recording of a liability for an asset retirement obligation will require
the recording of a corresponding asset which will be required to be amortized.
SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are
in the process of evaluating the impact of the adoption of this standard on our
financial position and results of operations.
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants ("AICPA") has issued an exposure draft of a
proposed statement of position ("SOP") entitled "Accounting for Certain Costs
and Activities Related to Property, Plant and Equipment." If adopted as
proposed, this SOP would require companies to expense as incurred turnaround
costs, which it terms as "the non-capital portion of major maintenance costs."
Adoption of the proposed SOP would also require that any existing unamortized
turnaround costs be expensed immediately. A turnaround is a periodically
required standard procedure for maintenance of a refinery that involves the
shutdown and inspection of major processing units and generally occurs every
three to five years. Turnaround costs include actual direct and contract labor
and material costs for the overhaul, inspection, and replacement of major
components of refinery processing and support units performed during turnaround.
Turnaround costs, which are included in our consolidated balance sheet in "Other
Assets," are currently amortized on a straight-line basis over the period until
the next scheduled turnaround, beginning the month following completion. The
amortization of turnaround costs is presented as "Amortization" in our
consolidated statements of operations.
The proposed SOP requires adoption for fiscal years beginning after June
15, 2002. If this proposed change were in effect at June 30, 2001, we would have
been required to write-off unamortized turnaround costs of approximately $107
million. Unamortized turnaround costs will change throughout the year as
maintenance turnarounds are performed and past maintenance turnarounds are
amortized. If adopted in its present form, charges related to this proposed
change would be taken in the first quarter of 2003 and would be reported as a
cumulative effect of an accounting change, net of tax, in the consolidated
statements of operations.
26
PART II - OTHER INFORMATION
ITEM 1. - Legal Proceedings
The following is an update of developments during the quarter of material
pending legal proceedings to which we or any of our subsidiaries are a party or
to which any of our or their property is subject, including environmental
proceedings that involve potential monetary sanctions of $100,000 or more and to
which a governmental authority is a party.
Hartford Federal Enforcement. In February 1999, we were served with a
complaint in the matter United States v. Clark Refining & Marketing, Inc.,
alleging violations of the Clean Air Act and regulations promulgated thereunder,
in the operation and permitting of the Hartford refinery fluid catalytic
cracking unit. The parties settled this matter in July, 2001 by executing a
consent decree which requires installation of a wet gas scrubber on the fluid
catalytic cracking unit at an estimated cost of $8 to $10 million, and low
nitrogen oxide burners at a cost of $1.5 million, and payment of a civil penalty
of $2 million.
Port Arthur Natural Resource Damage Assessment. On June 7, 1999, Premcor
USA and Chevron received a notice from a number of federal and Texas agencies
that a study would be conducted to determine whether any natural resource damage
occurred as a result of the operation of the Port Arthur refinery. We will
cooperate with the government agencies in this investigation. We have reached an
agreement in principle with Chevron pursuant to which Chevron will indemnify us
for the claim in consideration of a payment by us of $750,000.
Port Arthur: Enforcement. The Texas Natural Resources Conservation
Commission, or TNRCC, conducted a site inspection of our Port Arthur refinery in
the spring of 1998. In August 1998, we received a notice of enforcement alleging
47 air-related violations and 13 hazardous waste-related violations. The number
of allegations was significantly reduced in an enforcement determination
response from the TNRCC in April 1999. A follow-up inspection of the refinery in
June 1999 concluded that only two items remained outstanding, namely, that the
refinery failed to maintain the temperature required by our air permit at two of
its incinerators, and that five process wastewater sump vents did not meet
applicable air emission control requirements. The TNRCC also conducted a
complete refinery inspection in the second quarter of 1999, resulting in another
notice of enforcement in August 1999. This notice alleged nine air-related
violations, relating primarily to deficiencies in our upset reports and fugitive
emissions monitoring program, and one hazardous waste-related violation
concerning spills. The 1998 and 1999 notices were combined and referred to the
TNRCC's litigation division. In May 2001, TNRCC proposed an order, covering some
of the 1998 hazardous waste allegations, the incinerator temperature deficiency,
the process wastewater sumps, and all of the 1999 allegations, by payment of a
fine of $562,675 and implementation of a series of technical corrective actions,
that in the aggregate are not expected to exceed a cost of $100,000. We are in
the process of amending our air permit to resolve the incinerator temperature
deficiency without completely replacing our equipment. Prior to the proposed
order, we installed control devices on the wastewater sump vents in 2000 and
performed other requested corrective actions. Negotiations with the TNRCC are
ongoing and are not expected to be resolved in 2001.
Lima: NESHAP Notice of Violations. The National Emission Standards for
Hazardous Air Pollutants, or NESHAP, requires refineries annually to report the
quantity of benzene in their wastewater streams. In 1999, our refinery's
uncontrolled wastewater system contained a quantity of benzene which exceeded
the maximum allowable limit, primarily due to a tank malfunction and a
maintenance turnaround. Accordingly, the Ohio Environmental Protection Agency
issued a notice of violation in December 1999. In July 2001, the Ohio EPA
proposed a settlement of this notice of violation and a separate violation
relating to excessive downtime of our continuous air emission monitor system.
That settlement offer includes mandatory
27
improvements to our continuous air emission monitor system, quality control
procedures, and reporting requirements, and a proposed $120,000 penalty, of
which $24,000 would be applied to a supplemental environmental project we would
agree to perform. This settlement offer recognizes that we have already
implemented corrective actions at a cost of $1.8 million with respect to both
violations by installing additional pumpout systems to more effectively recover
benzene wastewater and to expand our environmental awareness training program.
As of June 30, 2001, we had accrued a total of $67 million for legal and
environmental-related obligations that may result from the matters noted above,
other legal and environmental matters, and obligations associated with certain
retail sites we previously owned. We are of the opinion that the ultimate
resolution of these claims, to the extent not previously provided for, will not
have a material adverse effect on our consolidated financial condition, results
of operations, or liquidity. However, an adverse outcome of any one or more of
these matters could have a material effect on quarterly or annual operating
results or cash flows when resolved in a future period.
In addition to the specific matters discussed above, we also have been
named in various other suits and claims. While it is not possible to estimate
with certainty the ultimate legal and financial liability with respect to these
other legal proceedings, we believe the outcome of these other suits and claims
will not have a material adverse effect on our financial position, results of
operations, or liquidity.
28
ITEM 6 - Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit
Number Description
- ------- -----------
3.1 Restated Certificate of Incorporation of Premcor USA Inc. (formerly known as Clark USA, Inc.)
effective as of December 28, 1994 (Incorporated by reference to Exhibit 3.1 filed with the
Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission File No.
1-13514))
3.2 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of February 23, 1995 (Incorporated by reference to Exhibit 3.2 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.3 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of November 3, 1995 (Incorporated by reference to Exhibit 3.3 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.4 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of October 1, 1997 (Incorporated by reference to Exhibit 3.4 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.5 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of October 1, 1997 (Incorporated by reference to Exhibit 3.5 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.6 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of October 1, 1997 (Incorporated by reference to Exhibit 3.6 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.7 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of January 15, 1998 (Incorporated by reference to Exhibit 3.7 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.8 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of December 28, 1999 (Incorporated by reference to Exhibit 3.8 filed
with the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission
File No. 1-13514))
3.9 Certificate of Amendment of Certificate of Incorporation of Premcor USA Inc. (formerly known as
Clark USA, Inc.) effective as of May 10, 2000 (Incorporated by reference to Exhibit 3.9 filed with
the Company's Annual Report on Form 10-K, for the year ended December 31, 2000 (Commission File
No. 1-13514))
3.10 By-laws of Premcor USA Inc. (formerly known as Clark USA, Inc.) (Incorporated by reference to
Exhibit 3.2 filed with Premcor USA Inc. (formerly known as Clark USA, Inc.) Current Report on
Form 8-K, dated February 27, 1995 (Registration No. 33-59144))
29
Exhibit
Number Description
- ------- -----------
3.11 Certificate of Designations of the Powers, Preferences and Relative, Participating, Optional and
Other Special Rights of 11 1/2% Senior Cumulative Exchangeable Preferred Stock and Qualifications,
Limitations and Restrictions thereof (Incorporated by reference to Exhibit 4.1 filed with Premcor
USA Inc. (formerly known as Clark USA, Inc.) Registration Statement on Form S-4 (Registration
No. 333-42457))
3.12 Certificate of Amendment, dated July 31, 1998, to Certificate of Designation of the Powers, Prefer-
ences and Relative, Participating, Optional and Other Special Rights of 11 1/2% Senior Cumulative
Exchangeable Preferred Stock and Qualifications, Limitations and Restrictions thereof. (Incorporated
by reference to Exhibit 3.8 filed with the Company's Annual Report on Form 10-K, for the year
ended December 31, 1998 (Commission File No. 1-13514))
4.1 Indenture, dated as of October 1, 1997, between Premcor USA Inc. (formerly known as Clark USA,
Inc.) and Bankers Trust Company, as Trustee, including form of 11 1/2% Subordinated Exchange
Debentures due 2009 (Incorporated by reference to Exhibit 4.2 filed with Premcor USA Inc. (formerly
known as Clark USA, Inc.) Registration Statement on Form S-4 (Registration No. 333-42457))
4.2 Supplemental Indenture, dated as of August 10, 1998, to Indenture, dated as of October 1, 1997,
between Premcor USA Inc. (formerly known as Clark USA, Inc.) and Bankers Trust Company, as
Trustee (Incorporated by reference to Exhibit 4.4 filed with the Company's Annual Report on
Form 10-K, for the year ended December 31, 1998 (Commission File No. 1-13514))
4.3 Indenture, dated as of December 1, 1995, between Premcor USA Inc. (formerly known as Clark USA,
Inc.) and The Chase Manhattan Bank, N.A., as Trustee, including the form of 10 7/8% Series B,
Senior Notes due December 1, 2005 (Incorporated by reference to Exhibit 4.1 filed with Premcor
USA Inc. (formerly known as Clark USA, Inc.) Form 8-K, dated December 1, 1995 (File No. 33-59144))
4.4 Supplemental Indenture, dated as of August 10, 1998, to Indenture, dated as of December 1, 1995,
between Premcor USA Inc. (formerly known as Clark USA, Inc.) and The Chase Manhattan Bank,
N.A., as Trustee. (Incorporated by reference to Exhibit 4.6 filed with the Company's Annual Report
on Form 10-K, for the year ended December 31, 1998 (Commission file No. 1-13514))
10.1 First Amendment dated March 1, 2000 to the Amended and Restated Credit Agreement dated as of
November 19, 1999, among The Premcor Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
and Clark Oil & Refining Corporation), Bankers Trust Company, as Administrative and Collateral
Agent, The Toronto-Dominion Bank, as Syndication Agent, BankBoston, N.A., as Documentation Agent,
and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.1
filed with The Premcor Refining Group Inc. Form 10-Q for the quarter ended June 30, 2001
(File No. 1-11392))
10.2 Second Amendment dated September 27, 2000 to the Amended and Restated Credit Agreement dated as of
November 19, 1999, among The Premcor Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
and Clark Oil & Refining Corporation), Bankers Trust Company, as Administrative and Collateral
Agent, The Toronto-Dominion Bank, as Syndication Agent, BankBoston, N.A., as Documentation Agent
and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.2
filed with The Premcor Refining Group Inc. Form 10-Q for the quarter ended June 30, 2001
(File No. 1-11392))
10.3 Third Amendment dated December 31, 2000 to the Amended and Restated Credit Agreement dated as of
November 19, 1999, among The Premcor Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
and Clark Oil & Refining Corporation), Bankers Trust Company, as Administrative and Collateral
Agent, The Toronto-Dominion Bank, as Syndication Agent, BankBoston, N.A. as Documentation Agent,
and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.3
filed with The Premcor Refining Group Inc. Form 10-Q for the quarter ended June 30, 2001
(File No. 1-11392))
30
10.4 Fourth Amendment dated May 11, 2001 to the Amended and Restated Credit Agreement dated as of
November 19, 1999, among The Premcor Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
and Clark Oil & Refining Corporation), Bankers Trust Company, as Administrative and Collateral
Agent,, The Toronto-Dominion Bank, as Syndication Agent, BankBoston, N.A. as Documentation Agent
and the other financial institutions party thereto (Incorporated by reference to Exhibit 10.4
filed with The Premcor Refining Group Inc. Form 10-Q for the quarter ended June 30, 2001
(File No. 1-11392))
(b) Reports on Form 8-K
A report on Form 8-K dated July 13, 2001 (announcing a three year
extension of the collective bargaining agreement with the covered employees
at the Port Arthur, Texas and Lima, Ohio refineries and a settlement with
the U.S. Environmental Protection Agency and the State of Illinois for
alleged civil violations at the Hartford, Ill. refinery) was filed by the
Premcor Refining Group Inc. during the period covered by this report and up
to and including the date of filing of this report.
31
SIGNATURE
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.
PREMCOR USA INC.
(Registrant)
/s/ Dennis R. Eichholz
----------------------------------
Dennis R. Eichholz
Controller (Principal
Accounting Officer and
Duly Authorized Officer)
August 13, 2001
32