Prospectus
Table of Contents
 
Filed pursuant to Rule 424 (b)(1)
Registration No. 333-102087
PROSPECTUS
 
12,500,000 Shares
 
LOGO
 
COMMON STOCK
 
 
Premcor Inc. is offering 12,500,000 shares of its common stock.
 
 
Our common stock is listed on the New York Stock Exchange under the symbol “PCO.” On January 23, 2003, the reported last sale price of our common stock on the New York Stock Exchange was $20.32 per share.
 
 
Investing in our common stock involves risks. See “ Risk Factors” beginning on page 11.
 
 
PRICE $20 A SHARE
 
 
      
Price to
Public
     
Underwriting
Discounts and
Commissions
     
Proceeds to Premcor Inc.
Per Share
     
$20.00
     
$0.80
     
$19.20
Total
     
$250,000,000
     
$10,000,000
     
$240,000,000
 
We have granted the underwriters the right to purchase up to an additional 1,875,000, shares to cover over-allotments.
 
The Securities and Exchange Commission and state securities regulators have not approved or disapproved these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
Morgan Stanley & Co. Incorporated expects to deliver the shares of common stock to purchasers on January 29, 2003.
 
 
MORGAN STANLEY
CREDIT SUISSE FIRST BOSTON
DEUTSCHE BANK SECURITIES
GOLDMAN, SACHS & CO.
 
January 23, 2003

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[Inside front cover artwork and graphics:
 
At the top of the page is a heading with the words “Premcor Inc. Refining Assets Base”. At the center of the page is a map showing the location of our two refineries and our terminal, and four third-party owned pipelines we use. In the upper right corner, there is a photograph of our Lima, Ohio refinery accompanied by the caption “Lima refinery complex — Lima, Ohio”; in the lower left corner, there is a photograph of our Port Arthur, Texas refinery accompanied by the caption “Port Arthur refinery complex — Port Arthur, Texas”; in the lower right corner, there is a photograph of a portion of our Port Arthur, Texas refinery accompanied by the caption “Port Arthur heavy oil upgrade project — Port Arthur, Texas”. Below this photograph, in the extreme lower right hand corner, is the legend for the map which contains the following text: “Premcor Refineries”, “Premcor Terminal” and “Third-party owned Pipelines”.]

Table of Contents
TABLE OF CONTENTS
 
    
Page
  
  1
  
11
  
22
  
23
  
27
  
28
  
29
  
30
  
33
  
65
  
69
 
    
Page
  
  97
  
116
  
117
  
119
  
123
  
128
  
130
  
132
  
135
  
135
  
135
  
136
  
F-1
 
You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. We are offering to sell, and seeking offers to buy, shares of common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock.

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PROSPECTUS SUMMARY
 
This summary may not contain all the information that may be important to you. You should read the entire prospectus, including the “Risk Factors” section and our financial statements and notes to those statements, before deciding whether to buy our common stock. As used in this prospectus, the terms “we,” “our,” or “us” refer to Premcor Inc. and its consolidated subsidiaries, taken as a whole, and our predecessors, unless the context otherwise indicates. Premcor Inc. should be distinguished from its subsidiaries, including Premcor USA Inc., The Premcor Refining Group Inc. and Port Arthur Finance Corp., each of which has publicly traded debt outstanding. Because of the technical nature of our industry, we have included a Glossary of Selected Terms that explains many of the terms we use in this prospectus.
 
PREMCOR INC.
 
Overview
 
We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. We currently own and operate refineries in Port Arthur, Texas and Lima, Ohio with a combined crude oil volume processing capability, known as throughput capacity, of approximately 420,000 barrels per day, or bpd. In late September 2002, we ceased refining operations at our Hartford, Illinois refinery and we are currently pursuing all strategic options with respect to the refinery. We sell petroleum products in the Midwest, the Gulf Coast, eastern and southeastern United States. We sell our products on an unbranded basis to approximately 750 distributors and chain retailers through our own product distribution system and an extensive third-party owned product distribution system, as well as in the spot market.
 
Our Port Arthur refinery has the capacity to process substantial volumes of low-cost high-sulfur and high-density crude oil, known as sour and heavy sour crude oil. This results in lower feedstock costs and creates a distinct competitive advantage. For the nine months ended September 30, 2002, light products accounted for approximately 90% of our total product volume. For the same period, high-value, premium product grades, such as high octane and reformulated gasoline, low-sulfur diesel and jet fuel, which are the most valuable types of light products, accounted for approximately 40% of our total product volume.
 
We had revenue of $6.4 billion in 2001, a decrease of 12% compared to 2000. During 2001, our net income available to common stockholders was $142.6 million, an increase of $62.5 million compared to 2000, and our adjusted EBITDA was $635.1 million, an increase of $416.6 million compared to 2000. Adjusted EBITDA for 2001 represents EBITDA excluding $167.2 million of charges related to the closure of our Blue Island, Illinois refinery and $9.0 million of other charges. We had revenue of $4.8 billion for the nine months ended September 30, 2002, a 7% decrease compared to the corresponding period in the previous year. For the nine months ended September 30, 2002, our net loss to common stockholders was $164.3 million compared to net income available to common stockholders of $187.1 million in the corresponding period in the previous year. For the nine months ended September 30, 2002, our adjusted EBITDA was $75.4 million compared to $636.1 million in the corresponding period in the previous year. Adjusted EBITDA excluded charges of $172.9 million and $176.2 million for the nine months ended September 30, 2002 and 2001, respectively, principally related to the closure of the Hartford and Blue Island refineries. For further detail on our results of operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
The Transformation of Premcor
 
Beginning in early 1995 and continuing after Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, or Blackstone, acquired its controlling interest in us in 1997, we completed several strategic

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initiatives that have significantly enhanced our competitive position, the quality of our assets, and our financial and operating performance. For example:
 
 
•
 
We divested non-core assets during 1998 and 1999, generating net proceeds of approximately $325 million, which we reinvested into our refining business.
 
 
•
 
We increased our net crude oil throughput capacity from approximately 130,000 bpd to 420,000 bpd after closing two refineries by acquiring our Lima and Port Arthur refineries and subsequently upgrading our Port Arthur refinery.
 
 
•
 
We implemented capital projects to increase throughput and premium product yields and to reduce operating expenses within our refining asset base. These projects, together with our acquisitions, increased our coking capacity from 18,000 bpd to 113,000 bpd, increased our cracking capacity from 70,000 bpd to 178,000 bpd, and increased our capacity to process heavy sour crude oil from 45,000 bpd to 200,000 bpd.
 
 
•
 
We implemented a number of programs which increased the reliability of our operations and improved our safety performance, resulting in a reduction of our recordable injury rate from 3.12 to 1.14 per 200,000 hours worked.
 
 
•
 
We expanded and enhanced our capabilities to supply fuels, on an unbranded basis, to include the Midwest, Gulf Coast, eastern and southeastern United States.
 
 
•
 
We reduced our operating costs, which resulted in a reduction of our ratio of refining employees per thousand barrels from 7.2 to 3.4.
 
In February 2002, we recruited Mr. Thomas D. O’Malley, a chief executive officer with a proven track record of successfully operating businesses and growing and enhancing shareholder value. Since then, Mr. O’Malley has assembled a management team of energy and refining industry veterans to lead our company and our competitive position has continued to improve as a result of the following:
 
 
•
 
We raised $481.7 million in an initial public offering of 20.7 million shares of our common stock and a concurrent private placement of 850,000 shares of our common stock in May 2002.
 
 
•
 
We repaid $579.0 million of our subsidiaries’ long-term debt.
 
 
•
 
We completed an internal restructuring in June 2002, which resulted in Sabine River Holding Corp. becoming our wholly-owned subsidiary.
 
 
•
 
We ceased refining operations at our Hartford, Illinois refinery in late September 2002 after concluding it was uneconomical to reconfigure the refinery to meet new federally mandated fuel specification standards.
 
 
•
 
We entered into an agreement with The Williams Companies, Inc. and certain of its subsidiaries in November 2002 for the purchase of their Memphis, Tennessee refinery and related supply and distribution assets.
 
 
•
 
We have taken, and are continuing to take, steps to reduce our operating and general and administrative costs.
 
For further detail on our transformation, see “Business—The Transformation of Premcor.”
 
Market Trends
 
We believe that the outlook for the United States refining industry is attractive due to certain significant trends that we have identified. We believe that:
 
 
•
 
The supply and demand fundamentals for refined petroleum products have improved since the late 1990s and will continue to improve.

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•
 
Increasing worldwide supplies of lower-cost sour and heavy sour crude oil will provide an increasing cost advantage to those refineries with complex configurations that are able to process these crude oils.
 
 
•
 
Products meeting new and evolving fuel specifications will account for an increasing share of total fuel demand, which will benefit refiners possessing the capabilities to blend and process these fuels.
 
 
•
 
The continuing consolidation in the refining industry should create further attractive opportunities to acquire competitive refining capacity.
 
For further detail on market trends, see “Business—Market Trends.”
 
Competitive Strengths
 
As a result of our transformation, we have developed the following strengths:
 
 
•
 
As a “pure-play” refiner, which is a refiner without crude oil exploration and production or retail sales operations, we are free to supply our products to markets having the greatest profit potential and to focus our management attention and capital solely on refining.
 
 
•
 
Our Port Arthur and Lima refineries are logistically well-located modern facilities of significant size and scope with access to a wide variety of crude oils and product distribution systems.
 
 
•
 
Our Port Arthur refinery has significant heavy sour crude oil processing capacity, giving us a cost advantage over other refiners that are not able to process high volumes of these less expensive crude oils.
 
 
•
 
We have a long-term heavy sour crude oil supply agreement with an affiliate of Petroleos Mexicanos, or PEMEX, the Mexican state oil company, that contains a mechanism intended to provide us with a minimum average coker gross margin and to moderate fluctuations in coker gross margins.
 
 
•
 
We have an experienced and committed management team led by Thomas D. O’Malley, a refining industry veteran with a proven track record of growing businesses and shareholder value through acquisitions.
 
For further detail on our competitive strengths, see “Business—Competitive Strengths.”
 
Business Strategies
 
Our goal is to be a premier independent refiner and supplier of unbranded petroleum products in the United States and to be an industry leader in growing shareholder value. We intend to accomplish this goal, grow our business, enhance earnings and improve our return on capital by executing the following strategies:
 
 
•
 
We intend to grow through timely and cost-effective acquisitions and by undertaking discretionary capital projects to improve, upgrade and potentially expand our refineries.
 
 
•
 
We will continue to promote excellence in safety and reliability at our operations.
 
 
•
 
We intend to create an organization in which employees are highly motivated to enhance earnings and improve return on capital.
 
For further detail on our business strategies, see “Business—Business Strategies.”

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Memphis Refinery Acquisition
 
On November 25, 2002, we executed an agreement with The Williams Companies, Inc. and certain of its subsidiaries to purchase their Memphis, Tennessee refinery and related supply and distribution assets. The purchase price for the refinery and the other assets is $315 million, plus the value of inventories at closing. At current price levels, the value of the inventories is estimated to be $200 million. The agreement also provides for contingent participation, or earn-out, payments that could result in additional payments of $75 million by us to Williams over the next seven years, depending on the level of industry refining margins during that period.
 
The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd but typically processes approximately 170,000 bpd. The related assets include two truck-loading racks; three petroleum terminals in the area; supporting pipeline infrastructure that transports both crude oil and refined products; crude oil tankage at St. James, Louisiana; and an 80 megawatt power plant adjacent to the refinery.
 
We believe we are acquiring a quality refinery at an attractive price that will produce operating and economic synergies and that should be accretive to our earnings per share and generate positive cash flow from operations. Completion of the acquisition is subject to our obtaining the requisite financing and the satisfaction of customary conditions, including regulatory approvals. We intend to finance the acquisition with the proceeds from this offering and the other financing transactions described below. We expect the acquisition to close during the first quarter of 2003.
 
Other Financing Transactions
 
Debt Financing.    Concurrently with this offering, our subsidiary, The Premcor Refining Group Inc., or PRG, is offering $400 million aggregate principal amount of senior notes due 2010 and 2013. The senior notes are being offered in an offering that is exempt from the registration requirements of the Securities Act. This prospectus shall not be deemed to be an offer to sell or a solicitation of an offer to buy the senior notes.
 
 
Neither the offering made hereby nor the debt financing is contingent on the other or upon the closing of the Memphis refinery acquisition. However, the debt financing is contingent upon us obtaining various waivers and approvals under, and extending the maturity date of, our credit agreement. See “Description of Indebtedness—The Premcor Refining Group Credit Agreement.”
 
Private Equity Commitment.    We have the right to sell in a private placement up to $65 million of our common stock to Blackstone, to an affiliate of Occidental Petroleum Corporation, and to Mr. O’Malley, our chairman of the board and chief executive officer, or other executive officers designated by Mr. O’Malley who agree to participate, at a price per share equal to the public offering price in this offering, less the underwriting discount and commission per share. We expect that we will exercise this right and sell a substantial portion of such common stock. Any shares sold in the private equity commitment will be sold without registration under the securities laws. Unless we indicate otherwise, the information in this prospectus does not give effect to the sale of any shares of common stock in the private equity commitment.
 
Risks Relating to Our Business
 
As part of your evaluation of our company, you should take into account the risks we face in our business and not solely our outlook for the refining industry, our competitive strengths or our business strategies. For example, our position as a “pure-play” refiner exposes us to volatility in refining industry margins; our long-term heavy sour crude oil supply agreement renders us highly dependent upon that supply, which could be interrupted by events beyond the control of us or the supplier; and our strategy of growing through acquisitions and by undertaking discretionary capital projects involves many factors beyond our control. See “Risk Factors” for a more detailed discussion of factors you should carefully consider before deciding to invest in shares of our common stock.

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Fourth Quarter and Year-end Results (Unaudited)
 
The following table is a summary of our unaudited financial results for the quarter and year ended December 31, 2002 as compared to the same periods in 2001:
 
    
Three months ended December 31,
     
Year ended December 31,
  
    
2001
     
2002
     
2001
     
2002
  
    
(in millions, except per share data, unaudited)
  
Financial Results
                                    
Income (loss) from continuing operations before income taxes and minority interest
   
$
(58.4
)
   
$
53.3
 
   
$
236.2
 
   
$
(210.1
)
Income tax benefit (provision)
   
 
26.3
 
   
 
(18.6
)
   
 
(52.4
)
   
 
81.3
 
Minority interest
   
 
(0.4
)
   
 
—  
 
   
 
(12.8
)
   
 
1.7
 
    
  
  
  
Income (loss) from continuing operations
   
 
(32.5
)
   
 
34.7
 
   
 
171.0
 
   
 
(127.1
)
Discontinued operations, net of tax benefit
   
 
(9.5
)
   
 
—  
 
   
 
(18.0
)
   
 
—  
 
Preferred stock dividends
   
 
(2.5
)
   
 
—  
 
   
 
(10.4
)
   
 
(2.5
)
    
  
  
  
Net income (loss) available to common stockholders
   
$
(44.5
)
   
$
34.7
 
   
$
142.6
 
   
$
(129.6
)
    
  
  
  
Net income (loss) per common share (fully diluted):
                                    
Income (loss) from continuing operations
   
$
(1.10
)
   
$
0.60
 
   
$
4.65
 
   
$
(2.65
)
Discontinued operations
   
 
(0.30
)
   
 
—  
 
   
 
(0.52
)
   
 
—  
 
    
  
  
  
Net income (loss)
   
$
(1.40
)
   
$
0.60
 
   
$
4.13
 
   
$
(2.65
)
    
  
  
  
Weighted average common shares outstanding (in millions)
   
 
31.8
 
   
 
58.1
 
   
 
34.5
 
   
 
49.0
 
Selected Operational Data
                                    
Crude oil throughput (in thousands of barrels per day)
   
 
443.3
 
   
 
354.9
 
   
 
439.7
 
   
 
412.8
 
Per barrel of throughput (in dollars):
                                    
Gross margin
   
$
3.16
 
   
$
6.33
 
   
$
7.27
 
   
$
4.45
 
Operating expenses
   
 
2.74
 
   
 
2.88
 
   
 
2.91
 
   
 
2.87
 
Market Indicators
                                    
(dollars per barrel, except as noted)
                                    
West Texas Intermediate (WTI) crude oil
   
$
20.32
 
   
$
28.30
 
   
$
25.96
 
   
$
26.13
 
Crack Spreads:
                                    
Gulf Coast 3/2/1
   
 
1.94
 
   
 
3.72
 
   
 
4.22
 
   
 
3.13
 
Gulf Coast 2/1/1
   
 
2.08
 
   
 
3.61
 
   
 
3.92
 
   
 
2.72
 
Chicago 3/2/1
   
 
4.49
 
   
 
6.24
 
   
 
7.90
 
   
 
5.00
 
Crude Oil Differentials:
                                    
WTI less WTS (sour)
   
 
1.91
 
   
 
1.72
 
   
 
2.81
 
   
 
1.38
 
WTI less Maya (heavy sour)
   
 
6.33
 
   
 
6.14
 
   
 
8.76
 
   
 
5.21
 
WTI less Dated Brent (foreign)
   
 
0.87
 
   
 
1.46
 
   
 
1.48
 
   
 
1.12
 
Natural Gas (per million btus)
   
 
2.17
 
   
 
3.92
 
   
 
4.22
 
   
 
3.17
 
 
Our net income (loss) available to common stockholders improved from a loss of $44.5 million, or $1.40 per share, for the fourth quarter ended December 31, 2001 to income of $34.7 million, or $.60 per share, for the 2002 fourth quarter. This improvement was due primarily to improved crack spreads in both the Gulf Coast and Chicago markets, partially offset by lower crude oil throughput rates as a result of refinery disruptions due to hurricanes, scheduled and unscheduled maintenance, and the closure of our Hartford, Illinois refinery at the

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beginning of the quarter. Additionally, our earnings improved as a result of reductions in non-energy related operating expenses and our general and administrative expenses, and a decline in our interest expense due to the application of proceeds from our initial public offering to retire long-term debt.
 
Net income (loss) available to common stockholders for the year ended December 31, 2002 was a loss of $129.6 million, or $2.65 per share, compared to earnings of $142.6 million, or $4.13 per share, for the year ended December 31, 2001. Our operating results declined from the prior year due primarily to a decline in crack spreads and a substantial narrowing of the heavy sour crude oil differential. Our pretax results included restructuring and other charges totaling $172.9 million and $176.2 million for the years ended December 31, 2002 and 2001, respectively. For 2002, these charges included $137.4 million related to the closure of the Hartford refinery, $27.4 million primarily for severance and other charges related to the restructuring of our Port Arthur, Texas and Lima, Ohio refineries and our St. Louis general and administrative operations, $2.5 million related to the restructuring of two of our subsidiaries, $1.4 million for idled equipment, and $4.2 million related to the write-off of an equity investment. For 2001, restructuring charges included $167.2 million for the closure of our Blue Island, Illinois refinery and $9.0 million for idled equipment.
 
****
 
Our principal executive offices are located at 1700 E. Putnam Avenue, Suite 500, Old Greenwich, CT 06870 and our telephone number is (203) 698-7500.
 

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THE OFFERING
 
Common stock offered
12,500,000 shares
 
Common stock to be outstanding after this offering
70,543,935 shares
 
Over-allotment option
1,875,000 shares
 
Use of proceeds
We expect to receive net proceeds from the sale of shares of our common stock in this offering of approximately $239.0 million, or $275.0 million if the underwriters exercise their over-allotment option in full. We intend to use the net proceeds from this offering and the other financing transactions to finance the Memphis refinery acquisition and to refinance certain indebtedness of our subsidiaries.
 
Dividend policy
We do not expect to pay dividends on our shares of common stock for the foreseeable future.
 
New York Stock Exchange symbol
“PCO”
 
The number of shares of common stock to be outstanding after this offering is based on 58,043,935 shares outstanding as of December 31, 2002 and, unless we indicate otherwise, excludes:
 
 
•
 
4,589,480 shares issuable upon the exercise of stock options held by our directors, employees and former employees which were outstanding as of December 31, 2002, with exercise prices ranging from $9.90 to $24.95 per share;
 
 
•
 
an additional 1,967,575 shares authorized and reserved for issuance to our directors or employees under our stock incentive plans and other agreements; and
 
 
•
 
shares that the underwriters have the option to purchase from us solely to cover over-allotments.

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SUMMARY FINANCIAL DATA
 
The following table presents summary financial and other data about us. The summary statement of earnings and cash flow data for the years ended December 31, 1999, 2000 and 2001 are derived from our audited consolidated financial statements, including the notes thereto, appearing elsewhere in this prospectus. The summary statement of earnings and cash flow data for the nine months ended September 30, 2001 and 2002, and the balance sheet data as of September 30, 2002, are derived from our unaudited condensed consolidated financial statements, including the notes thereto, appearing elsewhere in this prospectus. The interim information was prepared on a basis consistent with that used in preparing our audited financial statements with only such recurring adjustments as are necessary, in management’s opinion, for a fair statement of the results for the periods presented. The as adjusted balance sheet data give effect to this offering, the debt financing and the use of proceeds as if each had occurred on September 30, 2002. This table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements, including the notes thereto, appearing elsewhere in this prospectus.
 
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1999
     
2000
     
2001
     
2001
     
2002
  
    
(in millions, except per share data)
  
Statement of earnings data:
                                             
Net sales and operating revenues
   
$
  4,520.5
 
   
$
  7,301.7
 
   
$
  6,417.5
 
   
$
  5,170.9
 
   
$
  4,807.1
 
Cost of sales
   
 
4,099.8
 
   
 
6,562.5
 
   
 
5,251.4
 
   
 
4,133.7
 
   
 
4,342.8
 
    
  
  
  
  
Gross margin
   
 
420.7
 
   
 
739.2
 
   
 
1,166.1
 
   
 
1,037.2
 
   
 
464.3
 
Operating expenses(1)
   
 
402.8
 
   
 
467.7
 
   
 
467.7
 
   
 
355.8
 
   
 
338.2
 
General and administrative expenses(1)
   
 
51.5
 
   
 
53.0
 
   
 
63.3
 
   
 
45.3
 
   
 
40.8
 
Stock option compensation expense
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
9.9
 
Depreciation and amortization(2)
   
 
63.1
 
   
 
71.8
 
   
 
91.9
 
   
 
67.7
 
   
 
64.9
 
Inventory recovery from market write-down
   
 
(105.8
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Refinery restructuring and other charges
   
 
—  
 
   
 
—  
 
   
 
176.2
 
   
 
176.2
 
   
 
172.9
 
    
  
  
  
  
Operating income (loss)
   
 
9.1
 
   
 
146.7
 
   
 
367.0
 
   
 
392.2
 
   
 
(162.4
)
Interest expense and finance income, net(3)
   
 
(91.5
)
   
 
(82.2
)
   
 
(139.5
)
   
 
(106.3
)
   
 
(81.5
)
Gain (loss) on extinguishment of long-term debt(4)
   
 
—  
 
   
 
—  
 
   
 
8.7
 
   
 
8.7
 
   
 
(19.5
)
Income tax (provision) benefit
   
 
12.0
 
   
 
25.8
 
   
 
(52.4
)
   
 
(78.7
)
   
 
99.9
 
Minority interest in subsidiary
   
 
1.4
 
   
 
(0.6
)
   
 
(12.8
)
   
 
(12.4
)
   
 
1.7
 
    
  
  
  
  
Income (loss) from continuing operations
   
 
(69.0
)
   
 
89.7
 
   
 
171.0
 
   
 
203.5
 
   
 
(161.8
)
Discontinued operations, net of taxes(5)
   
 
32.6
 
   
 
—  
 
   
 
(18.0
)
   
 
(8.5
)
   
 
—  
 
    
  
  
  
  
Net income (loss)
   
 
(36.4
)
   
 
89.7
 
   
 
153.0
 
   
 
195.0
 
   
 
(161.8
)
Preferred stock dividends
   
 
(8.6
)
   
 
(9.6
)
   
 
(10.4
)
   
 
(7.9
)
   
 
(2.5
)
    
  
  
  
  
Net income (loss) available to common stockholders
   
$
(45.0
)
   
$
80.1
 
   
$
142.6
 
   
$
187.1
 
   
$
(164.3
)
    
  
  
  
  
Income (loss) from continuing operations per share:
                                             
—basic
   
$
(3.59
)
   
$
2.79
 
   
$
5.05
 
   
$
6.15
 
   
$
(3.57
)
—diluted
   
 
(3.59
)
   
 
2.55
 
   
 
4.65
 
   
 
5.67
 
   
 
(3.57
)
Weighted average number of common shares outstanding:
                                             
—basic
   
 
21.6
 
   
 
28.8
 
   
 
31.8
 
   
 
31.8
 
   
 
46.0
 
—diluted
   
 
21.6
 
   
 
31.5
 
   
 
34.5
 
   
 
34.5
 
   
 
46.0
 

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Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1999
     
2000
     
2001
     
2001
     
2002
  
    
(in millions, except as noted)
  
Cash flow data:
                                             
Cash flow from operating activities
   
$
85.5
 
   
$
124.4
 
   
$
439.2
 
   
$
  390.2
 
   
$
(42.2
)
Cash flow from investing activities
   
 
(321.3
)
   
 
(375.3
)
   
 
(152.9
)
   
 
(98.5
)
   
 
(91.8
)
Cash flow from financing activities
   
 
393.9
 
   
 
234.8
 
   
 
(66.3
)
   
 
(68.8
)
   
 
(219.8
)
EBITDA(6)
   
 
72.2
 
   
 
218.5
 
   
 
458.9
 
   
 
459.9
 
   
 
(97.5
)
Adjusted EBITDA(7)
   
 
(33.6
)
   
 
218.5
 
   
 
635.1
 
   
 
636.1
 
   
 
75.4
 
                                              
Capital expenditures for property, plant and equipment
   
 
438.2
 
   
 
390.7
 
   
 
94.5
 
   
 
57.8
 
   
 
64.1
 
Capital expenditures for turnarounds
   
 
77.9
 
   
 
31.5
 
   
 
49.2
 
   
 
41.3
 
   
 
33.4
 
Key operating statistics:
                                             
Production (barrels per day in thousands)
   
 
460.5
 
   
 
477.3
 
   
 
463.4
 
   
 
459.6
 
   
 
454.8
 
Crude oil throughput (barrels per day in thousands)
   
 
451.7
 
   
 
468.0
 
   
 
439.7
 
   
 
438.8
 
   
 
432.4
 
Per barrel of crude oil throughput:
                                             
Gross margin
   
$
2.55
 
   
$
4.32
 
   
$
7.27
 
   
$
8.66
 
   
$
3.93
 
Operating expenses
   
 
2.44
 
   
 
2.73
 
   
 
2.91
 
   
 
2.97
 
   
 
2.87
 
 
    
As of September 30,
2002
    
Actual
   
As Adjusted
    
(in millions)
Balance sheet data:
              
Cash, cash equivalents and short-term investments(8)
   
$
209.9
   
$
226.5
Working capital
   
 
291.7
   
 
308.3
Total assets
   
 
2,292.5
   
 
2,649.1
Total debt
   
 
925.3
   
 
1,045.2
Stockholders’ equity
   
 
658.6
   
 
895.4
(1)
 
Certain reclassifications have been made to prior period amounts to conform them to current period presentation.
 
(2)
 
Amortization includes amortization of turnaround costs. However, this may not be permitted under generally accepted accounting principles, or GAAP, in future periods. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Accounting Standards—Critical Accounting Standards.”
 
(3)
 
Interest expense and finance income, net, includes amortization of debt issuance costs of $7.9 million, $12.4 million, $14.9 million, $10.9 million and $9.5 million for the years ended December 31, 1999, 2000 and 2001, and for the nine months ended September 30, 2001 and 2002, respectively. Interest expense and finance income, net, also includes interest on all indebtedness, net of capitalized interest and interest income.
 
(4)
 
In the second quarter of 2002, we elected the early adoption of SFAS No. 145 and, accordingly, have included the gain (loss) on extinguishment of long-term debt in “Income from continuing operations” as opposed to as an extraordinary item, net of taxes, below “Income from continuing operations” in our statement of operations. We have accordingly restated our statement of operations and statement of cash flow for 2001.
 
(5)
 
Discontinued operations is net of an income tax provision of $21.0 million in 1999, and income tax benefits of $11.5 million and $8.5 million in 2001 and for the nine months ended September 30, 2001, respectively.
 
(6)
 
Earnings before interest, taxes, depreciation and amortization, or EBITDA, is a commonly used non-GAAP financial measure but should not be construed as an alternative to operating income or net income as an indicator of our performance, nor as an alternative to cash flow from operating activities, investing activities

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or financing activities as a measure of liquidity, in each case as such measures are determined in accordance with GAAP. EBITDA is presented because we believe that it is a useful indicator of a company’s ability to incur and service debt. EBITDA, as we calculate it, may not be comparable to similarly-titled measures reported by other companies.
 
(7)
 
Adjusted EBITDA represents EBITDA excluding refinery restructuring and other charges of $176.2 million in 2001, $176.2 million in the nine months ended September 30, 2001, and $172.9 million in the nine months ended September 30, 2002, and an inventory recovery from market write-down of $105.8 million in 1999. The $176.2 million charge in the full year of 2001 and in the nine months ended September 30, 2001 included $167.2 million related to the closure of our Blue Island refinery. For the nine months ended September 30, 2002, the charge of $172.9 million included $137.4 million related to the closure of the Hartford refinery. Adjusted EBITDA is presented because we believe it is a useful indicator to our investors of our ability to incur and service debt based on our ongoing operations. Adjusted EBITDA should not be considered by investors as an alternative to operating income or net income as an indicator of our performance, nor as an alternative to cash flow from operating activities, investing activities or financing activities as a measure of liquidity. Because all companies do not calculate EBITDA identically, this presentation of adjusted EBITDA may not be comparable to EBITDA, adjusted EBITDA or other similarly-titled measures of other companies.
 
(8)
 
Cash, cash equivalents and short-term investments includes $51.9 million of cash and cash equivalents restricted for debt service as of September 30, 2002.

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RISK FACTORS
 
An investment in our common stock involves risk. You should consider carefully, in addition to the other information contained in this prospectus, the following risk factors before deciding to purchase any common stock.
 
Risks Related to our Business and our Industry
 
Volatile margins in the refining industry may negatively affect our future operating results and decrease our cash flow.
 
Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire our feedstocks and the price at which we can ultimately sell refined products depend upon a variety of factors beyond our control. Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Future volatility may negatively affect our results of operations, since the margin between refined product prices and feedstock prices may decrease below the amount needed for us to generate net cash flow sufficient for our needs.
 
Specific factors, in no particular order, that may affect our refining margins include:
 
 
•
 
accidents, interruptions in transportation, inclement weather or other events that cause unscheduled shutdowns or otherwise adversely affect our plants, machinery, pipelines or equipment, or those of our suppliers or customers;
 
 
•
 
changes in the cost or availability to us of transportation for feedstocks and refined products;
 
 
•
 
failure to successfully implement our planned capital projects or to realize the benefits expected for those projects;
 
 
•
 
changes in fuel specifications required by environmental and other laws, particularly with respect to oxygenates and sulfur content;
 
 
•
 
rulings, judgments or settlements in litigation or other legal matters, including unexpected environmental remediation or compliance costs at our facilities in excess of any reserves, and claims of product liability or personal injury; and
 
 
•
 
aggregate refinery capacity in our industry to convert heavy sour crude oil into refined products.
 
Other factors that may affect our margins, as well as the margins in our industry in general, include, in no particular order:
 
 
•
 
domestic and worldwide refinery overcapacity or undercapacity;
 
 
•
 
aggregate demand for crude oil and refined products, which is influenced by factors such as weather patterns, including seasonal fluctuations, and demand for specific products such as jet fuel, which may themselves be influenced by acts of God, nature and acts of terrorism;
 
 
•
 
domestic and foreign supplies of crude oil and other feedstocks and domestic supply of refined products, including from imports;
 
 
•
 
the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain oil price and production controls;
 
 
•
 
political conditions in oil producing regions, including the Middle East, Africa and Latin America;
 
 
•
 
refining industry utilization rates;
 
 
•
 
pricing and other actions taken by competitors that impact the market;

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•
 
price, availability and acceptance of alternative fuels;
 
 
•
 
adoption of or modifications to federal, state or foreign environmental, taxation and other laws and regulations;
 
 
•
 
price fluctuations in natural gas and electricity; and
 
 
•
 
general economic conditions.
 
A significant interruption or casualty loss at either of our refineries could reduce our production, particularly if not fully covered by our insurance.
 
Our business currently consists of owning and operating two refineries. As a result, our operations could be subject to significant interruption if either of our refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down. Any such shutdown would reduce the production from that refinery. For example, in late September 2002 and early October 2002, two hurricanes, both of which had paths that brought them through the Gulf Coast region of the United States, caused crude oil delivery delays and the shutdown of various plants and businesses in the region. These hurricanes caused delays in crude oil deliveries to both of our refineries and forced a complete shutdown of the operating units at our Port Arthur refinery for approximately four days. It took several additional days to return all of the Port Arthur units to normal processing amounts. Following the startup of the Port Arthur refinery units, we discovered problems with our reformer unit that we believe were caused by the shutdown and subsequent restart. As a result, we experienced additional crude oil processing limitations and reduced production for approximately two weeks while the reformer unit was repaired. There is also risk of mechanical failure and equipment shutdowns. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. For example, in February 2002, we shut down the coker unit at our Port Arthur refinery for ten days for unplanned maintenance and, as a result of the shutdown, we reduced crude throughput to some of the downstream units for that ten-day period. In the event any of our refineries is forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole. Furthermore, if any of the above events were not fully covered by our insurance, it could have a material adverse effect on our earnings, our other results of operations and our financial condition.
 
Disruption of our ability to obtain crude oil could reduce our margins and our other results of operations.
 
Although we have one long-term crude oil supply contract, the majority of our crude oil supply is acquired under short-term contractual arrangements or in the spot market. Our short-term crude oil supply contracts are terminable on one to three months’ notice. Further, a significant portion of our feedstock requirements is supplied from Latin America, Africa and the Middle East (including Iraq), and we are subject to the political, geographic and economic risks attendant to doing business with suppliers located in those regions. For example, on April 8, 2002, Iraq announced that it was halting all oil exports for a 30-day period. In the event that one or more of our supply contracts is terminated, we may not be able to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are only able to obtain such volumes at unfavorable prices, our margins and our other results of operations could be materially adversely affected.
 
Our Port Arthur refinery is highly dependent upon a PEMEX affiliate for its supply of heavy sour crude oil, which could be interrupted by events beyond the control of PEMEX.
 
For the nine months ended September 30, 2002, we sourced approximately 83% of our Port Arthur refinery’s crude oil from P.M.I. Comercio Internacional, S.A. de C.V., or PMI, an affiliate of PEMEX. Therefore, a large proportion of our crude oil needs is influenced by the adequacy of PEMEX’s crude oil reserves, the estimates of which are not precise and are subject to revision at any time. In the event that PEMEX’s affiliate were to terminate our crude oil supply agreement or default on its supply obligations, we

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would need to obtain heavy sour crude oil from another supplier and would lose the potential benefits of the coker gross margin support mechanism contained in the supply agreement. Alternative supplies of crude oil may not be available or may not be on terms as favorable as those negotiated with PEMEX’s affiliate. In addition, the processing of oil supplied by a third party may require changes to the configuration of our Port Arthur refinery, which could require significant unbudgeted capital expenditures.
 
Furthermore, the obligation of PEMEX’s affiliate to deliver heavy sour crude oil under the agreement may be delayed or excused by the occurrence of conditions and events beyond the reasonable control of PEMEX, such as:
 
 
•
 
extreme weather-related conditions;
 
 
•
 
production or operational difficulties and blockades;
 
 
•
 
embargoes or interruptions, declines or shortages of supply available for export from Mexico, including shortages due to increased domestic demand and other national or international political events; and
 
 
•
 
certain laws, changes in laws, decrees, directives or actions of the government of Mexico.
 
The government of Mexico may direct a reduction in our supply of crude oil, so long as that action is taken in common with proportionately equal supply reductions under its long-term crude oil supply agreements with other parties and the amount by which it reduces the quantity of crude oil to be sold to us shall first be applied to reduce quantities of crude oil scheduled for sale and delivery to our Port Arthur refinery under any other crude oil supply agreement with us or any of our affiliates. Mexico is not a member of OPEC, but in 1998 it agreed with the governments of Saudi Arabia and Venezuela to reduce Mexico’s exports of crude oil by 200,000 bpd. In March 1999, Mexico further agreed to cut exports of crude oil by an additional 125,000 bpd. As a consequence, during 1999, PEMEX reduced its supply of oil under some oil supply contracts by invoking an excuse clause based on governmental action similar to one contained in our long-term crude oil supply agreement. It is possible that PEMEX could reduce our supply of crude oil by similarly invoking the excuse provisions in the future.
 
Competitors who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us.
 
The refining industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. A number of our competitors also have materially greater financial and other resources than we possess. These competitors have a greater ability to bear the economic risks inherent in all phases of the refining industry. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, our financial condition and results of operations, as well as our business prospects, could be materially adversely affected.
 
Our substantial indebtedness may limit our financial flexibility.
 
Our substantial indebtedness has significantly affected our financial flexibility historically and may significantly affect our financial flexibility in the future. As of September 30, 2002, after giving effect to this offering and the debt financing and the use of a portion of these proceeds to refinance certain indebtedness of

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our subsidiaries, we would have had total consolidated debt, including current maturities, of $1,045.2 million and cash, short-term investments and cash restricted for debt service of $226.5 million. On the same basis, we would have had stockholders’ equity of $895.4 million and a total debt to total capitalization ratio of 53.9% as of September 30, 2002. In addition to the debt financings, we or our subsidiaries may incur additional indebtedness in the future, although our ability to do so will be restricted by the terms of our existing indebtedness. In addition to the Memphis refinery acquisition, we are currently evaluating several refinery acquisitions, some of which may be significant. Any future acquisition could also require us to incur additional indebtedness in order to finance all or a portion of such acquisition. The level of our indebtedness has several important consequences for our future operations, including that:
 
 
•
 
a significant portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
 
 
•
 
covenants contained in our existing debt arrangements require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
 
 
•
 
our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited;
 
 
•
 
we may be at a competitive disadvantage to those of our competitors that are less leveraged; and
 
 
•
 
we may be more vulnerable to adverse economic and industry conditions.
 
Restrictive covenants in our subsidiaries’ debt instruments limit our ability to move funds and assets among our subsidiaries and may limit our ability to undertake certain types of transactions.
 
Various covenants in our subsidiaries’ debt instruments and other financing arrangements may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our indebtedness subjects our subsidiaries to significant financial and other restrictive covenants, including restrictions on their ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, enter into certain transactions with affiliates, make certain payments to us, enter into sale and leaseback transactions, conduct businesses other than their current businesses, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of their assets. Some of our subsidiaries’ debt instruments also require them to satisfy or maintain certain financial condition tests. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and they may not meet such tests.
 
We have significant principal payments under our indebtedness coming due in the next several years; we may be unable to repay or refinance such indebtedness.
 
We have significant principal payments due under our debt instruments. After giving effect to this offering and the debt financing and the use of a portion of these proceeds to refinance certain indebtedness of our subsidiaries, we will be required to make the following principal payments on our long-term debt: $14.9   million in 2003; $25.6 million in 2004; $38.5 million in 2005; $46.4 million in 2006; $318.4 million in 2007; and $601.9 million in the aggregate thereafter. In addition to the Memphis refinery acquisition, we are currently evaluating several refinery acquisitions, some of which may be significant. Any future acquisition could also require us to incur additional indebtedness in order to finance all or a portion of such acquisition, and therefore may increase our principal payments coming due in the next several years.
 
Our ability to meet our principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash

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flow from operations to repay our substantial indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
 
Compliance with, and changes in, environmental laws could adversely affect our results of operations and our financial condition.
 
We are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention, remediation of contaminated sites and the characteristics and composition of gasoline and diesel fuels. In addition, some of these laws and regulations require our facilities to operate under permits that are subject to renewal or modification. These laws and regulations and permits can often require expensive pollution control equipment or operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of these laws and regulations or permit conditions can result in substantial fines, criminal sanctions, permit revocations and/or facility shutdowns. Compliance with environmental laws and regulations significantly contributes to our operating costs. In addition, we have made and expect to make substantial capital expenditures on an ongoing basis to comply with environmental laws and regulations.
 
In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional unforeseen expenditures. These expenditures or costs for environmental compliance could have a material adverse effect on our financial condition, results of operations and cash flow. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Flow from Investing Activities.” For example, the United States Environmental Protection Agency, or EPA, has promulgated regulations under the federal Clean Air Act that establish stringent sulfur content specifications for gasoline and low-sulfur highway, or “on-road”, diesel fuel designed to reduce air emissions from the use of these products.
 
In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles mandating that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 parts per million, or ppm, during any calendar year by January 1, 2006 with a phase in of these requirements beginning on January 1, 2004. We currently expect to produce gasoline under the new sulfur standards at the Port Arthur refinery prior to January 1, 2004 and, as a result of the corporate pool averaging provisions of the regulations, will not be required to meet the new sulfur standards at the Lima refinery until July 1, 2004, a six month deferral. A further delay in the requirement to meet the new sulfur standards at the Lima refinery through 2005 may be possible through the purchase of sulfur allotments and credits which arise from a refiner producing gasoline with a sulfur content below specified levels prior to the end of 2005, the end of the phase-in period. There can be no assurances that sufficient allotments or credits to defer investment at the Lima refinery will be available, or if available, at what cost. We believe, based on current estimates and on a January 1, 2004 compliance date for both the Port Arthur and Lima refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures for the Lima and Port Arthur refineries in the aggregate through 2005 of approximately $255 million. More than 95% of the total investment to meet the Tier 2 gasoline specifications is expected to be incurred during 2002 through 2004, with the greatest concentration of spending occurring in 2003.
 
In January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. We estimate capital expenditures in the aggregate through 2006 required to comply with the diesel standards at our Port Arthur and Lima refineries of approximately $245 million. More than 95% of the projected investment is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. Since the Lima refinery does not currently produce diesel fuel to on-road specifications, we are considering an acceleration of the low-sulfur diesel investment at the Lima refinery in order to capture this incremental

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product value. If the investment is accelerated, production of the low-sulfur fuel may begin by the first quarter of 2005. Regulations regarding the sulfur content of off-road diesel are pending. See “Business—Environmental Matters—Environmental Compliance—Fuel Regulations.”
 
In addition, on April 11, 2002, the EPA promulgated regulations to implement Phase II of the petroleum refinery Maximum Achievable Control Technology rule under the federal Clean Air Act, referred to as MACT II, which regulates emissions of hazardous air pollutants from certain refinery units. Based on currently available information, we expect to spend approximately $45 million over the next three years, with the greatest concentration of spending evenly spread out over 2003 and 2004.
 
Based on currently available information, we expect our acquisition of the Memphis refinery to increase our costs of complying with Tier 2 gasoline standards and low sulfur diesel standards by approximately $80 million and $100 million, respectively. The estimated $80 million in spending for Tier 2 gasoline compliance would be incurred during 2003 and 2004. The estimated $100 million in spending for low sulfur diesel compliance would be incurred between 2004 and 2006, with the greatest concentration of spending in 2005. No capital expenditures are expected to be required for MACT II compliance at the Memphis refinery. Any future acquisition could require us to make significant capital expenditures to comply with environmental laws and regulations. There can be no assurances that our internally generated cash flow will be sufficient to support each of the foregoing capital expenditures at all of the facilities.
 
Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our cash flow, reduce our results of operations and impair our financial condition.
 
We are subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own or operate, at certain properties we formerly owned or operated and at off-site locations where we arranged for the disposal of hazardous substances. We are involved in several proceedings or other projects relating to our liability for the investigation and clean-up of such sites. We may become involved in further litigation or other proceedings. If we were to be held responsible for damages in any existing or future litigation or proceedings, such costs may not be covered by insurance and may be material. For example, there is extensive contamination at our Port Arthur refinery site and contamination at our Lima refinery site. Chevron Products Company, the former owner of the Port Arthur refinery, has retained environmental remediation obligations regarding pre-closing contamination for all areas of the refinery except those under or within 100 feet of active processing units, and BP has retained liability for certain environmental costs relating to operations of, or associated with, the Lima refinery site prior to our acquisition of that facility. However, if either of these parties fails to satisfy its obligations for any reason, or if significant liabilities arise in the areas in which we assumed liability, we may become responsible for the remediation. If we are forced to assume liability for the cost of this remediation or other remediation relating to our current or former facilities, such liability could have a material adverse effect on our financial condition. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially adversely affect our financial condition, results of operations and cash flow.
 
In connection with the closure of our Blue Island, Illinois and Hartford, Illinois refineries, we are required to conduct environmental remediation at those facilities. We are currently assessing our remedial obligations at these closed facilities and have an aggregate reserve of $49.6 million as of September 30, 2002. Also, in connection with our sale of certain retail properties and product terminals in 1999, we agreed to indemnify the purchasers for certain environmental conditions arising during our ownership and operation of these assets. Clean-up costs with respect to any of these matters may exceed our estimates, which could, in turn, have a material adverse effect on our financial condition, results of operations and cash flow. In particular, we sold the majority of our former retail properties to Clark Retail Enterprises, Inc., or CRE, which, together with its parent company, Clark Retail Group, has recently filed for Chapter 11 bankruptcy protection. In addition to our obligations under the indemnities, we may be jointly and severally liable for CRE’s obligations under leases for

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these retail locations, including payment of rent and environmental cleanup responsibilities for releases of petroleum occurring during the term of the leases. We may also incur other significant liabilities for environmental obligations at these sites.
 
We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other hazardous substances, such as asbestos and benzene, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination or hazardous substances from our facilities. A significant increase in the number or success of these claims could materially adversely affect our financial condition, results of operations and cash flow. See “Business—Environmental Matters” and “Business—Legal Proceedings” for a description of some of these claims.
 
We have additional capital needs for which our internally generated cash flow may not be adequate; we may have insufficient liquidity to meet those needs.
 
In addition to the capital expenditures we will make to comply with Tier 2 gasoline standards, on-road diesel regulations and MACT II regulations, we have additional short-term and long-term capital needs. Our short-term working capital needs are primarily crude oil purchase requirements, which fluctuate with the pricing and sourcing of crude oil. Our internally generated cash flow and availability under our working capital facilities may not be sufficient to meet these needs. We also have significant long-term needs for cash. We estimate that mandatory capital and turnaround expenditures, excluding the non-recurring capital expenditures required to comply with Tier 2 gasoline standards, on-road diesel regulations and MACT II regulations described above, will be approximately $105 million per year from 2003 through 2006. Based on currently available information, we expect that our acquisition of the Memphis refinery will increase this amount to approximately $153 million annually through 2006 and any other significant acquisition could require us to make additional capital expenditures in this regard. Our internally generated cash flow may not be sufficient to support such capital expenditures.
 
We may not be able to implement successfully our discretionary capital expenditure projects.
 
We could undertake a number of discretionary capital expenditure projects designed to increase the productivity and profitability of our refineries. Many factors beyond our control may prevent or hinder our undertaking of some or all of these projects, including compliance with or liability under environmental regulations, a downturn in refining margins, technical or mechanical problems, lack of availability of capital and other factors. Failure to successfully implement these profit-enhancing strategies may adversely affect our business prospects and competitive position in the industry.
 
A substantial portion of our workforce is unionized and we may face labor disruptions that would interfere with our refinery operations.
 
As of December 1, 2002, we employed 1,413 people, approximately 60% of whom were covered by collective bargaining agreements. The collective bargaining agreement covering employees at our Port Arthur refinery expires in January 2006 and the agreement covering employees at our Lima refinery expires in April 2006. The Memphis refinery employs approximately 320 people, including support personnel. Approximately 50% of those employees are covered by a collective bargaining agreement which expires in January 2006. Our relationships with the relevant unions at our current facilities have been good and we have never experienced a work stoppage as a result of labor disagreements. However, we cannot assure you that this situation will continue. A labor disturbance at any of our refineries could have a material adverse effect on that refinery’s operations.
 
We are controlled by a limited number of stockholders, and in the future there may be conflicts of interest between these stockholders and our other stockholders, who will have less ability to influence our business.
 
After this offering and assuming no shares are sold pursuant to the private equity commitment, Blackstone will beneficially own 39.4% of our common stock, or 38.4% if the underwriters exercise their over-allotment

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option in full, and Occidental will own 11.0% of our common stock, or 10.7% if the underwriters exercise their over-allotment option in full. As a result, each of these stockholders, individually or in conjunction with other stockholders, may be able to control the election of our directors and determine our corporate policies and business strategy, including the approval of potential mergers or acquisitions, asset sales and other significant corporate transactions. Each of these stockholders’ interests may not coincide with the interests of the other holders of our common stock.
 
We have not fully developed or implemented a disaster recovery plan for our information systems, which could adversely affect business operations should a major physical disaster occur.
 
We are dependent upon functioning information systems to conduct our business. A system failure or malfunction may result in an inability to process transactions or lead to a disruption of operations. Although we regularly backup our programs and data, we do not currently have a comprehensive disaster recovery plan providing a hot site facility for immediate system recovery should a major physical disaster occur at our general office, our executive office or at one of our refineries. A comprehensive disaster recovery plan is currently being developed, with completion targeted in 2003.
 
Our federal income tax carryforward attributes could be substantially limited if we experience an ownership change as defined in the Internal Revenue Code.
 
We had consolidated federal income tax net operating loss carryforwards of approximately $245.9 million at December 31, 2001, and have incurred an additional net operating loss during the nine months ended September 30, 2002. Our net operating loss carryforwards will begin to terminate with the year ending December 31, 2012, to the extent they have not been used to reduce taxable income prior to such time. Our ability to use our net operating loss carryforwards to reduce taxable income and to utilize other losses and certain tax credits is dependent upon, among other things, our not experiencing an ownership change of more than 50% during any three-year testing period as defined in the Internal Revenue Code. We have had significant changes in the ownership of our common stock in the three-year testing period immediately prior to this offering. We expect that as a result of this offering we will be very close to experiencing an ownership change of more than 50%. Accordingly, future changes, even slight changes, in the ownership of our common stock (including, among other things, the exercise of compensatory options) could result in an aggregate change in ownership of more than 50% as defined in the Internal Revenue Code, which could substantially limit the availability of our net operating loss carryforwards, other losses and tax credits.
 
Risks Related to the Memphis Refinery Acquisition and Future Acquisitions
 
We may not realize the anticipated benefits of the Memphis refinery acquisition.
 
Our estimates regarding the earnings, operating cash flow, capital expenditures and liabilities resulting from our acquisition of the Memphis refinery may prove to be incorrect. In addition, we may not realize the anticipated synergies and we may not be successful in integrating the acquired assets into our existing business.
 
If we do not consummate the Memphis refinery acquisition, we will not realize the anticipated benefits from the acquisition.
 
Although the information in this prospectus assumes the consummation of the Memphis refinery acquisition, the consummation is subject to the satisfaction of certain conditions precedent, and may be terminated by Williams if the acquisition has not been completed by March 31, 2003. Our failure to acquire the Memphis refinery and related supply and distribution assets from Williams would result in our asset base being smaller than what has been described in this prospectus. Accordingly, we would not realize the anticipated benefits we discuss in this prospectus which are based on our completion of this acquisition. Additionally, if the Memphis refinery acquisition is not consummated for any reason, we would retain broad discretion as to the use of the net proceeds of this offering and the debt financing and may not be able to effectively deploy them.

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We may be liable for significant environmental costs relating to the Memphis refinery acquisition or future acquisitions.
 
The Memphis refinery acquisition agreement provides that the sellers will indemnify us for certain unknown and undisclosed environmental liabilities. The maximum potential amount we can recover for environmental liabilities is limited to $50 million from the sellers under the indemnity plus $50 million under an insurance policy. We are responsible for all other environmental liabilities, including various pending cleanup and compliance matters that we estimate will cost between $9 million and $16 million. Accordingly, we may be responsible for significant environmental related liabilities and costs relating to the acquisition of the Memphis refinery and the related assets. See “—Compliance with, and changes in, environmental laws could adversely affect our results of operations and our financial condition” for a description of capital expenditures we expect to incur with respect to the Memphis refinery. There can be no assurances that these environmental liabilities and/or costs or expenditures to comply with environmental laws will not have a material adverse effect on our financial condition, results of operations and cash flow.
 
We may not be able to consummate future acquisitions or successfully integrate the Memphis refinery or other future acquisitions into our business.
 
A substantial portion of our growth over the last several years has been attributed to acquisitions. A principal component of our strategy going forward is to continue to selectively acquire refining assets in order to increase cash flow and earnings. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired businesses and obtain financing to support our growth and many other factors beyond our control. We may not be successful in implementing our acquisition strategy and, even if implemented, such strategy may not improve our operating results. In addition, the financing of future acquisitions may require us to incur additional indebtedness, which could limit our financial flexibility, or to issue additional equity, which could result in further dilution of the ownership interest of existing shareholders.
 
In connection with the Memphis refinery acquisition or with future acquisitions, we may experience unforeseen operating difficulties as we integrate the acquired assets into our existing operations. These difficulties may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. The Memphis refinery acquisition and any future acquisitions involve risks, including:
 
 
•
 
unexpected losses of key employees, customers and suppliers of the acquired operations;
 
 
•
 
difficulties in integrating the financial, technological and management standards, processes, procedures and controls of the acquired business with those of our existing operations;
 
 
•
 
challenges in managing the increased scope, geographic diversity and complexity of our operations; and
 
 
•
 
mitigating contingent liabilities.
 
Risks Related to this Offering
 
Our stock price may be volatile.
 
The market price of our common stock has been in the past, and could be in the future, subject to significant fluctuations in response to factors such as those listed in “—Risks Related to our Business and our Industry—Volatile margins in the refining industry may negatively affect our future operating results and decrease our cash flow,” and the following, some of which are beyond our control:
 
 
•
 
fluctuations in the market prices of crude oil, other feedstocks and refined products, which are beyond our control and may be volatile, such as announcements by OPEC members that they may reduce crude oil output in order to increase prices;

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•
 
quarterly variations in our operating results such as those related to the summer and winter driving seasons and resulting demand for unleaded gasoline and heating oil;
 
 
•
 
operating results that vary from the expectations of securities analysts and investors;
 
 
•
 
operating results that vary from those of our competitors;
 
 
•
 
changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;
 
 
•
 
announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
 
 
•
 
announcements by third parties of significant claims or proceedings against us;
 
 
•
 
future sales of our common stock, for example, when lock-up agreements expire 90 days following this offering; and
 
 
•
 
general domestic and international economic conditions, particularly following the terrorist attacks of September 2001.
 
If we or our existing stockholders sell additional shares of our common stock after this offering, the market price of our common stock could decline.
 
The market price of our common stock could decline as a result of sales of a large number of shares of common stock in the market after this offering, or the perception that such sales could occur. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
 
All of the shares we are selling in this offering, plus any shares issued upon the underwriters’ option to purchase additional common stock, will be freely tradable without restriction under the United States securities laws, unless purchased by our affiliates.
 
We, our directors and executive officers, Blackstone and Occidental, owning an aggregate of 36,469,406 shares, have agreed not to offer or sell, directly or indirectly, any common stock without the permission of Morgan Stanley & Co. Incorporated for a period of 90 days from the date of this prospectus, subject to certain exceptions. Sales of a substantial number of shares of our common stock following the expiration of these lock-up periods could cause our stock price to fall. In addition, in connection with the Memphis refinery acquisition, under certain circumstances, we may pay up to $100 million of the purchase price through the issuance of our shares instead of cash. These shares of common stock would be valued at $15.00 per share less an underwriting discount. See “The Acquisition of the Memphis Refinery—Overview of the Acquisition.” We are also currently evaluating several other refinery acquisitions, some of which may be significant. Any other significant acquisition may require us to issue shares of our common stock or securities linked to shares of our common stock to finance all or a portion of such acquisition. Additionally, we have granted registration rights to certain of our stockholders and, if the sellers receive shares of common stock under the circumstances described above, to the sellers of the Memphis refinery. See “Shares Eligible for Future Sale—Registration Rights.”
 
In addition, 4,589,480 shares of our common stock are issuable upon the exercise of presently outstanding stock options granted to our directors, employees and former employees under our 1999 Stock Incentive Plan, 2002 Equity Incentive Plan and our 2002 Special Stock Incentive Plan. An additional 1,967,575 shares have been reserved for future issuance under our stock incentive plans and other agreements. We have registered on Form S-8 under the Securities Act all shares of common stock subject to outstanding stock options issuable under our stock incentive plans and shares of certain of our officers and directors. Sales of a substantial number of shares of our common stock following the vesting of these options could cause our stock price to fall.

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Our governing documents and applicable laws include provisions that may discourage a takeover attempt.
 
Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. For example, our certificate of incorporation precludes stockholders from taking action by consent, which inhibits stockholders’ ability to replace board members. Further, only the board of directors or our chairman of the board or chief executive officer may call special meetings of stockholders, which prevents stockholders from calling special meetings to vote on corporate actions. Stockholders who wish to nominate a director or present a matter for consideration at an annual meeting are required to give us notice of such proposal, which gives us time to respond. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.

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FORWARD-LOOKING STATEMENTS
 
Some of the matters discussed under the captions “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and elsewhere in this prospectus include forward-looking statements based on current expectations, estimates, forecasts and projections, beliefs and assumptions made by management. You can identify these forward-looking statements by the use of words like “strategy,” “expects,” “plans,” “believes,” “will,” “estimates,” “intends,” “projects,” “goals,” “targets” and other words of similar meaning. You can also identify them by the fact that they do not relate strictly to historical or current facts.
 
Even though we believe our 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 our forward-looking statements include those discussed under “Risk Factors—Risks Related to our Business and our Industry” and “The Acquisition of the Memphis Refinery —Impact of the Acquisition.” Because of these uncertainties and others, you should not place undue reliance on our forward-looking statements.

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THE ACQUISITION OF THE MEMPHIS REFINERY
 
Overview of the Acquisition
 
On November 25, 2002, we executed an agreement with The Williams Companies and certain of its subsidiaries to purchase their Memphis refinery and related supply and distribution assets located in and around Memphis, Tennessee. The purchase price is $315 million, plus the value of inventories at closing. At current price levels, the value of the inventories is estimated to be $200 million. In addition, the sellers will be entitled to receive from us earn-out payments over the next seven years, up to a maximum of $75 million, based on the excess of a specified average industry refining margin per barrel over a specified margin per barrel, multiplied by a specified throughput volume at the refinery.
 
The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd, but typically processes approximately 170,000 bpd. Also included in the acquisition are two truck-loading racks, three petroleum terminals located in the area, pipeline infrastructure that transports both crude oil and refined products, crude oil tankage in Louisiana and an 80 megawatt power plant adjacent to the refinery.
 
We intend to finance the acquisition with the proceeds from this offering and the other financing transactions. See “Use of Proceeds.” Additionally, we have received a financing commitment letter from Morgan Stanley Senior Funding, Inc. to provide a portion of the financing to consummate the acquisition, if necessary.
 
Consummation of the acquisition is conditioned upon us securing the requisite financing. If we are unable to secure this financing, the sellers may elect, under certain circumstances, to receive up to $100 million of the purchase price through the issuance of shares of our common stock instead of cash. These shares would be valued at $15.00 per share less an underwriting discount. If we fail to consummate the transaction, we may be obligated to pay the sellers $30 million in cash as liquidated damages. If the sellers elect to receive our common stock under the circumstances described above, they will also have the right, from time to time, to require us to register their stock for resale and to include their shares in future registration statements filed by us.
 
We also intend to enter into a two-year crude oil supply and product off-take agreement with Morgan Stanley Capital Group Inc., or MSCG, under which MSCG will purchase the Memphis refinery petroleum inventories at closing. Under this agreement, MSCG will (1) lease from us the Memphis refinery tankage, (2) receive, via assignment or sublease, Southcap Capline pipeline storage and historic shipping capacity associated with the Memphis refinery operations, and (3) assign or sub-lease for storage capacity at various product terminals supporting the Memphis refinery operations. Over the term of the agreement, we will purchase crude oil from MSCG delivered into the crude unit and will sell products to MSCG delivered into refinery tankage. Among other things, this transaction will reduce our need to issue standby letters of credit in order to support purchases of crude oil inventory for the Memphis refinery. We intend to enter into a commitment to purchase the petroleum inventories acquired by MSCG upon termination of the agreement with them at then current market prices, as adjusted by certain predetermined contract provisions. There are no assurances that we will enter into this agreement or on these terms.
 
In the event that the gross proceeds from this offering and the other financing transactions exceed $650 million in the aggregate for any reason, we may use the additional gross proceeds to pay for the purchase of inventory at closing or to fund our investment in accounts receivable that will result as refinery operations commence. Any inventory purchased by us at closing would not be part of the proposed crude oil supply and product off-take agreement with MSCG.
 
The sellers have agreed, subject to the limitations described below, to indemnify us against all environmental liabilities incurred by us as a result of a breach of their environmental representations and as a result of environmental related matters (1) known by them prior to the closing but not disclosed to us and (2) not

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known by them prior to the closing. We are responsible for all other environmental liabilities, including various pending cleanup and compliance matters that we estimate will cost between $9 million and $16 million. Any claims made by us against the sellers for environmental liabilities must be made within seven years. The sellers, as a condition to closing, will be required to obtain, at their expense, a ten-year fully pre-paid $50 million environmental insurance policy in support of this obligation covering unknown and undisclosed liabilities for the period of time prior to the acquisition. The maximum amount we can recover for environmental liabilities is limited to $50 million from the sellers plus any amounts provided under the insurance policy. The sellers have also agreed to indemnify us against breaches of their representations and from liabilities arising from the ownership and operation of the assets (other than environmental liabilities) prior to the closing, but the liability of the sellers will be subject to a $5 million deductible and a maximum liability of $50 million.
 
Completion of the acquisition is also subject to the satisfaction of customary conditions, including regulatory approvals. Pursuant to the requirements of the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, we filed a Notification and Report Form with respect to the Memphis acquisition with the Antitrust Division of the Department of Justice and the Federal Trade Commission on December 10, 2002. As a result, the waiting period applicable to the Memphis refinery acquisition expired at 11:59 p.m., New York City time, on January 9, 2003. The acquisition is expected to close in the first quarter of 2003.
 
The Memphis Refinery
 
The Memphis refinery was originally constructed in 1941 and is located on 223 acres along the Mississippi River’s Lake McKellar in Memphis, Tennessee. According to the sellers, approximately $400 million has been invested in the refinery over the past four years creating a modern, highly-efficient facility with a 190,000 bpd crude oil throughput capacity. The refinery processes light, sweet crude oil delivered via the Capline pipeline system and distributes its products primarily in the Memphis area and the Mississippi River and lower Ohio River valleys, with occasional market-driven distribution in other markets.
 
The Memphis refinery’s major processing units and associated capacity are listed below:
 
Unit
  
Capacity
(in barrels per day,
except as noted)
  
Year Built
  
Most Recent
Modification
             
West crude
 
80,000
  
1941
  
2002
East crude
  
110,000
  
1980
  
1999
Naptha desulfurizer
  
60,000
  
1974
  
2000
Isomerization
  
4,000
  
1987
  
1999
Reformer
  
36,000
  
2000
  
—
Distillate desulfurizer
  
51,000
  
1980
  
1993
Fluid catalytic cracking
  
68,000
  
1980
  
1999
Alkylation
 
12,000
  
1968
  
1999
C3/C4 (propane/butane) splitter
  
8,000
  
1998
  
—
Sulfur recovery
  
15-50 tons per day
  
1982
  
—
Cryogenic unit
  
300-700
  
1989
  
2002
Saturates gas plant
  
12,000
  
1996
  
—
 
We will depreciate these assets in accordance with our policies related to property, plant and equipment, and the assets will have estimated useful lives of approximately 25 to 30 years.
 
Feedstocks.    The Memphis refinery processes predominantly light, sweet crude oil and draws its crude supply (both domestic and foreign) from the Capline pipeline system. It can also receive crude oil via barge. Capline is a 1,140,000 bpd common carrier crude oil pipeline that originates at St. James, Louisiana and terminates at Patoka, Illinois. The refinery is linked to Capline via a 28-mile proprietary pipeline, which connects to Capline near Collierville, Tennessee and has a capacity of 200,000 bpd.

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Product Offtake.    The Memphis refinery is the sole supplier of jet fuel to the Memphis International Airport, a major air cargo thoroughfare and a central hub for Federal Express. Federal Express is, and we expect will continue to be, a significant customer of the refinery. The Memphis refinery supplies Federal Express pursuant to a long-term supply agreement which represents approximately 12% of the refinery’s total output. In addition to Federal Express, the refinery has a number of supply agreements with terms in excess of one year representing an aggregate of approximately 13% of the refinery’s total output. Other than the agreement with Federal Express, no other supply agreement accounts for 10% or more of the refinery’s total output.
 
The refinery’s position along the Mississippi River provides a cost advantage in serving numerous upriver markets due to the superior economics of shipping crude oil for refining and subsequent product distribution versus shipping refined products from the Gulf Coast to Memphis. It is also well situated to meet demand for refined products in Nashville, Tennessee, which the Gulf Coast market cannot economically satisfy. The refinery’s close proximity to several major electric power plants also provides access to increased distillate demand associated with peaking plants and fuel switching.
 
Products of the refinery include: premium, mid-grade and regular grades of unleaded gasoline; commercial Jet-A; kerosene; military JP8; diesel; No. 6 fuel oil; propane; refinery grade propylene and sulfur. The Memphis refinery is capable of distributing its products through facilities with nominal capacities as follows: (1) a 120,000 bpd truck-loading rack at the refinery; (2) a 50,000 bpd truck-loading rack at the West Memphis, Arkansas products terminal; (3) a 30,000 bpd jet fuel pipeline to the Memphis International Airport; (4) a 96,000 bpd barge dock at the refinery; (5) a 108,000 bpd barge dock connected to the West Memphis terminal; (6) a two-lane LPG truck-loading rack and (7) a 24-spot LPG rail car-loading rack. Refinery production can also be distributed via barge to markets in Henderson, Owensboro, and Paducah, Kentucky; Nashville, Tennessee; Evansville, Indiana; Cape Girardeau, Missouri; and Greenville, Mississippi.
 
Energy.    The sellers recently completed construction of an 80 megawatt power plant adjacent to the refinery to provide a reliable source of power and to reduce power costs.
 
Employees.    The sellers have indicated that the refinery employs approximately 320 employees, of which approximately one-half is represented by a union. We have agreed to recognize and enter into a contract with the union and intend to offer employment to qualified represented personnel and intend to consider the non-represented employees as candidates for employment.
 
Impact of the Acquisition
 
We understand that the sellers historically operated the Memphis refinery as a component of their integrated energy services with a corresponding emphasis on the trading and hedging of energy and energy-related commodities. We believe that decisions such as those relating to crude slate, yield, total throughput, marketing, distribution, risk management and capital expenditures were likely made to optimize an integrated energy commodities system, as opposed to that of the Memphis refinery specifically. As a result of this and various other factors, we believe we have purchased an asset, rather than a business, from the sellers. Accordingly, we are not providing historical or pro forma financial statements for this acquisition. We intend to optimize the refinery’s operations as part of our existing refining system with an emphasis on the production and sale of the refinery’s petroleum products.
 
We believe that our acquisition of the Memphis refinery will benefit us in the following ways:
 
We expect to achieve growth through the acquisition of a high quality refinery in a niche market. The Memphis refinery is a modern facility and the only refinery in Tennessee. It is strategically located on the Mississippi River, which gives it more immediate access to numerous mid-continent markets with steadily growing demand. We can easily adapt the product slate to meet changing demand patterns in an extensive market

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area. The refinery’s location should provide us with a cost advantage over other refiners because it is typically less expensive to ship crude oil to Memphis for refining and subsequent product distribution than to transport refined products to the market area by barge or the TEPPCO pipeline system.
 
We believe we are acquiring the refinery at an attractive purchase price based on recent refinery transactions. The $315 million purchase price for the refinery assets equates to $1,658 per barrel per day of crude oil throughput capacity, which we believe compares very favorably to the average price paid in recent U.S. refinery asset acquisitions.
 
We believe the acquisition will be accretive to our earnings per share and will generate positive cash flow from operations. We plan to operate the Memphis refinery at a daily crude oil throughput of approximately 170,000 bpd, which is consistent with its historical operating rate. We also expect that the operating results from the refinery’s production will track a Gulf Coast 2/1/1 benchmark crack spread and that we will be able to realize a gross margin benefit over the Gulf Coast 2/1/1 benchmark crack spread resulting from location premiums for refined products, partially offset by crude oil transportation costs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook”. Our ability to achieve these results depends on various factors, many of which are beyond our control, including market prices for refined products and crude oil, economic conditions, regulatory environment and unanticipated changes in the Memphis refinery’s operations. There can be no assurances that we will achieve our expected results.
 
We expect that the acquisition will allow us to realize operating and economic synergies with our existing Midwestern refining system. Both the Memphis and Lima refineries process light, sweet crude oil and can be supplied via the Capline pipeline system. We believe we can realize greater efficiencies by acquiring larger water-borne cargoes of foreign crude oils at lower prices. We also believe we will be able to use our Mid-continent terminal system to distribute product that is not marketed in the immediate Memphis area, enabling us to reach markets not currently served by the Memphis refinery, including customers that had previously relied on our recently shut down Hartford refinery.
 
We expect increased flexibility and cost savings in implementing our plan to comply with new clean fuels regulations. The Memphis refinery should provide us with additional flexibility in complying with Tier 2 gasoline specifications utilizing the corporate pool averaging provision of the regulation. While there can be no assurances, this provision and others set forth in the regulations could allow us to defer a significant portion of the investment required for compliance until the end of 2005 for one or both of the Lima and Memphis refineries. Without the acquisition, our Lima refinery would be required to comply by July 1, 2004.
 
The sellers estimated that the Memphis refinery’s cost for complying with Tier 2 gasoline specifications will be $80 million based on an implementation date of the first quarter of 2004. We are reviewing this estimate and believe there may be opportunities for significant cost savings based on a revised project design and deferral of compliance to 2005. Based on currently available information, we estimate that the cost of complying with low sulfur diesel standards for the Memphis refinery will be approximately $100 million, which would be incurred between 2004 and 2006, with the greatest concentration of spending in 2005. We also do not anticipate the need to spend any capital for MACT II compliance at the Memphis refinery.
 
The acquisition should enhance and diversify our asset base. With the acquisition of the Memphis refinery, we will increase the number of our operating refineries from two to three and our combined crude oil throughput capacity from 420,000 bpd to 610,000 bpd. The acquisition increases our presence in the attractive PADD II market, where demand has historically exceeded production, creating a strong market environment for refiners. We believe the location advantage of the Memphis refinery will also complement our Port Arthur refinery, which is located in the more competitive PADD III market, but benefits from its significant capacity to process lower-cost heavy sour crude oil.

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USE OF PROCEEDS
 
We estimate that the net proceeds we will receive from the sale of the shares of our common stock in this offering, after deducting underwriting discounts and commissions and estimated expenses payable by us, will be approximately $239.0 million, or $275.0 million if the underwriters exercise their over-allotment option in full. We expect to receive proceeds of $400.0 million from the issuance of the senior notes in the debt financing. Further, we expect to receive proceeds of up to $65.0 million from the private equity commitment.
 
We intend to use a portion of the total net proceeds to finance the Memphis refinery acquisition. However, neither the consummation of this offering nor the consummation of the debt financing is contingent on the other or on the completion of the Memphis refinery acquisition. We will retain broad discretion as to the use of the net proceeds currently allocated to the Memphis refinery acquisition if it is not completed.
 
In addition, we intend to use approximately $42.4 million of the net proceeds to redeem all of the outstanding 11 1/2% subordinated debentures issued by Premcor USA Inc. and $240.0 million to repay principal under the floating rate notes due 2003 and 2004 issued by PRG. The 11 1/2% subordinated debentures are due in December 2009 and are currently redeemable by Premcor USA at a redemption price equal to 105.75%. As of September 30, 2002, $240.0 million principal amount of floating rate notes due 2003 and 2004 was outstanding, which may be repaid by us at any time at par. See “Description of Indebtedness.”
 
In the event that the gross proceeds from this offering and the other financing transactions exceed $650 million in the aggregate for any reason, we may use the additional gross proceeds to pay for the purchase of inventory at closing or to fund our investment in accounts receivable that will result as refinery operations commence. Any inventory purchased by us at closing would not be part of the proposed crude oil supply and product off-take agreement with MSCG.
 
Pending the uses described above, we intend to invest the net proceeds in direct or guaranteed obligations of the United States, interest-bearing, investment-grade investments or certificates of deposit.
 
The following table sets forth the expected sources and uses of the proceeds of this offering and the debt financing:
 
      
Amount
      
(in millions)
Sources:
       
Proceeds from this offering
     
$  250.0
Proceeds from the debt financing
     
    400.0
      
Total sources
     
$  650.0
      
Uses:
       
Purchase of the Memphis refinery and related assets
     
$  315.0
Redemption of the 11 1/2% subordinated debentures
     
      42.4
Repayment of the floating rate notes
     
    240.0
General corporate purposes
     
      16.6
Fees and expenses
     
      36.0
      
Total uses
     
$  650.0
      
 

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PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
 
Our common stock began trading on the NYSE on April 30, 2002 under the symbol “PCO.” Before that date, no public market for our common stock existed. Set forth below are the high and low closing sales prices per share of our common stock as reported on the NYSE Composite Tape.
 
    
High
   
Low
Fiscal Year 2002
              
Second Quarter (commencing April 30, 2002)
   
$
  28.25
   
 $
  24.52
Third Quarter
   
 
24.95
   
 
15.65
Fourth Quarter
   
 
22.93
   
 
13.40
 
On January 23, 2003, the last reported sales price of our common stock on the NYSE was $20.32 per share. As of January 23, 2003, there were 15 shareholders of record.
 
We do not anticipate paying cash dividends on our common stock in the foreseeable future. We currently intend to retain our future earnings to finance the improvement and expansion of our business. In addition, our ability to pay dividends is effectively limited by the terms of the debt instruments of our subsidiaries, which significantly restrict their ability to pay dividends directly or indirectly to us. See “Description of Indebtedness.” Future dividends on our common stock, if any, will be at the discretion of our board of directors and will depend on, among other things, our results of operations, cash requirements and surplus, financial condition, contractual restrictions and other factors that our board of directors may deem relevant.

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CAPITALIZATION
 
The following table sets forth our cash, cash equivalents and short-term investments and capitalization as of September 30, 2002:
 
 
•
 
on an actual basis; and
 
 
•
 
on an as adjusted basis to reflect:
 
 
•
 
our receipt of the proceeds from the sale of our common stock in this offering;
 
 
•
 
our receipt of the proceeds from the debt financing; and
 
 
•
 
the use of the proceeds from this offering and the debt financing as described under “Use of Proceeds.”
 
The table below should be read in conjunction with “Summary Financial Data,” “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our condensed consolidated financial statements and the notes to those statements appearing elsewhere in this prospectus.
 
    
As of September 30, 2002
  
    
Actual
       
As Adjusted
  
    
(in millions)
  
Cash, cash equivalents and short-term investments (1)
   
$
209.9
 
     
$
226.5
 
    
    
Debt (2):
                    
Port Arthur Finance Corp.:
                    
12 1/2% Senior Secured Notes due 2009
   
$
250.7
 
     
$
250.7
 
Premcor Refining Group:
                    
Floating Rate Loans due 2003 and 2004
   
 
240.0
 
     
 
—  
 
8 3/8% Senior Notes due 2007
   
 
99.6
 
     
 
99.6
 
8 5/8% Senior Notes due 2008
   
 
109.8
 
     
 
109.8
 
8 7/8% Senior Subordinated Notes due 2007
   
 
174.4
 
     
 
174.4
 
Ohio Water Development Authority
                    
Environmental and Facilities Revenue Bonds
   
 
10.0
 
     
 
10.0
 
Senior Notes due 2010 and 2013 to be issued
   
 
—  
 
     
 
400.0
 
Obligations under capital leases
   
 
0.7
 
     
 
0.7
 
Premcor USA:
                    
11 1/2% Subordinated Debentures due 2009
   
 
40.1
 
     
 
—  
 
    
    
Total debt
   
 
925.3
 
     
 
1,045.2
 
    
    
Common stockholders’ equity:
                    
Common Stock, $0.01 par value (57,473,935 shares issued and outstanding; 69,973,935 shares issued and outstanding, as adjusted)
   
 
0.6
 
     
 
0.7
 
Paid-in capital
   
 
851.6
 
     
 
1,090.5
 
Retained earnings (deficit)
  
 
(193.6
)
     
 
(195.8
)
    
    
Total common stockholders’ equity
   
 
658.6
 
     
 
895.4
 
    
    
Total capitalization
   
$
  1,583.9
 
     
$
  1,940.6
 
    
    
(1)
 
Includes $51.9 million of cash restricted for debt service.
(2)
 
In addition, PRG has a credit agreement that provides for the issuance of letters of credit and revolving loan borrowings of up to the lesser of $650 million or the amount available under a borrowing base calculation. As of September 30, 2002, $520.2 million of the line of credit was utilized for the issuance of letters of credit primarily to secure purchases of crude oil. Direct cash borrowings under the credit facility are limited to $50 million. There were no direct cash borrowings under the facility as of September 30, 2002. In connection with the debt financing and the Memphis refinery acquisition, we must obtain various waivers and approvals under, and extend the maturity date of, this credit agreement. See “Description of Indebtedness—The Premcor Refining Group Credit Agreement.”

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SELECTED FINANCIAL DATA
 
The following table presents selected financial and other data about us. The selected statement of earnings and cash flow data for the years ended December 31, 1999, 2000, and 2001 and the selected balance sheet data as of December 31, 2000 and 2001 are derived from our consolidated financial statements, including the notes thereto, audited by Deloitte & Touche LLP, independent accountants, appearing elsewhere in this prospectus. The selected statement of earnings and cash flow data for the years ended December 31, 1997 and 1998, and the selected balance sheet data as of December 31, 1997, 1998 and 1999 have been derived from our consolidated financial statements and those of our predecessor, Premcor USA Inc., formerly Clark USA Inc., including the notes thereto, not included in this prospectus, which were audited by Deloitte & Touche LLP. The selected financial data for the nine-month periods ended September 30, 2001 and 2002 and as of September 30, 2002 are derived from our unaudited condensed consolidated financial statements including the notes thereto, appearing elsewhere in this prospectus. The interim information was prepared on a basis consistent with that used in preparing our audited financial statements with only such recurring adjustments as are necessary, in management’s opinion, for a fair statement of the results for the periods presented. This selected consolidated financial and other operating data set forth below should be read together with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements, including the notes thereto, appearing elsewhere in this prospectus.
 
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1997
     
1998
     
1999
     
2000
     
2001
     
2001
     
2002
  
    
(in millions, except per share data)
  
Statement of earnings data:
                                                               
Net sales and operating revenues
   
$
  3,880.7
 
   
$
  3,581.7
 
   
$
  4,520.5
 
   
$
  7,301.7
 
   
$
  6,417.5
 
   
$
  5,170.9
 
   
$
  4,807.1
 
Cost of sales
   
 
3,432.1
 
   
 
3,113.2
 
   
 
4,099.8
 
   
 
6,562.5
 
   
 
5,251.4
 
   
 
4,133.7
 
   
 
4,342.8
 
    
  
  
  
  
  
  
Gross margin
   
 
448.6
 
   
 
468.5
 
   
 
420.7
 
   
 
739.2
 
   
 
1,166.1
 
   
 
1,037.2
 
   
 
464.3
 
Operating expenses(1)
   
 
295.0
 
   
 
342.8
 
   
 
402.8
 
   
 
467.7
 
   
 
467.7
 
   
 
355.8
 
   
 
338.2
 
General and administrative expenses(1)
   
 
43.5
 
   
 
51.2
 
   
 
51.5
 
   
 
53.0
 
   
 
63.3
 
   
 
45.3
 
   
 
40.8
 
Stock option compensation expense
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
9.9
 
Depreciation and amortization (2)
   
 
46.8
 
   
 
54.5
 
   
 
63.1
 
   
 
71.8
 
   
 
91.9
 
   
 
67.7
 
   
 
64.9
 
Inventory write-down (recovery) to market value
   
 
19.2
 
   
 
86.6
 
   
 
(105.8
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Gain on sale of pipeline interest
   
 
—  
 
   
 
(69.3
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Refinery restructuring, recapitalization, asset write-offs and other charges
   
 
41.8
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
176.2
 
   
 
176.2
 
   
 
172.9
 
    
  
  
  
  
  
  
Operating income (loss)
   
 
2.3
 
   
 
2.7
 
   
 
9.1
 
   
 
146.7
 
   
 
367.0
 
   
 
392.2
 
   
 
(162.4
)
Interest expense and finance income, net (3)
   
 
(80.1
)
   
 
(70.5
)
   
 
(91.5
)
   
 
(82.2
)
   
 
(139.5
)
   
 
(106.3
)
   
 
(81.5
)
Gain (loss) on extinguishment of long-term debt (4)
   
 
(20.7
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
8.7
 
   
 
8.7
 
   
 
(19.5
)
Income tax (provision) benefit
   
 
(7.6
)
   
 
25.0
 
   
 
12.0
 
   
 
25.8
 
   
 
(52.4
)
   
 
(78.7
)
   
 
99.9
 
Minority interest in subsidiary
   
 
—  
 
   
 
—  
 
   
 
1.4
 
   
 
(0.6
)
   
 
(12.8
)
   
 
(12.4
)
   
 
1.7
 
    
  
  
  
  
  
  
Income (loss) from continuing operations
   
 
(106.1
)
   
 
(42.8
)
   
 
(69.0
)
   
 
89.7
 
   
 
171.0
 
   
 
203.5
 
   
 
(161.8
)
Discontinued operations, net of taxes(5)
   
 
(2.0
)
   
 
13.1
 
   
 
32.6
 
   
 
—  
 
   
 
(18.0
)
   
 
(8.5
)
   
 
—  
 
    
  
  
  
  
  
  
Net income (loss)
   
 
(108.1
)
   
 
(29.7
)
   
 
(36.4
)
   
 
89.7
 
   
 
153.0
 
   
 
195.0
 
   
 
(161.8
)
Preferred stock dividends
   
 
(1.8
)
   
 
(7.6
)
   
 
(8.6
)
   
 
(9.6
)
   
 
(10.4
)
   
 
(7.9
)
   
 
(2.5
)
    
  
  
  
  
  
  
Net income (loss) available to common stockholders
   
$
(109.9
)
   
$
(37.3
)
   
$
(45.0
)
   
$
80.1
 
   
$
142.6
 
   
$
187.1
 
   
$
(164.3
)
    
  
  
  
  
  
  
Income (loss) from continuing operations per share:
                                                               
—basic
   
$
(4.13
)
   
$
(2.54
)
   
$
(3.59
)
   
$
2.79
 
   
$
5.05
 
   
$
6.15
 
   
$
(3.57
)
—diluted
   
 
(4.13
)
   
 
(2.54
)
   
 
(3.59
)
   
 
2.55
 
   
 
4.65
 
   
 
5.67
 
   
 
(3.57
)
Weighted average number of common shares outstanding:
                                                               
—basic
   
 
26.1
 
   
 
19.9
 
   
 
21.6
 
   
 
28.8
 
   
 
31.8
 
   
 
31.8
 
   
 
46.0
 
—diluted
   
 
26.1
 
   
 
19.9
 
   
 
21.6
 
   
 
31.5
 
   
 
34.5
 
   
 
34.5
 
   
 
46.0
 

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Table of Contents
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1997
     
1998
     
1999
     
2000
     
2001
     
2001
     
2002
  
    
(in millions, except as noted)
  
Cash flow data:
                                                               
Cash flow from operating activities
   
$
68.2
 
   
$
(61.0
)
   
$
85.5
 
   
$
124.4
 
   
$
439.2
 
   
$
  390.2
 
   
$
(42.2
)
Cash flow from investing activities
   
 
(125.6
)
   
 
(230.7
)
   
 
(321.3
)
   
 
(375.3
)
   
 
(152.9
)
   
 
(98.5
)
   
 
(91.8
)
Cash flow form financing activities
   
 
(46.7
)
   
 
205.5
 
   
 
393.9
 
   
 
234.8
 
   
 
(66.3
)
   
 
(68.8
)
   
 
(219.8
)
EBITDA (6)
   
 
49.1
 
   
 
57.2
 
   
 
72.2
 
   
 
218.5
 
   
 
458.9
 
   
 
459.9
 
   
 
(97.5
)
Adjusted EBITDA (7)
   
 
110.1
 
   
 
74.5
 
   
 
(33.6
)
   
 
218.5
 
   
 
635.1
 
   
 
636.1
 
   
 
75.4
 
Capital expenditures for property, plant and equipment
   
 
27.4
 
   
 
101.4
 
   
 
438.2
 
   
 
390.7
 
   
 
94.5
 
   
 
57.8
 
   
 
64.1
 
Capital expenditures for turnarounds
   
 
47.4
 
   
 
28.3
 
   
 
77.9
 
   
 
31.5
 
   
 
49.2
 
   
 
41.3
 
   
 
33.4
 
Refinery acquisition expenditures
   
 
—  
 
   
 
175.0
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Key operating statistics:
                                                               
Production (barrels per day in thousands)
   
 
349.3
 
   
 
403.8
 
   
 
460.5
 
   
 
477.3
 
   
 
463.4
 
   
 
459.6
 
   
 
454.8
 
Crude oil throughput (barrels per day in thousands)
   
 
335.1
 
   
 
400.9
 
   
 
451.7
 
   
 
468.0
 
   
 
439.7
 
   
 
438.8
 
   
 
432.4
 
Per barrel of crude oil throughput:
                                                               
Gross margin
   
$
3.67
 
   
$
3.20
 
   
$
2.55
 
   
$
4.32
 
   
$
7.27
 
   
$
8.66
 
   
$
3.93
 
Operating expenses
   
 
2.41
 
   
 
2.34
 
   
 
2.44
 
   
 
2.73
 
   
 
2.91
 
   
 
2.97
 
   
 
2.87
 
 
    
As of December 31,
     
As of September 30, 2002
    
1997
   
1998
   
1999
   
2000
   
2001
     
    
(in millions)
Balance sheet data:
                                            
Cash, cash equivalents and short-term investments (8)
   
$
249.2
   
$
152.6
   
$
307.6
   
$
291.8
   
$
542.6
     
$
209.9
Working capital
   
 
454.3
   
 
382.6
   
 
305.8
   
 
325.0
   
 
482.6
     
 
291.7
Total assets
   
 
1,194.9
   
 
1,450.3
   
 
1,984.1
   
 
2,469.1
   
 
2,509.8
     
 
2,292.5
Total debt
   
 
768.4
   
 
983.4
   
 
1,340.4
   
 
1,516.0
   
 
1,472.8
     
 
925.3
Exchangeable preferred stock
   
 
64.8
   
 
72.5
   
 
81.1
   
 
90.6
   
 
94.8
     
 
—  
Stockholders’ equity
   
 
38.4
   
 
2.2
   
 
14.7
   
 
152.1
   
 
294.7
     
 
658.6
(1)
 
Certain reclassifications have been made to prior period amounts to conform them to current period presentation.
 
(2)
 
Amortization includes amortization of turnaround costs. However, this may not be permitted under GAAP in future periods. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Accounting Standards—Critical Accounting Standards.”
 
(3)
 
Interest expense and finance income, net, includes amortization of debt issuance costs of $10.6 milion, $2.8 million, $7.9 million, $12.4 million, $14.9 million, $10.9 million and $9.5 million for the years ended December 31, 1997, 1998, 1999, 2000 and 2001, and for the nine months ended September 30, 2001 and 2002, respectively. Interest expense and finance income, net, also includes interest on all indebtedness, net of capitalized interest and interest income.
 
(4)
 
In the second quarter of 2002, we elected the early adoption of SFAS No. 145 and, accordingly, have included the gain (loss) on extinguishment of long-term debt in “Income from continuing operations” as opposed to as an extraordinary item, net of taxes, below “Income from continuing operations” in our Statement of Operations. We have accordingly restated our statement of operations and statement of cash flow for 1997 and 2001.
 
(5)
 
Discontinued operations is net of income tax provisions of nil, $9.8 million, $21.0 million, and income tax benefits of $11.5 million and $5.5 million in 1997, 1998, 1999 and 2001, and for the nine months ended September 30, 2001, respectively.
 
(6)
 
Earnings before interest, taxes, depreciation and amortization, or EBITDA, is a commonly used non-GAAP financial measure but should not be construed as an alternative to operating income or net income as an indicator of our performance, nor as an alternative to cash flow from operating activities, investing activities or financing activities as a measure of liquidity, in each case as such measures are determined in accordance

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Table of Contents
 
with GAAP. EBITDA is presented because we believe that it is a useful indicator of a company’s ability to incur and service debt. EBITDA, as we calculate it, may not be comparable to similarly-titled measures reported by other companies.
 
(7)
 
Adjusted EBITDA represents EBITDA excluding refinery restructuring, recapitalization, asset write-offs and other charges of $41.8 million in 1997, $176.2 million in 2001, $176.2 million in the nine months ended September 30, 2001, and $172.9 million in the nine months ended September 30, 2002, gain on sale of pipeline interest of $69.3 million in 1998 and inventory recovery (write-down) to market value of $(19.2) million in 1997, $(86.6) million in 1998, and $105.8 million in 1999. The $176.2 million charge in the full year of 2001 and for the nine months ended September 30, 2001 included $167.2 million related to the closure of our Blue Island refinery. For the nine months ended September 30, 2002, charges of $172.9 million included $137.4 million related to the closure of the Hartford refinery. Adjusted EBITDA is presented because we believe it is a useful indicator to our investors of our ability to incur and service debt based on our ongoing operations. Adjusted EBITDA should not be considered by investors as an alternative to operating income or net income as an indicator of our performance, nor as an alternative to cash flow from operating activities, investing activities or financing activities as a measure of liquidity. Because all companies do not calculate EBITDA identically, this presentation of adjusted EBITDA may not be comparable to EBITDA, adjusted EBITDA or other similarly-titled measures of other companies.
 
(8)
 
Cash, cash equivalents and short-term investments includes $30.8 million and $51.9 million of cash and cash equivalents restricted for debt service as of December 31, 2001 and September 30, 2002, respectively.

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Table of Contents
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  
AND RESULTS OF OPERATIONS
 
Overview
 
We currently own and operate two refineries with a combined crude oil throughput capacity of approximately 420,000 barrels per day, or bpd. Our refineries are located in Port Arthur, Texas and Lima, Ohio. In late September 2002, we ceased refining operations at our Hartford, Illinois refinery, and we are currently pursuing all strategic options, including expanding the uses of the petroleum product and distribution facility and selling or leasing the refinery, to mitigate the loss of jobs and refinery capacity in the Midwest. We continue to operate the terminal facility at the Hartford refinery in connection with our wholesale petroleum product distribution business. Our Port Arthur refinery has the capacity to process substantial volumes of low-cost sour and heavy sour crude oil, resulting in lower feedstock costs, a distinct competitive advantage. Our heavy sour crude oil processing capacity is approximately 50% of throughput on a company-wide basis and 80% of throughput at our Port Arthur refinery, which possesses one of the world’s largest coking units. For the nine months ended September 30, 2002, light products accounted for approximately 90% of our total product volume. For the same period, high-value, premium product grades, such as high octane and reformulated gasoline, low-sulfur diesel and jet fuel, which are the most valuable types of light products, accounted for approximately 40% of our total product volume. For further detail on our business, see “Business”.
 
Developments in 2002
 
Memphis Refinery Acquisition
 
On November 25, 2002, we executed an agreement with The Williams Companies, Inc. and certain of its subsidiaries to purchase their Memphis, Tennessee refinery and related supply and distribution assets. The purchase price for the refinery and the other assets is $315 million, plus the value of inventories at closing. At current price levels, the value of the inventories is estimated to be $200 million. The agreement also provides for earn-out payments that could result in additional payments of $75 million by us to Williams over the next seven years, depending on the level of industry refining margins during that period.
 
The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd but typically processes approximately 170,000 bpd. The related assets include two truck-loading racks; three petroleum terminals in the area; supporting pipeline infrastructure that transports both crude oil and refined products; crude oil tankage at St. James, Louisiana; and an 80 megawatt power plant adjacent to the refinery.
 
We believe we are acquiring a quality refinery at an attractive price that will produce operating and economic synergies and that should be accretive to our earnings per share and generate positive cash flow from operations. Completion of the acquisition is subject to our obtaining the necessary financing and the satisfaction of customary conditions, including regulatory approvals. We intend to finance the refinery and the related assets with the proceeds from this offering and the other financing transactions. We expect the acquisition to close during the first quarter of 2003. For more details concerning the acquisition of the Memphis refinery, see “The Acquisition of the Memphis Refinery.”
 
Initial Public Offering
 
On May 3, 2002, we completed an initial public offering of 20.7 million shares of common stock. The initial public offering, plus the concurrent purchases of 850,000 shares in the aggregate by Thomas D. O’Malley, our chairman of the board and chief executive officer, and two of our directors, netted proceeds of approximately $482 million. The proceeds from the offering were committed to retiring certain indebtedness of our subsidiaries.

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Table of Contents
 
Sabine Restructuring
 
On June 6, 2002, we completed a series of transactions, referred to as the Sabine restructuring, that resulted in Sabine River Holding Corp., or Sabine, and its subsidiaries becoming wholly owned subsidiaries of PRG. Prior to the Sabine restructuring, Sabine was 90% owned by us and 10% owned by Occidental. Sabine, through its principal operating subsidiary, Port Arthur Coker Company L.P., or PACC, owns and operates a heavy oil processing facility, which is operated in conjunction with PRG’s Port Arthur, Texas refinery. PACC owns all of the outstanding common stock of Port Arthur Finance Corp., or PAFC.
 
The Sabine restructuring was permitted by the successful consent solicitation of the holders of PAFC’s 12½% senior notes. The Sabine restructuring was accomplished according to the following steps, among others:
 
 
•
 
We contributed $225.6 million in proceeds from our initial public offering of common stock to Sabine. Sabine used the proceeds from the equity contribution, plus cash on hand, to prepay $221.4 million of its senior secured bank loan and to pay a dividend of $141.4 million to us;
 
 
•
 
Commitments under Sabine’s senior secured bank loan, working capital facility, and certain insurance policies were terminated and related guarantees were released;
 
 
•
 
PRG’s existing working capital facility was amended and restated to, among other things, permit letters of credit to be issued on behalf of Sabine;
 
 
•
 
Occidental exchanged its 10% interest in Sabine for 1,363,636 newly issued shares of our common stock;
 
 
•
 
We contributed our 100% ownership interest in Sabine to our wholly owned subsidiary, Premcor USA, and Premcor USA, in turn, contributed its 100% ownership interest to its wholly owned subsidiary, PRG; and
 
 
•
 
PRG fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations under the 12½% senior notes.
 
Our acquisition of Occidental’s 10% ownership in Sabine was accounted for under the purchase method. The purchase price was based on the exchange of 1,363,636 shares of our common stock for the 10% interest in Sabine and was valued at $30.5 million or approximately $22 per share. The purchase price of the 10% minority interest in Sabine exceeded the book value by $8.0 million. Based on an appraisal of the Sabine assets, the excess of the purchase price over the book value of the minority interest, along with a $5.0 million deferred income tax adjustment, was recorded as an investment in property, plant and equipment and will be depreciated over the remaining useful lives of the related Sabine assets. The income tax adjustment reflected the temporary difference between the book and tax basis of property, plant and equipment related to the excess of the purchase price over book value. Because the purchase price did not exceed the fair value of the underlying assets, no goodwill was recognized.
 
Factors Affecting Comparability
 
Our results over the past three years and over the nine months ended September 30, 2001 and 2002 have been influenced by the following events, which must be understood in order to assess the comparability of our period-to-period financial performance.
 
Inventory Price Risk Management.    The nature of our business leads us to maintain a substantial investment in petroleum inventories. Since 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 appropriate and consistent with normal business operations. This target inventory position includes both titled inventory and fixed price purchase and sale commitments. The portion of our current target

34

Table of Contents
inventory position consisting of sales commitments netted against fixed price purchase commitments amounts to a net long inventory position of approximately 4 million barrels.
 
Prior to the second quarter of 2002, we did not generally price protect any portion of our target inventory position. However, although we continue to generally leave the titled portion of our inventory position target fully exposed to price fluctuations, beginning in the second quarter of 2002, we began to actively mitigate some or all of the price risk related to our target level of fixed price purchase and sale commitments. These risk management decisions are based on the relative level of absolute hydrocarbon prices. The cumulative economic effect of our risk management strategy in the second and third quarter of 2002 resulted in an approximate $11 million loss as measured against a fully exposed fixed price commitment target. In the first quarter of 2002, we benefited by approximately $30 million from having our fixed price commitment target fully exposed in a rising absolute price environment.
 
We generally conduct our risk mitigation activities through the purchase or sale of futures contracts on the New York Mercantile Exchange, or NYMEX. Our price risk mitigation activities carry all of the usual time, location and product grade basis risks generally associated with these activities. 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 unless the market value of our target inventory is reduced below cost. However, since the current cost of our inventory purchases and sales are generally charged to our statement of operations, our financial results are affected by price movements on the portion of our target level of fixed price purchase and sale commitments that are not price protected.
 
Operation of the Port Arthur Heavy Oil Upgrade Project.    In January 2001, we began operating our heavy oil upgrade project at our Port Arthur refinery. The project, which began construction in 1998, included the construction of a new 80,000 bpd delayed coking unit, a 35,000 bpd hydrocracker, a 417 ton per day sulfur removal unit 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. We financed the construction of the new facilities with the proceeds from new indebtedness issued by our PAFC subsidiary and with new equity contributions from our principal shareholders, Blackstone and Occidental. Start-up of the project occurred in stages, with the sulfur removal units and the coker unit beginning operations in December 2000 and the hydrocracker unit beginning operations in January 2001. Performance and substantial reliability testing of the project was completed in the third quarter of 2001, and final completion of the project was achieved on December 28, 2001.
 
The comparability of our results is significantly influenced by the impact of the heavy oil upgrade project. In 2000, our Port Arthur refinery processed an average of 202,100 bpd of crude oil. Of that amount, 43,400 bpd, or 21.5%, represented heavy sour crude oil, primarily Maya crude oil, and had an average processed value of $8.00 per barrel less than the equivalent per barrel value of West Texas Intermediate crude oil, a benchmark sweet crude oil. The remaining 158,700 bpd, or 78.5%, consisted of medium sour, light sour and sweet crude oils valued at an average discount to West Texas Intermediate of $1.57 per barrel. In total, the 202,100 bpd of crude oil processed by our refinery during 2000 had a value, on the day of processing, of $218.4 million less than the value of an equivalent volume of West Texas Intermediate crude oil, representing a discount to West Texas Intermediate crude oil of $2.95 per barrel.
 
In contrast, in 2001, including the start-up of the heavy oil upgrade project, our Port Arthur refinery processed an average of 229,800 bpd of crude oil. Of that amount, 181,500 bpd, or 79.0%, represented heavy sour crude oil, all of which was Maya crude oil, and had an average processed value of $8.84 per barrel less than the equivalent per barrel value of West Texas Intermediate crude oil. The remaining 48,300 bpd, or 21.0%, was medium sour crude oil valued at a discount to West Texas Intermediate crude oil of $4.73 per barrel. As a result of the refinery upgrade, our Port Arthur refinery no longer processes sweet and light sour crude oils. In total, the 229,800 bpd of crude oil processed by the refinery during 2001 had a value, on the day of processing, of $669.0 million less than the value of an equivalent volume of West Texas Intermediate crude oil, representing a discount to West Texas Intermediate crude oil of $7.98 per barrel.

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Table of Contents
 
Although the heavy oil upgrade project has enabled us to process a less costly crude oil slate, the overall value of the resulting product slate is lower due to increased production of petroleum coke and other lower-valued products. In addition, the operating cost structure is higher under the new configuration of the Port Arthur refinery. Our operating results for 2001 and for the nine months ended September 30, 2002 demonstrate that the benefit of the less expensive crude oil slate exceeds the lower product realization and higher operating costs. For further discussion of our operating results see “—Results of Operations—Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001 and—Results of Operations—2001 Compared to 2000.”
 
Closure of Blue Island Refinery.    In January 2001, we ceased operations at our Blue Island, Illinois refinery due to economic factors and a decision that the capital expenditures necessary to produce low-sulfur transportation fuels required by recently adopted EPA regulations could not produce acceptable returns on investment. This closure resulted in a pretax charge of $167.2 million for 2001. We continue to utilize our petroleum products storage facility at the refinery site to supply selected products to the Chicago and other Midwest markets from our operating refineries. Since the Blue Island refinery operation had been only marginally profitable in recent years and since we will continue to operate a petroleum products storage and distribution business from the Blue Island site, our reduced refining capacity resulting from the closure is not expected to have a significant negative impact on net income or cash flow from operations. The only significant effect on net income and cash flow will result from the subsequent environmental site remediation as discussed below. Unless there is a need to adjust the closure reserve in the future, there should be no significant effect on net income beyond 2001.
 
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. The Blue Island refinery employed 297 employees, both hourly employees covered by collective bargaining agreements and salaried employees, the employment of 293 of which was terminated during 2001 and the remainder in 2002. A pretax charge of $150.0 million was recorded in the first quarter of 2001 and an additional charge of $17.2 million was recorded in the third quarter of 2001. The original charge included $92.5 million of non-cash asset write-offs in excess of realizable value and a reserve for future costs of $57.5 million, consisting of $12.0 million for severance, $26.4 million for the ceasing of operations, preparation of the plant for permanent closure and equipment remediation and $19.1 million for site remediation and other environmental matters. The third quarter charge of $17.2 million included an adjustment of $5.6 million to the asset write-off to reflect changes in realizable asset value and an increase to the reserve of $11.6 million related to an evaluation of expected future expenditures. The following schedule summarizes the restructuring reserve balance and net cash activity as of September 30, 2002:
 
    
Reserve as of December 31, 2001
   
Net Cash Outlays
     
Reserve as of September 30, 2002
Employee severance
   
$
2.1
   
$
2.1
     
$
—  
Plant closure/equipment remediation
   
 
13.9
   
 
8.1
     
 
5.8
Site clean-up/environmental matters
   
 
20.5
   
 
3.9
     
 
16.6
    
  
    
    
$
  36.5
   
$
  14.1
     
$
  22.4
    
  
    
 
We expect to spend approximately $15 million to $16 million in 2002 related to the reserve for future costs, with the remainder to be spent over the next several years. We are currently in discussions with governmental agencies concerning a remediation program, which we believe will likely lead to a final consent order and remediation plan. We do not expect these discussions to be concluded until 2003 at the earliest. Our site clean-up and environmental reserve takes into account costs that are reasonably foreseeable at this time, based on studies performed in conjunction with obtaining the insurance policy mentioned below. As the site remediation plan is finalized and work is performed, further adjustments of the reserve may be necessary.

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In 2002, environmental risk insurance policies covering the Blue Island refinery site were procured and bound, with final policies expected to be issued within the first quarter of 2003. This insurance program will allow us to quantify and, within the limits of the policy, cap our cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self-insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a $100,000 deductible per incident. We believe this program also provides governmental agencies financial assurance that, once begun, remediation of the site will be completed in a timely and prudent manner.
 
Sale of Product Terminals.    In December 1999, we sold 15 refined product terminals, mainly located in the Midwest for net cash proceeds of approximately $34 million. We have entered into a refined product exchange agreement with an affiliate of the buyer to broaden our wholesale geographical distribution capabilities in the Midwest and expand our distribution capability nationally.
 
Sale of Retail Division.    In 1999, we sold our retail marketing division for approximately $230 million, while maintaining an approximately 5% equity interest. The retail division included all company and independently operated Clark-branded stores and the Clark trade name. After all transaction costs, the sale generated cash proceeds of approximately $215 million. The retail marketing operations were classified as discontinued operations in our consolidated statements of operations for all periods presented. A pretax gain on the sale of $60.6 million, or $36.9 million net of income taxes, was recognized in the third quarter of 1999 and is included in our discontinued operations line item.
 
In 2001, we recorded an additional pretax charge of $29.5 million, or $18.0 million net of income taxes, related to the environmental and other liabilities of our discontinued retail operations. This charge represents an increase in our estimates regarding our environmental clean up obligations and workers compensation liability and a decrease in the estimated amount of reimbursements for environmental expenditures that are collectible from state agencies under various programs. The change in estimates was prompted by the availability of new information concerning site by site clean-up plans, changing postures of state regulatory agencies, and fluctuations in the amounts available under state reimbursement programs.
 
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 how the prices of refined products adjust to reflect such changes in crude oil prices.
 
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 costs and the price of refined products have historically been 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

37

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in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. For example, three consecutive unseasonably warm winters in the Northeast resulted in reduced demand, unusually high inventories and considerably lower prices for heating oil during 1999. For further details on the economics of refining, see “Industry Overview—Economics of Refining.”
 
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 United States 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. As explained below, each of our refineries, depending on market conditions, has certain feedstock cost and/or product value advantages as compared to the benchmark refinery, and as a result, our gross margin per barrel of throughput generally exceeds the Gulf Coast crack spread.
 
Our Port Arthur refinery is able to process significant quantities of sour and heavy sour crude oil that have historically cost less than West Texas Intermediate crude oil. We measure the cost advantage of heavy sour crude oil by calculating the spread between the value of Maya crude oil, a heavy crude oil produced in Mexico, to the value of West Texas Intermediate crude oil, a light crude oil. We use Maya for this measurement because a significant amount of our long-term supply of heavy crude oil throughput is Maya. We measure the cost advantage of sour crude oil by calculating the spread between the throughput 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 refineries, the value of foreign crude oil relative to domestic crude oil is also an important factor affecting our operating results. Since many foreign crude oils, other than Maya, 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.
 
We have crude oil supply contracts with PMI Comercio Internacional, S.A. de C.V., an affiliate of Petroleos Mexicanos (PEMEX), the Mexican state oil company, that provide for our purchase of approximately 200,000 bpd of crude oil under two separate contracts. One of these contracts is a long-term agreement, under which we currently purchase approximately 162,000 bpd, designed to provide us with a stable and secure supply of Maya crude oil. An important feature of this agreement is a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstocks. This price adjustment mechanism contains a formula that represents an approximation of the coker gross margin and provides for a minimum average coker gross margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The agreement expires in 2011. For purpose of comparison, the $15 per barrel minimum average coker gross margin support amount equates to a WTI/Maya crude oil price differential of approximately $6 per barrel using market prices during the period from 1988 to 2002, which slightly exceeds actual market differentials during that period.
 
On a monthly basis, the coker gross margin, as defined under this agreement, is calculated and compared to the minimum. Coker gross margins exceeding the minimum are considered a “surplus” while coker gross margins that fall short of the minimum are considered a “shortfall.” On a quarterly basis, the surplus and shortfall determinations since the beginning of the contract are aggregated. Pricing adjustments to the crude oil we purchase are only made when there exists a cumulative shortfall. When this quarterly aggregation first reveals

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that a cumulative shortfall exists, we receive a discount on our crude oil purchases in the next quarter in the amount of the cumulative shortfall. If thereafter, the cumulative shortfall incrementally increases, we receive additional discounts on our crude oil purchases in the succeeding quarter equal to the incremental increase, and conversely, if thereafter, the cumulative shortfall incrementally decreases, we repay discounts previously received, or a premium, on our crude oil purchases in the succeeding quarter equal to the incremental decrease. Cash crude oil discounts received by us in any one quarter are limited to $30 million, while our repayment of previous crude oil discounts, or premiums, are limited to $20 million in any one quarter. Any amounts subject to the quarterly payment limitations are carried forward and applied in subsequent quarters.
 
As of September 30, 2002, a cumulative quarterly surplus of $61.7 million existed under the contract. As a result, to the extent we experience quarterly shortfalls in our coker gross margins going forward, the price we pay for Maya crude oil in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls. Assuming the WTI less Maya crude oil differential continues at its third quarter 2002 average of $4.92 per barrel, and assuming a Gulf Coast 3/2/1 crack spread similar to the third quarter 2002 average of $2.64 per barrel, we estimate the current $61.7 million cumulative surplus would be fully reversed after the third quarter of 2003. At that time, assuming a continuation of weak market conditions, we would be eligible to receive discounts on our crude oil purchases under the long-term contract with the PEMEX affiliate as described above.
 
Other than the long-term contract with the PEMEX affiliate, our crude oil supply contracts are generally terminable upon one to three months’ notice by either party. We acquire the majority of the remainder of our crude oil supply on the spot market from unaffiliated foreign and domestic sources, allowing us to be flexible in our crude oil supply source.
 
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 high octane, or premium and reformulated gasoline, low-sulfur diesel, 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 Lima refinery are generally of higher value than similar products produced on the Gulf Coast due to the fact that the Midwest consumes more refined products 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 products into the region. This advantage is measured by the excess of the Chicago crack spread over the Gulf Coast crack spread plus or minus the differential in the cost of transporting crude oil versus refined products to the region. 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 feedstocks we produce compared to the production of lower value residual fuel oil and other by-products we produce, such as petroleum coke and sulfur. Our Lima refinery produces a product slate that is of significantly higher value than the products used to calculate the Gulf Coast crack spread. Our Lima refinery also 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. In contrast to our Lima refinery, our Port Arthur refinery produces a product slate that approximates the value of the products used to calculate the Gulf Coast crack spread. Although the significant shift to heavy sour crude oil resulting from the completion of the heavy oil upgrade project has slightly lowered the overall value of the products produced at the refinery, the lower crude oil costs has greatly exceeded the decline in product value.
 
Our operating cost structure is also important to our profitability. Major operating costs include costs relating to energy, employee and contract labor, maintenance and environmental compliance. The predominant variable cost is energy and the most important benchmark for energy costs is the value of natural gas. Because the complexity of our Port Arthur refinery and its ability to process significantly greater volumes of heavy sour crude oil increased significantly as a result of the heavy oil upgrade project, it now has a higher operating cost structure, primarily related to energy and labor.

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Safety, reliability, and the environmental performance of our refinery operations are critical 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, the 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. Since 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 includes both titled inventory and fixed price purchase and sale commitments. The portion of our current target inventory position consisting of sales commitments netted against fixed price purchase commitments amounts to a net long inventory position of approximately 4 million barrels. We are generally leaving the titled portion of our inventory position target fully exposed to price fluctuations; however, beginning in the second quarter of 2002, we began to actively mitigate some or all of the price risk related to our target level of fixed price purchase and sale commitments. These risk management decisions are based on the relative level of absolute hydrocarbon prices. We generally conduct our risk mitigation activities through the purchase or sale of futures contracts on the New York Mercantile Exchange, or NYMEX. Our price risk mitigation activities carry all of the usual time, location and product grade basis risks generally associated with these activities. 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 unless the market value of our target inventory is reduced below cost. However, since the current cost of our inventory purchases and sales are generally charged to our statement of operations, our financial results are affected by price movements on the portion of our target level of fixed price purchase and sale commitments that are not price protected.
 
Results of Operations
 
The following tables provide supplementary income statement and operating data. Selected items in each of the periods are discussed separately below.
 
Net sales and operating revenues consist principally of sales of refined petroleum products and, to a minimal extent, the occasional sale of crude oil to take advantage of substitute crude slate opportunities. Cost of sales consists of the purchases of crude oils and other feedstocks used in the refining process as well as transportation, inventory management and other costs associated with the refining process and sale of the petroleum products. Both net sales and operating revenues and cost of sales are mainly affected by crude oil and refined product prices, changes to the input and product mix, and volume changes caused by acquisitions, divestitures and operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, rather than lower value finished products, such as petroleum coke.
 
Gross margin is net sales and operating revenues less cost of sales. Industry-wide results are driven and measured by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks; therefore, we discuss our results of operations in the context of gross margin.
 
Operating expenses include the costs associated with the actual operations of our plants, such as labor, maintenance, energy, taxes and environmental compliance. All environmental compliance costs, other than capital expenditures but including maintenance and monitoring, are expensed when incurred. The labor costs include the incentive compensation plans available to union employees. Our general and administrative expenses include all activities at the executive and corporate offices, the finance, human resources and information system activities at the refineries and the company-wide incentive compensation programs available to salaried employees.

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Inventory recovery (write-down) to market reflects a non-cash accounting adjustment to the value of our petroleum inventory. In accordance with GAAP, we are required to record our inventory at the lower of its cost or market value. In late 1997 and throughout 1998, market prices were significantly less than cost determined under our last-in, first-out, or LIFO, inventory valuation method. This led to market write-downs of inventory in 1997 and 1998. In 1999, our inventory turned over and market prices recovered allowing us to fully reverse our 1997 and 1998 write-downs.
 
Minority interest represents Occidental’s 10% interest in our subsidiary, Sabine, prior to the restructuring.
 
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1999
     
2000
     
2001
     
2001
     
2002
  
Financial results
   
(in millions, except per share data)
  
Net sales and operating revenue
   
$
  4,520.5
 
   
$
  7,301.7
 
   
$
  6,417.5
 
   
$
  5,170.9
 
   
$
  4,807.1
 
Cost of sales
   
 
4,099.8
 
   
 
6,562.5
 
   
 
5,251.4
 
   
 
4,133.7
 
   
 
4,342.8
 
    
  
  
  
  
Gross margin
   
 
420.7
 
   
 
739.2
 
   
 
1,166.1
 
   
 
1,037.2
 
   
 
464.3
 
Operating expenses
   
 
402.8
 
   
 
467.7
 
   
 
467.7
 
   
 
355.8
 
   
 
338.2
 
General and administrative expenses
   
 
51.5
 
   
 
53.0
 
   
 
63.3
 
   
 
45.3
 
   
 
40.8
 
Stock option compensation expense
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
9.9
 
    
  
  
  
  
Adjusted EBITDA
   
 
(33.6
)
   
 
218.5
 
   
 
635.1
 
   
 
636.1
 
   
 
75.4
 
Inventory recovery from market write-down
   
 
(105.8
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Refinery restructuring and other charges
   
 
—  
 
   
 
—  
 
   
 
176.2
 
   
 
176.2
 
   
 
172.9
 
    
  
  
  
  
EBITDA
   
 
72.2
 
   
 
218.5
 
   
 
458.9
 
   
 
459.9
 
   
 
(97.5
)
Depreciation and amortization
   
 
63.1
 
   
 
71.8
 
   
 
91.9
 
   
 
67.7
 
   
 
64.9
 
    
  
  
  
  
Operating income (loss)
   
 
9.1
 
   
 
146.7
 
   
 
367.0
 
   
 
392.2
 
   
 
(162.4
)
Interest expense and finance income, net
   
 
(91.5
)
   
 
(82.2
)
   
 
(139.5
)
   
 
(106.3
)
   
 
(81.5
)
Gain (loss) on extinguishment of long-term debt
   
 
—  
 
   
 
—  
 
   
 
8.7
 
   
 
8.7
 
   
 
(19.5
)
Income tax (provision) benefit
   
 
12.0
 
   
 
25.8
 
   
 
(52.4
)
   
 
(78.7
)
   
 
99.9
 
Minority interest
   
 
1.4
 
   
 
(0.6
)
   
 
(12.8
)
   
 
(12.4
)
   
 
1.7
 
    
  
  
  
  
Income (loss) from continuing operations
   
 
(69.0
)
   
 
89.7
 
   
 
171.0
 
   
 
203.5
 
   
 
(161.8
)
Discontinued operations
   
 
32.6
 
   
 
—  
 
   
 
(18.0
)
   
 
(8.5
)
   
 
—  
 
    
  
  
  
  
Net income (loss)
   
 
(47.0
)
   
 
89.7
 
   
 
153.0
 
   
 
195.0
 
   
 
(161.8
)
Preferred stock dividends
   
 
(8.6
)
   
 
(9.6
)
   
 
(10.4
)
   
 
(7.9
)
   
 
(2.5
)
    
  
  
  
  
Net income (loss) available to common stockholders
   
$
(45.0
)
   
$
80.1
 
   
$
142.6
 
   
$
187.1
 
   
$
(164.3
)
    
  
  
  
  
Income (loss) from continuing operations per common share:
                                             
Basic
   
$
(3.59
)
   
$
2.79
 
   
$
5.05
 
   
$
6.15
 
   
$
(3.57
)
Diluted
   
 
(3.59
)
   
 
2.55
 
   
 
4.65
 
   
 
5.67
 
   
 
(3.57
)
Weighted average common shares outstanding:
                                             
Basic
   
 
21.6
 
   
 
28.8
 
   
 
31.8
 
   
 
31.8
 
   
 
46.0
 
Diluted
   
 
21.6
 
   
 
31.5
 
   
 
34.5
 
   
 
34.5
 
   
 
46.0
 
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1999
     
2000
     
2001
     
2001
     
2002
  
Market indicators
   
(dollars per barrel, except as noted)
  
West Texas Intermediate (WTI) crude oil
   
$
  19.27
 
   
$
  30.37
 
   
$
  25.96
 
   
$
  27.84
 
   
$
  25.41
 
Crack Spreads:
                                             
Gulf Coast 3/2/1
   
 
1.71
 
   
 
4.17
 
   
 
4.22
 
   
 
4.98
 
   
 
2.93
 
Gulf Coast 2/1/1
   
 
1.37
 
   
 
4.02
 
   
 
3.92
 
   
 
4.54
 
   
 
2.42
 
Chicago 3/2/1
   
 
2.83
 
   
 
5.84
 
   
 
7.90
 
   
 
9.04
 
   
 
4.59
 
Crude Oil Differentials:
                                             
WTI less WTS (sour)
   
 
1.30
 
   
 
2.17
 
   
 
2.81
 
   
 
3.11
 
   
 
1.26
 
WTI less Maya (heavy sour)
   
 
4.83
 
   
 
7.29
 
   
 
8.76
 
   
 
9.57
 
   
 
4.90
 
WTI less Dated Brent (foreign)
   
 
1.36
 
   
 
1.92
 
   
 
1.48
 
   
 
1.68
 
   
 
1.01
 
Natural gas (dollars per million btus)
   
 
2.25
 
   
 
3.94
 
   
 
4.22
 
   
 
4.90
 
   
 
2.92
 

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Table of Contents
 
 
    
Year Ended December 31,
   
Nine Months Ended September 30,
    
1999
   
2000
   
2001
   
2001
   
2002
Selected Operational Data
   
(in thousands of barrels per day,
except as noted)
Crude oil throughput by refinery:
                                   
Port Arthur
   
 
200.0
   
 
202.1
   
 
229.8
   
 
225.2
   
 
229.1
Lima
   
 
120.7
   
 
136.4
   
 
140.5
   
 
143.0
   
 
141.0
Hartford
   
 
59.4
   
 
64.2
   
 
65.5
   
 
65.3
   
 
62.3
Blue Island
   
 
71.6
   
 
65.3
   
 
3.9
   
 
5.3
   
 
—  
    
  
  
  
  
Total crude oil throughput
   
 
451.7
   
 
468.0
   
 
439.7
   
 
438.8
   
 
432.4
Per barrel of throughput (in dollars):
                                   
Gross margin
   
$
2.55
   
$
4.32
   
$
7.27
   
$
8.66
   
$
3.93
Operating expenses
   
 
2.44
   
 
2.73
   
 
2.91
   
 
2.97
   
 
2.87
 
    
Year Ended December 31,
     
Nine Months Ended September 30,
  
    
1999
     
2000
     
2001
     
2001
     
2002
  
Selected Volumetric Data
   
bpd (thousands)
  
Percent of Total
     
bpd (thousands)
  
Percent of Total
     
bpd (thousands)
  
Percent of Total
     
bpd (thousands)
  
Percent of Total
     
bpd (thousands)
  
Percent of Total
  
Feedstocks:
                                                       
Crude oil throughput:
                                                       
Sweet
   
195.3
  
42.8
%
   
201.5
  
42.6
%
   
143.6
  
31.9
%
   
147.0
  
33.0
%
   
137.7
  
31.6
%
Light/medium sour
   
220.1
  
48.2
 
   
207.4
  
44.0
 
   
107.7
  
23.9
 
   
109.5
  
24.5
 
   
101.9
  
23.4
 
Heavy sour
   
36.3
  
8.0
 
   
59.1
  
12.4
 
   
188.4
  
41.8
 
   
182.3
  
40.9
 
   
192.8
  
44.2
 
    
 
  
 
  
 
  
 
  
 
Total crude oil
   
451.7
  
99.0
 
   
468.0
  
99.0
 
   
439.7
  
97.6
 
   
438.8
  
98.4
 
   
432.4
  
99.2
 
Unfinished and blendstocks
   
4.6
  
1.0
 
   
4.6
  
1.0
 
   
10.6
  
2.4
 
   
7.3
  
1.6
 
   
3.9
  
0.8
 
    
 
  
 
  
 
  
 
  
 
Total feedstocks
   
456.3
  
100.0
%
   
472.6
  
100.0
%
   
450.3
  
100.0
%
   
446.1
  
100.0
%
   
436.3
  
100.0
%
    
 
  
 
  
 
  
 
  
 
Production:
                                                       
Light Products:
                                                       
Conventional gasoline
   
174.6
  
37.9
%
   
193.0
  
40.4
%
   
184.8
  
39.9
%
   
182.5
  
39.7
%
   
186.5
  
41.0
%
Premium and reformulated gasoline
   
67.1
  
14.6
 
   
57.8
  
12.1
 
   
44.9
  
9.7
 
   
47.1
  
10.2
 
   
39.3
  
8.6
 
Diesel fuel
   
119.4
  
25.9
 
   
117.8
  
24.7
 
   
121.7
  
26.3
 
   
118.6
  
25.8
 
   
102.9
  
22.6
 
Jet fuel
   
35.8
  
7.8
 
   
38.0
  
8.0
 
   
42.4
  
9.1
 
   
41.8
  
9.1
 
   
49.8
  
11.0
 
Petrochemical feedstocks
   
34.5
  
7.5
 
   
36.2
  
7.6
 
   
28.5
  
6.2
 
   
29.0
  
6.3
 
   
28.8
  
6.3
 
    
 
  
 
  
 
  
 
  
 
Total light products
   
431.4
  
93.7
 
   
442.8
  
92.8
 
   
422.3
  
91.2
 
   
419.0
  
91.1
 
   
407.3
  
89.5
 
Petroleum coke and sulfur
   
17.8
  
3.9
 
   
19.0
  
4.0
 
   
33.1
  
7.1
 
   
33.4
  
7.3
 
   
36.8
  
8.1
 
Residual oil
   
11.3
  
2.4
 
   
15.5
  
3.2
 
   
8.0
  
1.7
 
   
7.2
  
1.6
 
   
10.7
  
2.4
 
    
 
  
 
  
 
  
 
  
 
Total production
   
460.5
  
100.0
%
   
477.3
  
100.0
%
   
463.4
  
100.0
%
   
459.6
  
100.0
%
   
454.8
  
100.0
%
    
 
  
 
  
 
  
 
  
 
 
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001
 
Overview.    Our net loss to common stockholders was $164.3 million ($3.57 per diluted share) in the first nine months of 2002 as compared to net income available to common stockholders of $187.1 million ($5.42 per diluted share) in the corresponding period in 2001. Our operating loss was $162.4 million in the first nine months of 2002 as compared to operating income of $392.2 million in the corresponding period in 2001. Operating income (loss) included pretax refinery restructuring and other charges of $172.9 million and $176.2 million in the first nine months of 2002 and 2001, respectively. Excluding the refinery restructuring and other charges, our operating income was $10.5 million and $568.4 million in the first nine months of 2002 and 2001, respectively. Operating income, excluding the refinery restructuring and other charges, decreased in the first nine months of 2002 compared to the same period in 2001 principally due to significantly weaker market conditions in 2002 than in 2001.
 
Net Sales and Operating Revenues.    Net sales and operating revenues decreased $363.8 million, or 7%, to $4,807.1 million in the first nine months of 2002 from $5,170.9 million in the corresponding period in 2001. This decrease was mainly attributable to lower average product prices in the first nine months of 2002 as compared to

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the same period of 2001. The overall price decline in 2002 reflects the weaker market conditions in 2002 versus the higher product prices mainly observed in the first six months of 2001. This decrease was partially offset by higher product prices in the third quarter of 2002, which we believe were influenced by uncertainties about war with Iraq and associated concerns about future crude oil supply.
 
Gross Margin.    Gross margin decreased $572.9 million to $464.3 million in the first nine months of 2002 from $1,037.2 million in the corresponding period in 2001. This decrease in gross margin was principally driven by significantly weaker market conditions in 2002 than in 2001.
 
Market
 
These weak market conditions consisted of significantly weaker crack spreads and crude oil differentials. Beginning in late 2001 and continuing into the third quarter of 2002, on an overall basis, crack spreads have been poor due to weak demand and high levels of distillate and gasoline inventories. This margin environment has been principally driven by a sluggish world economy, significant declines in air travel following the events of September 11, 2001, and an extremely mild 2001/2002 winter. The normal increase in demand for the spring and summer driving season contributed slight improvements to the crack spreads in the second quarter; however, the third quarter again reflected depressed conditions. The Gulf Coast and Chicago crack spreads were approximately 40-50% lower in the first nine months of 2002 than in the corresponding period of 2001. The third quarter of 2001 reflected a decrease from historic highs reached earlier in that year in the Gulf Coast crack spreads as supply shortages from early in the year were addressed with high refinery utilization rates and increased import levels. The Chicago crack spreads did not weaken in proportion to the Gulf Coast crack spreads in the third quarter of 2001 due primarily to supply shortages caused by an unplanned, extended outage at a Chicago refinery, as well as other factors.
 
The crude oil differentials were also significantly lower in the first nine months of 2002 as compared to the same period in 2001. The crude oil differential between WTI and Maya heavy sour crude oil was approximately 50% lower for the first nine months of 2002 than for the same period last year, and the crude oil differential between WTI and WTS sour crude oil was approximately 60% lower for the first nine months of 2002 than for the same period last year. We believe these narrowed differentials were attributed to OPEC production cutbacks during 2002, which were concentrated in heavy sour and light/medium sour crude oils. This had a significant negative impact on our gross margin because a large proportion of our crude oil throughput is heavy sour and light/medium sour crude oils, which are typically purchased at a discount from WTI, the benchmark crude oil used in industry crack spread calculations. The heavy sour crude oil accounts for between 40% and 45% of our crude oil throughput. Light and medium sour crude oils account for between 21% and 27% of our crude oil throughput. Our gross margin for the first nine months of 2002 was also affected by planned and unplanned downtime at our refineries.
 
Refinery Operations
 
In the first nine months of 2002, our Port Arthur refinery experienced crude oil throughput restrictions due to planned turnaround maintenance, unplanned coker repairs, crude supply delays and extreme weather conditions. In the third quarter of 2002, our Port Arthur refinery experienced reduced crude oil throughput rates due to planned delays in crude oil supply resulting from anticipated repairs at the coker unit, which proved to be minimal, and due to unplanned delays in crude oil supply resulting from the impact of production and transportation interruptions caused by hurricanes Isidore and Lili. In the first quarter of 2002, our Port Arthur refinery operations were also affected by the February shutdown of our coker unit for ten days for unplanned maintenance. We took advantage of the coker outage to make repairs to the distillate and naphtha hydrotreaters, including turnaround maintenance that was originally planned for later in the year. Crude oil throughput rates were restricted by approximately 18,000 bpd during this time, but returned to near capacity of 250,000 bpd following the maintenance. In January 2002, we shut down the fluid catalytic cracking (FCC) unit, gas oil hydrotreating unit and sulfur plant for approximately 39 days at our Port Arthur refinery for planned turnaround

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maintenance. This turnaround maintenance did not affect crude oil throughput rates but did lower gasoline production. We sold more unfinished products during the first quarter of 2002 due to this shutdown.
 
In the first nine months of 2001, crude oil throughput rates at our Port Arthur refinery were restricted due to a lightning strike in early May and restrictions on the crude unit as downstream process units were in start-up operations during the first quarter. The damage from the lightning strike limited the crude unit rate until the crude unit was shutdown in early July for ten days to repair the damage. Following these repairs, the Port Arthur refinery’s crude oil throughput rate was close to capacity for the remainder of the quarter.
 
In the first nine months of 2002, our Lima refinery operations were affected by an unplanned shutdown of the reformer unit in May. The result of the shutdown was the production of non-saleable inventory that was rerun in the later part of the second quarter and into the third quarter resulting in lost economics. Our Lima refinery had a slightly reduced crude oil throughput rate in the third quarter of 2002 due to delays in crude oil delivery caused by the hurricanes mentioned above. In the first nine months of 2001, crude oil throughput rates were below economic capacity at our Lima refinery due to crude oil delivery delays caused by bad weather in the Gulf Coast and a month-long maintenance turnaround on the coker and isocracker units in the first quarter.
 
Our Hartford refinery operated below capacity as it reduced inventories as it approached its closure date. The Hartford refinery ceased all crude oil processing operations in late September 2002. Crude oil throughput rates were below capacity for the first nine months of 2001 at our Hartford refinery due to coker unit repairs in the first and third quarters. All three refineries operated below economic crude oil throughput capacity during the first nine months of 2002 due to poor refining market conditions.
 
We continuously aim to achieve excellent safety and health performance. We believe that a superior safety record is inherently tied to achieving our productivity and financial goals. We measure our success in this area primarily through the use of injury frequency rates administered by the Occupational Safety and Health Administration, or OSHA. The recordable injury rate reflects the number of recordable incidents per 200,000 hours worked, and for the nine months ended September 30, 2002, our refineries had the following recordable injury rates: Port Arthur: 1.39; Lima: 1.59; and Hartford: 0.0. The United States refining industry average recordable injury rate for 2001 was 1.35. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurance that there will not be accidents resulting in injuries or even fatalities.
 
Operating Expenses.    Operating expenses decreased $17.6 million to $338.2 million for the first nine months of 2002 from $355.8 million in the corresponding period in 2001. This decrease was principally due to significantly lower natural gas prices partially offset by higher insurance and employee expenses. The higher insurance expenses related to the overall insurance environment after the events of September 11, 2001, and the higher employee expenses related primarily to new benefit plans and higher medical benefit costs for both current and post retirement plans.
 
General and Administrative Expenses.    General and administrative expenses decreased $4.5 million to $40.8 million in the first nine months of 2002 from $45.3 million in the corresponding period in 2001. This decrease included lower wages and benefits partially offset by relocation costs associated with our new Connecticut office. The lower wages related to a restructuring which resulted in a decrease by approximately one third of the administrative positions in our St. Louis office. The lower benefits principally related to lower incentive compensation under our annual incentive program partially offset by higher costs associated with new pension and retirement plans and both current and post retirement employee medical benefit plans.
 
Stock Option Compensation Expense.    Stock option compensation expense was $9.9 million in the first nine months of 2002. During the second quarter of 2002, we elected to adopt the fair value based expense recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). We previously applied the intrinsic value based expense recognition provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). SFAS No. 123 provides that the adoption of the fair value based

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method is a change to a preferable method of accounting. As provided by SFAS No. 123, the stock option compensation expense is calculated based only on stock options granted in the year of election and thereafter. All stock options granted prior to January 1, 2002 continue to be accounted for under APB No. 25.
 
In the period of adoption of SFAS No. 123, the adoption of this fair value based method increased our net loss by $0.6 million (less than $0.01 per basic share) and $0.8 million (less than $0.01 per basic share) for the three-month and six-month periods ended June 30, 2002, respectively. As provided by SFAS No. 123, the first quarter of 2002 was restated to reflect the adoption of SFAS No. 123. For the three months ended March 31, 2002, the effect of the adoption of SFAS No. 123 on loss from continuing operations and net loss to common stockholders was an additional loss of $0.2 million and $0.01 per common share.
 
Since nonvested awards issued to employees prior to January 1, 2002 continue to be accounted for using the intrinsic value based provisions of APB No. 25, employee stock-based compensation expense determined using the fair value based method applied prospectively is not necessarily indicative of future expense amounts when the fair value based method will apply to all outstanding nonvested awards. With respect to all stock option grants outstanding at September 30, 2002, the Company will record future non-cash stock option compensation expense and additional paid-in capital of $40.4 million over the applicable vesting periods of the grants.
 
Refinery Restructuring and Other Charges.    In 2002, we recorded refinery restructuring and other charges of $172.9 million, which consisted of the following:
 
 
•
 
a $137.4 million charge related to the shutdown of refining operations at our Hartford, Illinois refinery,
 
 
•
 
a $32.4 million charge related to the restructuring of our management team, refinery operations and administrative functions,
 
 
•
 
income of $5.0 million related to the unanticipated sale of a portion of the Blue Island refinery assets previously written off,
 
 
•
 
a $2.5 million charge related to the termination of certain guarantees at PACC as part of the Sabine restructuring,
 
 
•
 
a $1.4 million loss related to the sale of idled assets, and
 
 
•
 
a $4.2 million write-down of our 5% interest in Clark Retail Group, Inc., the sole stockholder of Clark Retail Enterprises, Inc., or CRE. We acquired an interest in Clark Retail Group, Inc. when PRG sold its retail business to CRE in 1999. Clark Retail Group, Inc. and CRE filed a petition to reorganize under Chapter 11 of the U.S. bankruptcy laws in October 2002.
 
See further details about the Hartford refinery closure and the management, operations and administrative restructuring below.
 
In 2001, refinery restructuring and other charges of $176.2 million consisted of a $167.2 million charge related to the January 2001 closure of the Blue Island, Illinois refinery and a $9.0 million charge related to the write-off of idled coker units at our Port Arthur refinery. See “—Factors Affecting Comparability—Closure of Blue Island Refinery” for additional discussion of the Blue Island charge and reserve. The write-off of idled coker units at our Port Arthur refinery included a charge of $5.8 million related to the net asset value of the coker units and a $3.2 million charge for future environmental clean-up costs related to the coker unit site.
 
Hartford Refinery Closure
 
In late September 2002, we ceased refining operations at our Hartford refinery after concluding there was no economically viable method of reconfiguring the refinery to produce fuels meeting new gasoline and diesel fuel specifications mandated by the federal government. Despite ceasing operations, we continue to pursue all strategic options, including expanding the uses of the petroleum product and distribution facility and selling or leasing the refinery, to mitigate the loss of jobs and refinery capacity in the Midwest.

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Since the Hartford refinery operation had been only marginally profitable over the last 10 years and since substantial investment would be required to meet new required product specifications in the future, our reduced refining capacity resulting from the shutdown is not expected to have a significant negative impact on net income or cash flow from operations. The only anticipated effect on net income and cash flow in the future will result from the actual shutdown process, including recovery of realizable asset value, and subsequent environmental site remediation, which we expect will occur over a number of years. Unless there is a need to adjust the shutdown reserve in the future as discussed below, there should be no significant effect on net income beyond 2002.
 
A pretax charge of $137.4 million was recorded in 2002, which included $70.7 million of non-cash long-lived asset write-offs to reduce the refinery assets to their estimated net realizable value of $61.0 million. The net realizable value was determined by estimating the value of the assets in a sale or operating lease transaction and was recorded as a current asset on our balance sheet. In October 2002, we announced that we would continue to operate the Hartford terminal facility to accommodate our wholesale petroleum product distribution business. As a result, we reclassified the net book value of the terminal assets from assets held for sale to property, plant and equipment. This reduced the estimated net realizable value of the remaining refinery assets to $49.0 million. We have had preliminary discussions with third parties regarding a transaction for the refinery assets, but there can be no assurance that one will be completed. In the event that a sale or lease transaction is not completed, the net realizable value may be less than $49.0 million and a further write-down may be required. In the second quarter of 2002, we completed an evaluation of our warehouse stock, catalysts, chemicals, and additives inventories, and we determined that a portion of these inventories would not be recoverable upon the closure or sale of the refinery. Accordingly, we wrote-down these assets by $3.2 million.
 
The total charge also included a reserve for future costs of $62.5 million as itemized below. The Hartford restructuring reserve balance and net cash activity as of September 30, 2002 is as follows:
 
    
Initial Reserve
   
Net Cash Outlay
     
Reserve as of September 30, 2002
Employee severance
   
$
16.6
   
$
0.2
     
$
16.4
Plant closure/equipment remediation
   
 
12.9
   
 
5.6
     
 
7.3
Site clean-up/environmental matters
   
 
33.0
   
 
—  
     
 
33.0
    
  
    
    
$
  62.5
   
$
5.8
     
$
  56.7
    
  
    
 
Management adopted an exit plan that details the shutdown of the process units at the refinery and the subsequent environmental remediation of the site. We completed the process unit shutdown and hydrocarbon purging in the fourth quarter of 2002. We terminated approximately 300 of 315 employees, both hourly (covered by collective bargaining agreements) and salaried, in October 2002. The remainder of the employees are expected to be terminated within a year. The site clean-up and environmental reserve takes into account costs that are reasonably foreseeable at this time. As the final disposition of the refinery is determined and a site remediation plan refined, further adjustments of the reserve may be necessary, and such adjustments may be material. We expect to spend approximately $20 million to $30 million in 2002 related to employee severance and the process unit shutdown and hydrocarbon purge.
 
Finally, the total charge included a $1.0 million reserve related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. This liability was recorded in “Other Long-term Liabilities” on the balance sheet together with our other post-retirement liabilities.
 
Alleged Asbestos Exposure    
 
We, along with numerous other defendants, have recently been named in approximately 22 individual lawsuits alleging personal injury resulting from exposure to asbestos. A majority of the claims have been filed by employees of third-party independent contractors who purportedly were exposed to asbestos while performing services at our Hartford refinery. We have recently been voluntarily dismissed in 17 of the lawsuits in which we

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have been named. The remainder are in the early stages of litigation. Substantive discovery has not yet been concluded. It is impossible at this time for us to quantify our exposure from these claims, but, based on currently available information, we do not believe that any liability resulting from the resolution of these matters will have a material adverse effect on our consolidated financial position, results of operations or cash flow.
 
Management, Refinery Operations and Administrative Restructuring
 
In February 2002, we began the restructuring of our executive management team and subsequently our administrative functions with the hiring of Thomas D. O’Malley as chairman, chief executive officer and president and William E. Hantke as executive vice president and chief financial officer. In the first quarter of 2002, as a result of the resignation of the officers who previously held these positions, we recognized severance expense of $5.0 million and non-cash compensation expense of $5.8 million resulting from modifications of stock option terms. In addition, we incurred a charge of $5.0 million for the cancellation of a monitoring agreement with an affiliate of our largest stockholder, Blackstone Management Associates III L.L.C.
 
In the second quarter of 2002, we commenced a restructuring of our St. Louis-based general and administrative operations and recorded a charge of $6.5 million for severance, outplacement and other restructuring expenses relating to the elimination of 107 hourly and salaried positions. In the third quarter of 2002, we announced plans to reduce our non-represented workforce at our Port Arthur, Texas and Lima, Ohio refineries and make additional staff reductions at our St. Louis administrative office. We recorded a charge of $10.1 million for severance, outplacement, and other restructuring expenses relating to the elimination of 140 hourly and salaried positions. Included in this charge is $1.3 million related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. This liability was recorded in “Other Long-term Liabilities” on the balance sheet together with our other post-retirement liabilities. Reductions at the refineries occurred in October 2002 and those at the St. Louis office will take place by the end of the first quarter of 2003. The reserve related to the refineries and St. Louis restructuring is as follows:
 
    
Initial Reserve
   
Additional Reserve
   
Net Cash Outlay
     
Reserve at September 30, 2002
Refineries and St. Louis restructuring
   
$
  6.5
   
$
  8.8
   
$
  4.6
     
$
  10.7
 
We expect to spend approximately $11 million to $13 million in 2002 related to these refinery and St. Louis restructuring activities.
 
Depreciation and Amortization.    Depreciation and amortization expenses decreased $2.8 million to $64.9 million in the first nine months of 2002 from $67.7 million in the corresponding period in 2001. This decrease was principally due to ceasing the recording of depreciation and amortization expense for the Hartford refinery assets beginning in March 2002. This decrease was partially offset by higher amortization expenses at our Lima refinery due to the completion of turnaround activity performed in 2001, and higher amortization at our Port Arthur refinery due to the completion of turnaround activity performed in early 2002.
 
Interest Expense and Finance Income, net.    Interest expense and finance income, net decreased $24.8 million to $81.5 million in the first nine months of 2002 from $106.3 million in the corresponding period in 2001. This decrease related primarily to lower interest expense due to the repurchase of certain debt securities in 2001 and 2002 and lower interest rates on our floating rate debt. The decrease was partially offset by lower interest income as cash balances declined.
 
Gain or Loss on Extinguishment of Long-term Debt.    In the first nine months of 2002, we recorded a loss on extinguishment of long-term debt of $19.5 million related to the redemption of certain long-term debt. This loss included premiums associated with the early repayment of long-term debt of $9.4 million, a write-off of unamortized deferred financing costs related to this debt of $9.5 million, and the write-off of a prepaid premium for an insurance policy guaranteeing the interest and principal payments on Sabine’s long-term debt of $0.6 million.

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In the first nine months of 2001, we repurchased in the open market $21.3 million in face value of our 9½% senior notes, $30.6 million in face value of our 10 7/8% senior notes, and $5.9 million in face value of our 11½% exchangeable preferred stock. As a result of these transactions, we recorded a gain of $8.7 million, which included discounts of $9.3 million offset by the write-off of deferred financing costs related to the notes.
 
Income Tax (Provision) Benefit.    We recorded a $99.9 million income tax benefit in the first nine months of 2002 as compared to an income tax provision of $78.7 million in the corresponding period in 2001. The income tax provision of $78.7 million for 2001 included the effect of a $30.0 million decrease in the deferred tax valuation allowance. During the first quarter of 2001, we reversed our remaining deferred tax valuation allowance as a result of the analysis of the likelihood of realizing the future tax benefit of our federal and state tax loss carryforwards, alternative minimum tax credits and federal and state business tax credits.
 
As of September 30, 2002, we had a net deferred tax asset of $78.8 million recorded on our balance sheet. SFAS No. 109, Accounting for Income Taxes, requires that deferred tax assets be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. When applicable a valuation allowance should be recorded to reduce the deferred tax asset to the amount that is more likely than not to be realized. As a result of the analysis of the likelihood of realizing the future tax benefit of our federal and state tax loss carryforwards, alternative minimum tax credits and federal and state business tax credits, we have not provided a valuation allowance related to the net deferred tax asset. The likelihood of realizing the net deferred tax asset is analyzed on a regular basis and should it be determined that it is more likely than not that some portion or all of the net deferred tax asset will not be realized, a tax valuation allowance and a corresponding income tax provision would be required at that time.
 
Future changes, even slight changes, in the ownership of our common stock (including, among other things, the exercise of compensatory options) could result in an aggregate change in ownership of more than 50% for purposes of Section 382 of the Internal Revenue Code, which could substantially limit the availability of our net operating loss carryforwards, other losses and tax credits.
 
Discontinued Operations.    In 2001, we recorded a pretax charge of $14.0 million, $8.5 million net of income taxes, related to environmental liabilities of discontinued retail operations. This charge represented an increase in estimates regarding our environmental clean up obligation and was prompted by the availability of new information concerning site by site clean up plans and changing postures of state regulatory agencies.
 
2001 Compared to 2000
 
Overview.    Net income available to common stockholders increased $62.5 million, or 78%, to $142.6 million in 2001 from $80.1 million in 2000. Operating income increased $220.3 million to $367.0 million in 2001 from $146.7 million in 2000. Excluding non-recurring restructuring and other charges of $176.2 million in 2001, operating income increased $396.5 million in 2001 compared to 2000. This increase was principally due to the completion and operation of the heavy oil upgrade project at our Port Arthur refinery, combined with continued strong market conditions.
 
Net Sales and Operating Revenues.    Net sales and operating revenues decreased by $884.2 million, or 12%, to $6,417.5 million in 2001 from $7,301.7 million in 2000. This decrease was principally attributable to steep declines in petroleum product prices in the second half of the year, particularly after the September 11th terrorist attacks, and to our shutdown of the Blue Island, Illinois refinery in January 2001.
 
Gross Margin.    Gross margin increased by $426.9 million, or 58%, to $1,166.1 million in 2001 from $739.2 million in 2000. This increase was principally due to the processing of a greater quantity of less expensive heavy sour crude oil at our Port Arthur refinery, significant discounts on sour and heavy sour crude oil, strong gasoline and distillate market conditions, especially in the first half of the year, as well as solid performance by

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our refineries. These gains were partially offset by poor market conditions in the fourth quarter and plant downtime and operational issues as described below.
 
The improvement in crude oil discounts was reflected in the increase in the average sour and heavy sour crude oil differentials to West Texas Intermediate. The completion of the heavy oil upgrade project at our Port Arthur refinery has positioned us to maximize the improved crude oil differentials, having processed heavy sour crude oil equal to 43% of total crude oil throughput in 2001 compared to 13% of heavy sour crude oil in 2000. The improved crude oil differentials and the increase in usage of heavy sour crude oil together contributed over $450 million to gross margin in 2001. Margins for light products such as gasoline and distillates remained strong in the first six months of 2001 due to the continued tight supply and demand balance. Industry inventories remained at low levels through most of the first six months of 2001 and were further lowered by industry-wide maintenance turnarounds performed in the first quarter. The improvement in gasoline and distillate margins was reflected by increases in the Gulf Coast and Chicago crack spreads. In the second half of the year, the Gulf Coast and Chicago crack spreads weakened as gasoline and distillate inventory levels increased due to high refinery utilization rates, high import levels, and unseasonably low demand. The lower demand was driven by decreases in air travel after the September 11th terrorist attacks, a weak industrial sector, a general downturn in the economy, and mild winter weather. Due primarily to significant unplanned downtime experienced by other Midwest refiners, the Chicago crack spread did not weaken in proportion to the Gulf Coast crack spread through the third quarter. The Chicago crack spread decreased significantly during the fourth quarter as product was imported into the region due to the higher margins. Overall, crack spreads in 2001 remained above prior year levels.
 
Excluding the Blue Island refinery’s results, our crude oil throughput rate was higher in 2001 as compared to 2000. Overall, our refineries ran well in 2001 with some planned maintenance shutdowns and restrictions and a few unplanned restrictions of our crude and other units. The crude oil throughput rate at our Port Arthur refinery of 229,800 bpd was below capacity of 250,000 bpd in 2001 because units downstream were in start-up operations during the first quarter and a lightning strike in early May 2001 limited the crude unit rate until the crude unit was shut down in early July for ten days to repair the damage caused by the lightning strike. The Port Arthur refinery also experienced a slightly reduced crude oil throughput rate late in the fourth quarter due to minor repairs of the coker and crude units. In March 2001, the Lima refinery performed a planned month-long maintenance turnaround on its coker and isocracker units, and in November 2001 it performed a planned seven-day maintenance turnaround on its crude and other units. The Lima refinery also experienced crude oil supply delays caused by bad weather in the Gulf Coast. Our Hartford refinery experienced ten days of unplanned downtime for coker unit repairs early in the year and planned restricted utilization of the coker unit late in the year due to minor repairs and a shutdown of a third party sulfur plant utilized by Hartford.
 
Operations in 2000 were affected by the planned month-long maintenance turnaround and subsequent 11-day unscheduled downtime of the Port Arthur refinery crude unit, planned restrictions at all refineries due to weak margin conditions early in the year, unplanned downtime at the Lima refinery due to two electrical outages and a failed compressor, unplanned downtime at the Blue Island refinery requiring maintenance on its vacuum and crude unit, and crude oil supply disruptions to all of the plants late in the year.
 
Operating Expenses.    Operating expenses remained the same at $467.7 million for both 2001 and 2000. Operating expenses benefited significantly in 2001 from the lack of eleven months of operating expenses for the Blue Island refinery in 2001 due to its closure in late January. Offsetting this decrease, however, were higher costs at our Port Arthur refinery for the operation of the new heavy oil processing units, higher energy costs at our Port Arthur refinery, and additional repair and maintenance costs at our Hartford refinery.
 
General and Administrative Expenses.    General and administrative expenses increased $10.3 million, or 19%, to $63.3 million in 2001 from $53.0 million in 2000. This increase was principally due to higher incentive compensation under our annual incentive plan, expenses related to the planning, design and implementation of a new financial and commercial information system, and new support services for the heavy oil processing facility.

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Refinery Restructuring and Other Charges.    The refinery restructuring and other charges consisted of a $167.2 million charge related to the January 2001 closure of the Blue Island refinery and a $9.0 million charge related to the write-off of idled coker units at the Port Arthur refinery. See “—Factors Affecting Comparability — Closure of Blue Island Refinery” for additional discussion of the Blue Island charge. The write-off of idled coker units at our Port Arthur refinery included a charge of $5.8 million related to the net asset value of the coker units and a $3.2 million charge for future environmental clean-up costs related to the site. We now believe that an alternative use of the coker units is not probable.
 
Depreciation and Amortization.    Depreciation and amortization expenses increased $20.1 million, or 28%, to $91.9 million in 2001 from $71.8 million in the corresponding period in 2000. This increase was principally due to depreciation on the new units associated with the heavy oil upgrade project. We began depreciating these assets in accordance with our property, plant and equipment policy during the first quarter of 2001 following substantial completion of the heavy oil upgrade project and commencement of operations. Amortization contributed to the increase due to a major 2000 Port Arthur refinery turnaround and a first quarter 2001 Lima refinery turnaround.
 
Interest Expense and Finance Income, net.    Interest expense and finance income, net increased by $57.3 million, or 70%, to $139.5 million in 2001 from $82.2 million in 2000. In 2000, the majority of the interest costs on the 12½% senior notes and the senior secured bank loan of our subsidiary, PAFC, were capitalized as part of the heavy oil upgrade project. These costs are now expensed as a result of the commencement of operations in early 2001. Offsetting a portion of this increase were lower interest rates on our floating rate loans.
 
Gain on Extinguishment of Long-term Debt.    In the third quarter of 2001, we repurchased in the open market $21.3 million in face value of our 9½% senior notes, $30.6 million in face value of our 10 7/8% senior notes, and $5.9 million in face value of our 11½% exchangeable preferred stock. As a result of these transactions, we recorded a gain of $8.7 million, which included discounts of $9.3 million offset by the write-off of deferred financing costs related to the notes.
 
Income Tax (Provision) Benefit.    The income tax provision increased $78.2 million to $52.4 million in 2001 from a tax benefit of $25.8 million in the corresponding period in 2000. The income tax provision of $52.4 million in 2001 consisted of a provision on income from continuing operations partially offset by the complete reversal of the remaining tax valuation allowance of $30.0 million. The income tax benefit of $25.8 million in 2000 included a reversal of a portion of our tax valuation allowance of $50.8 million partially offset by a provision on income. In September 2001, we made a federal estimated income tax payment of $13.0 million.
 
Our pretax earnings for financial reporting purposes in the future will generally be fully subject to income taxes, although our actual cash payment of taxes is expected to benefit from regular tax and alternative minimum tax net operating loss carryforwards available at December 31, 2001 of approximately $246 million and $186 million, respectively. Future changes, even slight changes, in the ownership of our common stock (including, among other things, the exercise of compensatory options) could result in an aggregate change in ownership of more than 50% for purposes of Section 382 of the Internal Revenue Code, which could substantially limit the availability of our net operating loss carryforwards, other losses and tax credits.
 
Discontinued Operations.    In 2001, we recorded an additional pretax charge of $29.5 million (net of income taxes—$18.0 million) related to the environmental and other liabilities of the discontinued retail operations. See “—Factors Affecting Comparability—Sale of Retail Division” for additional discussion of this charge.
 
2000 Compared to 1999
 
Overview.    Net income available to common stockholders increased by $125.1 million to net income available to common stockholders of 80.1 million in 2000 from a net loss to common stockholders of $45.0 million in 1999. Operating income increased $137.6 million to $146.7 million in 2000 from $9.1 million in 1999.

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Excluding the $105.8 million recovery of a non-cash inventory charge in 1999, operating income increased by $243.4 million in 2000 compared to 1999. This increase was principally due to strong market conditions throughout most of 2000, as evidenced by the change in the Gulf Coast crack spread, which increased from $1.71 per barrel in 1999 to $4.17 per barrel in 2000 and improved sour and heavy sour crude oil differentials.
 
Net Sales and Operating Revenues.    Net sales and operating revenues increased $2,781.2 million, or 62%, to $7,301.7 million in 2000 from $4,520.5 million in 1999. This increase was principally due to higher petroleum prices, as production remained steady. Our average sales price per barrel increased by approximately $14 per barrel for the full year 2000 versus 1999.
 
Gross Margin.    Gross margin increased $318.5 million, or 76%, to $739.2 million in 2000 from $420.7 million in 1999. This increase was principally due to continued strong refined product conditions, particularly for gasoline and distillate margins, and strong operational performance at our refineries in the second half of the year. These significant improvements were partially offset by poor margins on heavier products such as petroleum coke and asphalt due to higher import costs, planned and unplanned downtimes at our refineries, and negative inventory management results.
 
Market conditions for 2000 started improving over prior year levels during the first quarter and remained above prior year levels for the rest of the year, reaching record levels to date during the second quarter. The main contributor to the higher gross margin was the improvement in gasoline and distillate margins, which were reflected in significant increases in the average Gulf Coast and Chicago crack spreads. We believe these improved market conditions were due mainly to low domestic inventory levels, solid demand, the mandated introduction of a new summer-grade reformulated gasoline, and pipeline supply disruptions. Crude oil discounts for heavier and sour crude oils improved over the prior year, also contributing to gross margin, as evidenced by the improved sour and heavy sour crude oil differentials. These benefits were partially offset by poor heavy product margins as prices for products such as petroleum coke and residual fuel did not track the high feedstock prices in the period.
 
Major scheduled maintenance turnarounds at our Port Arthur refinery in 2000 and our Lima refinery in 1999 resulted in an opportunity cost from lost production of $30 million in 2000 and $23 million in 1999. In 2000, our Port Arthur refinery crude oil throughput rates were reduced in the first quarter due to problems with the FCC unit, and significantly lowered in the second quarter due to a scheduled turnaround and unscheduled downtime of the crude unit. The work performed during the scheduled turnaround expanded the crude unit capacity from 232,000 bpd to 250,000 bpd and readied the unit to process up to 80% heavy sour crude oil as part of the heavy oil upgrade project. In the third and fourth quarters, the crude oil throughput rate was near its new capacity of 250,000 bpd except for some minor crude oil availability problems in the fourth quarter due to bad weather. Crude oil throughput rates at our Port Arthur refinery were reduced below capacity in 1999 due to poor economic conditions. Crude oil throughput in 2000 was higher than in 1999 at our Lima and Hartford refineries. This was principally because both refineries had solid performance, with only short unplanned downtimes and reduced rates early in 2000 due to poor economic conditions and late in 2000 due to crude oil supply disruptions. Blue Island refinery crude oil throughput rates for 2000 were lower than 1999 due to unplanned downtimes and crude oil supply disruptions.
 
Our gross margin in 2000 was significantly reduced as a result of negative inventory management results. We incurred losses of approximately $73 million from hedging inventory positions in excess of our target inventory position levels in a backwardated market. Backwardation refers to the time structure of the futures market when the price of a commodity in the current month is higher than the price in the future. This creates an embedded hedging cost as short futures positions are closed, if prices are higher than the hedged price. The inventory position was over target because of the effects of unplanned refinery downtime early in the year, the timing of fixing crude oil price commitments and the fact that, for much of the year, we were hedging to a target inventory level that was not appropriate. The financial effects of inventory management in 1999 were marginally positive.

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Operating Expenses.    Operating expenses increased $64.9 million, or approximately 16%, to $467.7 million in 2000 from $402.8 million in 1999. This increase was principally due to higher energy and repair and maintenance costs. The average natural gas price increase of $1.69 per million btu, an increase of 75% over 1999 prices, reflected the increase in energy cost. In addition, our Port Arthur refinery incurred higher repair and maintenance costs in conjunction with the planned turnaround and subsequent unscheduled downtime of its crude unit.
 
General and Administrative Expenses.    General and administrative expenses increased $1.5 million, or approximately 3%, to $53.0 million in 2000 from $51.5 million in 1999. This slight increase was due to higher incentive compensation under our annual incentive plan, offset in part by lower wholesale costs due to the sale of the terminals, the absence of year 2000 systems remediation costs, and the absence of start-up costs related to the initial financing of the heavy oil upgrade project.
 
Depreciation and Amortization.    Depreciation and amortization increased $8.7 million, or approximately 14%, to $71.8 million in 2000 from $63.1 million in 1999. This increase was principally due to the full year impact of a Lima maintenance turnaround performed in 1999 and higher capital expenditures.
 
Interest Expense and Finance Income, net.    Interest expense and finance income, net decreased $9.3 million, or approximately 10%, to $82.2 million in 2000 from $91.5 million in 1999. Of this decrease, $7.6 million related to the absence in 2000 of start-up costs associated with the initial financing of the heavy oil upgrade project. For both 2000 and 1999, the majority of the interest expense from the debt incurred to finance the heavy oil upgrade project was capitalized as part of the project. The remainder of the decrease was due to higher interest income on invested cash balances which more than offset the higher interest expense due to higher interest rates on our $240 million floating rate term loan.
 
Income Tax Benefit.    The income tax benefit increased $13.8 million to $25.8 million in 2000 from $12.0 million in 1999. The income tax benefit of $25.8 million in 2000 represented a decrease in a deferred tax valuation allowance of $50.8 million, partially offset by a provision on income from continuing operations. The income tax benefit of $12.0 million in 1999 reflected the effect of intra-period tax allocations resulting from the utilization of current year operating losses to offset the net income of the discontinued retail division, partially offset by the write-down of a net deferred tax asset.
 
Discontinued Operations.    We reported the results of our retail marketing business that we sold in 1999, which consisted of a loss of $4.3 million, net of an income tax benefit of $2.7 million, and the gain on the sale of the business of $36.9 million, net of income tax provision of $23.7 million, as discontinued operations in 1999.
 
Outlook
 
The forward-looking statements made in this Outlook section, as well as any forward-looking statements within other sections of this prospectus, reflect our expectations regarding future events as of the date of the filing of this prospectus, but do not reflect the acquisition of the Memphis refinery. Words such as “expects,” “intends,” “plans,” “projects,” “believes,” “estimates,” “will” and similar expressions typically identify such forward-looking statements. Even though we believe our expectations regarding future events are based on reasonable assumptions, forward-looking statements are not guarantees of future performance. For example, set forth in the Refinery Operations section below, we discuss our expectations regarding the performance of our Port Arthur and Lima refineries for the fourth quarter of 2002. Despite our expectations, factors beyond our control such as the reliability and efficiency of our operating facilities, the impact of severe weather, crude oil supply interruptions, and acts of war or terrorism could result in restricted operations, unplanned downtime, and other unanticipated results. See “Risk Factors” for an expanded list of the factors that could cause actual results to differ materially from our current expectations.

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Market.    Crack spreads and crude oil differentials in the fourth quarter of 2002 improved over the results of the prior three quarters. The average Gulf Coast and Chicago crack spreads increased 27% and 36%, respectively, for the fourth quarter of 2002 over the average of the first nine months of 2002. We believe these margins were principally driven by production and transportation interruptions due to hurricanes Isidore and Lili at the beginning of the quarter. Crude oil differentials also improved in the quarter, increasing by approximately 25% for the fourth quarter of 2002 over the average for the first nine months of 2002.
 
Gross Margin.    It is common practice in our industry to look to benchmark market indicators as a predictor of actual refining margins. For example, the 3/2/1 benchmark crack spread models a refinery that consumes WTI sweet crude oil and produces roughly 66% regular gasoline and 33% high sulfur distillate. To improve the reliability of this benchmark as a predictor of actual refining margins, it must first be adjusted for a crude oil slate that is not 100% light and sweet. Secondly, it must be adjusted to reflect variances from the benchmark product slate to the actual, or anticipated, product slate. Lastly, it must be adjusted for any other factors not anticipated in the benchmark, including ancillary crude and product costs such as transportation, storage and credit fees, inventory fluctuations and price risk management activities.
 
Our Port Arthur refinery has historically produced roughly equal parts gasoline and distillate. For this reason, we believe the Gulf Coast 2/1/1 crack spread more closely reflects our product slate than the Gulf Coast 3/2/1 crack spread. However, approximately 15% of Port Arthur’s product slate is lower value petroleum coke and residual oils which will negatively impact the refinery’s performance against the benchmark crack spread.
 
Port Arthur’s crude oil slate is approximately 80% Maya heavy sour crude oil and 20% medium sour crude oil. Accordingly, the WTI/Maya and WTI/WTS crude oil differentials can be used as an adjustment to the benchmark crack spread. As discussed elsewhere in this prospectus, we will not receive any discounts on our purchases of Maya crude oil under our long-term crude oil supply agreement through the balance of 2002. Ancillary crude costs, primarily transportation, at Port Arthur averaged $0.95 per barrel of crude oil throughput for the first nine months of 2002. Our reformer unit was down for repairs for approximately two weeks during late October and early November and crude oil throughput rates were restricted during this period. No significant downtime is planned for our Port Arthur refinery for the balance of 2002, and we expect crude oil throughput rates in the fourth quarter of 2002 to continue at, or near, their year-to-date rate in 2002.
 
Our Lima refinery has a product slate of approximately 60% gasoline and 30% distillate and we believe the Chicago 3/2/1 is an appropriate benchmark crack spread. This refinery consumes approximately 95% light sweet crude oil with the balance being light sour crude oils. We opportunistically buy a mix of domestic and foreign sweet crude oils. The foreign crude oils consumed at Lima are priced relative to Brent and the WTI/Brent differential can be used to adjust the benchmark. Ancillary crude costs for Lima averaged $1.49 per barrel of crude throughput for the first nine months of 2002. In the fourth quarter of 2002, the Lima refinery shutdown its reformer unit for approximately 10 days for repairs, which restricted crude oil throughput rates as well as other unit operations. However, crude oil throughput in the fourth quarter of 2002 is expected to remain at or above year-to-date levels.
 
Operating Expenses.    Natural gas is the most variable component of our operating expenses. On an annual basis, our refineries consume approximately 26.7 million mmbtu of natural gas. Excluding the Hartford refinery, we anticipate this usage will be 21.9 million mmbtu. In a normalized natural gas pricing environment and assuming average crude oil throughput levels, our annual operating expenses should range between $450 million and $475 million. The closure of the Hartford refinery is expected to reduce this amount to between $360 million and $380 million.
 
General and Administrative Expenses.    During 2002, we restructured our general and administrative operations to reduce our overhead costs. As part of these cost reductions we have indefinitely suspended our Senior Executive Retirement Plan, or SERP, and the plan participants have consented to the suspension. In addition, Mr. O’Malley has voluntarily agreed to reduce his annual salary by 40% from $500,000 to $300,000.

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Mr. O’Malley may reinstate his previous annual salary by giving 30 days notice to us. The SERP may be reinstated with approval of our board of directors. We expect the restructuring to be completed by the end of the first quarter of 2003, and we expect our general and administrative expenses to total approximately $38 million for 2003.
 
We recognize non-cash, stock option compensation expense computed under SFAS No. 123. As of September 30, 2002, we had incurred $9.9 million in stock option compensation expense for all stock options granted to date in 2002, representing 77% of all stock options currently outstanding. We expect to record approximately $4.2 million per quarter for nine more quarters, reflecting the remaining vesting period for the outstanding 2002 options granted to date. Future stock option grants will be expensed pursuant to the recognition provisions of SFAS No. 123.
 
Insurance Expense.    We carry insurance policies on insurable risks, which we believe to be appropriate at commercially reasonable rates. While we believe that we are adequately insured, future losses could exceed insurance policy limits or, under adverse interpretations, be excluded from coverage. Future costs, if any, incurred under such circumstances would have to be paid out of general corporate funds.
 
The Company’s major insurance policies renewed on October 1, 2002 with a one-year term. Due primarily to the continuing effects of the events of September 11, 2001 on the insurance market, certain coverage terms, including terrorism coverage, were restricted or eliminated at renewal, certain deductibles were raised, certain coverage limits were lowered, and overall premium rates increased by 23%. Higher insurance premium expenses will be reflected in our results beginning in the fourth quarter.
 
Depreciation and Amortization.    Depreciation and amortization expense for the third quarter of 2002 was $20.8 million and excludes the Hartford refinery, which has been accounted for as an asset held for sale. This amount will increase in future periods based upon capital expenditure activity. Included in this amount is the amortization of our turnaround costs, generally over four years.
 
Interest Expense.    Based on our outstanding long-term debt at September 30, 2002, our annual gross interest expense is approximately $85 million. All of our debt is at fixed rates with the exception of $240 million in floating rate notes tied to LIBOR. Reported interest expense is reduced by capitalized interest.
 
Income Taxes.    Our effective tax rate for the nine months ended September 30, 2002 was 37.9% Our effective tax rate for the fourth quarter of 2002 was lower than the rate for the first nine months of the year, primarily due to business tax credits. Our effective tax rate in 2003 should approximate 37% to 38%.
 
Capital Expenditures and Turnarounds.    Capital expenditures and turnarounds for the first nine months of 2002 totaled $97.5 million. We spent $38.1 million in the fourth quarter of 2002 and plan to spend approximately $175 million in 2003. We plan to fund capital expenditures with internally generated funds. However, if the average market environment experienced in the first nine months of 2002 continues, this plan may not be practicable and we are reevaluating the scope and timing of our capital expenditures plan.
 
Liquidity and Capital Resources
 
Cash Balances
 
As of September 30, 2002, we had a cash and short-term investment balance of $158.0 million. In addition, under an amended common security agreement related to PAFC’s senior debt, PACC is required to restrict $45.0 million of cash for debt service at all times plus restrict an amount equal to the next scheduled principal and interest payment, prorated based on the number of months remaining until that payment is due. As of September 30, 2002, cash of $51.9 million was restricted under these requirements.

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We maintain a directors’ and officers’ insurance policy, which insures our directors and officers from any claim arising out of an alleged wrongful act by such persons in their respective capacities as directors and officers. Pursuant to indemnity agreements between us and each of our directors and officers, we have formed a captive insurance subsidiary, Opus Energy, to provide additional financial coverage for such claims. We have funded an initial $3.0 million and have committed to funding $1 million annually until a loss fund of $10 million is established.
 
As of December 31, 2001, we had cash, cash equivalents and short-term investments of $511.8 million. Under a common security agreement related to our senior debt at PAFC, PACC’s cash of $222.8 million was reserved under a secured account structure for specific operational uses and mandatory debt repayment. The operational uses included various levels of spending, such as current and operational working capital needs, interest and principal payments, taxes, and maintenance and repairs. Cash was applied to each level until that level had been fully funded, upon which the remaining cash flowed to the next level. Once these spending levels were funded, the remaining cash surplus satisfied obligations of a debt service reserve and mandatory debt prepayment with funding occurring semiannually on January 15th and July 15th. On January 15, 2002, PACC used $59.7 million of cash to make a mandatory prepayment of debt under the senior secured bank loan. In addition, as of December 31, 2001, PACC had $30.8 million of cash and cash equivalents restricted for debt service, which included principal of $6.5 million and interest of $24.3 million due in January 2002. These PACC cash restrictions were significantly modified and the secured account structure eliminated in June 2002 under the amended and restated common security agreement due to the Sabine restructuring as explained above.
 
Cash Flow from Operating Activities
 
Net cash used in operating activities for the nine months ended September 30, 2002 was $42.2 million compared to net cash provided from operations of $390.2 million in the corresponding period of 2001. The use of cash for operating activities in 2002 as compared to the provision of cash from operations in 2001 is mainly attributable to weak market conditions, which resulted in poor operating results. Working capital as of September 30, 2002 was $291.7 million, a 1.51-to-1 current ratio, versus $482.6 million as of December 31, 2001, a 1.83-to-1 current ratio. The decrease in working capital included the use of approximately $203 million of available cash, excluding initial public offering proceeds, to repay long-term debt. Our cash investment in hydrocarbon working capital at September 30, 2002 remained approximately $50 million above our normalized operating level due primarily to timing of crude oil purchases and product receipts. This incremental investment is believed to be recoverable in the ordinary course of business.
 
We have increased our reserve for uncollectible accounts receivable to $3.2 million primarily in response to increased risk with respect to our wholesale customers caused by the continued downturn of the U.S. economy.
 
In 1999, we sold crude oil linefill in the pipeline system supplying the Lima refinery to Koch Supply and Trading L.P. or Koch. As part of the agreement with Koch, we were required to repurchase approximately 2.7 million barrels of crude oil in this pipeline system in September 2002. On October 1, 2002, Morgan Stanley Capital Group Inc., or MSCG, purchased the 2.7 million barrels of crude oil from Koch in lieu of our purchase obligation. We have agreed to purchase those barrels of crude oil from MSCG upon termination of our agreement with them, at then current market prices as adjusted by certain predetermined contract provisions. The initial term of the contract continues until October 1, 2003, and thereafter automatically renews for additional 30-day periods unless terminated by either party. We have hedged the economic price risk related to the repurchase obligation through the purchase of exchange-traded futures contracts.
 
Clark Retail Group, Inc. and its wholly owned subsidiary, CRE, filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on October 15, 2002. As part of PRG’s sale of its retail business to CRE in July 1999, PRG assigned approximately 170 leases and subleases of retail stores to CRE. PRG remains jointly and severally liable for CRE’s obligations under approximately 150 of those leases, including payment of rent, taxes and environmental cleanup responsibilities for releases of petroleum occurring during the term of the

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leases. Should CRE reject some or all of these leases, PRG may become responsible for these obligations. We are currently evaluating what the financial impact on us will be if PRG is forced to assume liability for the rent and cleanup obligations under a significant number of these leases. Should any of these leases revert to PRG, we will attempt to reduce the potential liability by subletting or reassigning the leases.
 
Net cash provided by operating activities for the year ended December 31, 2001 was $439.2 million compared to $124.4 million for the year ended December 31, 2000 and $85.5 million for the year ended December 31, 1999. Cash flow from operating activities for the year ended December 31, 2000 and 2001 were mainly impacted by the improvement in cash earnings. Cash flow from operating activities for the year ended December 31, 1999 were mainly impacted by a significant working capital benefit offset by the effects of poor refining margins on cash earnings. Working capital as of December 31, 2001 was $482.6 million, a 1.83:1 current ratio, compared to $325.0 million as of December 31, 2000, a 1.51:1 current ratio.
 
As of December 31, 2001, our future minimum lease payments under non-cancelable operating leases were as follows (in millions): 2002–$8.0, 2003–$7.4, 2004–$6.0, 2005–$5.7, 2006–$5.3, and $3.6 in the aggregate thereafter.
 
Cash Flow from Investing Activities
 
Cash flow used in investing activities for the nine months ended September 30, 2002 were $91.8 million as compared to $98.5 million in the year-earlier period. Activity in both the nine months ended September 30, 2002 and 2001 primarily reflect capital expenditures. We classify our capital expenditures into two main categories, mandatory and discretionary. Mandatory capital expenditures, such as for turnarounds and maintenance, are required to maintain safe and reliable operations or to comply with regulations pertaining to soil, water and air contamination or pollution and occupational, safety and health issues. We estimate that total mandatory capital and turnaround expenditures will average approximately $100 million per year for 2002 through 2006. This estimate includes the capital costs necessary to comply with environmental regulations, except for Tier 2 gasoline standards, on-road diesel regulations and the MACT II regulations described below. Our total mandatory capital and refinery maintenance turnaround expenditure budget, excluding Tier 2 gasoline standards, on-road diesel regulations and the MACT II regulations described below, is approximately $65 million in 2002, of which $56.8 million has been spent as of September 30, 2002. Our total mandatory capital and refinery maintenance turnaround expenditure budget is approximately $85 million for 2003. Discretionary capital expenditures are undertaken by us on a voluntary basis after thorough analytical review and screening of projects based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields and/or a reduction in operating costs. Accordingly, total discretionary capital expenditures may be less than budget if cash flow is lower than expected and higher than budget if cash flow is better than expected. Our discretionary capital expenditure budget is approximately $30 million in 2002, of which $15.2 million has been spent as of September 30, 2002. Our discretionary capital expenditure budget is approximately $5 million for 2003. We plan to fund both mandatory and discretionary capital expenditures for 2002 with available cash and cash flow from operations.
 
In addition to mandatory capital expenditures, we expect to incur in the aggregate approximately $545 million through 2006 in order to comply with environmental regulations discussed below. The Environmental Protection Agency, or EPA, has promulgated new regulations under the Clean Air Act that establish stringent sulfur content specifications for gasoline and on-road diesel fuel designed to reduce air emissions from the use of these products.
 
Tier 2 Motor Vehicle Emission Standards.    In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 ppm during any calendar year by January 1, 2006, phasing in beginning on January 1, 2004. We currently expect to produce gasoline under the new sulfur standards at the Port Arthur refinery prior to

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January 1, 2004 and, as a result of the corporate pool averaging provisions of the regulations, will not be required to meet the new sulfur standards at the Lima refinery until July 1, 2004, a six month deferral. A further delay in the requirement to meet the new sulfur standards at the Lima refinery through 2005 may be possible through the purchase of sulfur allotments and credits which arise from a refiner producing gasoline with a sulfur content below specified levels prior to the end of 2005, the end of the phase-in period. There is no assurance that sufficient allotments or credits to defer investment at our Lima refinery will be available, or if available, at what cost. We believe, based on current estimates and on a January 1, 2004 compliance date for both the Port Arthur and Lima refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2005 of approximately $255 million, an increase of $79 million from 2001 year-end estimates. We have completed detailed engineering studies that have resulted in revised cost estimates based on refined implementation plans. Future revisions to these cost estimates may be necessary. More than 95% of the total investment to meet the Tier 2 gasoline specifications is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003.
 
Low Sulfur Diesel Standards.    In January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Regulations for off-road diesel requirements are pending. We estimate that capital expenditures required to comply with the on-road diesel standards at our Port Arthur and Lima refineries in the aggregate through 2006 is approximately $245 million, an increase of $20 million from previous estimates. The revised estimate is based on additional engineering studies and may be revised further as we move towards finalization of our implementation strategy. More than 95% of the projected investment is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. Since the Lima refinery does not currently produce diesel fuel to on-road specifications, we are considering an acceleration of the low-sulfur diesel investment at the Lima refinery in order to capture this incremental product value. If the investment is accelerated, production of the low-sulfur fuel is possible by the first quarter of 2005.
 
Maximum Achievable Control Technology.    On April 11, 2002, the EPA promulgated regulations to implement Phase II of the petroleum refinery Maximum Achievable Control Technology rule under the federal Clean Air Act, referred to as MACT II, which regulates emissions of hazardous air pollutants from certain refinery units. We expect to spend approximately $45 million in the next three years related to these new regulations with the greatest concentration of spending evenly spread out over 2003 and 2004. We are performing some tests at our Lima refinery that will determine if we currently meet the MACT II standards. If the tests confirm this compliance then our MACT II spending can be reduced to $25 million. We should know the results of these tests for our year-end 2002 reporting.
 
Our budget for complying with Tier 2 gasoline standards, on-road diesel regulations and the MACT II regulations is approximately $64 million in 2002, of which $25.5 million has been spent as of September 30, 2002. Our budget for complying with these regulations is approximately $86 million for 2003. It is our intention to fund expenditures necessary to comply with these new environmental standards with cash flow from operations. However, if the average market environment experienced in the first nine months of 2002 continues, it may not be possible for us to generate sufficient cash flow from operations to meet these obligations. Accordingly, we are evaluating our implementation plans.
 
In conjunction with the work being performed to comply with the above regulations, we have initiated a project to expand the Port Arthur refinery to 300,000 – 400,000 barrels per day of crude oil throughput capacity. A feasibility study is underway and the ultimate scope and outcome of this project has yet to be determined. We are also evaluating projects to reconfigure the Lima refinery to process a more sour and heavier crude slate. This initiative is in a very preliminary stage.
 
Cash flow used in investing activities for the year ended December 31, 2001 were $152.9 million as compared to $375.3 million for the year ended December 31, 2000 and $321.3 million for the year ended December 31, 1999. The years ended December 31, 2000 and 1999 reflected higher capital expenditures related

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to the heavy oil upgrade project. Net cash flow provided by investing activities in 1999 included the sale of the retail division for $214.8 million and the sale of the terminals for $33.7 million.
 
Capital expenditures for the year ended December 31, 2001 were $296.2 million lower than the same period in 2000, principally due to the completion of the construction of the refinery upgrade project. Turnaround costs increased $17.7 million in 2001 due to expenditures in 2001 for planned maintenance at the Port Arthur and Lima refineries while 2000 reflected only the planned maintenance turnaround on the crude unit at Port Arthur. Capital expenditures for property, plant and equipment totaled $94.5 million in 2001, $390.7 million in 2000 and $438.2 million in 1999. Expenditures for property, plant and equipment included $19.0 million, $346.0 million, and $387.6 million in 2001, 2000 and 1999, respectively, related to the Port Arthur heavy oil upgrade project. Expenditures for property, plant and equipment related to mandatory capital expenditures were $37.5 million in 2001, $33.2 million in 2000 and $27.7 million in 1999. Expenditures for refinery maintenance turnarounds totaled $49.2 million in 2001, $31.5 million in 2000 and $77.9 million in 1999, with the Lima refinery undergoing its first major turnaround in 1999 since its acquisition in 1998.
 
The estimates stated above for future capital expenditures do not include capital expenditure estimates for the Memphis refinery. The sellers of the Memphis refinery estimate that capital expenditures for the refinery will be approximately $80 million for compliance with Tier 2 gasoline standards based on an implementation date of the first quarter of 2004, and approximately $100 million for compliance with low sulfur diesel standards. We do not anticipate the need to spend any capital for MACT II compliance at the Memphis refinery. We also estimate that other mandatory and refinery maintenance turnaround expenditures will be approximately $48 million per year over the next four years for the Memphis refinery.
 
Cash Flow from Financing Activities
 
Cash flow used in financing activities were $219.8 million for the nine months ended September 30, 2002 compared to $68.8 million in the prior year for the same period. In 2002, we received total net proceeds, or IPO proceeds, of $482.0 million from the sale of our common stock, which consisted of net proceeds of $462.6 million from an initial public offering of 20.7 million shares of our common stock, $19.1 million from the concurrent sales of 850,000 shares of common stock in the aggregate to Mr. O’Malley and two of our directors, and $0.3 million from the exercise of stock options under our stock option plans. The proceeds from the initial public offering and concurrent sales are committed to reducing the long-term debt of our subsidiaries, and as of September 30, 2002 we had contributed a net $442.9 million to our subsidiaries for the early repayment of debt.
 
In 2002, we redeemed and repurchased portions of our long-term debt totaling $645.2 million in aggregate principal amount. In June 2002, we redeemed the remaining $150.4 million of our 9 1/2% senior notes at par and the remaining $144.4 million of our 10 7/8% senior notes with a $5.2 million premium, all mainly from IPO proceeds.
 
On April 1, 2002, we exchanged all of our 11 1/2% exchangeable preferred stock for 11 1/2% subordinated debentures. In 2002, we purchased, in the open market, $57.5 million in aggregate principal amount of our 11 1/2% subordinated debentures at a $3.3 million premium from IPO proceeds.
 
In January 2002, we made a $66.2 million principal payment on our senior secured bank loan with $59.7 million representing a mandatory prepayment pursuant to the common security agreement and secured account structure. In June 2002, we prepaid the remaining balance of $221.4 million on the senior secured bank loan at a $0.9 million premium, with $84.2 million of IPO proceeds and available cash. In the third quarter of 2002, we made a mandatory $4.3 million principal payment on our 12 1/2% senior notes.
 
Cash and cash equivalents restricted for debt service increased by $21.1 million, of which an increase of $45.2 million related to future principal payments is included in cash flow from financing activity and a decrease of $24.1 million related to future interest payments is included in cash flow from operating activities. The

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increase in the amount restricted for principal payments mainly reflected the new requirement under the amended and restated common security agreement to maintain a $45.0 million debt service reserve at all times.
 
In September 2001, we repurchased in the open market $21.3 million in face value of our 9 1/2% senior notes, $30.6 million in face value of our 10 7/8% senior notes, and $5.9 million in face value of our 11 1/2% exchangeable preferred stock, which on April 1, 2002 were converted into 11 1/2% subordinated debentures, for an aggregate purchase price of $48.5 million. We recorded a gain of $8.7 million related to the repurchase of this debt, which included a discount of $9.3 million and a write-off of associated deferred financing costs of $0.6 million.
 
In 2002, we incurred deferred financing costs of $11.4 million related to the consent process that permitted the Sabine restructuring, the registration of the 12 1/2% senior notes with the Securities and Exchange Commission following the restructuring, and the waiver related to insurance coverage required under the common security agreement.
 
Cash flow used in financing activities for the year ended December 31, 2001 were $66.3 million as compared to cash flow provided by financing activities of $234.8 million for the year ended December 31, 2000 and $393.9 million for the year ended December 31, 1999. The cash provided by financing activity in 2000 and 1999 included proceeds from our senior secured bank loan, 12 1/2% senior notes, and shareholder contributions received pursuant to capital contribution agreements that were all used to fund the heavy oil upgrade project. There were no similar proceeds in the year ended December 31, 2001.
 
We have incurred debt at three different entities within our corporate structure: Premcor USA, PRG, and PAFC. Any movement of funds, assets, or other transactions among our various subsidiaries must comply with all provisions of the debt instruments at each subsidiary in addition to customary limitations on transactions with affiliates. After giving effect to this offering and the debt financing and the use of a portion of the proceeds to refinance certain indebtedness of our subsidiaries, as of September 30, 2002, we are required to make the following principal payments on our long-term debt: $0.7 million in the remainder of 2002; $14.9 million in 2003; $25.6 million in 2004; $38.5 million in 2005; $46.4 million in 2006; $318.4 million in 2007; and $601.9 million in the aggregate thereafter. We continue to evaluate the most efficient use of capital and, from time to time, depending upon market conditions, may seek to purchase certain of our outstanding debt securities in the open market or by other means, in each case to the extent permitted by existing covenant restrictions.
 
As part of the Sabine restructuring, PACC terminated its Winterthur International Insurance Company Limited oil payment guaranty insurance policy, which had guaranteed Maya crude oil purchase obligations made under our long-term agreement with an affiliate of PEMEX. PACC also terminated its $35 million bank working capital facility, which primarily supported non-Maya crude oil purchase obligations. As such, all PACC crude oil purchase obligations are now supported under an amended PRG working capital facility.
 
PRG has a credit agreement, which provides for the issuance of letters of credit, primarily for the purchases of crude oil, up to the lesser of $650 million or the amount of a borrowing base calculation. In May 2002, PRG amended its $650 million credit agreement to allow for the PACC crude oil purchase obligations. The borrowing base is calculated with respect to our eligible cash and cash equivalents, investments, receivables, petroleum inventories, paid but unexpired letters of credit, and net obligations on swap contracts. Under the amendment, the borrowing base calculation was amended to include PACC inventory. Also as amended, the $650 million limit can be increased by $50 million at the request of PRG upon securing additional commitments. The credit agreement provides for direct cash borrowings up to $50 million. Borrowings under the credit agreement are secured by a lien on substantially all of PRG’s cash and cash equivalents, receivables, crude oil and refined product inventories and trademarks. The borrowing base associated with such facility at September 30, 2002 was $797.1 million with $520.2 million of the facility utilized for letters of credit. As of September 30, 2002, there were no direct cash borrowings under the credit agreement.

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The credit agreement contains covenants and conditions that, among other things, limit our dividends, indebtedness, liens, investments and contingent obligations. We are also required to comply with certain financial covenants, including the maintenance of working capital of at least $150 million, the maintenance of tangible net worth of at least $400 million, as amended, and the maintenance of minimum levels of balance sheet cash (as defined therein) of $75 million at all times. The covenants also provide for a cumulative cash flow test that from July 1, 2001 must not be less than zero. In March 2002, we received a waiver regarding the maintenance of the tangible net worth covenant, which allows for the exclusion of $120 million for the pretax restructuring charge related to the closure of the Hartford refinery.
 
We must amend this credit agreement to extend the maturity date from August 23, 2003 to three years from the closing of the amendment and obtain various waivers and approvals under this credit agreement in order to consummate the debt financing and the acquisition of the Memphis refinery. In addition, we are seeking to amend and restate this credit agreement to, among other things, increase the capacity under the agreement from $650 million to the lesser of $750 million or the amount available under the borrowing base; and increase the sub-limit for cash borrowings from $50 million to $200 million, subject to certain restrictions. Certain covenants relating to minimum cash requirements, permitted indebtedness and minimum net worth requirements will also be modified. There are no assurances that we will be able to obtain the necessary extension, waivers and approvals or enter into an amended and restated credit agreement on these terms or at all.
 
Our long-term debt instruments subject us to significant financial and other restrictive covenants. Covenants contained in various indentures, credit agreements, and term loan agreements place restrictions on, among other things, our subsidiaries’ ability to incur additional indebtedness, place liens upon our subsidiaries’ assets, pay dividends or make certain other restricted payments and investments. Some debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests.
 
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 for the next year. Due to the commodity nature of our products, our operating results are subject to rapid and wide fluctuations. While we believe that our operating philosophies will be sufficient to provide us 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.
 
Accounting Standards
 
Critical Accounting Standards
 
Contingencies.    We account for contingencies in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 5 (“SFAS No.5”), Accounting for Contingencies. SFAS No. 5 requires that we record an estimated loss from a loss contingency when information available prior to the issuance of our financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accounting for contingencies such as environmental, legal and income tax matters require us to use our judgment. While we believe that our accruals for these matters are adequate, if the actual loss from a loss contingency is significantly different than the estimated loss, our results of operations may be over or understated.
 
Major Maintenance Turnarounds.    The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants, or AcSEC, had issued an exposure draft of a proposed statement of position, or SOP, entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. If adopted as proposed, this SOP would have, among other things, required 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 have also required that any existing unamortized turnaround costs be expensed

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immediately. As of September 30, 2002, we had approximately $97 million in unamortized turnaround costs on our balance sheet. 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 the turnaround. We currently amortize turnaround costs, which are included in our consolidated balance sheets in “Other Assets,” 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” on our consolidated statements of operations.
 
In December 2002, AcSEC discontinued discussions concerning this SOP and handed over the responsibility for any further action to the FASB. The FASB stated that it might add the issues related to this SOP to its agenda, but it would be at least 12 months until any consideration is made. At its January 2003 meeting, AcSEC agreed to meet with the FASB to discuss the possibility of adopting a shortened version of the original exposure draft that would address major maintenance costs or turnaround costs. Whether there will be new accounting guidance and when it would become effective is currently unclear.
 
Impairment of Long-Lived Assets.    In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business (as previously defined in that Opinion). The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years, with early application encouraged. The implementation of SFAS 144 did not have a material impact on our financial position or results of operations.
 
Inventories.    Inventories for our company are stated at the lower of cost or market. As of January 1, 2002, cost is determined under the LIFO method for hydrocarbon inventories including crude oil, refined products, and blendstocks. Prior to this date the cost of Sabine’s hydrocarbon inventories was determined under the first-in, first-out, or FIFO, method. The cost of warehouse stock and other non-hydrocarbon inventories is determined under the FIFO method. Any reserve for inventory cost in excess of market value is reversed if physical inventories turn and prices recover above cost. At December 31, 2001 the replacement cost (market value) of our crude oil and refined product inventories exceeded its carrying value by $4.9 million. We had 15.4 million barrels of crude oil and refined product inventories at December 31, 2001 with an average cost of $19.09 per barrel. If the market value of these inventories had been lower by $1 per barrel at December 31, 2001, we would have been required to write-down the value of our inventory by $10.5 million. If prices decline from year-end 2001 levels, we may be required to write-down the value of our inventories in future periods.
 
New Accounting Standards
 
On January 1, 2002, we adopted Statement of Financial Accounting Standard, or SFAS, No. 142, Goodwill and Other Intangible Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The adoption of these standards did not have a material impact on our financial position and results of operations; however, SFAS No. 144 was utilized in the accounting for our announced intention to discontinue refining operations at the Hartford, Illinois refinery.
 
In July 2001, the Financial Accounting Standards Board, or 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 that will be required to be amortized. SFAS No. 143 is

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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 and believe implementation will not have a material impact.
 
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections. SFAS 145 rescinds SFAS No. 4, Reporting Gains and Losses from the Extinguishment of Debt; SFAS No. 44, Accounting for Intangible Assets of Motor Carriers; and SFAS No. 64, Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements. SFAS No. 145 also amends SFAS No. 13, Accounting for Leases, as it relates to sale-leaseback transactions and other transactions structured similar to a sale-leaseback as well as amends other pronouncements to make various technical corrections. The provisions of SFAS No. 145 as they relate to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. The provision of this statement related to the amendment to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions of this statement shall be effective for financial statements on or after May 15, 2002. As permitted by the statement, we have elected early adoption of SFAS 145 and, accordingly, have included any gains or losses on extinguishment of debt in “Income from continuing operations” as opposed to as an extraordinary item, net of taxes, below “Income from continuing operations” in our Statement of Operations.
 
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires the recognition of liabilities at fair value that are associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Such liabilities include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activities. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We will adopt SFAS  No. 146 for all restructuring, discontinued operations, plant closings or other exit or disposal activities initiated after December 31, 2002.
 
Quantitative and Qualitative Disclosures About Market Risk
 
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments is held for trading.
 
Commodity Risk
 
Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, commodities such as crude oil, gasoline and other refined products. The demand for these refined products depends on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, planned and unplanned downtime in refineries, pipelines and production facilities, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. As a result, crude oil and refined product prices fluctuate significantly, which directly impacts our net sales and operating revenues and costs of goods sold.
 
The movement in petroleum prices does not necessarily have a direct long-term relationship to net income. The effect of changes in crude oil prices on our operating results is determined more by the rate at which the prices of refined products adjust to reflect such changes. We are required to fix the price on our crude oil purchases approximately two to three weeks prior to the time when the crude oil can be processed and sold. As a result, we are exposed to crude oil price movements relative to refined product price movements during this period. In addition, earnings may be impacted by the write-down of our inventory cost to market value when market prices drop dramatically compared to our inventory cost. These potential write-downs may be recovered in subsequent periods as our inventories turn and market prices rise. If prices decline dramatically near the end of a period, we may be required to write-down the value of our inventories in future periods. In 1997 and 1998 the

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market value of our petroleum inventory was below original cost, which resulted in a write-down of inventory to fair market value. The write-down was fully recovered in 1999 when market values increased. Earnings may continue to be impacted by these write-downs, or recovery of write-downs, to market value.
 
As of December 31, 2001, we had 15.4 million barrels of crude oil and refined product inventories. We had 12.6 million barrels of crude oil and refined product inventories that were valued under the LIFO inventory method with an average cost of $20.32 per barrel. As of December 31, 2001, the replacement cost (market value) of this inventory exceeded its carrying value by $4.9 million. If the market value of these inventories had been lower by $1 per barrel as of December 31, 2001, we would have been required to write-down the value of our inventory by $7.7 million. We had 2.8 million barrels of crude oil and refined product inventories that were valued under the first-in, first-out, or FIFO, inventory method with an average cost of $13.58 per barrel. The carrying value of this inventory approximated replacement cost (market value). If the market value of these inventories had been lower by $1 per barrel we would have been required to write-down the value of our inventory by $2.8 million.
 
As of December 31, 2000, we had 18.0 million barrels of crude oil and refined product inventories. We had 15.6 million barrels of crude oil and refined product inventories that were valued under the LIFO inventory method with an average cost of $19.94 per barrel. The replacement cost (market value) of this inventory exceeded its carrying value by $100.8 million. If the market value of these inventories had been lower by $1 per barrel as of December 31, 2000, we would not have been required to write-down the value of our inventory and would not have had to record a write-down unless market was lower by over $7 per barrel. We had 2.4 million barrels of crude oil and refined product inventories that were valued under the FIFO inventory method with an average cost of $18.38 per barrel. If the market value of these inventories had been lower by $1 per barrel we would have been required to write-down the value of our inventory by $2.4 million.
 
As of January 1, 2002, all of our hydrocarbon inventories were valued using the LIFO method. Our inventories that are valued under the LIFO method are more susceptible to a material write-down when prices decline dramatically. If prices decline from year-end 2001 levels, we may be required to write-down the value of our LIFO inventories in future periods.
 
The nature of our business leads us to maintain a substantial investment in petroleum inventories. Since 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 appropriate and consistent with normal business operations. This target inventory position includes both titled inventory and fixed price purchase and sale commitments. The portion of our current target inventory position consisting of sales commitments netted against fixed price purchase commitments amounts to a net long inventory position of approximately 4 million barrels.
 
Prior to the second quarter of 2002, we did not generally price protect any portion of our target inventory position. However, although we continue to generally leave the titled portion of our inventory position target fully exposed to price fluctuations, beginning in the second quarter of 2002, we began to actively mitigate some or all of the price risk related to our target level of fixed price purchase and sale commitments. These risk management decisions are based on the relative level of absolute hydrocarbon prices. The cumulative economic effect of our risk management strategy in the second and third quarter of 2002 resulted in an approximate $11 million loss as measured against a fully exposed fixed price commitment target. In the first quarter of 2002, we benefited by approximately $30 million from having our fixed price commitment target fully exposed in a rising absolute price environment.
 
We use several strategies to minimize the impact on profitability of volatility in feedstock costs and refined product prices. These strategies generally involve the purchase and sale of exchange-traded, energy-related futures and options with a duration of six months or less. To a lesser extent we use energy swap agreements

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similar to those traded on the exchanges, such as crack spreads and crude oil options, to better match the specific price movements in our markets as opposed to the delivery point of the exchange-traded contract. These strategies are designed to minimize, on a short-term basis, our exposure to the risk of fluctuations in crude oil prices and refined product margins. The number of barrels of crude oil and refined products covered by such contracts varies from time to time. Such purchases and sales are closely managed and subject to internally established risk standards. The results of these price risk mitigation activities affect refining cost of sales and inventory costs. We do not engage in speculative futures or derivative transactions.
 
We prepared a sensitivity analysis to estimate our exposure to market risk associated with derivative commodity positions. This analysis may differ from actual results. The fair value of each derivative commodity position was based on quoted futures prices. As of September 30, 2002, a 10% change in quoted futures prices would result in an $8.8 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income. As of December 31, 2001, a 10% change in quoted futures prices would result in an $8.1 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income.
 
Interest Rate Risk
 
During 2002, as of September 30, we repaid $645.2 million of our long-term debt, leaving an outstanding balance, including current maturities, of $925.3 million at September 30, 2002. Our primary interest rate risk is associated with our long-term debt. We manage this interest rate risk by maintaining a high percentage of our long-term debt with fixed rates. The weighted average interest rate on our fixed rate long-term debt is slightly over 10%. We are subject to interest rate risk on our floating rate loans and any direct borrowings under our credit facility. As of September 30, 2002, a 1% change in interest rates on our floating rate loans, which totaled $250 million, would result in a $2.5 million change in pretax income on an annual basis. As of December 31, 2001, a 1% change in interest rate on our floating rate loans, which totaled $538 million, would result in a $5.4 million change in pretax income on an annual basis. As of September 30, 2002 and December 31, 2001, there were no borrowings under our credit agreement.

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INDUSTRY OVERVIEW
 
Oil refining is the process of separating hydrocarbon atoms present in crude oil and converting them into usable finished petroleum products. There are approximately 150 oil refineries operating in the United States. The refining industry is characterized by capacity shortage, high utilization, and reliance on imported products to meet demand for finished petroleum products. This overview explains the basics of the refining process and certain factors that influence our industry.
 
Refining Basics
 
Refineries are uniquely designed to process specific crude oils into selected products. In general, the different process units inside a refinery perform one of three functions:
 
 
•
 
separate the many types of hydrocarbons present in crude oil;
 
 
•
 
chemically convert the separated hydrocarbons into more desirable products; and
 
 
•
 
treat the products by removing unwanted elements and compounds.
 
Each step in the refining process is designed to maximize the value of the feedstocks, particularly the raw crude oil.
 
The first refinery units to process raw crude oil are typically the atmospheric and vacuum distillation units. Crude oil is separated by boiling point in the distillation units under high heat and low pressure and recovered as hydrocarbon fractions. The lowest boiling fractions, including gasoline and liquefied petroleum gas, vaporize and exit the top of the atmospheric distillation unit. Medium boiling liquids, including jet fuel, kerosene and distillates such as home heating oil and diesel fuel, are drawn from the middle. Higher boiling liquids, called gas oils and the highest boiling liquids, called residuum, are drawn together from the bottom and separated in the vacuum distillation unit. The various fractions are then pumped to the next appropriate unit in the refinery for further processing into higher-value products.
 
The next step in the refining process is to convert the hydrocarbon fractions into distinct products. One of the ways of accomplishing this is through “cracking,” a process that breaks or cracks higher boiling fractions into more valuable products such as gasoline, distillate and gas oil. The most important conversion units are the coker, the FCC unit, and the hydrocracker. Thermal cracking is accomplished in the coker, which upgrades residuum into naphtha, which is a low-octane gasoline fraction, distillate, and gas oil. The FCC unit converts gas oil from the crude distillation units and coker into liquefied petroleum gas, gasoline, and distillate by applying heat in the presence of a catalyst. The hydrocracker receives feedstocks from the coker, FCC and crude distillation units. This unit converts lower value intermediate products into gasoline, naphtha, kerosene, and distillates under very high pressure in the presence of hydrogen and a catalyst.
 
Finally, the intermediate products from the distillation and conversion processes are treated to remove impurities such as sulfur, nitrogen and heavy metals, and are processed to enhance octane, reduce vapor pressure, and meet other product specifications. Treatment is accomplished in hydrotreating units by heating the intermediates under high pressure in the presence of hydrogen and catalysts. Octane enhancement is accomplished primarily in a reformer. The reformer converts naphtha, or low-octane gasoline fractions, into higher octane gasoline blendstocks used in increasing the overall octane level of the gasoline pool. Vapor pressure reduction is accomplished primarily in an alkylation unit. The alkylation unit decreases the vapor pressure of gasoline blendstocks produced by the FCC and coker units through the conversion of light olefins to heavier, high-octane paraffins.

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Refinery Products
 
Major refinery products include:
 
Gasoline.    The most significant refinery product is motor gasoline. Various gasoline blendstocks are blended to achieve specifications for regular and premium grades in both summer and winter gasoline formulations. Refiners must also produce many grades of reformulated gasoline. Reformulated gasolines are special blends containing oxygenates, such as ethers or alcohols, that are tailored to areas of the country with severe ozone pollution. Additives are often used to enhance performance and provide protection against oxidation and rust formation.
 
Distillate Fuels.    Distillates are diesel fuels and domestic heating oils.
 
Kerosene.    Kerosene is a refined middle-distillate petroleum product that is used for jet fuel, cooking and space heating, lighting, solvents and for blending into diesel fuel.
 
Petrochemicals.    Many products derived from crude oil refining, such as ethylene, propylene, butylene and isobutylene, are primarily intended for use as petrochemical feedstock in the production of plastics, synthetic fibers, synthetic rubbers and other products. A variety of products are produced for use as solvents, including benzene, toluene and xylene.
 
Liquefied Petroleum Gas.    Liquefied petroleum gases, consisting primarily of propane and butane, are produced for use as a fuel and an intermediate material in the manufacture of petrochemicals.
 
Residual Fuels.    Many marine vessels, power plants, commercial buildings and industrial facilities use residual fuels or combinations of residual and distillate fuels for heating and processing. Asphalts are also made from residual fuels and are used primarily for roads and roofing materials.
 
Petroleum Coke.    Petroleum coke, a by-product of the coking process, is almost pure carbon and has a variety of uses. Fuel grade coke is used primarily by power plants as fuel for producing electricity. Premium grades of coke low in sulfur and metal content are used as anodes for the manufacture of aluminum.
 
Crude Oil
 
The quality of crude oil dictates the level of processing and conversion necessary to achieve the optimal mix of finished products. Crude oils are classified by their density (light to heavy) and sulfur content (sweet to sour). Light sweet crude oils are more expensive than heavy sour crude oils because they require less treatment and produce a slate of products with a greater percentage of high-priced, light, refined products such as gasoline, kerosene and jet fuel. The heavy sour crude oils typically sell at a discount to the lighter, sweet crude oils because they produce a greater percentage of lower-value products with simple distillation and require additional processing to produce the higher-value light products. Consequently, refiners strive to process the optimal mix, or slate, of crude oils through their refineries, depending on each refinery’s conversion and treating equipment, the desired product output, and the relative price of available crude oils.
 
Refinery Complexity
 
Refinery complexity refers to a refinery’s ability to process less-expensive feedstock, such as heavier and higher-sulfur content crude oils, into value-added products. Generally, the higher the complexity and more flexible the feedstock slate, the better positioned the refinery is to take advantage of the more cost-effective crude oils, resulting in incremental gross margin opportunities for the refinery.
 
Refinery Locations
 
A refinery’s location can have an important impact on its refining margins since a refinery’s location can influence its ability to access feedstocks and distribute its products efficiently. There are five regions in the

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United States, as defined by the Petroleum Administration for Defense Districts, or PADDs, that have historically experienced varying levels of refining profitability due to regional market conditions. For example, refiners located in the Gulf Coast operate in a highly competitive market due to the fact that this region (PADD III) accounts for approximately 37% of the total number of United States refineries and approximately 46% of the country’s refining capacity. Alternatively, demand for gasoline and distillates has historically exceeded refining production by approximately 35% in the Midwest (PADD II). PADD I represents the East Coast, PADD IV the Rocky Mountains and PADD V is the West Coast.
 
Structure of Refining Companies
 
Refiners typically are structured as part of an integrated oil company or as an independent entity. Integrated oil companies have upstream operations, which are concerned with the exploration and production of crude oil, combined with downstream, or refining, operations. An independent refiner has no source of proprietary crude oil production.
 
Refiners primarily distribute their products as either wholesalers or retailers. Refiners who operate as wholesalers principally sell their refined products under spot and term contracts to bulk and truck rack customers. Wholesalers who sell their products on an unbranded basis are called “merchant refiners.” Many refiners, both integrated and independent, distribute their refined products through their own retail outlets.
 
Economics of Refining
 
Refining is primarily a margin-based business where both the feedstocks and refined finished products are commodities. Because operating expenses are relatively fixed, the refiners’ goal is to maximize the yields of high-value products and to minimize feedstock costs.
 
The industry uses a number of benchmarks to measure market values and margins:
 
West Texas Intermediate.    In the United States, West Texas Intermediate crude oil is the reference quality crude oil. West Texas Intermediate is a light sweet crude oil and the West Texas Intermediate benchmark is used in both the spot and futures markets.
 
3/2/1 crack spread.    Crack spreads are a proxy for refining margins and refer to the margin that would accrue from the simultaneous purchase of crude oil and the sale of refined petroleum products, in each case at the then prevailing price. The 3/2/1 crack spread assumes three barrels of West Texas Intermediate crude oil will produce two barrels of regular unleaded gasoline and one barrel of high-sulfur diesel fuel. Average 3/2/1 crack spreads vary from region to region depending on the supply and demand balances of crude oils and refined products.
 
Actual refinery margins vary from the 3/2/1 crack spread due to the actual crude oil used and products produced, transportation costs, regional differences, and the timing of the purchase of the feedstock and sale of the light products.
 
High complexity refineries are able to utilize crude oils lower in cost than West Texas Intermediate. The economic advantage of these refineries is estimated by using the heavy/light and the sweet/sour differentials.
 
Heavy/light differential.    The heavy/light differential is the price differential between Maya, a heavy, sour crude oil, and West Texas Intermediate crude oil. Maya crude oil typically trades at a discount to West Texas Intermediate crude oil.
 
Sweet/sour differential.    The sweet/sour differential is the price differential between West Texas Sour, a medium sour crude oil and West Texas Intermediate crude oil. West Texas Sour crude oil trades at a discount to West Texas Intermediate crude oil. Typically, the sweet/sour differential is less than the heavy/light differential.

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Product differentials.    Because refineries produce many other products that are not reflected in the crack spread, product differentials to regular unleaded gasoline and high-sulfur diesel are calculated to analyze the product mix advantage of a given refinery. Those refineries that produce relatively high volumes of premium products such as premium and reformulated gasoline, low-sulfur diesel fuel and jet fuel and relatively low volumes of by-products such as liquefied petroleum gas, residual fuel oil, petroleum coke, and sulfur have an economic advantage.
 
Operating expenses.    Major operating costs include employee labor, repairs and maintenance, and energy. Employee labor and repairs and maintenance are relatively fixed costs that generally increase proportional to inflation. By far, the predominant variable cost is energy and the most reliable price indicator for energy costs is the cost of natural gas.

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BUSINESS
 
Overview
 
We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. We currently own and operate two refineries in Port Arthur, Texas and Lima, Ohio with a combined crude oil throughput capacity of approximately 420,000 bpd. In late September 2002, we ceased refining operations at our Hartford, Illinois refinery and are currently pursuing all strategic options, including expanding the uses of the petroleum product and distribution facility and selling or leasing the refinery, to mitigate the loss of jobs and refinery capacity in the Midwest. We continue to operate the terminal facility at the Hartford refinery to accommodate our wholesale petroleum product distribution business. We sell petroleum products in the Midwest, the Gulf Coast, eastern and southeastern United States. We sell our products on an unbranded basis to approximately 750 distributors and chain retailers through our own product distribution system and an extensive third-party owned product distribution system, as well as in the spot market.
 
For the nine months ended September 30, 2002, light products accounted for approximately 90% of our total product volume. For the same period, high-value, premium product grades, such as high octane and reformulated gasoline, low-sulfur diesel and jet fuel, which are the most valuable types of light products, accounted for approximately 40% of our total product volume.
 
We source our crude oil on a global basis through a combination of long-term crude oil purchase contracts, short-term purchase contracts and spot market purchases. The long-term contracts provide us with a steady supply of crude oil, while the short-term contracts and spot market purchases give us flexibility in obtaining crude oil. Since all of our refineries have access, either directly or through pipeline connections, to deepwater terminals, we have the flexibility to purchase foreign crude oils via waterborne delivery or domestic crude oils via pipeline delivery. Our Port Arthur refinery, which possesses one of the world’s largest coking units, can process 80% heavy sour crude oil. Approximately 80% of the crude oil supply to our Port Arthur refinery is lower cost heavy sour crude oil from Mexico, called Maya, most of which benefits from a mechanism intended to provide us with a minimum average coker gross margin and moderate fluctuations in coker gross margins during an eight-year period beginning on April 1, 2001.
 
Recent Developments
 
Memphis Refinery Acquisition
 
On November 25, 2002, we announced that we had executed a definitive agreement with The Williams Companies, Inc. and certain of its subsidiaries to purchase their Memphis, Tennessee refinery and related supply and distribution assets. The purchase price for the refinery and the other assets is $315 million, plus the value of inventories at closing. At current price levels, the value of the inventories is estimated to be $200 million. The agreement also provides for contingent participation, or earn-out, payments that could result in additional payments of up to $75 million by us to Williams over the next seven years, depending on the level of industry refining margins during that period.
 
The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd but typically processes approximately 170,000 bpd. The related assets include two truck-loading racks; three petroleum terminals in the area; supporting pipeline infrastructure that transports both crude oil and refined products; crude oil tankage at St. James, Louisiana; and an 80 megawatt power plant adjacent to the refinery.
 
We believe that we are acquiring a quality refinery at an attractive price that will produce operating and economic synergies and that should be accretive to our earnings per share and generate positive cash flow from operations. Completion of the acquisition is subject to our obtaining the requisite financing and the satisfaction of customary conditions, including regulatory approvals. We intend to finance the acquisition from the proceeds of this offering and the other financing transactions. We expect the acquisition to close during the first quarter of 2003.

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Our Predecessors and Corporate Structure
 
Clark USA, Inc., our predecessor, was formed by TrizecHahn Corporation, or TrizecHahn, in 1988 to acquire a controlling interest in certain refining, distribution and marketing assets from the bankruptcy estate of Clark Oil & Refining Corporation. Those assets, which included the Hartford refinery, a Blue Island, Illinois refinery and certain Clark USA retail operations and product terminals, were acquired by Clark Refining & Marketing, Inc., a wholly owned subsidiary of Clark USA. In November 1997, Blackstone acquired a majority interest in Clark USA from TrizecHahn. In 1999, we were formed as Clark Refining Holdings, Inc., a holding company for 100% of the capital stock of Clark USA. In 2000, we changed our name to Premcor Inc., Clark USA changed its name to Premcor USA Inc. and Clark Refining & Marketing, Inc., one of our operating subsidiaries, changed its name to The Premcor Refining Group Inc.
 
In 1999, in connection with the financing of the heavy oil upgrade project at our Port Arthur refinery, we acquired 90% of the capital stock of Sabine River Holding Corp., a new entity formed to be the general partner of PACC, the entity created to own and lease the assets comprising the heavy oil processing facility. Sabine also owns 100% of the capital stock of Neches River Holding Corp., which was formed to be the 99% limited partner of PACC. PACC entered into product purchase, service and supply agreements and facility, site and ground leases, and other arm’s length arrangements with PRG as part of the heavy oil upgrade project.
 
In connection with the Sabine restructuring, on June 6, 2002, we consummated a share exchange with Occidental Petroleum Corporation whereby we received the remaining 10% of the common stock of Sabine. For a discussion of our relationship with Occidental, see “Related Party Transactions—Our Relationship with Occidental.” Upon consummation of the share exchange with Occidental, we contributed our ownership interest in Sabine to PRG and Sabine became a direct, wholly owned subsidiary of PRG.

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The following chart summarizes the current corporate structure of Premcor Inc. and its affiliates as a result of the Sabine restructuring:
 
LOGO
 
The Transformation of Premcor
 
Beginning in early 1995 and continuing after Blackstone acquired its controlling interest in our predecessor in 1997, we completed several strategic initiatives that have significantly enhanced our competitive position, the quality of our assets, and our financial and operating performance. The following statements regarding our transformation exclude our Hartford refinery at which we ceased refining operations in late September 2002. For example, we:
 
Divested our Non-core Assets to Focus on Refining.    We divested our non-core assets during 1998 and 1999, generating net proceeds of approximately $325 million, which we reinvested into our refining business. In 1998, we sold minority interests in several crude oil and product pipelines. In July 1999, we sold our retail business, which included 672 company-operated, and over 200 franchised, gas convenience stores. Also in 1999, we sold the majority of our product distribution terminals.
 
Acquired Additional Competitive Refining Capacity.    We increased our net crude oil throughput capacity from approximately 130,000 bpd to 420,000 bpd after closing two refineries by acquiring our Lima and Port Arthur refineries and subsequently upgrading our Port Arthur refinery. In 1995, we significantly changed the character of our asset base by acquiring the Port Arthur refinery, which was then operating at a capacity of 178,000 bpd. In August 1998, we further expanded our refining capacity by acquiring the 170,000 bpd Lima refinery.

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Invested in Improving the Productivity of our Asset Base.    We implemented capital projects to increase throughput and premium product yields and to reduce operating expenses within our refining asset base. Upon the acquisition of our Port Arthur refinery in 1995, we initially upgraded the facility to a capacity of 232,000 bpd. In January 2001, we completed construction and commenced operation of a heavy oil upgrade project at Port Arthur, further increasing its capacity to 250,000 bpd and significantly expanding its ability to process heavy sour crude oil. Since the acquisition of the Lima refinery in 1998, we have improved the product distribution logistics surrounding the refinery to allow the refinery to increase its throughput and more fully utilize that facility’s 170,000 bpd capacity. We allocate capital to these projects based on a rigorous analysis of the expected return on capital. Based upon such a review of our 80,000 bpd Blue Island, Illinois refinery, we determined that, due to its poor competitive position as a relatively small refinery configured to process primarily light sweet crude oil, it would not have been able to meet our return on capital and free cash flow targets. As a result, we closed the Blue Island refinery in January 2001. In September 2002, we ceased refining operations at our Hartford refinery for the same reasons. The Hartford refinery would not have been able to meet our return on capital and free cash flow targets due to its relatively small size and the amount of investment necessary to meet new federally mandated fuel specifications. These productivity improvements, together with the acquisitions of our Port Arthur and Lima refineries, and the closure of non-competitive capacity strengthened our asset base, increased our coking capacity from 18,000 bpd to 113,000 bpd, increased our cracking capacity from 70,000 bpd to 178,000 bpd and increased our capacity to process sour and heavy sour crude oil from 45,000 bpd in 1994 to 200,000 bpd, an approximate 340% increase.
 
Improved our Operations and Safety Performance.    We have implemented a number of programs which increased the reliability of our operations and improved our safety performance resulting in a reduction of our “recordable injury” rate from 3.12 to 1.14 per 200,000 hours worked. In 2001, we appointed a director of reliability, established an internal benchmarking and best practices program, developed a root-cause analysis program and installed an automated maintenance management system. Over the last several years, we made significant expenditures to improve our safety record. As a result, we have significantly reduced our company-wide “recordable injuries” and “lost time injuries,” each as defined by the Occupational Safety and Health Administration, or OSHA. We reduced our “recordable injury” rate by approximately 60% from 1995 to September 2002. From our acquisition of the Lima refinery in July 1998 through the end of 2001 the refinery accumulated over approximately three million employee hours without a lost time injury. From August 1997 through the third quarter of 2001, our Port Arthur refinery accumulated over seven million employee hours without a lost time injury. The streak ended on October 4, 2001 when our Port Arthur refinery incurred its first lost time injury in over four years. According to a survey by the National Petrochemical & Refiners Association, or NPRA, which was conducted for year-end 1999, of the approximately 218 United States refining and chemical facilities included in the survey, only five such facilities had ever achieved the five million employee hour milestone.
 
Expanded our Unbranded Petroleum Product Distribution Capabilities.    We expanded and enhanced our capabilities to supply fuels on an unbranded basis to include the Midwest, Gulf Coast, southeastern and eastern United States. As part of the sale of our terminal operations, we gained access, subject to availability, to an extensive pipeline and terminal network for the distribution of products from each of our refineries.
 
Reduced Operating Costs.    We reduced our operating costs as evidenced by a reduction of our refining employees per thousand barrels from 7.2 to 3.4.
 
In February 2002, we recruited a new chairman and chief executive officer, Thomas D. O’Malley, the former chairman and chief executive officer of Tosco Corporation and former vice chairman and director of Phillips Petroleum Corporation. Mr. O’Malley has over 25 years of industry experience and a proven track record of successfully operating, growing and enhancing shareholder value. Since then, we have improved our competitive position as a result of the following:
 
Recruited and Developed an Experienced Management Team.     Mr. O’Malley has assembled an executive management team, consisting of Henry M. Kuchta, president and chief operating officer, who joined us in

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April 2002, William E. Hantke, executive vice president and chief financial officer, who joined us in February 2002, Joseph D. Watson, who joined us in March 2002 as senior vice president and chief administrative officer and currently serves as our senior vice president—corporate development, and Michael D. Gayda as senior vice president, general counsel and secretary, who joined us in October 2002. These executive officers have an average of almost twenty years experience in the energy and refining industry. In addition, our operational management team has an average of 26 years of energy industry experience.
 
Completed our IPO.    On May 3, 2002, we completed an initial public offering of 20.7 million shares of common stock. The initial public offering, plus the concurrent purchases of 850,000 shares in the aggregate by Thomas D. O’Malley and two of our independent directors, netted proceeds to us of approximately $482 million. The proceeds from the offering were committed to retire certain indebtedness of our subsidiaries.
 
Completed our Sabine Restructuring.    On June 6, 2002, we completed a series of transactions, referred to herein as the Sabine restructuring, that resulted in, among other things, all the senior secured debt of Sabine and its subsidiaries, other than the 12 1/2% senior secured notes, being paid in full, all commitments under the working capital facility and certain insurance policies being terminated and Sabine and its subsidiaries becoming wholly owned subsidiaries of PRG. In connection with the Sabine restructuring, PRG fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations under the notes. The Sabine restructuring was permitted by the successful consent solicitation of holders of the notes.
 
Closed our Hartford, Illinois Refinery.    In late September 2002, we ceased refining operations at our Hartford refinery after concluding there was no economically viable method of reconfiguring the refinery to produce fuels meeting new gasoline and diesel fuel specifications mandated by the federal government. Despite ceasing operations, we continue to pursue all strategic options to mitigate the loss of jobs and refinery capacity in the Midwest.
 
Pending Acquisition of the Memphis Refinery.    We entered into an agreement in November 2002 with The Williams Companies, Inc. and certain of its subsidiaries to purchase their Memphis, Tennessee refinery and related supply and distribution assets.
 
Actions to Reduce Operating and General and Administrative Costs.    We have taken and, are continuing to take, steps to reduce our operating and general and administrative costs, including:
 
 
•
 
reducing our St. Louis-based administrative workforce by 107 positions, or approximately one-third of the total St. Louis administrative workforce in April 2002;
 
 
•
 
announcing our intention to eliminate additional administrative positions by the end of the first quarter of 2003;
 
 
•
 
eliminating approximately 80 of our non-represented refinery positions in October 2002; and
 
 
•
 
entering into a new crude oil supply agreement for our Lima refinery in October 2002 that we believe will reduce our crude acquisition costs for Lima by roughly 20 cents per barrel.
 
Market Trends
 
We believe that the outlook for the United States refining industry is attractive due to the following trends:
 
Favorable Supply and Demand Fundamentals.    We believe that the supply and demand fundamentals for refined petroleum products have improved since the late 1990s and will continue to improve. Decreasing petroleum product demand and deregulation of the domestic refining industry in the 1980s, along with new fuel standards introduced in the early 1990s, contributed to years of decreasing domestic refining capacity. According to the Department of Energy’s Energy Information Administration, or EIA, and the Oil and Gas Journal’s 2001 Worldwide Refinery Survey, the number of United States refineries has decreased from a peak of 324 in 1981 to

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143 in January 2002. The EIA projects that capacity additions at existing refineries will increase total domestic refining capacity at an annual rate of only 0.5% per year over the next two decades and that utilization will remain high relative to historic levels, ranging from 91% to 95% of design capacity. We believe that impending regulatory requirements will result in the rationalization of non-competitive refineries, further reducing refining supply.
 
Net imports of petroleum products, largely from northwest Europe and Asia, have historically supplemented domestic refining supply shortfalls, accounting for a relatively consistent amount of approximately 7% of total United States supply over the last 15 years. We expect that imports will continue to occur primarily during periods when refined product prices in the United States are materially higher than in Europe and Asia.
 
While refining capacity growth is expected by the EIA to be nominal, the EIA expects demand for petroleum products to continue to grow steadily at 1.3% per year over the next two decades. Almost 96% of the projected growth is expected to come from the increased consumption of light products including gasoline, diesel, jet fuel and liquefied petroleum gas.
 
Increasing Supplies of Lower Cost Sour and Heavy Sour Crude Oil.    We believe that increasing worldwide supplies of lower-cost sour and heavy sour crude oil will provide an increasing cost advantage to those refineries with complex configurations that are able to process these crude oils. Purvin & Gertz, an independent engineering firm, estimates that the total worldwide heavy sour crude oil production will increase by approximately 39% from 9.7 million bpd in 2000 to 13.5 million bpd in 2010, resulting in a continuation of the downward price pressure on these crude oils relative to benchmark West Texas Intermediate crude oil. Over the next several years, significant volumes of sour and heavy sour crude oils are expected to be imported into the United States, primarily from Latin America and Canada. Purvin & Gertz expects domestic imports of this production to increase from 3.0 million bpd presently to 5.3 million bpd by 2010.
 
Increasing Demand for Specialized Refined Petroleum Products.    We expect that products meeting new and evolving fuel specifications will account for an increasing share of total fuel demand, which may benefit refiners possessing the capabilities to blend and process these fuels. As part of the Clean Air Act of 1990 and subsequent amendments, several major metropolitan areas in the United States with air pollution problems are required to use reformulated gasoline meeting certain environmental standards. According to the EIA, demand for reformulated gasoline and the oxygenates used in its production will increase from approximately 3.3 million bpd in 2000 to approximately 4 million bpd in 2010, accounting for approximately 40% of all annual gasoline sales. According to officials of the United States Department of Energy, the trend toward banning MTBE as a blendstock in reformulated gasoline will result in an annual reduction of the gasoline supply by 3% to 4%.
 
Continued Consolidation of the Refining Sector.    We believe that the continuing consolidation in the refining industry may create attractive opportunities to acquire competitive refining capacity. During the period from 1990 to 2001, the percentage of refining capacity owned by major integrated oil companies decreased from 66% to 62%. Many integrated oil companies divested refining assets rather than making costly investments to meet increasingly strict product specifications. During this same period, the percentage of refining capacity owned by the top ten owners of refining assets increased from 57% to 69% and the share held by independent refiners increased from 16% to 33%. New environmental regulations will require the refining sector to make substantial investments in refining assets and pollution control technologies. We believe these substantial costs will likely force many smaller inefficient refiners out of the market.
 
Competitive Strengths
 
As a result of our transformation, we have developed the following strengths:
 
Refining Focus.    We are a “pure-play” refiner, without the obligation to supply our own retail outlets or the cost of supporting our own retail brand. As a result, we are free to supply our products into the distribution

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channel or market that we believe will maximize profit. We do not own any other assets or businesses, such as petroleum exploration and production or retail distribution assets, that compete for capital or management attention. Therefore, our capital and attention are focused on improving our existing refineries and acquiring additional competitive refining capacity. Although many of our competitors are integrated oil companies that are better positioned to withstand market volatility, such competitors are not fully able to capitalize on periods of strong refining margins. See “—Competition.”
 
Significant Refineries Located in Key Geographic Regions.    Our Port Arthur and Lima refineries are logistically well located, modern facilities of significant size and scope with access to a wide variety of crude oils and product distribution systems. Our access to key port locations on the Gulf Coast enables us to ship waterborne crude oil to our Midwest refineries via major pipeline systems. Our Lima refinery provides us with a strong presence in the attractive PADD II market. This refinery also benefits from the facts that the Midwest region is dependent upon the import of supplies from outside the region and that the pipelines available to deliver products to the region are fully utilized, which effectively places a ceiling on external supply into the region, giving local refineries such as ours a logistical advantage. Therefore, any disruption in local refinery production or pipeline supply magnifies this supply shortage.
 
Significant Capacity to Process Low-Cost Heavy Sour Crude Oil.    Our Port Arthur refinery, which possesses one of the largest coking units in the world, can process 80% heavy sour crude oil which gives us a cost advantage over other refiners that are not able to process high volumes of these less expensive crude oils.
 
Favorable Crude Oil Supply Contract with PEMEX Affiliate.    We have a long-term heavy sour crude oil supply agreement with an affiliate of PEMEX that provides a stable and secure supply of Maya crude oil. This contract, which currently covers approximately one-third of our company-wide crude oil requirements, contains a mechanism intended to provide us with a minimum average coker gross margin and to moderate fluctuations in coker gross margins during an eight-year period beginning April 1, 2001. Essentially, if the formula-based coker gross margin set forth in the contract, which is calculated on a cumulative quarterly basis, results in a shortfall from the support amount of $15 per barrel, we receive discounts from the PEMEX affiliate. In the event that there is a recovery of a prior shortfall upon which we received a discount from the PEMEX affiliate, we would reimburse the PEMEX affiliate in the form of a crude oil premium. Since we are not required to pay premiums in excess of accumulated net shortfalls, we retain the benefit of net cumulative surpluses in our coker gross margins as compared to the support amount of $15 per barrel. For purpose of comparison, the $15 per barrel minimum average coker gross margin support amount equates to a WTI/Maya crude oil price differential of approximately $6 per barrel using market prices during the period from 1988 to September 2002, which slightly exceeds actual market differentials during that period. See “—Refinery Operations—Gulf Coast Operations—Port Arthur Refinery” for a further discussion of this contract.
 
Experienced and Committed Growth-Oriented Management Team.    Our chairman and chief executive officer, Thomas D. O’Malley, has a proven track record in the refining industry. From 1990 to 2001 Mr. O’Malley was chairman and chief executive officer of Tosco Corporation. During that period, Mr. O’Malley led Tosco Corporation through a period of significant growth in operations and shareholder returns through acquisitions. At Premcor, Mr. O’Malley has assembled an experienced and committed management team consisting of executives who have held management positions in growth-oriented organizations in the energy sector.
 
Business Strategies
 
Our goal is to be a premier independent refiner and supplier of unbranded petroleum products in the United States and to be an industry leader in growing shareholder value. We intend to accomplish this goal, grow our business, enhance earnings and improve our return on capital by executing the following strategies, which we believe capitalize on our existing competitive strengths.

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Grow Through Acquisitions and Discretionary Capital Expenditure Projects at Our Existing Refineries.    We intend to pursue timely and cost-effective acquisitions of crude oil refining capacity and undertake discretionary capital expenditure projects to improve, upgrade, and potentially expand our Port Arthur and Lima refineries. We will pursue opportunities that we believe will be promptly accretive to earnings and improve our return on capital, assuming historic average margins and crude oil differentials.
 
We believe that the continuing consolidation in our industry, the strategic divestitures by major integrated oil companies and the rationalization of specific refinery assets by merging companies will present us with attractive acquisition opportunities. We are currently evaluating several refinery acquisitions, some of which may be significant. In addition, based upon our engineering and financial analysis, we have identified discretionary capital projects at our Port Arthur and Lima refineries that we believe should, if undertaken, be accretive to earnings and generate an attractive return on capital. For example, in conjunction with a project to comply with new diesel fuel specifications, we have initiated a project at our Port Arthur refinery to expand this refinery to 300,000 - 400,000 bpd. We are also currently evaluating potential projects to reconfigure our Lima refinery to process a more sour and heavier crude slate. The management team assembled by Mr. O’Malley has a proven track record of growing businesses via acquisitions, which we believe complements an existing strength of our organization. Since 1995, we have demonstrated our expertise in evaluating, structuring, implementing and integrating projects, as well as our acquisition and technical abilities by transforming our asset base through the acquisition of, and subsequent performance enhancement at, our Port Arthur and Lima refineries. We believe we are well situated to capitalize on these acquisitions and discretionary capital project opportunities.
 
In executing the strategies outlined above, we want to own and operate refineries, whether they be our existing refineries or refineries we may acquire in the future, which not only prosper in good market conditions, but are resilient during downturns in the market. We believe this resiliency can be created by, among other things:
 
 
•
 
being a low-cost operator of safe and reliable refineries with a continuous focus on controlling costs;
 
 
•
 
having an inherent cost advantage due to lower feedstock costs, such as the cost advantage which comes from having significant sour and heavy sour crude oil processing capabilities;
 
 
•
 
owning refineries in strategic geographic locations; and
 
 
•
 
having the capability to produce and distribute a variety of the fuels required by varying regional fuel specifications.
 
Promote Operational Excellence in Safety and Reliability.    We will continue to devote significant time and resources toward improving the safety and reliability of our operations. We will seek to increase operating performance through our commitment to our preventative maintenance program and to training and development programs such as our current “proactive manufacturing” and “defect elimination” programs. We will continue to emphasize safety in all aspects of our operations. We believe that a superior safety record is inherently tied to profitability and that safety can be measured and managed like all other aspects of our business. We have identified several projects designed to increase our operational excellence. For example, at our Port Arthur refinery we are pursuing a portfolio of projects designed to increase reliability. At Lima, we have identified and are implementing a number of projects designed to decrease energy consumption and improve safety.
 
Create an Organization Highly Motivated to Enhance Earnings and Improve Return on Capital.    We intend to create an organization in which employees are highly motivated to enhance earnings and improve return on capital. In order to create this motivation, we have adopted a new annual incentive program under which the annual bonus award for every employee in the organization is dependent to a substantial degree upon earnings. The primary parameter for determining bonus awards under the program for our executive officers and our senior level management team members is earnings. The program allows our executive officers and other senior

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management team members to earn annual bonus awards only if certain predetermined earnings levels are met, but provides significant bonus opportunities if those levels are exceeded. For the remainder of our employees, earnings is a substantial factor which determines whether a bonus pool is available for annual rewards. In approving annual awards under the program, the compensation committee of our board of directors will also consider our return on capital, and our environmental, health and safety performance.
 
Refinery Operations
 
We currently own and operate two refineries: our Port Arthur, Texas refinery comprises our Gulf Coast operations; our Lima, Ohio refinery comprises our Midwest operations.
 
In late September 2002, we ceased operations at our Hartford, Illinois refinery. We concluded that there was no economically viable manner of reconfiguring the refinery to produce fuels which meet new gasoline and diesel fuel specifications mandated by the federal government. We are pursuing all strategic options, including expanding the uses of the petroleum product and distribution facility and selling or leasing the refinery, to mitigate the loss of jobs and refining capacity in the Midwest. For a discussion of the pretax charge to earnings that we recorded in 2002 as a result of the closure of our Hartford refinery, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001—Refinery Restructuring and Other Charges—Hartford Refinery Closure.”
 
Our aggregate crude oil throughput capacity at our two refineries is 420,000 bpd. The configuration at each of our refineries is single-train coking, which means that each of our refineries has a single crude unit and a coker unit. The following table provides a summary of key data for our refineries, excluding the now closed Hartford refinery, as of September 30, 2002 and for the nine months then ended.
 
Refinery Overview
 
    
Port Arthur, Texas
     
Lima, Ohio
     
Combined
  
Crude distillation capacity (bpd)
   
250,000
 
   
170,000
 
   
420,000
 
Crude slate capability:
                     
Heavy sour
   
80
%
   
—  
%
   
48
%
Medium and light sour
   
20
 
   
10
 
   
16
 
Sweet
   
—  
 
   
90
 
   
36
 
    
  
  
Total
   
100
%
   
100
%
   
100
%
    
  
  
Production
                     
Light products:
                     
Conventional gasoline
   
33.0
%
   
53.6
%
   
40.2
%
Premium and reformulated gasoline
   
8.5
 
   
8.4
 
   
8.5
 
Diesel fuel
   
25.6
 
   
12.8
 
   
21.1
 
Jet fuel
   
11.0
 
   
16.2
 
   
12.8
 
Petrochemical feedstocks
   
7.2
 
   
5.5
 
   
6.6
 
    
  
  
Subtotal light products
   
85.3
 
   
96.5
 
   
89.2
 
Petroleum coke and sulfur
   
11.8
 
   
2.0
 
   
8.4
 
Residual oil
   
2.9
 
   
1.5
 
   
2.4
 
    
  
  
Total production
   
100.0
%
   
100.0
%
   
100.0
%
    
  
  

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Products
 
Our principal refined products are gasoline, on and off-road diesel fuel, jet fuel, liquefied petroleum gas, petroleum coke and residual oil. Gasoline, on-road (low-sulfur) diesel fuel and jet fuel are primarily transportation fuels. Off-road (high-sulfur) diesel fuel is used mainly in agriculture and as railroad fuel. Liquefied petroleum gas is used mostly for home heating and as chemical and refining feedstocks. Petroleum coke, a by-product of the coking process, can be burned for power generation or used to process metals. Residual oil (slurry oil and vacuum tower bottoms) is used mainly as heavy industrial fuel, such as for power generation, or to manufacture roofing materials or create asphalt for highway paving. We also produce many unfinished petrochemical feedstocks that are sold to neighboring chemical plants at our Port Arthur and Lima refineries.
 
Gulf Coast Operations
 
The Gulf Coast, or PADD III, region of the United States, which is the largest PADD in the United States in terms of crude oil throughput capacity, is comprised of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas. According to the NPRA, 56 refineries were operating in PADD III as of December 31, 2001, with a total crude oil throughput capacity of approximately 7.5 million bpd.
 
The market has historically had an excess supply of products, with the EIA estimating light product demand, as of December 31, 2001, at approximately 2.2 million bpd and light product production at approximately 6.0 million bpd. Approximately 62%, or 3.7 million barrels, is exported mainly to the eastern seaboard or midwest markets.
 
Explorer, TEPPCO, Seaway and Phillips pipelines transport Gulf Coast product to markets located in the Midwest region, and the Colonial and Plantation pipelines transport products to markets located in the northeast and southeast United States. In addition to the product pipeline system, product can be shipped by barge and tanker to both the eastern seaboard and west coast markets.
 
Port Arthur Refinery
 
Our Port Arthur refinery is located on the Gulf Coast, which accounts for 47% of total domestic refining capacity and is one of the most competitive markets in the United States. We acquired the refinery from Chevron Products Company in February 1995. This refinery is located in Port Arthur, Texas approximately 90 miles east of Houston on a 4,000-acre site, of which less than 1,500 acres are occupied by refinery assets. Since acquiring the refinery, we have increased the crude oil throughput capacity from approximately 178,000 bpd to its current 250,000 bpd and expanded the refinery’s ability to process heavy sour crude oil. The refinery now has the ability to process 100% sour crude oil, including up to 80% heavy sour crude oil. The refinery includes a crude unit, a catalytic reformer, a hydrocracker, a FCC unit, a delayed coker and a hydrofluoric acid alkylation unit. It produces conventional gasoline, reformulated gasoline, low-sulfur diesel fuel and jet fuel, petrochemical feedstocks, sulfur and fuel grade coke.
 
The heavy oil upgrade project at our Port Arthur refinery increased from 20% to 80% the refinery’s capability of processing heavy sour crude oil. The project achieved mechanical completion in December 2000 and became fully operational in the first quarter of 2001. Both milestones were achieved on time and under budget. Final completion was achieved on December 28, 2001.
 
The project, which cost approximately $830 million, involved the construction of new coking, hydrocracking and sulfur removal capabilities and upgrades to existing units and infrastructure. According to Purvin & Gertz, the 80,000 bpd coker unit at the refinery is one of the largest in the world. The upgrades completed in 2000 included improvements to the crude unit, which increased crude oil throughput capacity from 232,000 bpd to 250,000 bpd. Our Port Arthur refinery is now particularly well suited to process significantly greater quantities of lower-cost heavy sour crude oil. The heavy oil upgrade project has significantly improved the financial performance of the refinery. Our subsidiary, PACC, which owns the coker, the hydrocracker, the sulfur removal unit and related assets and equipment and leases the crude unit and the hydrotreater from another

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of our subsidiaries, The Premcor Refining Group, sells the refined products and intermediate products produced by the heavy oil processing facility to The Premcor Refining Group pursuant to arm’s length pricing formulas based on public market benchmark prices. The Premcor Refining Group then sells these products to third parties.
 
Feedstocks and Production at Port Arthur Refinery
 
 
    
For the Year Ended December 31,
     
For the Nine
Months Ended
September 30, 2002
  
    
1999
     
2000
     
2001
     
    
bpd (thousands)
   
Percent of Total
     
bpd (thousands)
   
Percent of Total
     
bpd (thousands)
   
Percent of Total
     
bpd (thousands)
   
Percent of Total
  
Feedstocks
                                                
Crude oil throughput:
                                                
Sweet crude oil
   
10.4
   
5.0
%
   
3.6
   
1.7
%
   
—  
   
—  
%
   
—  
   
—  
%
Medium and light sour crude oil
   
156.2
   
75.8
 
   
155.1
   
74.9
 
   
48.3
   
20.0
 
   
39.5
   
16.8
 
Heavy sour crude oil
   
33.4
   
16.2
 
   
43.4
   
21.0
 
   
181.5
   
75.2
 
   
189.6
   
80.8
 
    
  
  
  
  
  
  
  
Total crude oil
   
200.0
   
97.0
 
   
202.1
   
97.6
 
   
229.8
   
95.2
 
   
229.1
   
97.6
 
Unfinished and blendstocks
   
6.0
   
3.0
 
   
5.0
   
2.4
 
   
11.4
   
4.8
 
   
5.7
   
2.4
 
    
  
  
  
  
  
  
  
Total feedstocks
   
206.0
   
100.0
%
   
207.1
   
100.0
%
   
241.2
   
100.0
%
   
234.8
   
100.0
%
    
  
  
  
  
  
  
  
Production
Light products:
                                                
Conventional gasoline
   
75.9
   
36.4
%
   
73.4
   
34.9
%
   
82.9
   
32.7
%
   
83.5
   
33.0
%
Premium and reformulated gasoline
   
15.6
   
7.5
 
   
18.1
   
8.6
 
   
24.4
   
9.6
 
   
21.6
   
8.5
 
Diesel fuel
   
61.1
   
29.3
 
   
58.0
   
27.5
 
   
77.2
   
30.4
 
   
64.7
   
25.6
 
Jet fuel
   
18.1
   
8.7
 
   
16.6
   
7.9
 
   
19.7
   
7.8
 
   
27.7
   
11.0
 
Petrochemical feedstocks
   
23.1
   
11.1
 
   
23.7
   
11.3
 
   
18.3
   
7.2
 
   
18.3
   
7.2
 
    
  
  
  
  
  
  
  
Total light products
   
193.8
   
93.0
 
   
189.8
   
90.2
 
   
222.5
   
87.7
 
   
215.8
   
85.3
 
Petroleum coke and sulfur
   
11.1
   
5.3
 
   
11.3
   
5.3
 
   
26.5
   
10.4
 
   
29.9
   
11.8
 
Residual oil
   
3.6
   
1.7
 
   
9.5
   
4.5
 
   
4.8
   
1.9
 
   
7.3
   
2.9
 
    
  
  
  
  
  
  
  
Total production
   
208.5
   
100.0
%
   
210.6
   
100.0
%
   
253.8
   
100.0
%
   
253.0
   
100.0
%
    
  
  
  
  
  
  
  
 
Our Port Arthur refinery has significantly reduced combined “recordable injuries” and “lost time injuries” as defined by OSHA. The refinery’s recordable injury rate, which reflects the number of recordable incidents per 200,000 hours worked, has improved from 4.40 in 1995 to an average of 1.39 as of September 30, 2002, compared to a United States refining industry average recordable injury rate of 1.35 in 2001. From August 1997 through the third quarter of 2001, our Port Arthur refinery accumulated over seven million employee hours without a lost time injury. The streak ended on October 4, 2001 when the refinery incurred its first lost time injury in over four years.
 
Feedstock and Other Supply Arrangements.    The refinery’s Texas Gulf Coast location is close to the major heavy sour crude oil producers and permits access to many cost-effective domestic and international crude oil sources via waterborne delivery to the refinery dock or from two terminals, the Sun terminal and the Oiltanking Beaumont Inc. terminal at Nederland, Texas, and through the Equilon pipeline. We purchase approximately 200,000 bpd of heavy sour crude oil, or 80% of the refinery’s daily crude oil processing capacity, via waterborne delivery from an affiliate of PEMEX under term crude oil supply agreements, one of which is a long-term agreement with PACC expiring in 2011. Under this long-term agreement, PEMEX guarantees its affiliate’s obligations to us. The remaining 20% of processing capacity utilizes a medium sour crude oil, the sourcing of which is optimally allocated between foreign waterborne crude oil and domestic offshore Gulf Coast sour crude oil delivered by pipeline.
 
Waterborne crude oil is delivered to the refinery docks or via the Sun terminal or the Oiltanking Beaumont terminal, both of which are connected by pipeline to our Lucas tank farm for redelivery to the refinery. Pipeline crude oil can also be received from Equilon’s pipeline originating in Clovelly, Louisiana.

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The long-term crude oil supply agreement with the PEMEX affiliate provides our subsidiary, PACC, with a stable and secure supply of Maya crude oil. The long-term crude oil supply agreement includes a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstock. This price adjustment mechanism contains a formula that represents an approximation of the coker gross margin and provides for a minimum average coker gross margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The agreement expires in 2011.
 
On a monthly basis, the coker gross margin, as defined in the agreement, is calculated and compared to the minimum. Coker gross margins exceeding the minimum are considered a “surplus” while coker gross margins that fall short of the minimum are considered a “shortfall.” On a quarterly basis, the surplus and shortfall determinations since the beginning of the contract are aggregated. Pricing adjustments to the crude oil we purchase are only made when there exists a cumulative shortfall. When this quarterly aggregation first reveals that a cumulative shortfall exists, we receive a discount on our crude oil purchases in the next quarter in the amount of the cumulative shortfall. If, thereafter, the cumulative shortfall incrementally increases, we receive additional discounts on our crude oil purchases in the succeeding quarter equal to the incremental increase, and conversely, if, thereafter, the cumulative shortfall incrementally decreases, we repay discounts previously received, or a premium, on our crude oil purchases in the succeeding quarter equal to the incremental decrease. Cash crude oil discounts received by us in any one quarter are limited to $30 million, while our repayment of previous crude oil discounts, or premiums, are limited to $20 million in any one quarter. Any amounts subject to the quarterly payment limitations are carried forward and applied in subsequent quarters.
 
As of September 30, 2002, a cumulative quarterly surplus of $61.7 million existed under the contract. As a result, to the extent we experience quarterly shortfalls in coker gross margins going forward, the price we pay for Maya crude oil in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls. Assuming the WTI less Maya crude oil differential continues at its third quarter 2002 average of $4.92 per barrel, and assuming a Gulf Coast 3/2/1 crack spread similar to the third quarter 2002 average of $2.64 per barrel, we estimate the current $61.7 million cumulative surplus would be fully reversed after the third quarter of 2003. At that time, assuming a continuation of weak market conditions, we would be eligible to receive discounts on our crude oil purchases under the PEMEX contract as described above.
 
In May 2001, we entered into marine charter agreements with The Sanko Steamship Co., Ltd. of Tokyo, Japan, for three tankers custom designed for delivery to our docks. We use the ships solely to transport Maya crude oil from the loading port in Mexico to our refinery dock in Port Arthur. Because of the custom design of the tankers, our dock is accessible 24 hours a day by the tankers, unlike the daylight-only transit requirement applicable to ships approaching all other terminals in the Port Arthur area. In addition, the size of the custom-designed tankers allows our crude oil requirements to be satisfied with fewer trips to the docks. We believe our marine charter arrangement will improve delivery reliability of crude oil to the Port Arthur refinery and will save approximately $10 million per year due to reduced third party terminal costs and the benefit of fewer trips. As of late 2002, all three ships had been delivered to us. The charter agreements have an eight-year term from the date of delivery of each ship and are renewable for two one-year periods.
 
Hydrogen is supplied to the refinery under a 20-year contract with Air Products and Chemicals Inc., or Air Products. Air Products has constructed, on property leased from us, a new steam methane reformer and two hydrogen purification units. Air Products also supplies steam and electricity to our Port Arthur refinery. If our requirements exceed the daily amount provided for under the contract, we may purchase additional hydrogen from Air Products. Certain bonuses and penalties are applicable for various performance targets under the contract.
 
Mixed butylenes from the FCC unit and the coker unit are processed for a fee by Huntsman Petrochemical Corporation, or Huntsman, to produce MTBE for sale or refinery consumption. The unused portion of the mixed butylene stream and incremental purchases are returned to our refinery for use as alkylation feedstock. Methanol

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required to produce the MTBE is purchased by us and delivered to Huntsman. The butylenes are transported to and from Huntsman by dedicated pipelines owned by Huntsman. This is a one-year renewable agreement between Huntsman and us, which may be cancelled upon 90 days’ notice.
 
We purchase Huntsman’s entire production of pyrolysis gasoline, or pygas, produced from their Port Arthur ethylene cracker. Pygas is transported by dedicated pipeline from Huntsman to the refinery for use as a refinery gasoline blendstock. This agreement is for five years ending December 31, 2004, but can be cancelled by us, if desired as a result of gasoline specification changes due to Tier 2 gasoline standards, since the sulfur content of pygas may exceed that which is permitted by the regulations.
 
Energy.    We generate most of the electricity for our Port Arthur refinery in our own cogeneration plants. The remainder of our electricity needs is supplied under a long-term agreement with Air Products, which has a cogeneration plant as part of its on-site hydrogen plant. In addition, we buy power from Entergy Gulf States, Inc., or Entergy, under peak load conditions, or if a generator experiences a mechanical failure. During times when we have excess power, we sell the excess to Entergy. Entergy has exercised its right to terminate the agreement because of impending deregulation, which deregulation is expected to occur in mid-2003. The agreement will stay in effect on a month-to-month basis until deregulation occurs. We are in the process of making alternative arrangements to replace the Entergy agreement.
 
Our Port Arthur refinery purchases natural gas at a price based on a monthly index, pursuant to a contract with Entex Gas Marketing, a subsidiary of Reliant Energy, that terminates in June 2003. The contract provides for 60,000 million btu of natural gas per day on a firm, uninterruptible basis, which is the amount of natural gas consumed by us each day at the refinery. The contract also allows for wide flexibility in volumes at a specified pricing formula. If we need to replace this contract, there are many alternative sources of natural gas available.
 
Product Offtake.    The gasoline, low-sulfur diesel and jet fuel produced at our Port Arthur refinery are distributed into the Colonial pipeline, Explorer pipeline, TEPPCO pipeline or through the refinery dock into ships or barges. The advantage of a variety of distribution channels is that it gives us the flexibility to direct our product into the most profitable market. The TEPPCO pipeline is fed directly out of the refinery tankage, through pipelines we own and operate. The Colonial and Explorer pipelines are fed from our Port Arthur Products Station tank farm, which we partly own through a joint venture with Motiva Enterprises LLC and Unocal Pipeline Company, operated by Equilon Enterprises LLC, or Equilon. We also own the pipelines which distribute products from the refinery to the Port Arthur Products Station tank farm. Products loaded at the refinery docks come directly out of our Port Arthur refinery tankage. A pipeline also runs from our refinery to Equilon’s Beaumont light products terminal. We supply all the products to the Equilon terminal. The petroleum coke produced is moved through the refinery dock by third-party shiploaders. The petroleum coke is sold to five customers under term agreements, for periods of one to four years.
 
Other Arrangements.    Within our Port Arthur refinery, Chevron Phillips Chemical Company, L.P. operates a 164-acre petrochemical facility to manufacture olefins, benzene, cumene and cyclohexane. This facility is well integrated with the refinery and relies heavily on the refinery infrastructure for utility, operating and support services. We provide these services at cost. In addition to services, Chevron Phillips Chemical Company L.P. purchases feedstock from the refinery for use in its olefin cracker, aromatic extraction unit and propylene fractionator. By-products from the petrochemical facility are sold to the refinery for use as gasoline and diesel blendstock, saturate gas plant feedstock, hydrogen and fuel gas. Chevron Phillips Chemical Company L.P. has expressed intent to discontinue operation of the aromatic extraction unit. We are currently evaluating the impact of this discontinued operation on our refinery operations.
 
Chevron Products Company also operates a distribution facility on 102 acres within our Port Arthur refinery. The distribution center is operated by Chevron Products Company to blend, package, and distribute lubricants and grease. This facility also relies heavily on the refinery infrastructure for utility, operating and support services.

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Other Gulf Coast Assets
 
We own other assets associated with our Port Arthur refinery, including:
 
 
•
 
a crude oil terminal and a liquefied petroleum gas terminal, with a combined capacity of approximately 5.0 million barrels;
 
 
•
 
an interest in a jointly held product terminal operated by Equilon Pipeline Company;
 
 
•
 
proprietary refined product pipelines that connect our Port Arthur refinery to our liquefied petroleum gas terminal;
 
 
•
 
refined product common carrier pipelines that connect our Port Arthur refinery to several other terminals; and
 
 
•
 
crude oil common carrier pipelines that connect our Port Arthur refinery to several other terminals and third party pipeline systems.
 
Midwest Operations
 
The Midwest, or PADD II, region of the United States, which is the second largest PADD in the United States in terms of crude oil throughput capacity, is comprised of North Dakota, South Dakota, Minnesota, Iowa, Nebraska, Kansas, Missouri, Oklahoma, Wisconsin, Illinois, Michigan, Indiana, Ohio, Kentucky and Tennessee. According to the NPRA, 27 refineries were operating in PADD II as of December 31, 2001, with a total crude oil throughput capacity of approximately 3.5 million bpd.
 
Production of light, or premium, petroleum product by refiners located in PADD II has historically been less than the demand for such product within that region, resulting in product being supplied from surrounding regions.
 
According to the EIA, total light product demand in PADD II, as of December 31, 2001, is approximately 3.9 million bpd, with refinery production of light products in PADD II estimated at approximately 2.9 million bpd. Net imports have supplemented PADD II refining in satisfying product demand and are currently estimated by the EIA at approximately 840,000 bpd, with the Gulf Coast continuing to be the largest area for sourcing product, accounting for approximately 670,000 bpd.
 
The Explorer, TEPPCO, Seaway, Orion, Colonial and Plantation pipelines are the primary pipeline systems for transporting Gulf Coast refinery output to PADD II. In addition, product began shipping via the Centennial product pipeline in April. Supply is also available via barge transport up the Mississippi River with significant deliveries into markets along the Ohio River. Although inefficient compared to pipelines, barge transport serves a role in supplying inland markets that are remote from pipeline access and in supplementing pipeline supply when they are bottlenecked or short of product.
 
Lima Refinery
 
Our Lima refinery, which we acquired from BP in August 1998, is located on a 650-acre site in Lima, Ohio, about halfway between Toledo and Dayton. The refinery, with a crude oil throughput capacity of approximately 170,000 bpd, processes primarily light, sweet crude oil, although 22,500 bpd of coking capability allows the refinery to upgrade lower-valued products. Our Lima refinery is highly automated and modern and includes a crude unit, a hydrocracker unit, a reformer unit, an isomerization unit, a FCC unit, a coker unit, a trolumen unit, an aromatic extraction unit and a sulfur recovery unit. We also own a 1.1 million-barrel crude oil terminal associated with our Lima refinery. The refinery can produce conventional gasoline, reformulated gasoline, jet fuel, high-sulfur diesel fuel, anode petroleum coke, benzene and toluene.

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Feedstocks and Production at Lima Refinery
 
    
For the Year Ended December 31,
     
For the Nine
Months Ended
September 30, 2002
  
    
1999
     
2000
     
2001
     
    
bpd (thousands)
     
Percent of Total
     
bpd (thousands)
     
Percent of Total
     
bpd (thousands)
     
Percent of Total
     
bpd (thousands)
     
Percent of Total
  
Feedstocks
                                                        
Crude oil throughput:
                                                        
Sweet crude oil
   
120.7
 
   
103.6
%
   
130.5
 
   
99.5
%
   
136.5
 
   
99.7
%
   
137.7
 
   
102.0
%
Light sour crude oil
   
—  
 
   
—  
 
   
5.9
 
   
4.5
 
   
4.0
 
   
2.9
 
   
3.3
 
   
2.4
 
    
  
  
  
  
  
  
  
Total crude oil
   
120.7
 
   
103.6
 
   
136.4
 
   
104.0
 
   
140.5
 
   
102.6
 
   
141.0
 
   
104.4
 
Unfinished and blendstocks
   
(4.2
)
   
(3.6
)
   
(5.3
)
   
(4.0
)
   
(3.6
)
   
(2.6
)
   
(6.0
)
   
(4.4
)
    
  
  
  
  
  
  
  
Total feedstocks
   
116.5
 
   
100.0
%
   
131.1
 
   
100.0
%
   
136.9
 
   
100.0
%
   
135.0
 
   
100.0
%
    
  
  
  
  
  
  
  
Production
                                                        
Light products:
                                                        
Conventional gasoline
   
55.2
 
   
46.7
%
   
67.5
 
   
50.8
%
   
71.2
 
   
51.4
%
   
73.1
 
   
53.6
%
Premium and reformulated gasoline
   
14.3
 
   
12.1
 
   
11.3
 
   
8.5
 
   
11.5
 
   
8.3
 
   
11.4
 
   
8.4
 
Diesel fuel
   
20.5
 
   
17.4
 
   
21.1
 
   
15.9
 
   
21.3
 
   
15.4
 
   
17.4
 
   
12.8
 
Jet fuel
   
17.7
 
   
15.0
 
   
21.4
 
   
16.1
 
   
22.7
 
   
16.4
 
   
22.1
 
   
16.2
 
Petrochemical feedstocks
   
6.4
 
   
5.4
 
   
7.1
 
   
5.3
 
   
7.0
 
   
5.1
 
   
7.5
 
   
5.5
 
    
  
  
  
  
  
  
  
Total light products
   
114.1
 
   
96.6
 
   
128.4
 
   
96.6
 
   
133.7
 
   
96.6
 
   
131.5
 
   
96.5
 
Petroleum coke and sulfur
   
2.5
 
   
2.1
 
   
2.5
 
   
1.9
 
   
2.8
 
   
2.0
 
   
2.8
 
   
2.0
 
Residual oil
   
1.5
 
   
1.3
 
   
2.0
 
   
1.5
 
   
2.0
 
   
1.4
 
   
2.0
 
   
1.5
 
    
  
  
  
  
  
  
  
Total production
   
118.1
 
   
100.0
%
   
132.9
 
   
100.0
%
   
138.5
 
   
100.0
%
   
136.3
 
   
100.0
%
    
  
  
  
  
  
  
  
 
Our Lima refinery crude oil input has not exceeded an annual average of 140,000 bpd over the last several years despite having a throughput capacity of approximately 170,000 bpd. This is largely due to the inability to market the incremental product, mainly high-sulfur diesel fuel, that is produced at throughput rates in excess of 140,000 bpd. A new pipeline connection between the Buckeye pipeline, which transports products out of Lima, and the TEPPCO pipeline, which delivers products into Chicago, was completed in August 2001. This connection in Indianapolis allows for the transportation of light products, specifically high-sulfur diesel fuel, to be transported into the Chicago market from our Lima refinery, thereby providing the opportunity to increase throughput rates closer to the 170,000 bpd capacity when economically justifiable. The ability to transport reformulated gasoline on this TEPPCO interconnection from our Lima refinery to the Chicago market was made available in late 2002, and we may utilize this connection for reformulated gasoline in 2003.
 
Our Lima refinery’s combined “recordable injuries” and “lost work days” rate, or recordable injury rate, which reflects the number of recordable incidents per 200,000 hours worked, was an average of 1.59 as of September 30, 2002, as compared to a United States refining industry average recordable injury rate of 1.35 in 2001.
 
Feedstock and Other Supply Arrangements.    The crude oil supplied to our refinery is purchased on a spot basis and delivered via the Marathon pipeline and the Mid-Valley pipeline. The reactivation and reversal of the Millennium pipeline in June 2000 allows the delivery of up to 65,000 bpd of foreign waterborne crude oil to the Mid-Valley pipeline at Longview, Texas. The Mid-Valley pipeline is also supplied with West Texas Intermediate domestic crude oil via the West Texas Gulf pipeline. The Marathon pipeline is supplied via the Capline, Ozark, Platte, ExxonMobil and Mustang pipelines. The current crude oil slate includes foreign waterborne crude oil ranging from heavy sweet to light sweet, domestic West Texas Intermediate and a small amount of light sour crude oil in order to maximize the sulfur plant capacity. This flexibility in crude oil supply helps to assure availability and allows us to minimize the cost of crude oil delivered into our refinery.

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In March 1999, we entered into an agreement with Koch Supply and Trading Group L.P., or Koch, as a means of minimizing our working capital investment. Pursuant to the agreement, we sold Koch our crude oil linefill in the Mid-Valley pipeline and the West Texas Gulf pipeline that is required for the delivery of crude oil to our Lima refinery, which amounted to 2.7 million barrels. As part of the agreement with Koch, we were required to repurchase these barrels of crude oil in September 2002. On October 1, 2002, Morgan Stanley Capital Group Inc., or MSCG, purchased the 2.7 million barrels of crude oil from Koch in lieu of our purchase obligation. We are obligated to repurchase the linefill from MSCG upon termination of our agreement with them. The initial term of that agreement continues through October 1, 2003 and thereafter the agreement automatically extends for additional 30 day periods unless terminated by either party. Because ownership of the linefill confers shipper status, MSCG is the shipper of record on all barrels delivered to Lima from the Mid-Valley pipeline. This routing is the primary source of West Texas Intermediate crude oil to the refinery. We also have the ability to transport foreign crude oils to the origin of the Mid-Valley pipeline for further delivery by way of the MSCG contract to Lima. All deliveries to Lima, whether domestic or foreign, are accomplished on a daily ratable basis.
 
Energy.    Electricity is supplied to our refinery at a competitive rate pursuant to an agreement with Ohio Power Company, which is terminable by either party on twelve months’ notice. We believe this is a stable, long-term energy supply; however, there are alternative sources of electricity in the area if necessary. We purchase natural gas at a price based on a monthly index, pursuant to a contract with BP. The contract was renewed in August 2002 and renews automatically in August of each year, unless terminated by us on 120 days’ notice. If necessary, alternative sources of natural gas supply are available, although probably at higher prices.
 
Product Offtake.    Our Lima refinery’s products are distributed through the Buckeye and Inland pipeline systems and by rail, truck or third party-owned terminals. The Buckeye system provides access to markets in northern/central Ohio, Indiana, Michigan and western Pennsylvania. The Inland pipeline system is a private intra-state system through which products from our Lima refinery can be delivered to the pipeline’s owners. A high percentage of our Lima refinery’s production supplies the wholesale business through direct movements or exchanges. Gasoline and diesel fuel are sold or exchanged to the Chicago market under term arrangements. Jet fuel production is sold primarily under annual contracts to commercial airlines and delivered via pipelines. Propane products are sold by truck or, during the summer, transported via the TEPPCO pipeline to caverns for winter sale. The mixed butylenes and isobutane products are transported by rail to customers throughout the country. The anode grade petroleum coke production, which commands a higher price than fuel grade petroleum coke, is transported by rail to customers in West Virginia and Illinois.
 
Other Arrangements.    Adjacent to our Lima refinery is a chemical complex owned and operated by BP Chemical, a plant owned by PCS Nitrogen and operated by BP Chemical, and a plant that processes by-products from the BP Chemical plant. The chemical complex relies heavily on our Lima refinery’s infrastructure for utility, operating and support services. We provide these services at cost; however, costs for the replacement of capital are shared based on the proportion each party uses the equipment. In addition to services, BP Chemical purchases chemical grade propylene and normal butane for its plants.
 
We process BP’s Toledo refinery production of low purity propylene. The low purity propylene is transported by pipeline to the refinery for purification. High purity propylene is purchased by BP Chemical and is received by rail or truck and commingled with high purity propylene production from the refinery to provide feed to the adjacent BP Chemical plant. This agreement has a seven-year term ending September 30, 2006, and continues year to year thereafter, unless terminated upon three years’ notice.
 
Hartford Refinery
 
Our Hartford refinery is located on a 400-acre site on the Mississippi River in Hartford, Illinois, approximately 17 miles northeast of St. Louis, Missouri. The refinery, which has a crude oil throughput capacity of approximately 70,000 bpd, is designed to process primarily sour crude oil into higher-value products such as gasoline and diesel fuel. The refinery includes a coker unit and can therefore process a wide variety of crude oil

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slates, including approximately 60% heavy sour crude oil and 40% medium and light sour crude oil or up to 100% medium sour crude oil. The refinery can produce conventional gasoline, reformulated gasoline, high-sulfur diesel fuel, residual fuel and petroleum coke. The refinery includes a crude unit, a hydrogen plant, an isomerization unit, a FCC unit, a coker unit and a hydrofluoric alkylation unit.
 
In late September 2002, we ceased refining operations at our Hartford refinery. We concluded there was no economically viable method of reconfiguring the refinery to produce fuels meeting new gasoline and diesel fuel specifications mandated by the federal government. We are pursuing all strategic options, including expanding the uses of the petroleum product and distribution facility and selling or leasing the refinery, to mitigate the loss of jobs and refining capacity in the Midwest. For a discussion of the pretax charge to earnings that we recorded in 2002 as a result of the closure of our Hartford refinery, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001—Refinery Restructuring and Other Charges—Hartford Refinery Closure.” In October 2002, we announced our intention to operate our Hartford terminal facility on an on-going basis. The facility has total storage capacity of approximately 1.5 million barrels, of which we will utilize approximately 500,000 barrels for our wholesale activity.
 
Product Marketing
 
Our product marketing group sells approximately 2.2 billion gallons per year of gasoline, diesel fuel and jet fuel to a diverse group of approximately 750 distributors and chain retailers. We believe we are one of the largest suppliers of unbranded refined petroleum products in the United States. We sell the majority of our products through an extensive third-party owned terminal system in the midwest, southeast and eastern United States.
 
We also sell our products to end-users in the transportation and commercial sectors, including airlines, railroads and utilities.
 
In 1999, we sold our network of distribution terminals, with the exception of our Alsip terminal and two terminals affiliated with our Port Arthur refinery, to a group composed of Equiva Trading Company, Equilon Enterprises LLC and Motiva Enterprises LLC. As part of the transaction, we entered into a ten-year agreement with the group under which we have the right to distribute our refined products from our refineries through all of the group’s extensive network of approximately 113 terminals, including the terminals we sold to the group. Our right to use the terminals is subject to availability and, as a result, our use of the terminals is sometimes limited. This agreement facilitates our strategy of expanding our wholesale business in Texas, the Southeast and eastern seaboard of the United States.
 
Our Alsip terminal is adjacent to our former Blue Island refinery (which is located approximately 17 miles from Chicago), which we closed in January 2001. We also own a dedicated pipeline that runs from the Alsip terminal to a Hammond, Indiana terminal owned by Equilon. Since the closure of the Blue Island refinery, we have been evaluating alternatives for optimizing the Alsip terminal. The terminal will continue to service the geographic niche market it has historically supplied with reformulated gasoline and distillates. We supply the terminal with products from our Port Arthur refinery via barge and via the Equilon terminal and from our Lima refinery via the Buckeye/TEPPCO pipeline.
 
A one million barrel refinery tank farm formerly associated with our Blue Island refinery is currently used to store crude oil, light products, ethanol, heavy oils and liquefied petroleum gas. Our refinery tank farm can receive products via Kinder Morgan, Capline and TEPPCO pipelines, barge, rail and through our proprietary pipeline from Equilon’s Hammond terminal. Products can be shipped out of the refinery tank farm into the Kinder Morgan and Westshore pipelines, barges, railcars, trucks and via our pipeline back to Hammond where it can access the Wolverine pipeline, Badger pipeline and Buckeye pipeline. The location and variety of transportation into and out of the facility positions us well to supply the Chicago market or to lease our refinery tank farm to third parties.

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Our distribution network is an integral part of our refining business. However, due to ordinary course logistical issues concerning production schedules and product sales commitments, it is common for us to purchase refined products from third parties in order to balance the requirements of our product marketing activities. Less than 15% of net sales and operating revenues in 2001 were represented by sales of products purchased from third parties. This percentage was higher than normal in 2001 because we purchased refined products in order to cover shortfalls resulting from the closure of our Blue Island refinery. Although third party purchases are essential to effectively market our production, the effects from these activities on our operating results are not significant.
 
Crude Oil Supply
 
We have crude oil supply contracts with an affiliate of PEMEX pursuant to which we purchase approximately 200,000 bpd under two separate contracts. One of these contracts is a long-term agreement, under which we currently purchase approximately 162,000 bpd, designed to provide our Port Arthur refinery with a stable and secure supply of Maya heavy sour crude oil. We acquire the remainder of our crude oil supply on the spot market from unaffiliated foreign and domestic sources, allowing us to be flexible in our crude oil supply source. The following table shows our average daily sources of crude oil for the nine months ended September 30, 2002:
 
Sources of Crude Oil Supply
 
    
Nine Months Ended September 30, 2002
  
    
bpd
(thousands)
   
Percent of Total
  
Latin America
            
Mexico
   
190.2
   
43.2
%
Rest of Latin America
   
15.1
   
3.4
 
United States
   
143.8
   
32.7
 
Middle East
   
36.3
   
8.2
 
North Sea
   
21.4
   
4.9
 
Africa
   
15.4
   
3.5
 
Russia
   
15.3
   
3.5
 
Canada
   
2.5
   
0.6
 
    
  
Total
   
440.0
   
100.0
%
    
  
 
In both of our operating regions, we have the flexibility to receive feedstocks from several suppliers using either pipelines or waterborne delivery. Our Port Arthur refinery receives Maya crude oil and light sour crude oil, which is delivered largely from third-party terminals and also through waterborne delivery via our docks. In the Midwest, we receive our crude oil largely through the Mid-Valley pipeline, the Capline pipeline and also under contract through the Millennium pipeline.
 
Competition
 
Many of our principal competitors are fully integrated national or multinational oil companies engaged in many segments of the petroleum business, including exploration, production, transportation, refining and marketing. Because of their geographic diversity, integrated operations, larger capitalization and greater resources, these competitors may be better able to withstand volatile market conditions, compete more effectively on the basis of price, and obtain crude oil more readily in times of shortage.

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The refining industry is highly competitive. Among the principal competitive factors are feedstock supply and product distribution. We compete with other companies for supplies of feedstocks and for outlets for our refined products. Many of our competitors produce their own feedstocks and have extensive retail outlets. We do not produce any of our own feedstocks and have sold our retail outlets. The constant supply of feedstocks and ready market and distribution channels of such competitors places us at a competitive disadvantage in periods of feedstock shortage, high feedstock prices, low refined product prices or unfavorable distribution channel market conditions. In addition, competitors with their own production or retail outlets may be better able to withstand such periods of depressed refining margins or feedstock shortages because they can offset refining losses with profits from their production or retail operations.
 
Our industry is subject to extensive environmental regulations, including new standards governing sulfur content in gasoline and diesel fuel. These regulations will have a significant impact on the refining industry and will require substantial capital outlays by us and our competitors in order to upgrade our facilities to comply with the new standards. For further information on environmental compliance, see “—Environmental Matters—Environmental Compliance.” Competitors who have more modern plants than we do may not spend as much to comply with the regulations and may be better able to afford the upgrade costs.
 
Several significant merger transactions have recently closed between several of our refining industry competitors. We expect this trend toward industry consolidation and restructuring through a variety of transaction structures to continue. As a result of this consolidation, we believe, as has already been the case, that regulators will require merging parties to divest themselves of certain assets. In addition, other assets may also become available as the merged entities go through the process of rationalization regarding overlapping assets and production capability. As such, we believe that the continued consolidation and rationalization within the refining market may present us with attractive acquisition opportunities.
 
Employees
 
As of December 1, 2002, we employed approximately 1,413 people, with approximately 60% covered by collective bargaining agreements at our Lima and Port Arthur refineries. In October 2002, approximately 300 positions were terminated at our Hartford refinery in relation to its closure.
 
The collective bargaining agreement covering employees at our Port Arthur refinery expires in January 2006 and the agreement covering employees at our Lima refinery expires in April 2006. Our relationships with the relevant unions have been good and we have never experienced a work stoppage as a result of labor disagreements.
 
The Memphis refinery employs approximately 320 people, including support personnel. Approximately 50% of those employees are covered by a collective bargaining agreement expiring in January 2006. We intend to offer employment to the refinery’s qualified represented employees and intend to consider the non-represented employees as candidates for employment.
 
Environmental Matters
 
We are subject to extensive federal, state and local laws and regulations relating to the protection of the environment. These laws and the accompanying regulatory programs and enforcement initiatives, some of which are described below, impact our business and operations by imposing, among other things:
 
 
•
 
restrictions or permit requirements on our ongoing operations;
 
 
•
 
liability in certain cases for the remediation of contaminated soil and groundwater at our current or former facilities and at facilities where we have disposed of hazardous materials; and
 
 
•
 
specifications on the petroleum products we market, primarily gasoline and diesel fuel.

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The laws and regulations we are subject to change often and may become more stringent. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws such as the Resource Conservation and Recovery Act and the Clean Air Act have not yet been finalized, are under governmental or judicial review or are being revised. These regulations and other new air and water quality standards and stricter fuel regulations could result in increased capital, operating and compliance costs. See “Risk Factors—Risks Related to our Business and our Industry—Compliance with, and changes in, environmental laws could adversely affect our results of operations and our financial condition” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Flow from Investing Activities.”
 
In addition, we are currently a party to a number of enforcement actions filed by federal, state and local agencies alleging violations of environmental laws and regulations and party to a number of third-party claims alleging exposure to hazardous substances, including asbestos. See “—Environmental Matters—Certain Environmental Contingencies; Legal and Environmental Reserves” and “—Legal Proceedings.”
 
Environmental Compliance
 
The principal environmental risks associated with our refinery operations are air emissions, releases into soil and groundwater and wastewater excursions. The primary legislative and regulatory programs that affect these areas are outlined below.
 
The Clean Air Act
 
The Clean Air Act and the corresponding state laws that regulate emissions of materials into the air affect refining operations both directly and indirectly. Direct impacts on refining operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to specific air pollutants. For example, fugitive dust, including fine particulate matter measuring ten micrometers in diameter or smaller, may be subject to future regulation. The Clean Air Act indirectly affects refining operations by extensively regulating the air emissions of sulfur dioxide and other compounds, including nitrogen oxides, emitted by automobiles, utility plants and mobile sources, which are direct or indirect users of our products.
 
The Clean Air Act imposes stringent limits on air emissions, establishes a federally mandated operating permit program and allows for civil and criminal enforcement sanctions. The Clean Air Act also establishes attainment deadlines and control requirements based on the severity of air pollution in a geographical area.
 
In July 1997, the EPA promulgated more stringent National Ambient Air Quality Standards for ground-level ozone and fine particulate matter. In May 1999, a federal appeals court overturned the new standards. In February 2001, the United States Supreme Court affirmed in part, reversed in part, and remanded the case to the EPA to develop a reasonable interpretation of the nonattainment implementation provisions insofar as they relate to the revised ozone standards. Additionally, in 1998, the EPA published a final rule addressing the regional transport of ground-level ozone across state boundaries to the eastern United States through nitrogen oxide emissions reduction from various emissions sources, including refineries. The rule requires nineteen states and the District of Columbia to revise their state implementation plans to reduce nitrogen oxide emissions. In a related action in December 1999, the EPA granted a petition from several northeastern states seeking the adoption of stricter nitrogen oxide standards by midwestern states. The impact of the revised ozone and nitrogen oxide standards could be significant to us, but the potential financial effects cannot be reasonably estimated until the EPA takes further action on the revised ozone National Ambient Air Quality Standards, or any further judicial review occurs, and the states, as necessary, develop and implement revised state implementation plans in response to the revised ozone and nitrogen oxide standards.
 
At the Port Arthur refinery, we have committed to acquire permits for “grandfathered” emissions sources under the Governor’s Clean Air Responsibility Enterprise program. To date, we have permitted 99% of the

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emissions from the refinery. We have been granted a flexible operating use permit for the refinery that allows us greater operational flexibility than we previously had, including the ability to increase throughput capacities, provided we do not exceed emissions thresholds set forth in the permit. In return for the flexible operating use permit, we agreed to install advanced pollution control technology at the refinery. We will begin our ninth year of a ten year schedule to install such technology.
 
The Clean Water Act
 
The federal Clean Water Act of 1972 affects refining operations by imposing restrictions on effluent discharge into, or impacting, navigable water. Regular monitoring, reporting requirements and performance standards are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water. We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented internal programs to oversee our compliance efforts. In addition, we are regulated under the Oil Pollution Act, which amended the Clean Water Act. Among other requirements, the Oil Pollution Act requires the owner or operator of a tank vessel or a facility to maintain an emergency oil response plan to respond to releases of oil or hazardous substances. We have developed and implemented such a plan for each of our facilities covered by the Oil Pollution Act. Also, in case of such releases, the Oil Pollution Act requires responsible companies to pay resulting removal costs and damages, provides for substantial civil penalties, and imposes criminal sanctions for violations of this law. The State of Texas, in which we operate, has passed laws similar to the Oil Pollution Act.
 
Ethanol and MTBE are the essential blendstocks for producing cleaner-burning gasoline. However, the presence of MTBE in some water supplies, resulting from gasoline leaks primarily from underground and aboveground storage tanks, has led to public concern that MTBE has contaminated drinking water supplies, thus posing a health risk, or has adversely affected the taste and odor of drinking water supplies. As a result of heightened public concern, California has banned the use of MTBE as a gasoline component in that state effective at the end of 2004. In addition, the federal legislature and other states have either passed or proposed or are considering proposals to restrict or ban the use of MTBE. We have primarily used ethanol as the blendstock for the reformulated gasoline we produce. We have, however, produced gasoline containing MTBE at our refineries, and we have sold MTBE to third parties for use as a blendstock for gasoline.
 
Resource Conservation and Recovery Act
 
Our refining operations are subject to Resource Conservation and Recovery Act requirements for the treatment, storage and disposal of hazardous wastes. When feasible, Resource Conservation and Recovery Act materials are recycled through our coking operations instead of being disposed of on-site or off-site. The Resource Conservation and Recovery Act establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, the Resource Conservation and Recovery Act also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks containing regulated substances. In addition, new laws are being enacted and regulations are being adopted by various regulatory agencies on a continuing basis, and the costs of compliance with these new rules can only be broadly appraised until their implementation becomes more accurately defined.
 
Fuel Regulations
 
Reformulated Fuels.    EPA regulations also require that reformulated gasoline and low-sulfur diesel intended for all on-road consumers be produced for ozone non-attainment areas, including Chicago, Milwaukee and Houston, which are in our direct market areas. In addition, because St. Louis is a voluntary participant in the EPA’s ozone reduction program, reformulated gasoline and low-sulfur diesel is also required in the St. Louis market area, another of our direct market areas. Expenditures necessary to comply with existing reformulated fuels regulations are primarily discretionary. Our decision whether or not to make these expenditures is driven by

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market conditions and economic factors. The reformulated fuels programs impose restrictions on properties of fuels to be refined and marketed, including those pertaining to gasoline volatility, oxygenate content, detergent addition and sulfur content. The restrictions on fuel properties vary in markets in which we operate, depending on attainment of air quality standards and the time of year. Our Port Arthur refinery can produce up to approximately 60% of its gasoline production in reformulated gasoline. Its maximum reformulated gasoline production may be limited by the clean fuels attainment of our total refining system. Our Port Arthur refinery’s diesel production complies with the current on-road sulfur specification of 500 ppm.
 
Tier 2 Motor Vehicle Emission Standards.    In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 ppm during any calendar year by January 1, 2006. These requirements will be phased in beginning on January 1, 2004. We currently expect to produce gasoline under the new sulfur standards at the Port Arthur refinery prior to January 1, 2004 and, as a result of the corporate pool averaging provisions of the regulations, will not be required to meet the new sulfur standards at the Lima refinery until July 1, 2004, a six month deferral. A further delay in the requirement to meet the new sulfur standards at the Lima refinery through 2005 may be possible through the purchase of sulfur allotments and credits which arise from a refiner producing gasoline with a sulfur content below specified levels prior to the end of 2005, the end of the phase-in period. There is no assurance that sufficient allotments or credits to defer investment at the Lima refinery will be available, or if available, at what cost. We believe, based on current estimates and on a January 1, 2004 compliance date for both the Port Arthur and Lima refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures for the Lima and Port Arthur refineries in the aggregate through 2005 of approximately $255 million. More than 95% of the total investment to meet the Tier 2 gasoline specifications is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003.
 
Low Sulfur Diesel Standards.    In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Regulations for off-road diesel requirements are pending. We estimate capital expenditures in the aggregate through 2006 required to comply with the diesel standards at our Port Arthur and Lima refineries of approximately $245 million. More than 95% of the projected investment is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. Since the Lima refinery does not currently produce diesel fuel to on-road specifications, we are considering an acceleration of the low-sulfur diesel investment at the Lima refinery in order to capture this incremental product value. If the investment is accelerated, production of the low-sulfur fuel is possible by the first quarter of 2005.
 
Maximum Achievable Control Technology.    In addition, on April 11, 2002, the EPA promulgated regulations to implement Phase II of the petroleum refinery Maximum Achievable Control Technology rule under the federal Clean Air Act, referred to as MACT II, which regulates emissions of hazardous air pollutants from certain refinery units. We expect to spend approximately $45 million in the next three years in order to comply with the regulations with the greatest concentration of spending evenly spread out over 2003 and 2004.
 
Permits
 
Refining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with oil refining. Once a permit application is prepared and submitted to the regulatory agency, it is subject to a completeness review, technical review and public notice and comment period before it can be approved. Depending on the size and complexity of the refining operation, some refining permits can take considerable time to prepare and often take six months to sometimes two years to be approved. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. However, certain pending proceedings involving our Port Arthur refinery allege permit violations. See “—Legal Proceedings.”

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Environmental Remediation
 
Under the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and the Resource Conservation and Recovery Act and related state laws, certain persons may be liable for the release or threatened release of hazardous substances including petroleum and its derivatives into the environment. These persons include the current owner or operator of property where the release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who arranged for the disposal of hazardous substances at the property. Liability under CERCLA is strict, retroactive and in most cases involving the government as plaintiff is joint and several, so that any responsible party may be liable for the entire cost of investigating and remediating the release of hazardous substances. As a practical matter, however, liability at most CERCLA and similar sites is shared among all solvent potentially responsible parties. The liability of a party is determined by the cost of investigation and remediation, the portion of the hazardous substance(s) the party contributed to the site, and the number of solvent potentially responsible parties.
 
The release or discharge of crude oil, petroleum products or hazardous materials can occur at refineries and terminals. We have identified a variety of potential environmental issues at our refineries, terminals, and previously owned retail stores. In addition, each refinery has areas on-site that may contain hazardous waste or hazardous substance contamination that may need to be addressed in the future at substantial cost. The terminal sites may also require remediation due to the age of tanks and facilities and as a result of current or past activities at the terminal properties including several significant spills and past on-site waste disposal practices. See “Risk Factors—Risks Related to our Business and our Industry—Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition.”
 
Port Arthur and Lima Refineries
 
The original refineries on the sites of our Port Arthur and Lima refineries began operating in the late 1800s and early 1900s, prior to modern environmental laws and methods of operation. There is contamination at these sites, which we believe will be required to be remediated. Under the terms of the 1995 purchase of our Port Arthur refinery, Chevron Products Company, the former owner, retained liability for all required investigation and remediation relating to pre-purchase contamination discovered by June 1997, except with respect to certain areas on or around which active processing units are located, which are our responsibility. Less than 200 acres of the 4,000-acre refinery site are occupied by active processing units. Extensive due diligence efforts prior to our acquisition and additional investigation after our acquisition documented contamination for which Chevron is responsible. In June 1997, we entered into an agreed order with Chevron and the Texas Commission on Environmental Quality, or TCEQ, that incorporates the contractual division of the remediation responsibilities for certain assets into an agreed order. We have accrued $11.9 million for our portion of the Port Arthur remediation as of September 30, 2002. Under the terms of the purchase of our Lima refinery, BP, the former owner, indemnified us, subject to certain time and dollar limits, for all pre-existing environmental liabilities, except for contamination resulting from releases of hazardous substances in or on sewers, process units, storage tanks and other equipment at the refinery as of the closing date, but only to the extent the presence of these hazardous substances was as a result of normal operations of the refinery and does not constitute a violation of any environmental law. Although we are not primarily responsible for the majority of the currently required remediation of these sites, we may become jointly and severally liable for the cost of investigating and remediating a portion of these sites in the event that Chevron or BP fails to perform the remediation. In such an event, however, we believe we would have a contractual right of recovery from these entities. The cost of any such remediation could be substantial and could have a material adverse effect on our financial position. See “Risk Factors—Risks Related to our Business and our Industry—Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition.”
 
Blue Island Refinery Decommissioning and Closure
 
In January 2001, we ceased refining operations at our Blue Island refinery. The decommissioning, dismantling and tear down of the facility is underway. We are currently in discussions with federal, state and

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local governmental agencies concerning remediation of the site. The governmental agencies have proposed a remediation process patterned after national contingency plan provisions of CERCLA. We have proposed to the agencies a site investigation and remediation that incorporates certain elements of the CERCLA process and the State of Illinois’ site remediation program. Related to the closure of the facility, we accrued $56.4 million for decommissioning, remediation of the site and asbestos abatement. As of September 30, 2002, we had spent $34.0 million. In 2002, environmental risk insurance policies covering the Blue Island refinery site have been procured and bound, with final policies expected to be issued within the first quarter of 2003. This insurance program will allow us to quantify and, within the limits of the policy, cap our cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self-insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a $100,000 deductible per incident. For further discussion of the closure of our Blue Island refinery, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability—Closure of Blue Island Refinery.”
 
Hartford Refinery Closure
 
In September 2002, we ceased refining operations at our Hartford refinery. In the fourth quarter of 2002, we completed the removal of hydrocarbons, catalyst and chemicals from the refinery processing units. We are also currently in preliminary discussions with state governmental agencies concerning environmental remediation of the site. Related to the closure of the refinery, we have accrued $45.9 million for decommissioning, remediation of the site and asbestos abatement. As of September 30, 2002, we spent $5.6 million related primarily to the decommissioning of the facility. The accrual of $45.9 million assumes that a portion of the refinery will be operated on an on-going basis as part of a lease or sale transaction and that remediation will occur in non-operating portions of the refinery. In addition, state governmental agencies are investigating a large petroleum hydrocarbon plume underlying a portion of the Village of Hartford. Responsibility for the plume has not been determined and no enforcement action has been taken. Nonetheless, since the mid-1990s we have operated, on a voluntary basis, a vapor recovery system designed to prevent gasoline odors from rising into the homes in that area of Hartford overlying the plume. The final disposition of the refinery assets and the final outcome of our discussions with the governmental agencies will have a significant bearing on any necessary adjustments to this accrual. For further discussion of the closure of our Hartford Refinery see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001—Refinery Restructuring and Other Charges—Hartford Refinery Closures.”
 
Former Retail Sites
 
In 1999, we sold our former retail marketing business, which we operated from time to time on a total of 1,150 sites. During the normal course of operations of these sites, releases of petroleum products from underground storage tanks have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the underground storage tank regulations under the Resource Conservation and Recovery Act has been delegated to the states that administer their own underground storage tank programs. Our obligation to remediate such contamination varies, depending upon the extent of the releases and the stringency of the laws and regulations of the states in which the releases were made. A portion of these remediation costs may be recoverable from the appropriate state underground storage tank reimbursement fund once the applicable deductible has been satisfied. The 1999 sale included 672 sites, 225 of which had no known preclosure contamination, 365 of which had known pre-closure contamination of varying extent, and 80 of which had been previously remediated. The purchaser of our retail division assumed pre-closure environmental liabilities of up to $50,000 per site at the sites on which there was no known contamination. We are responsible for any liability above that amount per site for pre-closure liabilities, subject to certain time limitations. With respect to the sites on which there was known pre-

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closing contamination, we retained liability for 50% of the first $5 million in remediation costs and 100% of remediation costs over that amount. We retained any remaining pre-closing liability for sites that had been previously remediated.
 
In relation to the 1999 sale, we assigned approximately 170 leases and subleases of retail stores to the purchaser of our retail division, Clark Retail Enterprises, Inc., or CRE. We remain jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent, taxes and environmental cleanup responsibilities for releases of petroleum occurring during the term of the leases. On October 15, 2002, CRE and its parent company, Clark Retail Group, Inc. filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Should CRE reject some or all of these leases, we may become responsible for these obligations. For further discussion of these lease obligations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Flow from Operating Activities.”
 
Of the remaining 478 former retail sites not sold in the 1999 transaction described above, we have sold all but 8 in open market sales and auction sales. We generally retain the remediation obligations for sites sold in open market sales with identified contamination. Of the retail sites sold in auctions, we agreed to retain liability for all of these sites until an appropriate state regulatory agency issues a letter indicating that no further remedial action is necessary. However, these letters are subject to revocation if it is later determined that contamination exists at the properties and we would remain liable for the remediation of any property at which such a letter was received but subsequently revoked. We are currently involved in the active remediation of approximately 140 of the retail sites sold in open market and auction sales. We are actively seeking to sell the remaining 8 properties. During the period from the beginning of 1999 through September 30, 2002, we expended $20 million to satisfy the obligations described above and as of September 30, 2002, had $23.4 million accrued to satisfy those obligations in the future.
 
Former Terminals
 
In December 1999, we sold 15 refined product terminals to a third party, but retained liability for environmental matters at four terminals and, with respect to the remaining eleven terminals, the first $250,000 per year of environmental liabilities for a period of six years up to a maximum of $1.5 million. As of September 30, 2002, we had expended $0.8 million on these obligations and have accrued $2.6 million for these obligations in the future.
 
Certain Environmental Contingencies; Legal and Environmental Reserves
 
As a result of our activities, we and our subsidiaries are party to a number of environmental proceedings. Those that could have a material effect on our operations, or involve potential monetary sanctions of $100,000 or more and to which a governmental authority is a party, are described below under “—Legal Proceedings.” We accrued a total of $99 million, on an undiscounted basis, as of September 30, 2002 for all legal and environmental contingencies and obligations, including those items described under “—Environmental Matters—Environmental Remediation” and “—Legal Proceedings.” This accrual includes approximately $78 million as of September 30, 2002, for site clean-up and environmental matters associated with the Hartford and Blue Island closures and retail sites.
 
Environmental Outlook
 
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. To the extent these expenditures are not ultimately reflected in the prices of the products and services we offer, our operating results will be adversely affected. We believe that substantially all of our competitors are subject to similar environmental laws and

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regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether or not it is engaged in the petrochemical business or the marine transportation of crude oil or refined products.
 
Safety and Health Matters
 
We aim to achieve excellent safety and health performance. We measure our success in this area primarily through the use of injury frequency rates administrated by OSHA. We believe that a superior safety record is inherently tied to achieving our productivity and financial goals. We seek to implement this goal by:
 
 
•
 
training employees in safe work practices;
 
 
•
 
encouraging an atmosphere of open communication;
 
 
•
 
involving employees in establishing safety standards; and
 
 
•
 
recording, reporting and investigating all accidents to avoid reoccurrence.
 
From our acquisition of the Lima refinery in 1998 through the end of 2001 the refinery accumulated over three million employee hours without a lost time injury. From August 1997 through the third quarter of 2001 our Port Arthur refinery accumulated over seven million employee hours without a lost time injury. As of September 30, 2002, our refineries’ record of hours worked without a lost time accident stood at 4.7 million hours. Subsequent to September 30, 2002, we have experienced four OSHA recordable injury incidents.
 
Legal Proceedings
 
The following is a summary 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, and proceedings that involve potential monetary sanctions of $100,000 or more and to which a governmental authority is a party.
 
In addition to the specific matters discussed below, we also have been named in various other suits and claims. We believe 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 flow.
 
Port Arthur: Enforcement.    The TCEQ 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 TCEQ 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 one of its incinerators and that five process wastewater sump vents did not meet applicable air emission control requirements. The TCEQ 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 emissions monitoring program, and one hazardous waste-related violation concerning spills. The 1998 and 1999 notices were combined and referred to the TCEQ’s litigation division. On September 7, 2000 the TCEQ issued a notice of enforcement regarding our alleged failure to maintain emission rates at permitted levels. In May 2001, the TCEQ proposed an order covering some of the 1998 hazardous waste allegations (i.e., the incinerator temperature deficiency and the process wastewater sumps) and all of the 1999 and 2000 allegations, and proposing the payment of a fine of $562,675 and the implementation of a series of technical provisions requiring corrective actions. Negotiations with the TCEQ are ongoing.
 
Blue Island: Federal and State Enforcement.    In September 1998, the federal government filed a complaint, United States v. Clark Refining & Marketing, Inc., alleging that our Blue Island refinery violated

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federal environmental laws relating to air, water and solid waste. The Illinois Attorney General intervened in the case. The State of Illinois and Cook County had brought an action several years earlier, People ex rel. Ryan v. Clark Refining & Marketing, Inc., also alleging violations under environmental laws. In the first quarter of 2002, we reached an agreement to settle both cases. The consent order in the state case was formally approved and entered by the state court on April 8, 2002, and the federal court approved the settlement on June 12, 2002. The consent order in the federal case required payments totaling $6.25 million as civil penalties (plus $0.1 million in interest), which the Company paid on July 12, 2002, and requires permit modifications and limited ongoing monitoring at the now-idled refinery. The consent order in the state case requires an ongoing tank inspection program along with enhanced release reporting obligations and reporting of decommissioning/dismantling plans, payment of a civil penalty of $24,000 and payment of the state’s engineering consultant fees of to a maximum of $75,000. The consent order for the state case was approved by the state court in the second quarter of 2002.
 
Blue Island: Criminal Matters.    In June 2000, PRG pled guilty to one felony count of violating the Clean Water Act and one count of conspiracy to defraud the United States at our Blue Island refinery. These charges arose out of the discovery, during an EPA investigation at the site conducted in 1996, that two former employees had allegedly falsified certain reports regarding wastewater sent to the municipal wastewater treatment facility. As part of the plea agreement, PRG agreed to pay a fine of $2 million and was placed on probation for three years beginning September 22, 2000. We do not anticipate that the probation of PRG will have a significant adverse impact on our business on an ongoing basis. The primary remaining condition of its probation is an obligation not to commit future environmental crimes. If PRG were to commit a crime in the future, it would be subject not only to prosecution for that new violation, but also to a separate charge that it had violated a condition of its probation. Any violation of probation charge would be brought before the same judge who entered the original sentence, and that judge would have the authority to enter a new and potentially more severe sentence for the offense to which PRG pled guilty in June 2000. One of the former employees pled guilty to a misdemeanor charge and was placed on one year probation and another former employee was found guilty on felony charges and sentenced to 21 months in prison related to these events.
 
Blue Island: Class Action Matters.    In October 1994, our Blue Island refinery experienced an accidental release of used catalyst into the air. In October 1995, a class action, Rosolowski v. Clark Refining & Marketing, Inc., et al., was filed against us seeking to recover damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. The complaint underlying this action was later amended to add allegations of subsequent events that allegedly diminished property values. In June 2000, our Blue Island refinery experienced an electrical malfunction that resulted in another accidental release of used catalyst into the air. Following the 2000 catalyst release, two cases were filed purporting to be class actions, Madrigal et al. v. The Premcor Refining Group Inc. and Mason et al. v. The Premcor Refining Group Inc. Both cases seek damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. These cases have been consolidated for the purpose of conducting discovery, which is currently proceeding.
 
Sashabaw Road Retail Location: State Enforcement.    In July 1994, the Michigan Department of Natural Resources brought an action alleging that one of our retail locations caused groundwater contamination, necessitating the installation of a new $600,000 drinking water system. The Michigan Department of Natural Resources sought reimbursement of this cost. Although our site may have contributed to contamination in the area, we maintained that numerous other sources were responsible and that a total reimbursement demand from us would be excessive. Mediation resulted in a $200,000 finding against us. We made an offer of judgment equal to the mediation finding. The Michigan Department of Natural Resources rejected the offer and the matter was tried in November 1999, resulting in a judgment against us of $110,000 plus interest. Since the judgment was over 20% below our previous settlement offer, under applicable state law we are entitled to recover our legal fees. Both the Michigan Department of Natural Resources and we appealed the decision. The appellate court rendered its decision on January 10, 2003 and affirmed the trial court’s ruling in all respects. The parties have until January 31, 2003 to file an appeal with the Michigan Supreme Court. If the Michigan Department of Natural Resources does not file an appeal, it will owe us mediation sanctions which should net us approximately $100,000.

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Port Arthur Natural Resource Damage Assessment.    In 1999, we and Chevron Products Company were notified by 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 our Port Arthur refinery prior to January 1, 2000. We are cooperating with the governmental agencies in this investigation. We have entered into an agreement with Chevron Products Company pursuant to which Chevron Products Company will indemnify us for any future claims in consideration of a payment of $750,000, which we paid in October 2001.
 
Alleged Asbestos Exposure.    We, along with numerous other defendants, have recently been named in approximately 22 individual lawsuits alleging personal injury resulting from exposure to asbestos. A majority of the claims have been filed by employees of third-party independent contractors who purportedly were exposed to asbestos while performing services at our Hartford refinery. We have recently been voluntarily dismissed in 17 of the lawsuits in which we have been named. The remainder are in the early stages of litigation. Substantive discovery has not yet been concluded. It is impossible at this time for us to quantify our exposure from these claims, but, based on currently available information, we do not believe that any liability resulting from the resolution of these matters will have a material adverse effect on our financial condition, results of operations and cash flow.
 
New Source Review Permit Issues
 
New Source Review requirements under the Clean Air Act apply to newly constructed facilities, significant expansions of existing facilities, and significant process modifications and requires new major stationary sources and major modifications at existing major stationary sources to obtain permits, perform air quality analysis and install stringent air pollution control equipment at affected facilities. The EPA has commenced an industry-wide enforcement initiative regarding New Source Review. The current EPA initiative, which includes sending numerous refineries information requests pursuant to Section 114 of the Clean Air Act, appears to target many items that the industry has historically considered routine repair, replacement, maintenance or other activity exempted from the New Source Review requirements.
 
We have responded to an information request from the EPA regarding New Source Review compliance at our Port Arthur and Lima refineries, both of which were purchased within the last seven years. We believe that any costs to respond to New Source Review issues at those refineries prior to our purchase are the responsibility of the prior owners and operators of those facilities. We responded to the request in late 2000, providing information relating to our period of ownership, and are awaiting a response.
 
In July 2001, we settled a lawsuit with the EPA and the State of Illinois that resolved, among other historic compliance issues, a New Source Review issue resulting from repairs made to the FCC unit at our Hartford refinery in 1994. In settlement of the lawsuit, we agreed to install a wet gas scrubber on the FCC unit and low nitrogen oxide burners and agreed to pay a civil penalty of $2 million. As a result of the closure of the Hartford refinery in September 2002, we do not anticipate making these capital expenditures.
 
The federal and state enforcement action at the Blue Island refinery, which was settled in the second quarter of 2002 with the EPA and the State of Illinois, also includes New Source Review issues. In settlement of this litigation, we agreed to pay a civil penalty of $6.25 million, and to modify permits and perform limited monitoring at the now-idled refinery and active terminal. For a description of the litigation at the Blue Island refinery, see “Legal Proceedings—Blue Island: Federal and State Enforcement.”
 

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MANAGEMENT
 
Directors and Executive Officers
 
Our directors, executive officers, their ages as of January 1, 2003, and their positions with us are set forth in the table below.
 
Name
  
Age
   
Position
Thomas D. O’Malley
  
61
   
Chairman of the Board and Chief Executive Officer
Jefferson F. Allen*†
  
57
   
Director
Stephen I. Chazen*
  
56
   
Director
Marshall A. Cohen*‡
  
67
   
Director
David I. Foley‡
  
35
   
Director
Robert L. Friedman†
  
59
   
Director
Richard C. Lappin†
  
58
   
Director
Wilkes McClave III‡
  
55
   
Director
Henry M. Kuchta
  
46
   
President and Chief Operating Officer
William E. Hantke
  
55
   
Executive Vice President and Chief Financial Officer
Dennis R. Eichholz
  
49
   
Senior Vice President—Finance and Controller
Michael D. Gayda
  
48
   
Senior Vice President, General Counsel and Secretary
James R. Voss
  
36
   
Senior Vice President and Chief Administrative Officer
Joseph D. Watson
  
37
   
Senior Vice President—Corporate Development
Gregory R. Bram
  
38
   
Refinery Manager—Lima Refinery
Donovan J. Kuenzli
  
63
   
Refinery Manager—Port Arthur Refinery
*
 
Member of the Audit Committee
†
 
Member of the Compensation Committee
‡
 
Member of the Committee on Governance
 
Thomas D. O’Malley has served as our chairman of the board of directors and chief executive officer since February 2002 and served as our president from February 2002 until January 2003. Mr. O’Malley served as vice chairman of the board of Phillips Petroleum Company from the consummation of that company’s acquisition of Tosco Corporation in September 2001 until January 2002. Mr. O’Malley served as chairman and chief executive officer of Tosco from January 1990 to September 2001 and president of Tosco from May 1993 to May 1997 and from October 1989 to May 1990. He currently serves on the board of directors of Lowe’s Companies, Inc. and PETsMART, Inc.
 
Jefferson F. Allen has served as a director since February 2002. From June 1990 to September 2001, Mr. Allen served in various positions with Tosco Corporation, most recently serving as Tosco’s president and chief financial officer. From November 1988 to June 1990, Mr. Allen served in various positions at Comfed Bancorp, Inc., including chairman and chief executive officer.
 
Stephen I. Chazen has served as a director since our formation in April 1999. Mr. Chazen served as a director of our predecessor from 1995 to April 1999. Mr. Chazen has served as executive vice president—corporate development and chief financial officer of Occidental Petroleum Corporation since February 1999. From May 1994 to February 1999, he served as executive vice president—corporate development of Occidental. From 1982 to April 1994, Mr. Chazen was an investment banker at Merrill Lynch & Co., Inc., where he was a managing director. He currently serves on the governance committees of Equistar Chemicals, LP and OxyVinyls, L.P.
 
Marshall A. Cohen has served as a director since our formation in April 1999. Mr. Cohen served as chairman of the board of directors from April 1999 to February 2002. Mr. Cohen has served as counsel at Cassels Brock & Blackwell LLP since October 1996. From November 1988 to September 1996, he served as president and chief executive officer of The Molson Companies Limited. Mr. Cohen also serves as a member of the board

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of directors of American International Group, Inc., Barrick Gold Corporation, Collins & Aikman Corporation, The Goldfarb Corporation, Golf Town Canada Inc., Haynes International, Inc., Lafarge Corporation, Metaldyne Corporation, SMK Speedy International Inc., and The Toronto-Dominion Bank.
 
David I. Foley has served as a director since our formation in April 1999. Mr. Foley is a principal at The Blackstone Group L.P., which he joined in 1995. Prior to joining Blackstone, Mr. Foley was an employee of AEA Investors Inc. from 1991 to 1993 and a consultant with The Monitor Company from 1989 to 1991. He currently serves on the board of directors of Mega Bloks Inc.
 
Robert L. Friedman has served as a director since July 1999. Mr. Friedman has served as a senior managing director of The Blackstone Group L.P. since February 1999. From 1974 until the time he joined Blackstone, Mr. Friedman was a partner with Simpson Thacher & Bartlett, a New York law firm. He currently also serves on the board of directors of American Axle & Manufacturing, Inc., Axis Capital Holdings Limited, Corp Group, Crowley Data LLC, Houghton Mifflin Holdings, Inc. and Northwest Airlines, Inc.
 
Richard C. Lappin has served as a director since October 1999. Mr. Lappin has served as a senior managing director of The Blackstone Group L.P. since February 1999. From 1989 to 1998, he served as president of Farley Industries, which included West Point-Pepperell, Inc., Acme Boot Company, Inc., Tool and Engineering, Inc., Magnus Metals, Inc. and Fruit of the Loom, Inc. Mr. Lappin currently also serves on the board of directors of American Axle & Manufacturing, Inc. and Haynes International, Inc. Fruit of the Loom, Inc. filed a petition seeking relief under Chapter 11 of the federal bankruptcy laws in December 1999.
 
Wilkes McClave III has served as a director since February 2002. From September 1982 to September 2001, Mr. McClave served in various positions with Tosco Corporation, most recently serving as Tosco’s executive vice president and general counsel.
 
Henry M. Kuchta has served as our president since January 2003 and chief operating officer since April 2002. From April 2002 to December 2002, Mr. Kuchta served as executive vice president—refining. Prior to this position he served as business development manager for Phillips 66 Company, since Phillips’ acquisition of Tosco Corporation in September 2001. Prior to joining Phillips, Mr. Kuchta served in various corporate, commercial and refining positions at Tosco from 1993 to 2001. Prior to joining Tosco, Mr. Kuchta spent 12 years at Exxon Corporation in various refining engineering and financial positions, including assignments overseas.
 
William E. Hantke has served as our executive vice president and chief financial officer since February 2002. From 1990 to January 2002, Mr. Hantke served in various positions with Tosco Corporation, most recently serving as Tosco’s vice president of corporate development. He has held various finance and accounting positions in the oil industry and other commodity industries since 1975.
 
Dennis R. Eichholz has served as our senior vice president—finance and controller since February 2001. Since joining us in 1988, Mr. Eichholz has held various financial positions, including vice president—treasurer and director of tax. Prior to joining us, Mr. Eichholz held various corporate finance positions and began his career with Arthur Andersen & Co. in 1975.
 
Michael D. Gayda has served as our senior vice president, general counsel and secretary since October 2002. Prior to this position he served as general counsel—refining for Phillips Petroleum Company, since Phillips’ acquisition of Tosco Corporation in September 2001. Prior to joining Phillips, from 1990 to 2001, Mr. Gayda served in various positions at Tosco Corporation, most recently serving as vice president and associate general counsel at Tosco Refining Company, a division of Tosco Corporation, from 1996 to 2001. Prior to joining Tosco, Mr. Gayda spent 11 years at Pacific Enterprises, predecessor of Sempra Energy, in various positions, including special counsel.

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James R. Voss has served as our senior vice president and chief administrative officer since September 2002. From December 2000 to September 2002, Mr. Voss served as our vice president and director of human resources. From June 1999 to December 2000, Mr. Voss served as the director of human resources for Swank Audio Visuals, Inc., a nationally recognized audio visual service provider, and from October 1996 to June 1999, he served as a human resource manager of Foodmaker, Inc., a $1 billion food distribution and restaurant company. Prior to joining Foodmaker, Inc., he spent 10 years in human resources management, operations and labor relations with United Parcel Service (UPS).
 
Joseph D. Watson has served as our senior vice president—corporate development since September 2002. Mr. Watson served as our senior vice president and chief administrative officer from March 2002 to September 2002. He served as president of The e-Place.com, Ltd., a wholly owned subsidiary of Tosco Corporation, and a vice president of Tosco Shared Services from November 2000 to February 2002. He previously held various financial positions with Tosco from 1993 to 2000. From 1991 to 1993, he served as vice president of Argus Investments, Inc., a private investment company.
 
Gregory R. Bram has served as the refinery manager of our Lima refinery since October 1999. From 1996 to September 1999, Mr. Bram held several senior positions in our corporate office, including manager of planning and development and optimization manager. Prior to joining us, Mr. Bram held various engineering and operations positions with Amoco. Mr. Bram has more than 14 years of experience within the refining industry.
 
Donovan J. Kuenzli has served as the refinery manager of our Port Arthur refinery since October 1998. Prior to joining us, Mr. Kuenzli held various positions with BP, including refinery manager of the Lima refinery (then owned by BP), plant manager of a Texas chemicals facility, operations manager at BP’s Alliance refinery and a corporate position in BP’s London corporate office. Mr. Kuenzli has more than 40 years of experience within the refining and petrochemical industry.
 
Our board of directors is currently composed of the eight directors listed above, each of whom will serve until the next annual meeting of stockholders or until a successor is duly elected.
 
Committees of our Board of Directors
 
Our board of directors has formed three standing committees, an audit committee, a compensation committee and a committee on corporate governance.
 
Audit Committee.    The principal duties of our audit committee are as follows:
 
 
•
 
to assist the board of directors in fulfilling its oversight responsibilities by reviewing: the financial reports and other financial information we provide to any governmental body or the public; our systems of internal controls, established by management and the board of directors, regarding finance, accounting, legal compliance and ethics; and our auditing, accounting and financial reporting processes generally. Consistent with this function, the audit committee should encourage continuous improvement of, and should foster adherence to, our policies, procedures and practices at all levels;
 
 
•
 
to serve as an independent and objective body to monitor our financial reporting process and internal control system;
 
 
•
 
to review and appraise the audit efforts of our independent accountants and internal auditing department; and
 
 
•
 
to provide an open avenue of communication among the independent accountants, financial and senior management, the internal auditing department, and the board of directors.
 
The members of the audit committee are Messrs. Allen (Chairman), Chazen and Cohen.

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Compensation Committee.    The principal duties of our compensation committee are as follows:
 
 
•
 
to ensure our senior executives are compensated effectively in a manner consistent with our stated compensation strategy, internal equity considerations, competitive practice, and the requirements of the appropriate regulatory bodies; and
 
 
•
 
to communicate to shareholders our compensation policies and the reasoning behind such policies, as required by the Securities and Exchange Commission.
 
The members of the compensation committee are Messrs. Lappin (Chairman), Allen and Friedman.
 
Committee on Corporate Governance.    The principal duties of our committee on corporate governance are as follows:
 
 
•
 
to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies which occur between stockholder meetings; and
 
 
•
 
to make recommendations to the board of directors regarding corporate governance matters and practices.
 
The members of the committee on corporate governance are Messrs. McClave (Chairman), Cohen and Foley.
 
Director Compensation
 
Our directors did not receive any compensation for their services as directors during 2001. In 1999, for his past and future services as a director, Mr. Cohen received a one-time grant of 65,656 shares of our common stock. He also received a one-time grant of an option to purchase 50,505 shares of our common stock at an exercise price of $9.90 per share, which was the fair market value on the date of grant. We also provide Mr. Cohen certain health care insurance coverage. All our directors are reimbursed for their out-of-pocket expenses. The directors of our company and our subsidiaries did not receive any compensation for their services as directors during 2001. See “—Directors and Executive Officers” for additional information regarding our directors.
 
In February 2002, in consideration for Mr. Allen’s future services as a director, we granted him options (with a three-year vesting schedule) to purchase 100,000 shares of our common stock at an exercise price equal to $10 per share. In connection with our IPO, Mr. Allen purchased 50,000 shares of our common stock at a price of $22.50 per share (the public offering price per share paid by the investors in the IPO, less the underwriting commission per share). We also granted Mr. Allen matching options (with a three-year vesting schedule) to purchase 50,000 shares of our common stock, at an exercise price of $22.50 per share.
 
In February 2002, in consideration for Mr. McClave’s future services as a director, we granted him options (with a three-year vesting schedule) to purchase 100,000 shares of our common stock at an exercise price equal to $10 per share. In connection with the IPO, Mr. McClave purchased 50,000 shares of our common stock at a price of $22.50 per share (the public offering price per share paid by the investors in the IPO, less the underwriting commission per share). We also granted Mr. McClave matching options (with a three-year vesting schedule) to purchase 50,000 shares of our common stock, at an exercise price of $22.50 per share.
 
We adopted a compensation program for our non-employee directors consisting of an annual retainer of $50,000, board of directors and committee meeting fees of $1,000 per meeting, and an annual grant of options (with a five-year vesting schedule) to acquire 2,500 shares of our common stock at the then fair market value. In addition, non-employee board and committee chairpersons receive an additional retainer of $10,000 per year. Director compensation for Messrs. Foley, Friedman and Lappin is paid directly to Blackstone. Director compensation for Mr. Chazen is paid directly to Occidental.

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Compensation Committee Interlocks and Insider Participation
 
The following individuals served as members of our compensation committee during 2001: Messrs. Lappin (chairman), Cohen and Friedman. None of the compensation committee members is, or at any time has been, officers or employees of us or any of its subsidiaries. Messrs. Friedman and Lappin are members of Blackstone. See “Principal Stockholders” and “Related Party Transactions” for additional information regarding the relationship between us and Blackstone.
 
Executive Compensation
 
The following table sets forth the annual compensation for our former chief executive officer, former chief financial officer, former general counsel and our two other most highly compensated executive officers for their services to our company during the fiscal years 2001, 2000 and 1999. For information about the future compensation for each of Messrs. O’Malley, Kuchta, Hantke, Gayda, Voss and Watson, see “—Executive Officer Benefits and Agreements—Employment Agreement with Thomas D. O’Malley,” “—Employment Agreement with Henry M. Kuchta,” “—Employment Agreement with William E. Hantke,” “—Employment Agreement with Michael D. Gayda,” “—Employment Agreement with James R. Voss” and “—Employment Agreement with Joseph D. Watson.”
 
Summary Compensation Table
 
    
Annual Compensation
   
All Other Compensation ($) (5)
Name and Principal Position
   
Fiscal Year
   
Salary ($)
   
Bonus ($)
   
Other ($) (4)
   
William C. Rusnack (1)
Former President, Chief Executive Officer and Chief Operating Officer
   
2001
2000
1999
   
497,693
477,694
454,808
   
746,800
610,000
370,000
   
18,679
—  
1,535
   
10,200
10,200
9,600
Ezra C. Hunt (2)
Former Executive Vice President and Chief Financial Officer
   
2001
   
317,309
   
378,000
   
45,980
   
344,739
Jeffry N. Quinn (3)
Former Executive Vice President and General Counsel
   
2001
2000
   
297,981
236,867
   
344,500
232,000
   
13,901
—  
   
10,200
130,215
Donovan J. Kuenzli
Refinery Manager, Port Arthur Refinery
   
2001
2000
1999
   
223,732
212,846
203,538
   
202,600
200,000
80,000
   
9,573
400
45,392
   
10,200
10,200
9,600
Dennis R. Eichholz
Senior Vice President—Finance and Controller
   
2001
2000
1999
   
167,693
148,443
136,038
   
151,500
100,000
62,502
   
31,125
7,875
7,875
   
9,928
9,033
8,635
(1)
 
Mr. Rusnack resigned in January 2002. See “—Executive Officer Benefits and Agreements—Termination Agreement with William C. Rusnack” for a discussion of the terms of Mr. Rusnack’s termination agreement with us.
(2)
 
Mr. Hunt resigned in January 2002. Mr. Hunt joined us in February 2001 as our executive vice president and chief financial officer. We therefore do not have compensation to disclose for Mr. Hunt for years prior to 2001. See “—Executive Officer Benefits and Agreements—Termination Agreement with Ezra C. Hunt” for a discussion of the terms of Mr. Hunt’s termination agreement with us.
(3)
 
Mr. Quinn resigned in November 2002. See “—Executive Officer Benefits and Agreements—Separation Agreement with Jeffry N. Quinn” for a discussion of the terms of Mr. Quinn’s separation agreement with us.

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(4)
 
Represents (i) amounts for financial planning services for Messrs. Rusnack, Quinn and Eichholz, amounts for unused vacation for Messrs. Kuenzli and Eichholz, an amount for a safety award for Mr. Kuenzli and relocation expenses for Mr. Hunt for 2001, (ii) an amount for a safety award for Mr. Kuenzli and an amount for unused vacation for Mr. Eichholz for 2000 and (iii) amounts for relocation expenses for Messrs. Rusnack and Kuenzli and amounts for unused vacation for Messrs. Kuenzli and Eichholz for 1999.
(5)
 
Represents (i) amounts accrued for the account of such individuals under the Premcor Retirement Savings Plan for 2001, as well as a starting bonus of $336,950 paid to Mr. Hunt upon his joining us in February 2001, (ii) amounts accrued for the account of such individuals under the Premcor Retirement Savings Plan for 2000, as well as a starting bonus of $125,000 paid to Mr. Quinn upon his joining us in March 2000 and (iii) amounts accrued for the account of such individuals under the Premcor Retirement Savings Plan and the Supplemental Savings Plan for 1999.
 
Stock Option Grants
 
The following table sets forth information concerning grants of each of time vesting and performance vesting stock options to purchase our common stock made during the year ended December 31, 2001, to each of the named executive officers.
 
Option Grants in Last Fiscal Year
 
    
Individual Grants(1)
     
    
Number of Securities Underlying Options Granted(#)
     
% of Total Options Granted To Employees In Fiscal Year
     
Exercise or
Base Price ($/Share)
   
Potential Realizable Value at
Assumed Annual Rates of Stock
Price Appreciation For Option Term
               
Expiration Date
   
5%
   
10%
Ezra C. Hunt (2)
   
120,000
     
60
%
   
9.90
   
November 9, 2002
   
$
13,308
   
$
26,831
Dennis R. Eichholz (3)
   
30,000
     
15
 
   
9.90
   
September 30, 2008
   
 
13,297
   
 
157,428
Donovan J. Kuenzli (4)
   
20,000
     
10
 
   
9.90
   
September 30, 2008
   
 
8,865
   
 
104,952
(1)
 
All options are options to purchase shares of our common stock. All options were granted pursuant to Premcor Inc.’s 1999 Stock Incentive Plan. The options are exercisable at a price of $9.90 per share, which was the fair market value at the date of grant.
(2)
 
On February 26, 2001, we granted Mr. Hunt 60,000 time vesting options and 60,000 performance vesting options. Of the 120,000 options granted, 20,000 time vesting options vested upon Mr. Hunt’s termination of employment on January 31, 2002 and the remainder were forfeited. Mr. Hunt has exercised the 20,000 options.
(3)
 
All 30,000 options granted to Mr. Eichholz are performance vesting options. The options vest seven years from the date of grant, with vesting being accelerated upon the achievement of certain targeted stock prices or a change in control transaction. Of the 30,000 options, 15,000 are currently vested. The date of  Mr. Eichholz’s grant was March 2, 2001.
(4)
 
All 20,000 options granted to Mr. Kuenzli are performance vesting options. The options vest seven years from the date of grant, with vesting being accelerated upon the achievement of certain targeted stock prices or a change in control transaction. Of the 20,000 options, 10,000 are currently vested. The date of  Mr. Kuenzli’s grant was March 2, 2001.

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Exercises of Stock Options
 
The following table shows aggregate exercises of options to purchase our common stock and the number and value of securities underlying unexercised stock options held by the named executive officers as of December 31, 2001.
 
Name
     
Shares Acquired on Exercise (#)
     
Value Realized ($)
   
Number of Securities
Underlying Unexercised
Options At Fiscal Year-End (#)
     
Value of Unexercised In-
The-Money Options At
Fiscal Year-End ($)
            
Exercisable
     
Unexercisable
     
Exercisable
     
Unexercisable
William C. Rusnack (1)
     
0
     
0
   
300,000
     
300,000
     
0
     
0
Ezra C. Hunt (1)
     
0
     
0
   
0
     
120,000
     
0
     
0
Jeffry N. Quinn (1)
     
0
     
0
   
15,000
     
105,000
     
0
     
0
Donovan J. Kuenzli
     
0
     
0
   
0
     
80,000
     
0
     
0
Dennis R. Eichholz
     
0
     
0
   
20,000
     
40,000
     
0
     
0
(1)
 
For a discussion of what impact, if any, Mr. Rusnack’s, Mr. Hunt’s and Mr. Quinn’s terminations of employment had on their outstanding options, see “—Executive Officer Benefits and Agreements—Termination Agreement with William C. Rusnack,” and “—Termination Agreement with Ezra C. Hunt” and “—Separation Agreement with Jeffry N. Quinn.”
 
Compensation Principles
 
Our compensation program for executive officers is designed to attract, retain and motivate these officers to enhance long-term stockholder value. The program consists of the following three key elements:
 
 
•
 
a base salary;
 
 
•
 
a performance-based annual bonus; and
 
 
•
 
long-term equity incentive programs.
 
Our compensation philosophy:
 
 
•
 
targets base pay at median levels of an appropriate comparator group with total compensation in line with relative performance;
 
 
•
 
emphasizes variable, incentive-oriented pay that rewards executives for achievement of predetermined operating and financial objectives;
 
 
•
 
places increased emphasis on variable pay and long-term incentives at higher levels in the organization;
 
 
•
 
balances the focus on short-term and long-term performance; and
 
 
•
 
utilizes plans which are fair and understandable so that the plans drive performance and do not simply follow performance.
 
Short-Term Performance
 
Annual Base Salary
 
Annual salary is designed to compensate our executive officers for enhancing earnings per share and the creation of shareholder value. Salaries for the executive officers and certain other officers who report directly to the chief executive officer are established on an annual basis by the compensation committee, typically at the first committee meeting of the year. Individual and/or corporate performance is considered in determining salary amounts.

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Annual Incentive Bonus for Calendar Year 2001
 
We have adopted the Premcor Executive Recognition Plan which provides key salaried employees, or participants, the opportunity to receive annual bonuses based upon the achievement of operating, financial and/or individual performance goals. In calendar year 2001, a total of 149 salaried employees participated in the Executive Recognition Plan, including the named executive officers. Under the Executive Recognition Plan each participant has a target bonus, which is expressed as a fixed percentage of base pay. The 2001 target bonus opportunity was 150% of annual base pay for Mr. Rusnack, 100% of annual base pay for Mr. Hunt and Mr. Quinn and 75% of annual base pay for the other named executive officers.
 
For 2001, target bonus opportunities were divided into two components, an objective performance component and a personal performance component. Objective performance measures constituted 70% of the bonus opportunity of Messrs. Rusnack, Hunt and Quinn and 60% for the other named executive officers. The remaining portion of their bonus opportunities was based upon personal performance.
 
In determining annual bonuses for 2001, the objective performance component was measured by a weighting of the following three performance measures: cash flow; costs, which for such purpose means operating expenses, excluding energy costs, plus general and administrative expenses; and a measure of gross margin which utilizes a constant price set and constant energy cost, referred to as the Premcor Value Index. Refinery participants, including corporate direct reports located at the refineries, had a significant portion of their objective award tied to the performance of the refinery. Objective awards of the corporate participants were tied to the performance of our company.
 
Annual Bonuses for Calendar Year 2002
 
In February 2002, the Premcor Executive Recognition Plan was renamed the Premcor Incentive Compensation Plan and was expanded to include all of our salaried employees, except for Messrs. O’Malley, Kuchta, Hantke, Gayda, Voss and Watson whose bonus terms are provided in their employment agreements with us. For 2002, bonus awards for participants will be earned solely on the basis of our achievement of earnings per share results. The earnings per share measure has a threshold, target and maximum performance level and a corresponding payout level. For participants in the plan, the threshold performance level is earnings per share of $2.00, the target performance level is earnings per share of $3.50 and the maximum performance level is earnings per share of $5.00. The maximum bonus opportunity for participants is equal to 200% of annual base pay. For information regarding bonus award opportunities for each of Messrs. O’Malley, Kuchta, Hantke, Gayda, Voss and Watson, see “—Executive Officer Benefits and Agreements—Employment Agreement with Thomas D. O’Malley,” “—Employment Agreement with Henry M. Kuchta,” “—Employment Agreement with William E. Hantke,” “—Employment Agreement with Michael D. Gayda,” “—Employment Agreement with James R. Voss” and “—Employment Agreement with Joseph D. Watson.”
 
Long-Term Performance
 
2002 Special Stock Incentive Plan
 
In connection with the employment of Mr. Thomas D. O’Malley, we established a 2002 Special Stock Incentive Plan for Mr. O’Malley (the “Special Plan”).
 
Eligibility.    Mr. O’Malley is eligible for the grant of options to purchase shares of our common stock under the Special Plan.
 
Shares Reserved for Awards and Shares Outstanding.    The number of shares of our common stock that may be issued or delivered under the Special Plan for stock options granted during the term of the Special Plan is 3,400,000 shares. As of December 31, 2002, we granted Mr. O’Malley 2,200,000 stock options at an exercise

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price of $10 per share and, in connection with the IPO, 750,000 stock options at an exercise price of $22.50 per share (the public offering price per share paid by the investors in the IPO, less the underwriting commission per share). In addition, pursuant to the terms of Mr. O’Malley’s employment agreement we have committed to grant him 150,000 options a year during 2003 through 2005 at an exercise price equal to the fair market value on the date of the grant. See “—Executive Officer Benefits and Agreements—Employment Agreement with Thomas D. O’Malley.”
 
Administration.    Our board of directors administers the Special Plan, and has full and exclusive power to grant waivers of stock option restrictions and to adopt such rules, regulations and guidelines for carrying out the Special Plan and such modifications, amendments, procedures, and the like as are necessary or proper to comply with provisions of the laws and regulations of the jurisdictions in which we operate in order to assure the viability of stock options granted under the Special Plan and to enable Mr. O’Malley, regardless of where employed, to receive advantages and benefits under the Special Plan and such laws and regulations. In general, our board of directors may delegate their authority to administer the Special Plan to the compensation committee of our board of directors (if any) or such other committee as may be designated by our board of directors to administer the Special Plan; provided, however, that the committee shall satisfy the qualifications set forth in the Special Plan.
 
Stock Options.    Our board of directors determines the stock options to be awarded to Mr. O’Malley and shall set forth in the related stock option award certificate the terms, conditions, requirements and limitations applicable to such stock option. No stock option shall be exercisable more than ten years after the date of its grant. Nothing contained in the Special Plan or any stock option award certificate shall confer, and no grant of a stock option shall be construed as conferring, upon Mr. O’Malley any right to continue in our employ or to interfere in any way with our right to terminate Mr. O’Malley’s employment at any time or increase or decrease Mr. O’Malley’s compensation from the rate in existence at the time of granting of a stock option. No stock option shall confer on Mr. O’Malley any of the rights of a shareholder of us unless and until shares of our common stock are duly issued or transferred to Mr. O’Malley in accordance with the terms of the stock option.
 
The price at which shares of our common stock may be purchased under a stock option is determined by our board of directors and evidenced in the stock option award certificate, and shall be paid by Mr. O’Malley in full at the time of the exercise in cash or, to the extent permitted by the committee, in shares of our common stock having a fair market value equal to the aggregate exercise price under the stock option for the shares of our common stock being purchased, so long as such shares of our common stock have been held by Mr. O’Malley for no less than six months (or such other period as established from time to time by the committee or GAAP).
 
Termination of Employment.    If Mr. O’Malley’s employment is terminated, all stock options and stock option shares held by him shall be governed by, and shall be subject to, the terms and conditions set forth in this plan, in any stock option award certificate and in his employment agreement.
 
Nonassignability.    Unless otherwise provided by our board of directors, no stock option shall be assignable or transferable, or payable to or exercisable by anyone other than Mr. O’Malley (other than upon death or disability).
 
Adjustment and Change in Control.    In the event of any change in the outstanding shares of our common stock by reason of any stock dividend or split, reorganization, recapitalization, merger, consolidation, spin-off, combination or exchange of shares of our common stock or other corporate exchange, or any distribution to shareholders of our common stock other than regular cash dividends, our board of directors will make such equitable substitutions or adjustments, if any, as are necessary as to the number or kind of shares of our common stock or other securities issued or reserved for issuance pursuant to the Special Plan or pursuant to outstanding stock options, the stock option price and/or any other affected terms of such stock options.

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In the event of a change in control (as defined in the Special Plan), our board of directors will take such actions, if any, as it in good faith deems equitable with respect to any stock option (including, without limitation, the acceleration of the stock option, the payment of cash equal to the excess of the per share consideration received by the holders of shares of our common stock in the change in control, in exchange for the cancellation of the stock option and/or the requiring of the issuance of substitute stock options that will substantially preserve the value, rights and benefits of any affected stock options previously granted under the Special Plan) effective upon the date of the consummation of the change in control.
 
Amendment.    Our board of directors may amend the Special Plan without the consent of shareholders or Mr. O’Malley to the extent necessary to comply with any federal or state law or regulation or the rules of any stock exchange on which the shares of our common stock may be listed. Our board of directors may waive any conditions or rights under, or amend, alter, accelerate, suspend, discontinue or terminate, any stock option theretofore granted and any stock option award certificate relating thereto; provided, however, that, without the consent of Mr. O’Malley, no such amendment, alteration, suspension, discontinuation or termination of any stock option may impair his rights under such stock option.
 
Legal Requirements.    The Special Plan, the granting and exercising of stock options thereunder and the other obligations under the Special Plan shall be subject to all applicable federal and state laws, rules and regulations. It is our intention that any stock option granted to a person who is subject to Section 16 of the 1934 Act qualifies for exemption under Rule 16b-3.
 
2002 Equity Incentive Plan
 
Our board of directors has adopted the Premcor 2002 Equity Incentive Plan which is designed to permit us to grant to our key employees, directors and consultants incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, performance-based awards and other awards based on common stock, in each case in respect of our common stock.
 
Administration.    Our compensation committee administers the 2002 Equity Incentive Plan. The committee determines who will receive awards under the 2002 Equity Incentive Plan, as well as the form of the awards, the number of shares underlying the awards, and the terms and conditions of the awards consistent with the terms of the plan. The committee may delegate its authority under the 2002 Equity Incentive Plan in whole or in part as it determines, including to a subcommittee consisting solely of at least two outside directors within the meaning of Rule 16b-3 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
 
Shares Reserved for Awards, Limits on Awards and Shares Outstanding.    The total number of shares of our common stock initially available for issuance or delivery under the 2002 Equity Incentive Plan is 1,500,000 shares. As of December 31, 2002, there were 998,500 stock options outstanding under the plan. We have committed to granting options to purchase an aggregate of 365,000 shares of our common stock to certain officers during the period 2003 through 2005 at an exercise price equal to the fair market value of a share of our common stock on the date of the grant. All options granted as of December 31, 2002 and those options to be granted during 2003 through 2005 will vest in equal installments on each of the first three anniversaries of the date of grant.
 
The number of shares of our common stock issued or reserved pursuant to the 2002 Equity Incentive Plan and the number of shares issuable pursuant to outstanding awards are subject, at the compensation committee’s discretion, to adjustment as a result of stock splits, stock dividends and other dilutive changes in our common stock. Common stock covered by awards that terminate, lapse, or are cancelled will again be available for the grant of awards under the 2002 Equity Incentive Plan.
 
Stock Options.    The 2002 Equity Incentive Plan permits the committee to grant participants incentive stock options, which qualify for special tax treatment in the United States, as well as nonqualified stock options. The

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committee establishes the duration of each option at the time it is granted, with a maximum ten-year duration for incentive stock options. The committee may establish vesting and performance requirements that must be met prior to the exercise of options.
 
Stock option grants may include provisions that permit the option holder to exercise all or part of the holder’s vested options, or to satisfy withholding tax liabilities, by tendering shares of common stock already owned by the option holder for at least six months (or another period consistent with the applicable accounting rules) with a fair market value equal to the exercise price. Stock option grants may also include provisions that permit the option holder to exercise all or part of the holder’s vested options through an exercise procedure, which requires the delivery of irrevocable instructions to a broker to sell the shares obtained upon exercise of the option and deliver promptly to us the proceeds of the sale equal to the aggregate exercise price of the common stock being purchased.
 
Stock Appreciation Rights.    The committee may also grant stock appreciation rights, either alone or in tandem with underlying stock options, as well as limited stock appreciation rights, which are exercisable upon the occurrence of certain contingent events. Stock appreciation rights entitle the holder upon exercise to receive an amount in any combination of cash or shares of our common stock (as determined by the committee) equal in value to the excess of the fair market value of the shares covered by the right over the grant price.
 
Other Stock-Based Awards.    The 2002 Equity Incentive Plan permits the committee to grant awards that are valued by reference to, or otherwise based on, the fair market value of our common stock. These awards will be in such form and subject to such conditions as the committee may determine, including the satisfaction of performance goals, the completion of periods of service or the occurrence of certain events.
 
Change-in-Control Provisions.    The committee may, in the event of a change in control, provide that any outstanding awards that are unexercisable or otherwise unvested will become fully vested and immediately exercisable. In addition, the committee may, in its sole discretion, provide for the termination of an award upon the consummation of the change in control and the payment of a cash amount in exchange for the cancellation of an award, and/or the issuance of substitute awards that will substantially preserve the otherwise applicable terms of any affected award.
 
Amendment and Termination.    Our board of directors may amend or terminate the 2002 Equity Incentive Plan at any time, provided that no amendment or termination will be made that increases the number of shares available for awards under the 2002 Equity Incentive Plan or diminishes the rights of the holder of any award. Our board of directors may amend the plan in such manner as it deems necessary to permit awards to meet the requirements of applicable laws.
 
1999 Stock Incentive Plan
 
Our board of directors has adopted the Premcor 1999 Stock Incentive Plan, or the 1999 Incentive Plan, which is designed to attract and retain executive officers and other selected employees whose skills and talents are important to our company. Under the 1999 Incentive Plan, our executive officers and other employees are eligible to receive awards of options to purchase shares of our common stock.
 
The compensation committee of our board of directors administers the 1999 Incentive Plan. Subject to the provisions of the 1999 Incentive Plan, the committee is authorized to determine who may participate in the plan, the number and types of awards made to each participant, and the terms, conditions, requirements, and limitations applicable to each award. Awards may be granted singularly or in combination. Awards may also be made in combination or in tandem with, in replacement of, or as alternatives to, grants or rights under any other employee plan of our company, including the plan of any acquired entity. Subject to certain limitations, our board of directors is authorized to amend, modify or terminate the 1999 Incentive Plan.

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Options granted under the 1999 Incentive Plan to executive officers and other employees are either time vesting or performance vesting options. The time vesting options vest in one of the two following manners: (i) 50% at the date of grant and 25% on each January 1st thereafter, or (ii)  1/3 on the first, second, and third anniversaries of the date of grant. The performance vesting options fully vest on the seventh anniversary of the date of grant, provided, however, that following our IPO in May 2002 or upon a change in control of our company, the vesting is accelerated based on the achievement of certain per share prices of the common stock. The accelerated vesting schedule is as follows:
 
 
Average closing price
per share of capital stock for any
180 consecutive days; or change in control price
     
% of shares with respect to which option is exercisable
  
Below $12.00
     
0
%
$12.00-$14.99
     
10
 
$15.00-$17.99
     
20
 
$18.00-$19.99
     
30
 
$20.00-$24.99
     
50
 
$25.00-$29.99
     
75
 
Above $29.99
     
100
 
 
As of December 31, 2002, 50% of the performance vesting options granted under the plan had vested.
 
In the event of a change in control of our company, our board of directors may, with respect to any option award, take actions that cause: the acceleration of the award; the payment of a cash amount in exchange for the cancellation of the award; and/or the issuance of substitute awards that will substantially preserve the value, rights and benefits of any affected awards.
 
Options in an aggregate amount of 2,215,250 shares of our common stock are reserved for issuance under the 1999 Incentive Plan. The current aggregate amount of stock underlying option awards is, at the board of directors’ discretion, subject to a stock dividend or split, reorganization, recapitalization, merger, consolidation, spin-off, combination or exchange of stock. As of December 31, 2002, 527,975 stock options were outstanding at an exercise price of $9.90 per share and 62,500 stock options were outstanding at an exercise price of $15 per share. All options were granted at an exercise price equal to the fair market value of our common stock as of the date of grant. All options expire no more than ten years after the date of grant.
 
In addition, in the event of any termination of employment of a participant, we have the right, for a certain period of time and under certain conditions following such termination of employment, to purchase all of the participant’s exercisable stock options at a price equal to the net stock option value, which is the fair market value of the underlying shares less the exercise price, and any shares of our common stock acquired by the participant pursuant to the participant’s exercise of any stock option, generally at a price equal to the fair market value of our common stock, although upon a termination for cause by us, all of the participant’s options terminate immediately without payment and we can purchase, for a period of 30 days following such termination, all of the participant’s shares of common stock at a price per share equal to the lower of its fair market value or the exercise price.
 
Phantom Performance Shares
 
In 2000, the compensation committee of our board of directors adopted a Long Term Incentive Plan which was designed to provide certain key management employees of our company the opportunity to receive grants of performance units or awards, the value of which is measured based on the performance of our common stock. This plan was designed to reward participants for achieving pre-defined operating and financial performance goals over a three-year performance cycle. The first three-year performance cycle under the plan began on January 1, 2001. For such performance period, 87,300 performance units are currently outstanding.

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Messrs. Eichholz and Kuenzli were the only named executive officers to participate in the plan for that performance cycle. Our board of directors terminated the Long Term Incentive Plan in February 2002. As a result there will be no future grants under the plan.
 
Executive Officer Agreements
 
Employment Agreement with Thomas D. O’Malley
 
We entered into an employment agreement with Thomas D. O’Malley, dated January 30, 2002, and which was subsequently amended, pursuant to which Mr. O’Malley agreed to serve as our full-time chairman of the board of directors and as our chief executive officer and president. The agreement has a term of three years but is subject to automatic one-year extensions thereafter, unless either party gives the other 60 days prior written notice of its intention not to extend the term. The agreement provides for an annual base salary (with increases, if any, to be determined by our board of directors) of $500,000 (which Mr. O’Malley has voluntarily agreed to reduce to $300,000 until he reinstates the previous amount by providing 30 days notice to us). In addition, the employment agreement provides that Mr. O’Malley will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and in accordance with GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, is at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. O’Malley shall equal his unreduced base salary (his “base bonus”). Mr. O’Malley shall have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of six times his unreduced base salary. Pursuant to the employment agreement, Mr. O’Malley purchased 750,000 shares of our common stock issued in the IPO at a price of $22.50 per share (the public offering price per share paid by the investors in the IPO, less the underwriting commission per share). The employment agreement also provides that Mr. O’Malley will be granted (i) upon execution of the agreement, an initial option to purchase 2,200,000 shares of our common stock at an exercise price equal to $10 per share under the Special Plan; (ii) matching options to purchase the same number of shares of our common stock he purchases (as described above) at an exercise price equal to the purchase price per share paid for the shares he purchases (as described above) under the Special Plan; and (iii) annual options to purchase 150,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant, in each of the years 2003, 2004 and 2005, all under the Special Plan. Mr. O’Malley has agreed to customary transfer limitations, tag-along rights, drag-along rights and rights of first refusal with respect to any shares he acquires pursuant to the prior sentence (including any shares acquired by means of a stock split, stock dividend or distribution affecting the shares acquired pursuant to the prior sentence). Pursuant to the employment agreement, if Mr. O’Malley’s employment is terminated by us without cause, by Mr. O’Malley for good reason or upon our election not to extend the employment term, Mr. O’Malley will be entitled to receive (i) any accrued but unpaid base salary and annual bonus, (ii) subject to Mr. O’Malley’s continued compliance with non-competition, non-solicitation, no-hire and confidentiality covenants, three times the sum of Mr. O’Malley’s unreduced base salary plus base bonus, (iii) the accrued retirement benefit, whether or not vested, and (iv) full vesting of any outstanding stock options. Mr. O’Malley is also entitled to be “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Employment Agreement with Henry M. Kuchta
 
We entered into an amended and restated employment agreement with Henry M. Kuchta, dated as of June 1, 2002, and which was subsequently amended, pursuant to which Mr. Kuchta agreed to serve as executive vice president-refining. Mr. Kuchta was appointed president effective January 1, 2003. The agreement has a term of two years but is subject to automatic one-year extensions thereafter, unless either party gives the other 60 days prior written notice of its intention not to extend the term. The agreement provides for an annual base salary (with increases, if any, to be determined by our board of directors) of $250,000. In addition, the employment

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agreement provides that Mr. Kuchta will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and according to GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, are at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. Kuchta shall be equal to 50% of his annual base salary (his “base bonus”). Mr. Kuchta will have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of three times his base salary. Pursuant to the 2002 Equity Incentive Plan, Mr. Kuchta will receive annual options to purchase at least 25,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant in each of the years 2003 and 2004. Pursuant to the employment agreement, if Mr. Kuchta’s employment is terminated by us without cause, by Mr. Kuchta for good reason or upon our election not to extend the employment term, Mr. Kuchta will be entitled to receive (i) any accrued but unpaid base salary plus base bonus attributable to a prior fiscal year and (ii) subject to Mr. Kuchta’s continued compliance with non-competition, non-solicitation, no-hire and confidentiality covenants, three times the sum of Mr. Kuchta’s base salary plus base bonus. Mr. Kuchta is also entitled to be “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Employment Agreement with William E. Hantke
 
We entered into an amended and restated employment agreement with William E. Hantke, dated as of June 1, 2002, and which was subsequently amended, pursuant to which Mr. Hantke agreed to serve as our executive vice president and chief financial officer. The agreement has a term of three years but is subject to automatic one-year extensions thereafter, unless either party gives the other 60 days prior written notice of its intention not to extend the term. The agreement provides for an annual base salary (with increases, if any, to be determined by our board of directors) of $250,000. In addition, the employment agreement provides that Mr. Hantke will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and according to GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, is at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. Hantke shall be equal to 50% of his annual base salary (his “base bonus”). Mr. Hantke shall have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of three times his base salary. The employment agreement also provides that Mr. Hantke will be granted annual options to purchase 25,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant, in each of the years 2003, 2004 and 2005, all under the 2002 Equity Incentive Plan. Pursuant to the employment agreement, if Mr. Hantke’s employment is terminated by us without cause, by Mr. Hantke for good reason or upon our election not to extend the employment term, Mr. Hantke will be entitled to receive (i) any accrued but unpaid base salary and annual bonus attributable to a prior fiscal year and (ii) subject to Mr. Hantke’s continued compliance with non-competition, non-solicitation, no-hire and confidentiality covenants, three times the sum of Mr. Hantke’s base salary plus base bonus. Mr. Hantke is also entitled to be “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Employment Agreement with Michael D. Gayda
 
We entered into an employment agreement with Michael D. Gayda, dated as of October 1, 2002, and which was subsequently amended, pursuant to which Mr. Gayda agreed to serve as senior vice president, general counsel and secretary. The agreement has an initial term of two years but is subject to automatic one-year extensions thereafter, unless either party gives the other 60 days prior written notice of its intention not to extend the term. The agreement provides for an annual base salary (with increases, if any, to be determined by our board

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of directors) of $200,000. In addition, the employment agreement provides that Mr. Gayda will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and according to GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, is at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. Gayda shall be equal to 50% of his annual base salary (his “base bonus”). Mr. Gayda shall have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of three times his base salary. The employment agreement also provides that Mr. Gayda will be granted annual options to purchase not less than 25,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant, in each of the years 2003, 2004 and 2005, all under the 2002 Equity Incentive Plan. Pursuant to the employment agreement, if Mr. Gayda’s employment is terminated by us. without cause, by Mr. Gayda for good reason or upon our election not to extend the employment term, Mr. Gayda will be entitled to receive (i) any accrued but unpaid base salary and annual bonus attributable to a prior fiscal year and (ii) subject to Mr. Gayda’s continued compliance with confidentiality covenants, three times the sum of Mr. Gayda’s base salary plus base bonus. Mr. Gayda is also entitled to have his salary “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Employment Agreement with James R. Voss
 
We entered into an employment agreement with James R. Voss, dated as of September 16, 2002, and which was subsequently amended, pursuant to which Mr. Voss agreed to serve as senior vice president and chief administrative officer. The agreement has an initial term of two years but is subject to automatic one-year extensions thereafter, unless either party gives the other 60 days prior written notice of its intention not to extend the term. The agreement provides for an annual base salary (with increases, if any, to be determined by our board of directors) of $200,000. In addition, the employment agreement provides that Mr. Voss will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and according to GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, is at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. Voss shall be equal to 50% of his annual base salary (his “base bonus”). Mr. Voss shall have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of three times his base salary. The employment agreement also provides that Mr. Voss will be granted annual options to purchase not less than 25,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant, in each of the years 2003, 2004 and 2005, all under the 2002 Equity Incentive Plan. Pursuant to the employment agreement, if Mr. Voss’s employment is terminated by us without cause, by Mr. Voss for good reason or upon our election not to extend the employment term, Mr. Voss will be entitled to receive (i) any accrued but unpaid base salary and annual bonus attributable to a prior fiscal year and (ii) subject to Mr. Voss’s continued compliance with confidentiality covenants, three times the sum of Mr. Voss’s base salary plus base bonus. Mr. Voss is also entitled to have his salary “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Employment Agreement with Joseph D. Watson
 
We entered into an amended and restated employment agreement with Joseph D. Watson, dated June 1, 2002, and which was subsequently amended, pursuant to which Mr. Watson agreed to serve as senior vice president. The agreement has a term of two years but is subject to automatic one-year extensions thereafter, unless either party gives the other sixty days prior written notice of its intention not to extend the term. The agreement provides for

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an annual base salary (with increases, if any, to be determined by our board of directors) of $200,000. In addition, the employment agreement provides that Mr. Watson will be eligible to earn an annual bonus if net earnings per share to our common shareholders, calculated on a fully diluted basis and according to GAAP, excluding the after-tax impact of any extraordinary or special items that our board of directors determines in good faith are not appropriately includable in such calculation because such items do not accurately reflect our operating performance, is at least equal to $2.00. Upon achievement of such $2.00 earnings per share, the annual bonus for Mr. Watson shall be equal to 50% of his annual base salary (his “base bonus”). Mr. Watson shall have an opportunity to earn a larger bonus for increases in such earnings per share over $2.00, subject to a cap of three times his base salary. The employment agreement also provides that Mr. Watson will be granted annual options to purchase 25,000 shares of our common stock per year at an exercise price equal to fair market value on the date of grant, in each of the years 2003 and 2004, all under the 2002 Equity Incentive Plan. Pursuant to the employment agreement, if Mr. Watson’s employment is terminated by us without cause, by Mr. Watson for good reason or upon our election not to extend the employment term, Mr. Watson will be entitled to receive (i) any accrued but unpaid base salary and annual bonus attributable to a prior fiscal year and (ii) subject to Mr. Watson’s continued compliance with non-competition, non-solicitation, no-hire and confidentiality covenants, three times the sum of Mr. Watson’s base salary plus base bonus. Mr. Watson is also entitled to have his salary “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he receives in connection with benefits and payments provided to him in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Termination Agreement with William C. Rusnack
 
William C. Rusnack served as the chief executive officer and president from April 1998 to January 31, 2002. On January 31, 2002, we entered into a termination agreement with Mr. Rusnack pursuant to which he resigned from all executive officer and board positions with us and our affiliates. Mr. Rusnack agreed to release us and our affiliates from any claims he may have against us and our affiliates, and we agreed to provide certain severance payments and benefits. Upon the termination of his employment, Mr. Rusnack received a lump sum severance payment of $3,375,000. All 300,000 nonqualified time vesting stock options to purchase shares of our common stock that had been granted to Mr. Rusnack under the 1999 Incentive Plan had vested prior to his termination. However, Mr. Rusnack’s exercise period was modified such that he was entitled to exercise his vested options until November 9, 2002. Fifty percent of the 300,000 performance vesting options granted to Mr. Rusnack under the 1999 Incentive Plan vested prior to the November 9th expiration date and the remaining fifty percent expired. Mr. Rusnack has exercised all 450,000 vested options. For more detail on Mr. Rusnack’s stock options, see “—Long-Term Performance—1999 Stock Incentive Plan.” Mr. Rusnack is entitled to receive job relocation counseling services for up to 18 months and continued participation for up to one year in all life insurance and welfare programs in which he participated immediately prior to his termination. Mr. Rusnack is also entitled to have his salary “grossed up,” on an after-tax basis, for excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” as set forth in his original employment agreement. Mr. Rusnack has agreed to certain post-termination confidentiality covenants.
 
Termination Agreement with Ezra C. Hunt
 
Mr. Hunt served as executive vice president and chief financial officer from February 26, 2001 to January 31, 2002. On January 31, 2002, we entered into a termination agreement with Mr. Hunt, pursuant to which he resigned from his executive officer positions. Mr. Hunt agreed to release us and our affiliates from any claims he may have against us and our affiliates, and we agreed to provide certain severance payments and benefits. Under the agreement, Mr. Hunt is entitled to $1,500,000 (less the present value of any other termination benefits payable by us) which is equal to two times the sum of his base salary and target bonus, such amount being payable over a 24-month period. Of the 120,000 nonqualified stock options to purchase shares of our common stock granted to Mr. Hunt under the 1999 Incentive Plan, 20,000 options vested upon his termination and the remainder were forfeited. However, Mr. Hunt’s exercise period was modified such that he was entitled to exercise his vested options until November 9, 2002. Mr. Hunt has exercised his 20,000 vested options. Mr. Hunt

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is entitled to receive job relocation counseling services for up to 18 months and continued participation for up to one year in all life insurance and welfare programs in which he was entitled to participate immediately prior to his termination. Mr. Hunt is also entitled to have his salary “grossed up,” on an after-tax basis, for excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” as set forth in his original employment agreement. Mr. Hunt has agreed to certain post-termination confidentiality covenants.
 
Separation Agreement with Jeffry N. Quinn
 
Mr. Quinn served as executive vice president and general counsel from March 2000 to November 1, 2002. On November 1, 2002, we entered into a separation agreement with Mr. Quinn, pursuant to which he resigned from all executive officer and board positions with us and our affiliates. Mr. Quinn agreed to release us and our affiliates from any claims he may have against us and our affiliates, and we agreed to provide certain severance payments and benefits. Under the agreement, on January 2, 2003, Mr. Quinn will receive a lump sum severance payment of $1,165,000. Of the 120,000 nonqualified stock options granted to Mr. Quinn under the 1999 Incentive Plan, 90,000 options were vested as of his termination date or vested upon his termination. As of December 1, 2002, Mr. Quinn had exercised 45,000 of these options. Mr. Quinn is entitled to exercise the remaining vested options until March 1, 2004. All of the 50,000 nonqualified stock options granted to Mr. Quinn under the 2002 Equity Incentive Plan were forfeited upon his termination. Mr. Quinn is entitled to receive job relocation counseling services up to $35,000. He is also entitled to have his salary “grossed up,” on an after-tax basis, for excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” as set forth in his original employment agreement. Mr. Quinn has agreed to certain post-termination confidentiality covenants.
 
Other Employee Benefits
 
Senior Executive Retirement Plan
 
We adopted a Senior Executive Retirement Plan (SERP) covering seven executive officers. Benefits under the plan will vest after three years of continuous service. The annual retirement benefit payable under the plan at a normal retirement date (as defined by the plan) will be a single life annuity for the life of the participant which is equal to the lesser of:
 
 
•
 
the sum of six percent (6%) of average earnings times years of service less than or equal to five (5), plus three percent (3%) of average earnings times years of service greater than five (5), or
 
 
•
 
sixty percent (60%) of average earnings.
 
Average earnings are defined as the average of the participant’s annual earnings (generally, annual base compensation plus bonus paid under an annual incentive plan) during the three consecutive calendar year period of employment in which the participant had the highest aggregate earnings.
 
Any benefit payable under the plan will be offset by benefits, if any, payable to the participant under our pension plan. Further, a SERP participant will not accrue a benefit under our non-qualified pension restoration plan during the period in which he participates in the plan. The plan also provides death, disability and post-employment medical benefits.
 
On September 10, 2002, we suspended the SERP. Unless and until the plan is reactivated by us, participants in the plan will accrue no benefits; however, service during this time will count toward vesting of any benefit earned in the future. There is no certainty that the plan will be reactivated in the future. The suspension of the plan has been consented to by each of the participants.
 
Pension Plans
 
We implemented a “cash balance” pension plan for our salaried workforce, including the named executive officers, effective January 1, 2002. Benefits under the plan will vest after five years of continuous service. The

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plan will recognize existing service with us or our predecessors for purposes of vesting, allowing our employees that already have five or more years of service to be vested immediately.
 
On an annual basis each participant’s account will be credited with the following:
 
 
•
 
contribution credit equal to seven percent (7%) of pensionable earnings plus seven percent (7%) of pensionable earnings in excess of the Social Security Wage Base; and
 
 
•
 
interest credit equal to the average yield for one-year treasury bonds for the previous October, plus one percent (1%).
 
For the purposes of the plan, “pensionable earnings” are defined as regular annual salary, overtime pay, annual incentive payments and contributions to 401(k) plans.
 
We also adopted a non-qualified restoration plan which restores the benefits lost by any employee, including any executive officer, under the qualified pension plan as a result of Internal Revenue Code imposed limitations on pensionable income.
 
As of December 1, 2002, the estimated annual annuities payable at age sixty-five (65) to Messrs. O’Malley, Kuchta, Hantke, Eichholz, Gayda, Kuenzli, Voss and Watson are as follows:
 
Name
   
Current Age
     
Estimated Annual Payments(1)
Thomas D. O’Malley
   
61
     
$
126,178
Henry M. Kuchta
   
46
     
 
238,888
William E. Hantke
   
55
     
 
103,390
Dennis R. Eichholz
   
49
     
 
118,165
Michael D. Gayda
   
48
     
 
155,017
James R. Voss
   
36
     
 
453,991
Joseph D. Watson
   
37
     
 
390,696
Donovan J. Kuenzli
   
63
     
 
13,876
(1)
 
Assumes the executive officer works until age sixty-five (65), annual base compensation remains unchanged from his current salary and that future incentive compensation awards are equal to 250% of base pay for Mr. O’Malley, 100% of base pay for Messrs. Kuchta, Hantke, Gayda, Voss and Watson and 50% of base pay for Messrs. Eichholz and Kuenzli. Amounts include estimated benefits under our cash balance plan and non-qualified restoration plan. The interest rate used for determining the annuity was 7.5%. The interest credit for 2003 and future years was assumed to be 6.5%. The above amounts reflect that our senior executive retirement plan has been suspended and assume that each of the executive officers is eligible for benefits under the non-qualified pension restoration plan during the suspension period. For further discussion regarding the suspension of that plan, see “—Other Employee Benefits—Senior Executive Retirement Plan.”
 
On February 1, 2002, we implemented a cash balance pension plan for our represented workforce. Eligible represented employees are regular hourly-paid employees that have attained six months of continuous service with us. Benefits under the plan will vest after five years of continuous service. Past service from the most recent period of continuous employment at the facility will be recognized for participation and vesting. On an annual basis each participant’s account is credited with:
 
 
•
 
a contribution credit equal to a percentage of pensionable earnings; and
 
 
•
 
an interest credit equal to the average yield for one-year treasury bonds for the previous October, plus one percent (1%).

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For the purposes of the pension plan, pensionable earnings are defined as annual base salary plus overtime and shift differential paid during the plan year. The contribution credit is based on the participant’s age and service at year end.
 
Change-In-Control, Retention and Severance Agreements
 
We entered into change-in-control, retention and severance agreements with six of our key employees, including Messrs. Eichholz and Kuenzli. Each agreement has an initial term of three years, provided that if neither us nor the employee gives 12 months’ notice of termination prior to the expiration of the initial term or any extension thereof, then the agreement shall automatically extend for an additional two-year period. In the event of a change in control of us, each agreement shall remain in effect until at least the second anniversary of the change in control. In the event that, prior to the occurrence of a change in control, an employee’s employment is terminated by us without cause or is terminated by the employee for good reason (defined to include a material diminution of duties or titles, certain reductions in base salary, target incentive opportunity or employee benefits), then we shall pay the employee his or her base salary during the one-year period following such termination, plus a pro-rata portion of the employee’s annual target bonus for the year in which the termination occurs. In the event such termination occurs in connection with or after a change in control, the employee will receive a lump sum cash payment within 10 business days of the termination equal to two times the sum of his or her base salary amount and target bonus amount plus a pro-rata portion of his or her annual target bonus for the year in which the termination occurs. If the employee’s employment is terminated for the reasons set forth above, the employee will also receive up to two years of continued medical and other welfare benefits, as well as up to one year of outplacement services.
 
The agreements also provide that upon a change in control of us, all stock options and other equity awards immediately vest and become exercisable (performance-vesting options only vest if the applicable performance goals are satisfied). In addition, the agreements provide that each covered employee is entitled to have his or her salary “grossed up,” on an after-tax basis, for any excise taxes imposed under the Internal Revenue Code on any “excess parachute payment” that he or she receives in connection with benefits and payments provided to him or her in connection with any change in control (as such term is defined under the Internal Revenue Code) of us.
 
Premcor Retirement Savings Plan
 
Our Savings Plan permits our employees to make before-tax and after-tax contributions and provides for employer incentive matching contributions. Executive officers participate in the plan on the same terms as other eligible employees, subject to any legal limits on the amounts that may be contributed or paid to executive officers.
 
Under the Savings Plan, each of our employees may become a participant. Participants are permitted to make before-tax contributions to the Savings Plan, effected through payroll deduction, of from 1% to 15% of their compensation. Compensation, for purposes of the Savings Plan, is defined as regular annual salary, overtime pay and shift differential. We make matching contributions equal to 200% of a participant’s before-tax contributions for up to 3% of compensation. Additionally, for union represented employees at our Port Arthur and Lima refineries, we make matching contributions equal to 100% of a participant’s before-tax contributions between 4% and 6% of compensation. Participants are also permitted to make after-tax contributions through payroll deduction, of from 1% to 5% of compensation, which are not matched by employer contributions. Before-tax contributions and after-tax contributions, in the aggregate, may not exceed the lesser of 15% of compensation and before tax contributions may not exceed $11,000 in 2002. All employer contributions for non-union employees are fully vested from the onset of the employee’s participation in the plan. Subject to certain restrictions, employees may make loans or withdrawals of employee contributions during the term of their employment.
 
Other Plans
 
We provide medical benefits, life insurance, and other welfare benefits to our employees, including our executive officers.

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PRINCIPAL STOCKHOLDERS
 
The following table sets forth certain information concerning the beneficial ownership of our common stock as of January 1, 2003 by persons who beneficially own more than 5% of the outstanding shares of our common stock, each person who is a director of our company, each person who is a named executive officer and all directors and executive officers of our company as a group.
 
Name and Address
   
Shares Beneficially Owned Prior to the Offering
     
Shares Beneficially Owned After the Offering (4)
  
  
Number
   
Percent
     
Number
   
Percent
  
Blackstone Management Associates III L.L.C. (1)
345 Park Avenue
New York, NY 10154
   
27,817,104
   
47.9
%
   
27,817,104
   
39.4
%
Occidental Petroleum Corporation
10889 Wilshire Boulevard
Los Angeles, California 90024
   
7,734,646
   
13.3
 
   
7,734,646
   
11.0
 
Thomas D. O’Malley (2)
   
1,483,334
   
2.6
 
   
1,483,334
   
2.1
 
Jefferson F. Allen (2)
   
83,334
   
*
 
   
83,334
   
*
 
Marshall A. Cohen (2)
   
116,161
   
*
 
   
116,161
   
*
 
Wilkes McClave III (2)
   
83,334
   
*
 
   
83,334
   
*
 
Donovan J. Kuenzli (2)
   
41,000
   
*
 
   
41,000
   
*
 
Dennis R. Eichholz (2)
   
41,000
   
*
 
   
41,000
   
*
 
All directors and executive officers as a group (2)(3)
   
1,848,163
   
3.2
 
   
1,848,163
   
2.6
 
*
 
Less than 1%.
(1)
 
Blackstone affiliates currently own 27,817,104 shares of our common stock as follows: 22,193,918 shares by Blackstone Capital Partners III Merchant Banking Fund L.P., 3,954,154 shares by Blackstone Offshore Capital Partners III L.P. and 1,669,032 shares by Blackstone Family Investment Partnership III L.P, for each of which Blackstone Management Associates III L.L.C., or BMA, is the general partner having voting and investment power. Messrs. Peter G. Peterson and Stephen A. Schwarzman are the founding members of BMA and as such may be deemed to share beneficial ownership of the shares owned by Blackstone. Each of BMA and Messrs. Peterson and Schwarzman disclaims beneficial ownership of such shares.
(2)
 
Includes the following shares which such persons have, or will within 60 days of January 1, 2003 have, the right to acquire upon the exercise of stock options: Mr. O’Malley—733,334; Mr. Allen—33,334; Mr. Cohen—50,505; Mr. McClave—33,334; Mr. Kuenzli—40,000; and Mr. Eichholz—40,000. Mr. Cohen’s address is Cassels, Brock & Blackwell, Scotia Plaza, Suite 2200, 40 King Street West, Toronto Ontario, M5H-3C2 Canada. The address of each of the named executive officers is Premcor Inc., 1700 E. Putnam Avenue, Suite 500, Old Greenwich, CT 06870.
(3)
 
David I. Foley, Robert L. Friedman and Richard C. Lappin, all directors of us, are designees of Blackstone Management Associates III L.L.C., which has investment and voting control over the shares held or controlled by Blackstone and as such may be deemed to share beneficial ownership of the shares held or controlled by Blackstone. Stephen I. Chazen, a director of us, is an executive officer of Occidental Petroleum Corporation and to the extent he may be deemed to be a control person of Occidental Petroleum Corporation may be deemed to be a beneficial owner of shares of common stock owned by Occidental Petroleum Corporation. Each of such persons disclaims beneficial ownership of such shares.
(4)
 
Assumes no shares of common stock are sold by us in the private equity commitment and no exercise of the underwriters’ over-allotment option.

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RELATED PARTY TRANSACTIONS
 
Each of the related party transactions described below was negotiated on an arm’s length basis. We believe that the terms of each such agreement are as favorable as those we could have obtained from parties not related to us.
 
Our Relationship with Blackstone
 
The Blackstone Group L.P. is a private investment firm based in New York, founded in 1985. Its main businesses include private equity investing, merger and acquisition advisory services, restructuring advisory services, real estate investing, mezzanine debt investing, collateralized debt obligation investing and asset management. Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, or Blackstone, acquired its interest in our predecessor in November 1997 and, as of January 1, 2003, beneficially owned 47.9% of our common stock.
 
Under a Monitoring Agreement, dated November 14, 1997, among us, Premcor USA and Blackstone, we have paid a monitoring fee equal to $2 million per annum to an affiliate of Blackstone. In return, Blackstone provided financial advisory services to us including advice on the structure and timing of our entry into financial arrangements, relationships with key lenders, property dispositions and acquisitions, and other ancillary financial advisory services. Financial advisory services rendered by Blackstone relating to specific acquisitions and divestitures are expressly excluded from the agreement. As of December 31, 2001, we have paid in full all amounts due and payable under this agreement. Over the past three years, we have paid fees to Blackstone totaling approximately $17 million, consisting of $6.0 million in monitoring fees, a $2.4 million fee paid in connection with our purchase of the Lima refinery, an $8.0 million fee in connection with structuring of the heavy oil upgrade project, and an amount for reimbursed expenses. We have terminated this monitoring agreement effective as of March 31, 2002. To terminate such agreement, we have paid Blackstone $500,000 for services rendered during 2002 and a $5 million termination fee.
 
Under a Stockholder Agreement dated March 9, 1999 among us, Blackstone and Marshall A. Cohen, one of our directors and stockholders, if Blackstone transfers 25% or more of its holdings of our common stock to a third party, Mr. Cohen or any of his permitted affiliates may require the transferee to purchase a similar percentage of his shares. Conversely, if Blackstone receives and accepts an offer from a third party to purchase 25% or more of its holdings of our common stock, Mr. Cohen must transfer a similar percentage of his shares to the third party. This agreement terminates when Blackstone ceases to beneficially own at least 5% of our common stock on a fully diluted basis.
 
Pursuant to a Registration Rights Agreement, dated April 26, 2002, between us and Blackstone, Blackstone has the right, on up to three occasions, to request that we effect the registration of all or part of Blackstone’s shares. We are obligated to use our best efforts to effect the registration of all of the shares of which Blackstone requests except when in the opinion of the underwriter the number of securities requested to be registered is likely to adversely impact such offering. Blackstone also has the right to include its shares in certain registered public offerings by us. We are obligated to use our best efforts to effect the registration of the Blackstone shares along with the other shares, absent a determination by the underwriter that such registration exceeds the largest number of securities which can be sold without adversely impacting the offering.
 
Blackstone is also a party to a Capital Contribution Agreement, dated as of August 19, 1999, with Sabine, Neches, PACC, PAFC and us. Under that agreement, Blackstone agreed to make certain capital investments in Sabine in connection with the heavy oil upgrade project. Blackstone made $109.6 million of contributions under the agreement.
 
From time to time in the past, we have retained Blackstone to act as our financial advisor with respect to potential transactions. Blackstone is not currently acting as our financial advisor with respect to any such transaction.

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Our Relationship with Occidental
 
Occidental Petroleum Corporation explores for, develops, produces and markets crude oil and natural gas and manufactures and markets a variety of basic chemicals. Occidental acquired its interest in our predecessor in 1995 and, as of January 1, 2003, beneficially owned 13.3% of our common stock. Occidental also acquired an approximately 10% equity interest in Sabine pursuant to a Subscription Agreement, dated as of August 4, 1999, among Occidental, Sabine, Neches and PACC, in connection with the financing of the Port Arthur heavy oil upgrade project.
 
Pursuant to a Share Exchange Agreement dated April 27, 1999, we succeeded to, and Premcor USA ceased to be a party to, the Second Amended and Restated Stockholders’ Agreement dated November 3, 1997, originally between Premcor USA and Occidental C.O.B. Partners. That stockholders’ agreement entitles Occidental to designate one director to our board of directors for as long as it holds at least 10% of our fully diluted shares. We have the right of first refusal on any of our shares held by Occidental or a transferee of Occidental intended by such holder to be sold to a third party. Occidental has the right, on one occasion, to request that we effect the registration of all or part of Occidental’s holdings of our common stock. In addition, Occidental has the right to include its holdings of common stock in any registered public offering by us. We are required to use our best efforts to effect the registration of the shares of our common stock held by Occidental along with our other shares of common stock, unless the underwriters of the offering determine that the registration of the shares of our common stock held by Occidental will adversely impact the offering of our other shares of common stock.
 
Under an Advisory Agreement, dated November 14, 1997, among Premcor USA, PRG and Occidental, Occidental provides us with consulting services related to ongoing crude supplier decisions and related purchase and hedging strategies. In return, Occidental received 101,010 shares of our Class F Common Stock. Pursuant to a Warrant Exercise and Share Exchange Agreement, dated as of June 6, 2002, among Blackstone, Occidental, Sabine and us, Occidental’s 101,010 shares of our Class F Common Stock were converted into shares of our common stock upon completion of our IPO and, in connection with the Sabine restructuring, we consummated a share exchange with Occidental whereby we received the remaining 10% of the common stock of Sabine in exchange for shares of our common stock.
 
Our Relationship with PACC
 
Prior to the Sabine restructuring, PACC was our affiliate because we owned 90% of the capital stock of Sabine, the entity formed to be the general partner of PACC, and 100% of Neches, the entity formed to be the 99% limited partner of PACC. In connection with the Sabine restructuring, on June 6, 2002, we consummated a share exchange with Occidental whereby we received the remaining 10% of the common stock of Sabine and we then contributed its 100% ownership interest in Sabine to PRG. As a result, Sabine and its wholly owned subsidiaries, including PACC, became wholly-owned subsidiaries of PRG.
 
Consulting Agreement with Fuel Strategies International
 
Pursuant to a consulting agreement, Fuel Strategies International, Inc., the principal of which is James P. O’Malley, the brother of Thomas O’Malley, our chairman and chief executive officer, provides us with monthly consulting services relating to our petroleum coke operations. The initial term of the agreement runs from June 1, 2002 through May 30, 2003, and shall be automatically renewed for additional one-year periods unless terminated by either party upon 90 days notice prior to the expiration of the initial term or any renewal term. The agreement provides that Fuel Strategies will be paid a fixed fee of $12,000 per month for eight working days and $1,500 per day for each additional day thereafter. Fuel Strategies also is entitled to be reimbursed for its expenses and to be paid an additional $450 per day for expenses it may incur on business trips outside of Boca Raton, Florida. Effective October 2002, Fuel Strategies voluntarily agreed to work 10 days per month for its fixed monthly fee of $12,000 and to reduce its per diem fee for additional days to $1,200, which will be capped at a maximum rate of 12 days per month regardless of the actual number of days worked. For the year ended December 31, 2002, we paid $168,198 to Fuel Strategies under this agreement.

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DESCRIPTION OF CAPITAL STOCK
 
General
 
Upon consummation of this offering, our authorized capital stock will consist of:
 
 
•
 
150,000,000 shares of common stock, par value $0.01 per share, and
 
 
•
 
5,000,000 shares of preferred stock, par value $0.01 per share.
 
The following description of our capital stock and related matters is qualified in its entirety by reference to our certificate of incorporation and by-laws, copies of which are filed as exhibits to the registration statement of which this prospectus forms a part.
 
Common Stock
 
Voting Rights; Dividends; Other Rights
 
Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders, voting together as one class, except that holders of common stock are not entitled to vote with respect to matters reserved, by law or agreements, solely to any other class of capital stock. The holders of common stock do not have cumulative voting rights in the election of directors.
 
Holders of common stock are entitled to receive dividends payable either in cash, in property or in shares, if, as and when declared by our board of directors, out of assets legally available for that purpose. Dividend payments are subject to preferential rights, if any, of the preferred stock. Upon our liquidation, dissolution or winding up, after payment or provision for the payment of our debts and other liabilities and of the preferential amounts, if any, to which the holders of preferred stock are entitled, the holders of all outstanding shares of common stock will be entitled to receive our remaining assets that will be distributed ratably in proportion to the numbers of shares held by each holder of common stock. The common stock has no preemptive or conversion rights and is not subject to further calls or assessment by us. There are no redemption or sinking fund provisions applicable to shares of common stock.
 
Preferred Stock
 
Our certificate of incorporation authorizes our board of directors to establish one or more classes of preferred stock, to establish the number of shares to be included in each class and to fix the designations, powers, preferences and rights of the shares of each class of preferred stock and any qualifications, limitations or restrictions thereof.
 
Although we have no intention at the present time of establishing a new class of preferred stock, our certificate of incorporation allows us to do so as an anti-takeover defensive measure to impede an unsolicited acquisition proposal, tender offer or other takeover attempt. We will make any determination to establish a new class, and issue shares, of preferred stock based on our judgment as to the best interests of the company and our stockholders. Such class of preferred stock may have terms and conditions that discourage unsolicited acquisition proposals or other takeover attempts that some or a majority of you might believe to be in your best interests or in which you might receive a premium for you shares of common stock over the market price of such shares of common stock.
 
Authorized but Unissued Capital Stock
 
The Delaware General Corporation Law does not require stockholder approval for any issuance of authorized shares of common stock. However, the listing requirements of the New York Stock Exchange, that would apply so long as our common stock remains listed on the New York Stock Exchange, require stockholder

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approval of certain issuances equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of common stock. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions.
 
One of the consequences of the existence of unissued and unreserved common stock or preferred stock may be that our board of directors could issue shares to persons friendly to current management, which could render more difficult or discourage an attempt to obtain control of us by means of a merger, tender offer, proxy contest or otherwise, and thereby protect the continuity of our management and possibly deprive stockholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.
 
Anti-Takeover Effects of Provisions of Delaware Law and Our Certificate of Incorporation and By-Laws
 
Delaware Law
 
We are a Delaware corporation subject to Section 203 of the Delaware General Corporation Law. Section 203 provides that, subject to certain exceptions specified in the law, a Delaware corporation will not engage in certain business combinations with any interested stockholder for a three-year period following the time that the stockholder became an interested stockholder unless:
 
 
•
 
prior to the time that the stockholder becomes an interested stockholder, our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;
 
 
•
 
upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at east 85% of our voting stock outstanding at the time the transaction commenced, excluding certain shares; or
 
 
•
 
at or subsequent to the time that the stockholder becomes an interested stockholder, the business combination is approved by our board of directors and by the affirmative vote of holders of at least 66 2/3% of the outstanding voting stock not owned by the interested stockholder.
 
Generally, the term “business combination” includes a merger, asset or stock sale or other transaction resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an interested shareholder is a person who, together with that person’s affiliates and associates, owns, or within the previous three years did own, 15% or more of our voting stock.
 
Under certain circumstances, Section 203 makes it more difficult for a person who is an interested stockholder to effect various business combinations with a corporation for a three-year period. The provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board of directors for approval of certain transactions or business combinations in order to avoid the stockholder approval requirement. Section 203 also may have the effect of preventing changes in our board of directors and may make it more difficult to accomplish transactions that stockholders may otherwise deem to be in their best interests.
 
Certificate of Incorporation; By-Laws
 
Our certificate of incorporation and by-laws contain certain provisions that could make more difficult the acquisition of us by means of a tender offer, a proxy contest or otherwise.
 
Removal of Directors; Vacancies.    Our certificate of incorporation and by-laws provide that directors may be removed only for cause and only upon the affirmative vote of holders of at least 75% of the voting power of the then outstanding shares of stock entitled to vote generally in the election of directors, voting together as a single class. Our certificate of incorporation also provides that any vacancies on our board of directors will be filled only by the affirmative vote of a majority of the remaining directors, though less than a quorum.

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Action by Written Consent; Stockholder Action.    Our certificate of incorporation and by-laws provide that stockholder action can be taken only at an annual or special meeting of stockholders and may not be taken by written consent in lieu of a meeting. This provision will prevent the holders of a majority of the voting stock from using a written consent procedure to take stockholder action without affording all stockholders an opportunity to vote on the action. In addition, our certificate of incorporation and by-laws provide that, except as permitted by law and subject to the rights of holders of preferred stock, special meetings of stockholders can be called only by the chairman of our board of directors or the chief executive officer and will be called by our secretary at the direction of a majority of the board of directors. These stockholder action provisions have the effect of discouraging, delaying or preventing a change in control.
 
Advance Notice Procedure.    Our by-laws establish an advance notice procedure for stockholders to nominate candidates for election as directors, or to bring business before an annual meeting of stockholders. Only persons nominated by, or at the direction of, our board of directors or by a stockholder who has given timely written notice to the secretary of our company prior to the meeting, will be eligible for election as a director. In addition, any proposed business other than the nominations of persons for election to our board of directors must constitute a proper matter for stockholder action pursuant to the notice of meeting delivered to our company. For notice to be timely, it must be received by the secretary of our company not less than 90 days nor more than 120 days prior to the first anniversary of the previous year’s annual meeting (or if the date of the annual meeting is advanced by more than 30 days or delayed by more than 70 days from such anniversary date, not earlier than the 120th day prior to such meeting and not later than the later of (x) the 90th day prior to such meeting and (y) the 10th day after public announcement of the date of such meeting is first made). In the event that the number of directors to be elected to the board is increased and there is no public announcement by our company naming the nominees for directors at least 100 days prior to the first anniversary of the preceding year’s annual meeting, a stockholder’s notice will be timely, but only with respect to nominees for the additional directorships, if it is delivered to the secretary of our company not later than the 10th day following the day on which such public announcement is first made. For notice of a stockholder nomination to be made at a special meeting at which directors are elected, such notice must be received by our company not earlier than the 120th day before such meeting and not later than the later of (x) the 90th day prior to such meeting and (y) the 10th day after the date the public announcement is first made. A stockholder’s notice proposing to nominate a person for election as a director or relating to the conduct of other business must contain certain specified information. If the chairman of our board of directors determines that a person was not nominated, or other business was not brought before the meeting in accordance with the notice procedure, that person will not be eligible for election as a director, and that business will not be conducted at the meeting.
 
Amendment.    Our certificate of incorporation and by-laws provide that the affirmative vote of the holders of at least 75% of the voting power of all shares entitled to vote generally in the election of directors, voting together as a single class, is required to amend provisions of the certificate of incorporation relating to:
 
 
•
 
prohibition of stockholder action without a meeting;
 
 
•
 
the ability of our stockholders to call a special meeting;
 
 
•
 
the number, election and term of the members of the board of directors; and
 
 
•
 
the removal of directors.
 
Our certificate of incorporation further provides that our by-laws may be amended by our board of directors or by the affirmative vote of the holders of at least 75% of the voting power of all shares entitled to vote generally in the election of directors, voting together as a single class.
 
Registrar and Transfer Agent
 
The registrar and transfer agent for the common stock is American Stock Transfer & Trust Company.
 

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Limitation of Liability and Indemnification
 
Our by-laws provide that we will indemnify and advance expenses to our directors and officers to the fullest extent authorized by the Delaware General Corporation Law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on behalf of our company. In addition, our certificate of incorporation provides that our directors will not be liable for monetary damages to us for breaches of their fiduciary duty as directors, except to the extent such exemption from liability or limitation thereof is not permitted under the Delaware General Corporation Law.
 
Listing
 
Our common stock is listed on the New York Stock Exchange under the symbol “PCO.”

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DESCRIPTION OF INDEBTEDNESS
 
The following are summaries of the terms of our principal long-term debt.
 
The Premcor Refining Group
 
8 3/8% Senior Notes.    In November 1997, The Premcor Refining Group issued $100 million of unsecured 8 3/8% senior notes. The notes mature on November 15, 2007, with interest payable semi-annually in arrears on May 15th and November 15th. The Premcor Refining Group may redeem the notes on or after November 15, 2002, at a redemption price equal to 104.187% of the principal amount of the notes in the first year. The redemption prices decline yearly to par on November 15, 2004, plus accrued and unpaid interest to the date of redemption.
 
8 7/8% Senior Subordinated Notes.    In November 1997, The Premcor Refining Group issued $175 million of unsecured 8 7/8% senior subordinated notes. The notes mature on November 15, 2007, with interest payable semi-annually in arrears on May 15th and November 15th. The Premcor Refining Group may redeem the notes on or after November 15, 2002, at a redemption price equal to 104.437% of the principal amount of the notes in the first year. The redemption prices decline yearly to par on November 15, 2005, plus accrued and unpaid interest to the date of redemption. The notes are senior subordinated obligations of The Premcor Refining Group, subordinated in right of payment to all of its senior debt.
 
Floating Rate Loans.    The Premcor Refining Group borrowed $125 million in November 1997, and an additional $115 million in August 1998, under a floating rate term loan agreement expiring in 2004. In November 2003, $31.3 million of the outstanding principal amount is due with the remainder of the outstanding principal due in November 2004. The loan is a senior unsecured obligation of The Premcor Refining Group and bears interest at the London Interbank Offer Rate, or LIBOR, plus a margin of 275 basis points. The loan may be repaid from time to time at any time in whole or in part, without premium or penalty. We intend to repay the floating rate term loan with the proceeds from this offering and the other financing transactions.
 
8 5/8% Senior Notes.    In August 1998, The Premcor Refining Group issued $110 million of unsecured 8 5/8% senior notes. The notes mature on August 15, 2008, with interest payable semi-annually in arrears on February 15th and August 15th. The Premcor Refining Group may redeem the notes on or after August 15, 2003, at a redemption price equal to 104.312% of the principal amount of the notes in the first year. The redemption prices decline yearly to par on August 15, 2005, plus accrued and unpaid interest to the date of redemption.
 
Change of Control Provisions
 
Holders of each of the notes described above have the right, upon the occurrence of a change of control accompanied by a ratings downgrade, to require us to repurchase that holder’s notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest to the repurchase date. Each lender under the floating rate loan agreement described above has the right, upon a change of control accompanied by a ratings downgrade, to require us to repay that lender’s loan plus a fee of 1% of the principal repaid.
 
Restrictive Covenants
 
The indentures governing each of the notes and the floating rate term loan agreement described above contain covenants that, among other things, limit our ability to:
 
 
•
 
lease, convey or otherwise dispose of substantially all of our assets or those of our subsidiaries or merge or consolidate;
 
 
•
 
pay dividends or make other distributions on our capital stock, repay subordinated obligations, repurchase capital stock or make specified types of investments, unless we either have the requisite adjusted net worth or can incur an additional $1 of new debt under the operating cash flow to fixed

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charge ratio mentioned below and unless the aggregate amount of specified restricted repayments and investments does not exceed a customary formula based on 50% of net operating income accrued since a specified date at or near the date of the applicable instrument, plus capital contributions; exceptions include dividends up to $75 million for investments and up to $50 million for other restricted payments;
 
 
•
 
incur debt unless, after giving effect to the incurrence of the new debt and the application of the proceeds therefrom, the ratio of operating cash flow to fixed charges would be greater than 2 to 1; exceptions include bank borrowings up to a borrowing base; junior subordinated debt and debt equal to twice capital contributions in certain instruments; and other debt not to exceed the greater of $25 million and 1.25 million multiplied by the per barrel price of West Texas Intermediate crude oil in some instruments and $50 million or $75 million in others;
 
 
•
 
permit our subsidiaries to issue guarantees of indebtedness;
 
 
•
 
incur liens;
 
 
•
 
sell assets without receiving fair market value, 75% of the consideration in cash or cash equivalents or through the assumption by the buyer of debt and without having to apply the net proceeds to repay debt or reinvest in its business;
 
 
•
 
issue capital stock of certain subsidiaries;
 
 
•
 
restrict our subsidiaries’ ability to make dividend payments;
 
 
•
 
enter into transactions with affiliates; and
 
 
•
 
enter into sale leaseback transactions.
 
If the 8 3/8%, 8 5/8%, 8 7/8% notes or the floating rate loans are assigned an investment grade rating, certain of these covenants cease to apply to us and less restrictive covenants that limit only secured indebtedness and sale and leaseback transactions apply instead.
 
The Premcor Refining Group Credit Agreement
 
The credit agreement of our subsidiary, The Premcor Refining Group, provides for letter of credit issuances and revolving loan borrowings of up to the lesser of $650 million (which amount may be increased by up to $50 million under certain circumstances) and the amount of the borrowing base, calculated, on the date of determination, as the sum of 100% of eligible cash (less certain intercompany payables) and eligible cash equivalents, 95% of eligible investments, 90% of major oil company receivables, 85% of eligible receivables, 80% of eligible petroleum inventory, 80% of eligible petroleum inventory-not-received, and 100% of paid but unexpired standby letters of credit minus the greater of (i) the aggregate of all net obligations of PRG to any bank swap party under any swap contracts on such date of determination and (ii) zero. Similar assets of Sabine and its subsidiaries may be included in the calculation of the borrowing base on the same basis as assets of PRG. Revolving loans are limited to the principal amount of $50 million. The letters of credit and the proceeds of revolving loans may be used for working capital and general corporate purposes.
 
The Premcor Refining Group’s credit agreement is structured in two tranches, Tranche 1 of $150 million and Tranche 2 of $500 million. The Tranche 1 commitments are considered fully utilized at all times, while Tranche 2 commitments are considered utilized in an amount equal to the result of subtracting the Tranche 1 commitments from the total letters of credit outstanding at any time.
 
Borrowings and other obligations under the credit agreement and certain hedging agreements are secured by a lien on substantially all of PRG’s personal property, including inventory, accounts, contracts, cash and cash equivalents, general intangibles, including security and deposit accounts, intellectual property, books and records, futures and forwards accounts, commodities accounts, supporting obligations and after-acquired property and proceeds of the foregoing, other than in each case general intangibles arising from or related to its real property, buildings, structures, and other improvements, fixtures, apparatus, machinery, appliances and other

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equipment, and all extensions, renewals, improvements, substitutions and replacements thereto whether owned or leased, together with rents, income, revenues, issues and profits from and in respect of such property. The collateral also includes the capital stock of Sabine and certain inventory assets of PACC and certain proceeds thereof.
 
Outstanding loans under the credit agreement bear interest at annual floating rates equal to LIBOR plus marginal rates between 2.50% and 3.00% or the agent bank’s prime rate plus marginal rates between 1.50% and 2.00%. Unused commitments under the credit agreement are subject to a per annum commitment fee ranging from 0.75% to 1.25%. The marginal rates are subject to adjustment based upon our senior unsecured debt rating. The credit agreement terminates, and all amounts outstanding thereunder are due and payable, on August 23, 2003. The credit agreement contains representations and warranties, funding and yield protection provisions, borrowing conditions precedent, financial and other covenants and restrictions, events of default and other provisions customary for bank credit agreements of this type.
 
Covenants and provisions contained in the credit agreement restrict (with certain exceptions), among other things, the ability of The Premcor Refining Group and its restricted subsidiaries, in each case subject to certain exceptions:
 
 
•
 
to create or incur liens;
 
 
•
 
to engage in certain asset sales;
 
 
•
 
to engage in mergers, consolidations, and sales of substantially all assets;
 
 
•
 
to make loans and investments;
 
 
•
 
(covers PRG and all subsidiaries) to incur additional indebtedness;
 
 
•
 
to engage in certain transactions with affiliates;
 
 
•
 
(covers PRG and all subsidiaries) to use loan proceeds to acquire or carry margin stock, or to acquire securities in violation of certain sections of the Exchange Act;
 
 
•
 
to create or become or remain liable with respect to certain contingent liabilities;
 
 
•
 
to enter into certain joint ventures;
 
 
•
 
to enter into certain lease obligations;
 
 
•
 
to make certain dividend, debt and other restricted payments;
 
 
•
 
to engage in different businesses;
 
 
•
 
(covers all subsidiaries) to make any significant change in our accounting practices;
 
 
•
 
(covers certain affiliates) to incur certain liabilities or engage in certain prohibited transactions under the Employee Retirement Income Security Act of 1974, or ERISA;
 
 
•
 
to maintain deposit accounts not under the control of the banks that are parties to the credit agreement, or to take certain other action with respect to its bank accounts;
 
 
•
 
(covers PRG and all subsidiaries) to engage in speculative trading;
 
 
•
 
(covers PRG and all subsidiaries) to amend, modify or terminate certain material agreements;
 
 
•
 
to maintain cash in certain accounts of Sabine and its subsidiaries in excess of certain levels; and
 
 
•
 
to enter into contracts limiting the ability of restricted subsidiaries to pay dividends and make payments to PRG or other restricted subsidiaries.
 
We are required to cause Sabine and its subsidiaries to forgive certain intercompany indebtedness owed by us to them under certain circumstances. We are also required to comply with certain financial covenants. The current financial covenants are:
 
 
•
 
maintenance of working capital of at least $150 million at all times;

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•
 
maintenance of tangible net worth of at least $400 million; and
 
 
•
 
maintenance of the aggregate amount of its eligible cash, eligible cash equivalents and eligible investments that are both (a) in or for the benefit of collateral accounts existing prior to the date of the credit agreement and (b) permitted thereby, of at least $75 million.
 
The covenants also provide for a cumulative cash flow test, as defined in the credit agreement, that, from July 1, 2001, shall not be less than or equal to zero. The credit agreement also limits the amount of future additional indebtedness that may be incurred by us and our subsidiaries, subject to certain exceptions, including a general exception for up to $75 million of indebtedness (which amount may be increased to up to $200 million if our consolidated debt to capitalization ratio (after giving pro forma effect to the incurrence of such indebtedness) is less than or equal to 0.60), no more than $25 million of which may mature before or concurrently with the credit agreement.
 
Events of default under the credit agreement include, among other things:
 
 
•
 
any failure by us to pay principal thereunder when due, or to pay interest or any other amount due within three days after the date due;
 
 
•
 
material inaccuracy of any representation or warranty given by us or any restricted subsidiary therein or in any document delivered pursuant thereto;
 
 
•
 
breach by us of certain covenants contained therein;
 
 
•
 
the continuance of a default by us or a subsidiary in the performance of or the compliance with other covenants and agreements for a period of 3 or 20 days depending on the covenant, in each case after the earlier of (x) the date upon which a responsible officer knew or reasonably should have known of such failure and (y) the date upon which written notice thereof is given to us by the administrative agent or any bank;
 
 
•
 
breach of or default under any indebtedness in excess of $5 million and continuance beyond any applicable grace period;
 
 
•
 
certain acts of bankruptcy or insolvency;
 
 
•
 
the occurrence of certain events under ERISA;
 
 
•
 
certain judgments, writs or warrants of attachment of similar process equal to or greater than $5 million remaining undischarged, unvacated, unbonded, or unstayed for a period of 10 days or non-monetary judgments, orders or decrees which do or would reasonably be expected to have a material adverse effect;
 
 
•
 
the occurrence of a change of control;
 
 
•
 
the revocation of or failure to renew licenses or permits where such revocation or failure to renew could reasonably be expected to have a material adverse effect;
 
 
•
 
the failure of the liens of the banks to be first priority perfected liens, subject to certain permitted liens or unenforceability or written assertion of limitation or unenforceability by PRG or any subsidiary, of any collateral document; or
 
 
•
 
Premcor USA incurs on or after August 23, 2001 any secured or unsecured indebtedness in the aggregate in excess of $25 million.
 
We must amend this credit agreement to extend the maturity date from August 23, 2003 to three years from closing of the amendment and obtain various waivers and approvals in order to consummate the debt financing and the acquisition of the Memphis refinery. In addition, we are seeking to amend and restate this credit agreement to, among other things, increase the capacity under the agreement from $650 million to the lesser of

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$750 million or the amount available under the borrowing base; and increase the sub-limit for cash borrowings from $50 million to $200 million, subject to certain restrictions. Certain covenants relating to minimum cash requirements, permitted indebtedness and minimum net worth requirements will also be modified. There are no assurances that we will be able to obtain the necessary extension, waivers and approvals or enter into an amended and restated credit agreement on these terms or at all.
 
Premcor USA
 
11 1/2% Subordinated Debentures.    In October 1997, Premcor USA Inc. issued 63,000 shares of 11 1/2% senior cumulative exchangeable preferred stock, stated value $1,000 per share. Premcor USA gave notice on March 1, 2002 to exchange the 11 1/2% exchangeable preferred stock for 11 1/2% subordinated debentures of Premcor USA, due 2009. The exchange of $104.2 million aggregate liquidation preference of 11 1/2% exchangeable preferred stock for $104.2 million aggregate principal amount of subordinated debentures was consummated effective April 1, 2002. In 2002, Premcor USA used contributions from us from the proceeds of our IPO to purchase $57.5 million in aggregate principal amount of the 11 1/2% subordinated debentures at a purchase price of 105.750% of their principal amount. Premcor USA may redeem the subordinated debentures on or after October 1, 2002, in whole or in part, at a redemption price equal to 105.750%. The redemption prices decline yearly to par on October 1, 2005, plus accrued and unpaid interest to the date of redemption. Upon a change of control occurring after October 1, 2005, Premcor USA is required to offer to purchase all outstanding subordinated debentures at par plus accrued and unpaid interest, if any. We intend to defease the outstanding 11 1/2% subordinated debentures prior to the closing of the debt financing and thereafter redeem them with the proceeds from this offer.
 
Port Arthur Finance Corp.
 
12 1/2% Senior Secured Notes.    In August 1999, Port Arthur Finance Corp. issued $255 million of 12 1/2% senior secured notes, of which $4.3 million was repaid on July 15, 2002. The notes are secured by certain of the assets of Port Arthur Finance Corp. and Port Arthur Coker Company. The collateral does not include PACC’s crude oil inventory, refined or intermediate products or any proceeds of the foregoing that are cash or cash equivalents and is shared ratably among the senior lenders pursuant to a common security agreement. Each of PRG, Port Arthur Coker Company, Sabine River Holding and Neches River Holding have unconditionally guaranteed, on a joint and several basis, all the obligations of Port Arthur Finance Corp. under the notes. The notes amortize over time, with principal payments due semi-annually on January 15th and July 15th until January 15, 2009. We may redeem all of the notes at any time at a redemption price equal to par plus accrued and unpaid interest plus a make-whole premium which is based on the rates of treasury securities with average lives comparable to the average life of the remaining scheduled payments plus 75 basis points.
 
Restrictive Covenants
 
The 12 1/2% senior secured notes contain covenants which, among other things, limit the ability of PRG, Port Arthur Coker Company, Port Arthur Finance Corp., Sabine River Holding and Neches River Holdings to:
 
 
•
 
amend or modify their constitutive or governing documents;
 
 
•
 
conduct any business other than the business of the heavy oil upgrade project;
 
 
•
 
sell, assign, lease, transfer or otherwise dispose of project property without the consent of the lenders (and where applicable secured parties), with certain exceptions;
 
 
•
 
incur debt; and
 
 
•
 
make investments or advances or loans.
 
Port Arthur Coker Company is subject to restrictions on the making of distributions to its general partner Sabine River Holding and its limited partner Neches River Holding. Port Arthur Coker Company is required to fund certain restricted cash accounts to be used for future capital expenditures, tax payments, major maintenance, and debt repayments.

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SHARES ELIGIBLE FOR FUTURE SALE
 
Upon the closing of this offering we will have outstanding an aggregate of approximately 70,543,935 shares of common stock, assuming no exercise of outstanding options or exercise of the over-allotment option. In addition, in connection with the Memphis refinery acquisition, under certain circumstances, we may pay up to $100 million of the purchase price through the issuance of our shares of common stock instead of cash. These shares of common stock would be valued at $15.00 per share less an underwriting discount. See “The Acquisition of the Memphis Refinery—Overview of the Acquisition.” We are also currently evaluating several other refinery acquisitions, some of which may be significant. Any other significant acquisition may require us to issue shares of our common stock or securities linked to shares of our common stock to finance all or a portion of such acquisition.
 
Of the outstanding shares, the 18,000,000 shares sold in our IPO and the 12,500,000 shares sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except that any shares held by our affiliates, as that term is defined under Rule 144 of the Securities Act, may be sold only in compliance with the limitations described below. The remaining shares of common stock will be deemed restricted securities as defined under Rule 144. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rule 144 or 144(k) under the Securities Act, which we summarize below,
 
Subject to the provisions of Rule 144 and 144(k), additional shares of our common stock will be available for sale in the public market under exemptions from registration requirements as follows:
 
Rule 144
 
In general, under Rule 144 as currently in effect, a person (or persons whose shares are required to be aggregated), including an affiliate, who has beneficially owned shares of our common stock for at least one year, is entitled to sell in any three-month period a number of shares that does not exceed the greater of:
 
 
•
 
1% of the then outstanding shares of common stock, or approximately 705,439 shares, assuming no exercise of the over-allotment option; and
 
 
•
 
the average weekly trading volume in the common stock on the New York Stock Exchange during the four calendar weeks preceding the date on which notice of sale is filed, subject to restrictions.
 
Sales under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.
 
Rule 144(k)
 
In addition, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale and who has beneficially owned the shares proposed to be sold for at least two years, would be entitled to sell those shares under Rule 144(k) without regard to the manner of sale, public information, volume limitation or notice requirements of Rule 144. To the extent that our affiliates sell their shares, other than pursuant to Rule 144, Rule 144(k) or a registration statement, the purchaser receives restricted securities and the purchaser’s holding period for the purpose of effecting a sale under Rule 144 commences on the date of transfer from the affiliate.
 
Lock-Up Agreements
 
In connection with this offering, we, our directors and executive officers, Blackstone and Occidental, owning an aggregate of 36,469,406 shares, have agreed that none of us will sell, directly or indirectly, subject to certain exceptions, any shares of our common stock for a period of 90 days from the date of this prospectus, without the prior written consent of Morgan Stanley & Co. Incorporated. Morgan Stanley & Co. Incorporated, in its sole discretion, may release the shares subject to the lock-up agreements in whole or in part at any time with or without notice. When determining whether to release shares from the lock-up agreements, Morgan

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Stanley & Co. Incorporated will consider, among other factors, the stockholder’s reasons for requesting the release, the number of shares for which the release is being requested and market conditions at the time. Morgan Stanley & Co. Incorporated does not at this time have any intention of releasing any of the shares subject to the lock-up agreements prior to the expiration of the lock-up period.
 
We have agreed not to sell or otherwise dispose of any shares of our common stock during the 90-day period following the date of this prospectus, except we may issue, and grant options to purchase, shares of common stock under our employee benefit plans referred to in this prospectus. In addition, we may issue shares of common stock in connection with any acquisition of another company if the terms of the issuance provide that the common stock may not be resold prior to the expiration of the 90-day period described above.
 
Stock Options
 
Options to purchase an aggregate of approximately 5,131,430 shares of our common stock will be outstanding as of the closing of this offering. Of these options, 424,530 will have vested at or prior to the closing of this offering. Of the remaining options, approximately 3,948,500 are time vesting options which will vest over the next three years, 547,500 are time vesting options which will vest over the next five years and 210,900 are performance vesting options which will vest seven years from the date of grant, unless accelerated in accordance with their terms. For further discussion regarding our options granted under our stock option plans, see “Management—Long-Term Performance.”
 
We have filed a registration statement on Form S-8 under the Securities Act registering all shares of common stock subject to outstanding stock options and options issuable under our stock incentive plans and shares of certain of our officers and directors. Shares covered by this registration statement are eligible for sale in the public markets, other than shares owned by our affiliates, which may be sold in the public market if they are registered or qualify for an exemption from registration under Rule 144.
 
Registration Rights
 
Occidental has the right on one occasion to request that we effect the registration of all or part of its shares of our common stock. In addition, Occidental has the right to include its shares in any registered public offering by us, which it has waived in connection with this offering. We are obligated to use our reasonable best efforts to effect the registration of the Occidental shares along with the other shares, absent a determination that the registration of the Occidental shares will adversely impact the offering of our other shares.
 
Marshall A. Cohen has the right to include his holdings of up to 116,161 shares of our common stock and shares issuable upon the exercise of stock options in certain registered public offerings by us, which he has waived in connection with this offering. We are obligated to use our reasonable efforts to register Marshall A. Cohen’s holdings of our common stock, absent a determination that the registration of his shares will adversely impact the offering of our other shares.
 
Blackstone has the right, on up to three occasions, to request that we effect the registration of all or part of its shares of our common stock. We are obligated to use our best efforts to effect the registration of all of the shares of which Blackstone requests except when in the opinion of the underwriter the number of securities requested to be registered is likely to adversely impact such offering. Blackstone also has the right to include its shares in certain registered public offerings by us, which it has waived in connection with this offering. We are obligated to use our best efforts to effect the registration of the Blackstone shares along with the other shares, absent a determination by the underwriter that such registration exceeds the largest number of securities which can be sold without adversely impacting the offering.
 
If the sellers receive shares of our common stock as part of the consideration for the Memphis refinery acquisition, they will also have the right, from time to time, to require us to register their stock for resale and will also have the right to include their shares in future registration statements filed by us. See “The Acquisition of the Memphis Refinery.”

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CERTAIN U.S. TAX CONSEQUENCES TO NON-U.S. HOLDERS
 
General
 
The following summary describes the material U.S. federal income and estate tax consequences of the ownership of common stock by a Non-U.S. Holder (as defined below) as of the date hereof. This discussion does not address all aspects of U.S. federal income and estate taxes and does not deal with foreign, state and local tax consequences that may be relevant to Non-U.S. Holders in light of their personal circumstances. Special rules may apply to certain Non-U.S. Holders, such as “controlled foreign corporations,” “passive foreign investment companies,” “foreign personal holding companies,” individuals who are U.S. expatriates and corporations that accumulate earnings to avoid U.S. federal income tax, that are subject to special treatment under the Internal Revenue Code of 1986, as amended, or the Code. Those individuals or entities should consult their own tax advisors to determine the U.S. federal, state, local and other tax consequences that may be relevant to them. Furthermore, all Non-U.S. Holders should consult their U.S. tax advisors regarding the appropriate documentation and certifications described below. The discussion below is based upon the provisions of the Code and regulations, rulings and judicial decisions thereunder as of the date hereof, and such authorities may be repealed, revoked or modified, possibly with retroactive effect, so as to result in U.S. federal income tax consequences different from those discussed below. If a partnership holds common stock, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. A holder that is a partner in a partnership holding the common stock should consult its own tax advisor. Persons considering the purchase, ownership or disposition of common stock should consult their own tax advisors concerning the U.S. federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.
 
As used herein, a Non-U.S. Holder of common stock means a beneficial owner that is an individual or entity other than (1) a citizen or resident of the United States, (2) a corporation or partnership (or other entity properly classified as a corporation or partnership for U.S. federal income tax purposes) created or organized in or under the laws of the United States or any state thereof (including the District of Columbia), (3) an estate the income of which is subject to U.S. federal income taxation regardless of its source or (4) a trust (A) that is subject to the primary supervision of a court within the United States and the control of one or more U.S. persons as described in section 7701(a)(30) of the Code or (B) that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person.
 
Dividends
 
Dividends paid to a Non-U.S. Holder of common stock generally will be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be specified by an applicable income tax treaty. However, dividends that are effectively connected with the conduct of a trade or business by the Non-U.S. Holder within the United States and, where a tax treaty applies, are attributable to United States permanent establishment of the Non-U.S. Holder, are not subject to the withholding tax, but instead are subject to U.S. federal income tax on a net income basis at applicable graduated individual or corporate rates. Certain certification and disclosure requirements must be complied with in order for effectively connected income to be exempt from withholding. Any such effectively connected dividends received by a foreign corporation may, under certain circumstances, be subject to an additional branch profits tax at a 30% rate or a lower rate as may be specified by an applicable income tax treaty.
 
A Non-U.S. Holder of common stock who wishes to claim an exemption from, or reduction in, withholding under the benefit of an applicable treaty rate (and avoid backup withholding as discussed below) for dividends, will be required to provide us or their paying agent with an Internal Revenue Service Form W-8BEN (generally for persons that are not partnerships or trusts it will be Form W-8BEN) and satisfy certain certification requirements of applicable U.S. Treasury regulations. Where dividends are paid to a Non-U.S. Holder that is a partnership or other pass-through entity, persons holding an interest in the entity may also be required to provide the certification.

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A Non-U.S. Holder of common stock eligible for a reduced rate of U.S. withholding tax under an income tax treaty may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the Internal Revenue Service, or the IRS.
 
Gain on Disposition of Common Stock
 
A Non-U.S. Holder generally will not be subject to U.S. federal income tax with respect to gain recognized on a sale or other disposition of common stock unless (1) the gain is effectively connected with a trade or business in the United States of the Non-U.S. Holder, and, where a tax treaty applies, is attributable to a U.S. permanent establishment of the Non-U.S. Holder, (2) such holder is an individual that holds the common stock as a capital asset and is present in the United States for 183 or more days in the taxable year of the sale or other disposition and certain other conditions are met, or (3) the company is or has been a U.S. real property holding corporation for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition and the Non-U.S. Holder’s holding period for the common stock.
 
An individual Non-U.S. Holder described in clause (1) above will be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates. An individual Non-U.S. Holder described in clause (2) above will be subject to a flat 30% tax on the gain derived from the sale, which may be offset by U.S. source capital losses (even though the individual is not considered a resident of the U.S.). If a Non-U.S. Holder that is a foreign corporation falls under clause (1) above, it will be subject to tax on its gain under regular graduated U.S. federal income tax rates and, in addition, may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty.
 
Our company believes it should not be and does not anticipate becoming a “U.S. real property holding corporation” for United States federal income tax purposes. However, if we are or become a U.S. real property holding corporation, then assuming the common stock is regularly traded on an established securities market, a Non-U.S. Holder who holds or held (at any time during the shorter of the five-year period ending on the date of disposition and the Non-U.S. Holder’s holding period for the common stock) more than 5% of the common stock will be subject to U.S. federal income tax on the disposition of the common stock.
 
U.S. Estate Tax
 
Common stock held by an individual Non-U.S. Holder at the time of death will be included in such holder’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise.
 
Information Reporting and Backup Withholding
 
Our company must report annually to the IRS and to each Non-U.S. Holder the amount of dividends paid to that holder and the tax withheld with respect to those dividends, regardless of whether withholding was required. Copies of the information returns reporting those dividends and withholding may also be made available to the tax authorities in the country in which the Non-U.S. Holder resides under the provisions of an applicable income tax treaty.
 
A Non-U.S. Holder will be subject to backup withholding unless applicable certification requirements are met.
 
Proceeds of a sale of common stock paid within the United States or through certain U.S. related financial intermediaries are subject to both backup withholding and information reporting unless the beneficial owner certifies under penalties of perjury that it is a Non-U.S. Holder (and the payor does not have actual knowledge that the beneficial owner is a U.S. person), or the holder establishes another exemption.
 
Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against such holder’s U.S. federal income tax liability if the required information is furnished to the IRS.

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UNDERWRITERS
 
Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. Incorporated, Credit Suisse First Boston LLC, Deutsche Bank Securities Inc. and Goldman, Sachs & Co. are acting as representatives, have severally agreed to purchase, and we have agreed to sell to them, severally, the number of shares of our common stock indicated below:
 
Name
   
Number
of Shares
Morgan Stanley & Co. Incorporated
   
5,125,000
Credit Suisse First Boston LLC
   
2,625,000
Deutsche Bank Securities Inc. 
   
2,375,000
Goldman, Sachs & Co.
   
2,125,000
Credit Lyonnais Securities (USA) Inc.
   
50,000
Fahnestock & Co. Inc. 
   
50,000
Friedman, Billings, Ramsey & Co., Inc. 
   
50,000
Petrie Parkman & Co.
   
50,000
Wells Fargo Van Kasper, LLC
   
50,000
    
Total
   
12,500,000
    
 
The underwriters are offering the shares of common stock subject to their acceptance of the shares from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares of our common stock offered by this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the shares of common stock offered by this prospectus if any such shares are taken. However, the underwriters are not required to take or pay for the shares covered by the underwriters’ over-allotment option described below.
 
The underwriters initially propose to offer part of the shares of common stock directly to the public at the public offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $0.48 a share under the public offering price. After the initial offering of the shares of common stock, the offering price and other selling terms may from time to time be varied by the representatives.
 
We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an aggregate of 1,875,000 additional shares of common stock at the public offering price set forth on the cover page of this prospectus, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus. To the extent the option is exercised, each underwriter will become obligated, subject to specified conditions, to purchase approximately the same percentage of the additional shares of common stock as the number listed next to the underwriter’s name in the table above bears to the total number of shares set forth next to the names of all underwriters in that table.
 
If the underwriters’ option is exercised in full, the total price to the public would be $287.5 million, the total underwriting discounts and commissions would be $11.5 million and the total proceeds to us would be $276.0 million.
 
The underwriters have informed us that they do not intend sales to discretionary accounts to exceed five percent of the total number of shares of common stock offered by them.
 
We, our directors and executive officers, Blackstone and Occidental, owning an aggregate of 36,469,406 shares, have agreed that, without the prior written consent of Morgan Stanley & Co. Incorporated on behalf of the underwriters, none of us will, during the period ending 90 days after the date of this prospectus:
 
 
•
 
offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend, or otherwise transfer or dispose of,

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directly or indirectly, any shares of common stock or any securities convertible into or exercisable or exchangeable for shares of common stock; or
 
 
•
 
enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock;
 
whether any such transaction described above is to be settled by delivery of common stock or such other securities, in cash or otherwise, or, in the case of our company, otherwise file a registration statement, other than a registration statement on Form S-8 covering shares of common stock subject to outstanding options or options to be issued under our stock option plans.
 
The restrictions described in this paragraph do not apply to:
 
 
•
 
the sale of shares of common stock to the underwriters;
 
 
•
 
the issuance by us of shares of common stock upon the exercise of an option or a warrant or the conversion of a security outstanding on the date of this prospectus of which the underwriters have been advised in writing;
 
 
•
 
the issuance of common stock or the grant of an option to purchase common stock under our stock plans described in this prospectus;
 
 
•
 
the issuance of common stock in connection with the acquisition of another company, if recipients of the common stock agree to be bound by the 90-day lock-up described above, and the filing of a registration statement with respect thereto; or
 
 
•
 
transactions by any person other than us relating to shares of common stock or other securities acquired in open market transactions after the completion of the offering of the shares.
 
In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may sell more shares than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is “covered” if the short position is no greater than the number of shares available for purchase by the underwriters under the over-allotment option. The underwriters can close out a covered short sale by exercising the over-allotment option or purchasing shares in the open market. In determining the source of shares to close out a covered short sale, the underwriters will consider, among other things, the open market price of shares compared to the price available under the over-allotment option. The underwriters may also sell shares in excess of the over-allotment option, creating a “naked” short position. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. In addition, to cover any over-allotment or to stabilize the price of our common stock, the underwriters may bid for, and purchase, shares of common stock in the open market. Finally, the underwriting syndicate may also reclaim selling concessions allowed to an underwriter or a dealer for distributing common stock in transactions to cover syndicate short positions, in stabilization transactions or otherwise. Any of these activities may stabilize or maintain the market price of the common stock above independent market levels or prevent or retard a decline in the market price of our common stock. The underwriters are not required to engage in these activities, and may end any of these activities at any time.
 
A prospectus in electronic format may be made available on the websites maintained by one or more underwriters. The underwriters may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the lead manager to underwriters that may make internet distributions on the same basis as other allocations.

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From time to time, some of the underwriters and their affiliates have provided, and may continue to provide, investment banking and commercial banking services to us for fees and commissions that we believe are customary. For example, the representatives will act as initial purchasers in our concurrent debt financing. Additionally, affiliates of Deutsche Bank Securities Inc. are participants in our existing credit facility, and we expect that affiliates of one or more of the underwriters will participate in our amended and restated credit facility. Affiliates of Morgan Stanley & Co. Incorporated have also committed to finance a portion of our acquisition of the Memphis refinery, if necessary, and are expected to enter into a crude oil supply and product off-take agreement with us. As part of the financing commitment, Morgan Stanley & Co. Incorporated will be offered a lead role in repayment or refinancing transactions with respect to funds provided to us under the commitment for three years from the date of this prospectus. This is deemed compensation by the NASD and is valued under NASD rules at 1% of the proceeds of the offering.
 
We and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS
 
The validity of our common stock offered hereby and other legal matters will be passed upon for us by Stroock & Stroock & Lavan LLP, New York, New York. The validity of our common stock offered hereby will be passed upon for the underwriters by Davis Polk & Wardwell, New York, New York.
 
EXPERTS
 
The financial statements as of December 31, 2001 and 2000, and for each of the three years in the period ended December 31, 2001, included in this prospectus and the related financial statement schedules included elsewhere in the registration statement have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports appearing herein and elsewhere in the registration statement, and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.
 
With respect to the unaudited interim financial information for the periods ended September 30, 2002 and 2001 included in this prospectus, Deloitte & Touche LLP have applied limited procedures in accordance with professional standards for a review of such information. However, as stated in their reports in our Quarterly Reports on Form 10-Q for the quarter ended September 30, 2002 and included in this prospectus, they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. Deloitte & Touche LLP are not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their reports on the unaudited interim financial information because those reports are not “reports” or a “part” of the registration statement prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Securities Act.
 
WHERE YOU CAN FIND ADDITIONAL INFORMATION
 
We have filed with the Securities and Exchange Commission a registration statement on Form S-1 with respect to the common stock offered in this prospectus. This prospectus is a part of the registration statement and, as permitted by the Securities and Exchange Commission’s rules, does not contain all of the information presented in the registration statement. Whenever a reference is made in this prospectus to one of our contracts or other documents, please be aware that this reference is not necessarily complete and that you should refer to the exhibits that are a part of the registration statement for a copy of the contract or other document. You may review a copy of the registration statement, including exhibits to the registration statement, at the Securities and Exchange Commission’s public reference room at 450 Fifth Street, N.W, Washington, D.C. 20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for further information on the operation of the public reference room. Our filings with the Securities and Exchange Commission are also available to the public through the Securities and Exchange Commission’s internet site at http://www.sec.gov.
 
We are subject to the informational requirements of the Exchange Act, and in accordance with the Exchange Act have filed annual, quarterly and current reports and other information with the Securities and Exchange Commission. You may read and copy any documents filed by us at the address set forth above.
 
You may request copies of the filings, at no cost, by telephone at (203) 698-7500 or by mail at: Premcor Inc., 1700 East Putnam Avenue, Suite 500, Old Greenwich, Connecticut 06870, Attention: Investor Relations.

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GLOSSARY OF SELECTED TERMS
 
The following are definitions of certain terms used in this prospectus.
 
alkylation

   
A polymerization process uniting olefins and isoparaffins; particularly the reacting of butylene and isobutane, with sulfuric acid or hydrofluoric acid as a catalyst, to produce a high-octane, low-sensitivity blending agent for gasoline.
 
anode

   
A positively charged conductor that influences the flow of current in another conducting medium.
 
barrel
   
Common unit of measure in the oil industry which equates to 42 gallons.
 
blendstocks

   
Various compounds that are combined with gasoline from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.
 
bpd
   
Abbreviation for barrels per day.
 
btu

   
British thermal units: a measure of energy. One btu of heat is required to raise the temperature of one pound of water one degree fahrenheit.
 
by-products

   
Products that result from extracting high value products such as gasoline and diesel fuel from crude oil; these include black oil, sulfur, propane, petroleum coke and other products.
 
catalyst

   
A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
 
coker gross margin

   
The value of refined products derived from coker feedstocks less the cost of such coker feedstocks.
 
coker unit

   
A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into petroleum coke.
 
crack spread

   
A simplified model that measures the difference between the price for light products and crude oil. For example, a 3/2/1 crack spread is often referenced and represents the approximate gross margin resulting from processing one barrel of crude oil, being three barrels of crude oil to produce two barrels of gasoline and one barrel of diesel fuel.
 
crude unit

   
The initial refinery unit to process crude oil by separating the crude oil according to boiling point under high heat and low pressure to recover various hydrocarbon fractions.
 
distillates
   
Primarily diesel fuel, kerosene and jet fuel.
 
feedstocks

   
Hydrocarbon compounds, such as crude oil and natural gas liquids, that are processed and blended into refined products.
 
fluid catalytic cracking unit

   
Converts gas oil from the crude unit or coker unit into liquefied petroleum gas, distillate and gasoline blendstocks by applying heat in the presence of a catalyst.
 
fractionator
   
A cylindrical vessel designed to distill or separate compounds that have different vapor pressures at any given temperature. Also called stabilizer column, fractionating tower or bubble tower.

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heavy crude oil

   
A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.
 
hydrocracker unit

   
A refinery unit that converts low-value intermediates into gasoline, naphtha, kerosene and distillates under very high pressure in the presence of hydrogen and a catalyst.
 
independent refiner

   
A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.
 
light crude oil

   
A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
 
liquefied petroleum gas

   
Light hydrocarbon material gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling.
 
lost time
   
see “lost work day.”
 
lost time injury
   
Any injury that results in one or more lost work days.
 
lost time injury rate
   
The number of lost time injuries per 200,000 hours worked.
 
lost work day

   
The number of workdays (consecutive or not) beyond the day of injury or onset of illness the employee was away from work or limited to restricted work activity because of an occupational injury or illness.
 
    
(1) lost workdays—away from work. The number of workdays (consecutive or not) on which the employee would have worked but could not because of occupational injury or illness.
 
    
(2) lost workdays—restricted work activity. The number of workdays (consecutive or not) on which, because of injury or illness: (i) the employee was assigned to another job on a temporary basis; or (ii) the employee worked at a permanent job less than full time; or (iii) the employee worked at a permanently assigned job but could not perform all duties normally connected with it.
 
    
The number of days away from work or days of restricted work activity does not include the day of injury or onset of illness or any days on which the employee would not have worked even though able to work.
 
MTBE

   
Methyl Tertiary Butyl Ether, an ether produced from the reaction of isobutylene and methanol specifically for use as a gasoline blendstock. The EPA requires MTBE or other oxygenates to be blended into reformulated gasoline.
 
mbpd
   
thousand barrels per day.
 
Maya

   
A heavy, sour crude oil from Mexico characterized by an API gravity of approximately 21.5 and a sulfur content of approximately 3.6 weight percent.
 
merchant refiner

   
A refiner that is not vertically integrated to distribute its refinery products through branded retail outlets.
 
naphtha
   
The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane.
 

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olefin cracker

   
A chemical processing plant designed to produce predominantly ethylene and propylene for use in the production of plastics and other chemicals.
 
PADD I
   
East Coast Petroleum Area for Defense District.
 
PADD II
   
Midwest Petroleum Area for Defense District.
 
PADD III
   
Gulf Coast Petroleum Area for Defense District.
 
PADD IV
   
Rocky Mountains Petroleum Area for Defense District.
 
PADD V
   
West Coast Petroleum Area for Defense District.
 
particulate matter

   
Material suspended in the air in the form of minute solid particles or liquid droplets, especially when considered as an atmospheric pollutant.
 
petroleum coke

   
A coal-like substance that can be burned to generate electricity or used as a hardener in concrete.
 
propylene

   
A commodity chemical, derived from petroleum hydrocarbon cracking processes, which is used in the production of plastics and other chemicals.
 
pure-play refiner

   
A refiner without either crude oil production operations or retail distribution operations (that is, both an independent and a merchant refiner).
 
pyrolysis gasoline or pygas
   
A high octane blendstock produced as a by-product from an olefin cracker.
 
rack marketing system

   
A network of assets designed to deliver transportation fuels into trucks to wholesale customers.
 
rated crude oil capacity

   
The crude oil processing capacity of a refinery that is established by engineering design.
 
recordable injury

   
An injury, as defined by OSHA. All work-related deaths and illnesses, and those work-related injuries which result in loss of consciousness, restriction of work or motion, transfer to another job, or require medical treatment beyond first aid.
 
recordable injury rate
   
The number of recordable injuries per 200,000 hours worked.
 
refined products

   
Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.
 
refinery conversion

   
The ability of a refinery to produce high-value lighter refined products such as gasoline, diesel fuel and jet fuel from crude oil and other feedstocks.
 
reformer unit

   
A refinery unit that processes naphtha and converts it to high-octane gasoline by using a platinum/rhenium catalyst. Also known as a platformer.
 
reformulated gasoline

   
The composition and properties of which meet the requirements of the reformulated gasoline regulations.
 
single train
   
A refinery processing configuration consisting of only one crude unit and several downstream conversion units with no significant amount of redundancy in such units.
sour crude oil

   
A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
 
spot market

   
A market in which commodities are bought and sold for cash and delivered immediately.
 

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sweet crude oil

   
A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
 
throughput
   
The volume per day processed through a unit or a refinery.
 
turnaround

   
A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years.
 
unbranded

   
A term used in connection with fuel or the sale of fuel into the spot or wholesale markets, rather than fuel or the sale of fuel directly to retail outlets.
 
utilization
   
Ratio of total refinery throughput to the rated capacity of the refinery.
 
WTI

   
West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 38 and 40 and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.
 
yield
   
The percentage of refined products that are produced from feedstocks.

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PREMCOR INC. AND SUBSIDIARIES
 
INDEX TO FINANCIAL STATEMENTS
 
    
Page
Annual Financial Statements:
     
Independent Auditors’ Report
   
F-2
Consolidated Balance Sheets as of December 31, 2000 and 2001
   
F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 2000, and 2001
   
F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 2000, and 2001
   
F-5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 1999, 2000, and 2001
   
F-6
Notes To Consolidated Financial Statements
   
F-7
Financial Statement Schedules
     
Independent Auditors’ Report
   
F-35
Schedule I—Condensed Financial Information of the Registrant
   
F-36
Schedule II—Valuation and Qualifying Accounts
   
F-40
Interim Financial Statements:
     
Independent Accountants’ Report
   
F-41
Condensed Consolidated Balance Sheets as of December 31, 2001 and September 30, 2002
   
F-42
Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2001 and 2002
   
F-43
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2001 and 2002
   
F-44
Notes to Condensed Consolidated Financial Statements
   
F-45

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Table of Contents
 
INDEPENDENT AUDITORS’ REPORT
 
To the Board of Directors of Premcor Inc.:
 
We have audited the accompanying consolidated balance sheets of Premcor Inc. and subsidiaries (the “Company”) as of December 31, 2001 and 2000 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.
 
DELOITTE & TOUCHE LLP
 
St. Louis, Missouri
February 11, 2002 (March 29, 2002 as to Note 15, April 15, 2002 as to Note 10 and 19 and August 5, 2002 as to Note 2)

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PREMCOR INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
(dollars in millions, except per share data)
 
    
December 31,
  
    
2000
     
2001
  
ASSETS
                  
CURRENT ASSETS:
                  
Cash and cash equivalents
   
$
      290.1
 
   
$
      510.1
 
Short-term investments
   
 
1.7
 
   
 
1.7
 
Cash and cash equivalents restricted for debt service
   
 
—
 
   
 
30.8
 
Accounts receivable, net of allowance of $1.3 and $1.3
   
 
250.5
 
   
 
148.3
 
Inventories
   
 
378.3
 
   
 
318.3
 
Prepaid expenses and other
   
 
39.2
 
   
 
52.3
 
    
  
Total current assets
   
 
959.8
 
   
 
1,061.5
 
PROPERTY, PLANT AND EQUIPMENT, NET
   
 
1,348.3
 
   
 
1,299.6
 
OTHER ASSETS
   
 
161.0
 
   
 
148.7
 
    
  
    
$
2,469.1
 
   
$
2,509.8
 
    
  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                  
CURRENT LIABILITIES:
                  
Accounts payable
   
$
505.2
 
   
$
366.4
 
Accrued expenses and other
   
 
89.7
 
   
 
95.4
 
Accrued taxes other than income
   
 
38.4
 
   
 
35.7
 
Current portion of long-term debt
   
 
1.5
 
   
 
81.4
 
    
  
Total current liabilities
   
 
634.8
 
   
 
578.9
 
LONG-TERM DEBT
   
 
1,514.5
 
   
 
1,391.4
 
DEFERRED INCOME TAXES
   
 
—
 
   
 
16.7
 
OTHER LONG-TERM LIABILITIES
   
 
65.7
 
   
 
109.1
 
COMMITMENTS AND CONTINGENCIES
   
 
—
 
   
 
—
 
MINORITY INTEREST
   
 
11.4
 
   
 
24.2
 
EXCHANGEABLE PREFERRED STOCK OF SUBSIDIARY
                  
($0.01 par value per share; 250,000 shares authorized, 88,110 shares issued and outstanding in 2000 and 92,284 shares issued and outstanding in 2001)
   
 
90.6
 
   
 
94.8
 
COMMON STOCKHOLDERS’ EQUITY:
                  
Common, $0.01 par value per share, 53,000,000 authorized, 25,720,589 issued and outstanding in 2000 and in 2001; Class F Common, $0.01 par value, 7,000,000 authorized, 6,101,010 issued and outstanding in 2000 and 2001
   
 
0.3
 
   
 
0.3
 
Paid-in capital
   
 
323.7
 
   
 
323.7
 
Retained deficit
   
 
(171.9
)
   
 
(29.3
)
    
  
Total common stockholders’ equity
   
 
152.1
 
   
 
294.7
 
    
  
    
$
2,469.1
 
   
$
2,509.8
 
    
  
 
The accompanying notes are an integral part of these statements.

F-3

Table of Contents
 
PREMCOR INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars and shares in millions, except per share amount)
 
    
For the Year Ended December 31,
  
    
1999
     
2000
     
2001
  
NET SALES AND OPERATING REVENUES
   
$
    4,520.5
 
   
$
    7,301.7
 
   
$
    6,417.5
 
EXPENSES:
                           
Cost of sales
   
 
4,099.8
 
   
 
6,562.5
 
   
 
5,251.4
 
Operating expenses
   
 
402.8
 
   
 
467.7
 
   
 
467.7
 
General and administrative expenses
   
 
51.5
 
   
 
53.0
 
   
 
63.3
 
Depreciation
   
 
36.1
 
   
 
37.1
 
   
 
53.2
 
Amortization
   
 
27.0
 
   
 
34.7
 
   
 
38.7
 
Inventory recovery from market write-down
   
 
(105.8
)
   
 
—
 
   
 
—
 
Refinery restructuring and other charges
   
 
—
 
   
 
—
 
   
 
176.2
 
    
  
  
    
 
4,511.4
 
   
 
7,155.0
 
   
 
6,050.5
 
    
  
  
OPERATING INCOME
   
 
9.1
 
   
 
146.7
 
   
 
367.0
 
Interest and finance expense
   
 
(103.5
)
   
 
(99.6
)
   
 
(158.4
)
Gain on extinguishment of long-term debt
   
 
—
 
   
 
—
 
   
 
8.7
 
Interest income
   
 
12.0
 
   
 
17.4
 
   
 
18.9
 
    
  
  
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST
   
 
(82.4
)
   
 
64.5
 
   
 
236.2
 
Income tax (provision) benefit
   
 
12.0
 
   
 
25.8
 
   
 
(52.4
)
Minority interest in subsidiary
   
 
1.4
 
   
 
(0.6
)
   
 
(12.8
)
    
  
  
INCOME (LOSS) FROM CONTINUING OPERATIONS
  
 
(69.0
)
   
 
89.7
 
   
 
171.0
 
Discontinued operations:
                           
Loss from operations, net of income tax benefit (1999—$2.7; 2001—$11.5)
   
 
(4.3
)
   
 
—
 
   
 
(18.0
)
Gain on disposal of discontinued operations, net of income tax provision of $23.7
   
 
36.9
 
   
 
—
 
   
 
—
 
    
  
  
NET INCOME (LOSS)
   
 
(36.4
)
   
 
89.7
 
   
 
153.0
 
Preferred stock dividends
   
 
(8.6
)
   
 
(9.6
)
   
 
(10.4
)
    
  
  
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
   
$
(45.0
)
   
$
80.1
 
   
$
142.6
 
    
  
  
Net income (loss) per common share
                           
Basic:
                           
Income (loss) from continuing operations
   
$
(3.59
)
   
$
2.79
 
   
$
5.05
 
Discontinued operations
   
 
1.51
 
   
 
—
 
   
 
(0.57
)
    
  
  
Net income (loss)
   
$
(2.08
)
   
$
2.79
 
   
$
4.48
 
    
  
  
Weighted average common shares outstanding
   
 
21.6
 
   
 
28.8
 
   
 
31.8
 
Diluted:
                           
Income (loss) from continuing operations
   
$
(3.59
)
   
$
2.55
 
   
$
4.65
 
Discontinued operations
   
 
1.51
 
   
 
—
 
   
 
(0.52
)
    
  
  
Net income (loss)
   
$
(2.08
)
   
$
2.55
 
   
$
4.13
 
    
  
  
Weighted average common shares outstanding
   
 
21.6
 
   
 
31.5
 
   
 
34.5
 
 
The accompanying notes are an integral part of these statements.

F-4

Table of Contents
 
PREMCOR INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in millions)
 
    
For the Year Ended December 31,
  
    
1999
     
2000
     
2001
  
CASH FLOWS FROM OPERATING ACTIVITIES:
                           
Net income (loss)
   
$
(36.4
)
   
$
89.7
 
   
$
153.0
 
Discontinued operations
   
 
4.3
 
   
 
—
 
   
 
18.0
 
Adjustments:
                           
Depreciation
   
 
36.1
 
   
 
37.1
 
   
 
53.2
 
Amortization
   
 
34.6
 
   
 
45.5
 
   
 
50.3
 
Deferred income taxes
   
 
8.2
 
   
 
(24.2
)
   
 
52.0
 
Gain on sale of retail division
   
 
(36.9
)
   
 
—
 
   
 
—
 
Inventory recovery from market write-down
   
 
(105.8
)
   
 
—
 
   
 
—
 
Minority interest
   
 
(1.4
)
   
 
0.6
 
   
 
12.8
 
Refinery restructuring and other charges
   
 
—
 
   
 
—
 
   
 
118.5
 
Other, net
   
 
17.8
 
   
 
(0.2
)
   
 
1.5
 
Cash provided by (reinvested in) working capital
                           
Accounts receivable, prepaid expenses and other
   
 
(66.0
)
   
 
(54.6
)
   
 
89.1
 
Inventories
   
 
122.6
 
   
 
(126.1
)
   
 
60.0
 
Accounts payable, accrued expenses, taxes other than income, and other
   
 
133.6
 
   
 
156.6
 
   
 
(136.5
)
Cash and cash equivalents restricted for debt service
   
 
—
 
   
 
—
 
   
 
(24.3
)
    
  
  
Net cash provided by operating activities of continuing operations
   
 
110.7
 
   
 
124.4
 
   
 
447.6
 
Net cash used in operating activities of discontinued operations
   
 
(25.2
)
   
 
—
 
   
 
(8.4
)
    
  
  
Net cash provided by operating activities
   
 
85.5
 
   
 
124.4
 
   
 
439.2
 
    
  
  
CASH FLOWS FROM INVESTING ACTIVITIES:
                           
Expenditures for property, plant and equipment
   
 
(438.2
)
   
 
(390.7
)
   
 
(94.5
)
Expenditures for turnaround
   
 
(77.9
)
   
 
(31.5
)
   
 
(49.2
)
Cash and cash equivalents restricted for investment in capital additions
   
 
(46.6
)
   
 
46.6
 
   
 
(9.9
)
Proceeds from sale of assets
   
 
248.5
 
   
 
0.5
 
   
 
0.7
 
Equity investment in Clark Retail Enterprises
   
 
(5.0
)
   
 
—
 
   
 
—
 
Purchases of short-term investments
   
 
(3.2
)
   
 
(1.7
)
   
 
(1.7
)
Sales and maturities of short-term investments
   
 
2.9
 
   
 
1.5
 
   
 
1.7
 
Discontinued operations
   
 
(1.8
)
   
 
—
 
   
 
—
 
    
  
  
Net cash used in investing activities
   
 
(321.3
)
   
 
(375.3
)
   
 
(152.9
)
    
  
  
CASH FLOWS FROM FINANCING ACTIVITIES:
                           
Proceeds from issuance of long-term debt
   
 
360.0
 
   
 
182.6
 
   
 
10.0
 
Repurchase of long-term debt
   
 
—
 
   
 
—
 
   
 
(57.8
)
Cash and cash equivalents restricted for debt repayment
   
 
—
 
   
 
—
 
   
 
(6.5
)
Proceeds from issuance of common stock
   
 
61.0
 
   
 
57.3
 
   
 
—
 
Contribution from minority interest
   
 
5.7
 
   
 
6.5
 
   
 
—
 
Repurchase of common stock
   
 
(3.6
)
   
 
—
 
   
 
—
 
Capital lease payments
   
 
(3.3
)
   
 
(7.3
)
   
 
(1.5
)
Deferred financing costs
   
 
(25.9
)
   
 
(4.3
)
   
 
(10.2
)
Preferred stock dividend
   
 
—
 
   
 
—
 
   
 
(0.3
)
    
  
  
Net cash provided by (used in) financing activities
   
 
393.9
 
   
 
234.8
 
   
 
(66.3
)
    
  
  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
   
 
158.1
 
   
 
(16.1
)
   
 
220.0
 
CASH AND CASH EQUIVALENTS, beginning of period
   
 
148.1
 
   
 
306.2
 
   
 
290.1
 
    
  
  
CASH AND CASH EQUIVALENTS, end of period
   
$
306.2
 
   
$
290.1
 
   
$
510.1
 
    
  
  
 
The accompanying notes are an integral part of these statements.

F-5

Table of Contents
 
PREMCOR INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(dollars in millions)
 
    
Common Stock
   
Class F Common
   
Additional Paid-In Capital
       
Retained Earnings (Accumulated Deficit)
  
    
Shares
   
Par Value
   
Shares
   
Par Value
        
BALANCE, December 31, 1998
   
13,767,829
   
$
  0.1
   
6,101,010
   
$
  0.1
   
$
209.0
 
     
$
(207.0
)
Net loss
   
—
   
 
—
   
—
   
 
—
   
 
—
 
     
 
(45.0
)
Stock issuance
   
6,076,060
   
 
0.1
   
—
   
 
—
   
 
61.0
 
     
 
—
 
Redemption of common stock
   
—
   
 
—
   
—
   
 
—
   
 
(3.6
)
     
 
—
 
    
  
  
  
  
    
BALANCE, December 31, 1999
   
19,843,889
   
 
0.2
   
6,101,010
   
 
0.1
   
 
266.4
 
     
 
(252.0
)
Net income
   
—
   
 
—
   
—
   
 
—
   
 
—
 
     
 
80.1
 
Stock issuance
   
5,876,700
   
 
—
   
—
   
 
—
   
 
57.3
 
     
 
—
 
    
  
  
  
  
    
BALANCE, December 31, 2000
   
25,720,589
   
 
0.2
   
6,101,010
   
 
0.1
   
 
323.7
 
     
 
(171.9
)
Net income
   
—
   
 
—
   
—
   
 
—
   
 
—
 
     
 
142.6
 
    
  
  
  
  
    
BALANCE, December 31, 2001
   
25,720,589
   
$
0.2
   
6,101,010
   
$
0.1
   
$
  323.7
 
     
$
    (29.3
)
    
  
  
  
  
    
 
 
The accompanying notes are an integral part of these statements.

F-6

Table of Contents
 
PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 1999, 2000 and 2001
(Tabular dollar amounts in millions of US dollars)
 
1.    Nature of Business
 
Premcor Inc. (individually, “Premcor Inc.” and collectively with its subsidiaries, the “Company”), a Delaware corporation was incorporated in April 1999. The Company comprises one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. The Company owns and operates three refineries with a combined crude oil throughput capacity of 490,000 barrels per day (“bpd”). Our refineries are located in Port Arthur, Texas; Lima, Ohio; and Hartford, Illinois. The Company was formed pursuant to a share exchange agreement wherein all shares of Premcor USA Inc. (“Premcor USA”), were exchanged on a one-for-one basis for the shares of the Company. Premcor Inc.’s common equity is privately held and controlled by Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates (“Blackstone”) through its current voting interest of 80.2%. The Company’s other principal shareholder is a subsidiary of Occidental Petroleum Corporation (“Occidental”) with a current voting interest of 18.4%. Blackstone and Occidental exchanged their shares of Premcor USA for Premcor Inc. shares in May 1999 to facilitate the construction and financing of a heavy oil upgrade project as described below.
 
Premcor Inc. owns all of the outstanding common stock of Premcor USA and 90% of the outstanding common stock of Sabine River Holding Corp. (“Sabine”). Occidental owns the remaining 10% of the outstanding common stock of Sabine. The consolidated financial statements and footnotes represent the results of operations of Premcor USA and its subsidiaries through April 27, 1999 as the predecessor company of Premcor Inc.
 
Premcor USA, a Delaware corporation, was incorporated in 1988 as AOC Holdings, Inc. Its principal operating subsidiary is The Premcor Refining Group Inc. (“PRG”), a Delaware corporation formed in 1988 as Clark Oil & Refining Corporation. Premcor USA and the PRG changed their names in May 2000 after selling the “Clark” trade name as part of the sale of their retail division in July 1999. Since Premcor USA’s retail division was sold in 1999, the retail marketing operating results are segregated and reported as discontinued operations in the accompanying consolidated statements of operations and cash flows.
 
Sabine, a Delaware corporation, was incorporated in May 1999 and capitalized in August 1999. Its principal operating subsidiary is Port Arthur Coker Company L.P. (“PACC”). Sabine and PACC were formed to develop, construct, own, operate and finance a heavy oil processing facility that includes an 80,000 barrel per stream day delayed coking unit, a 35,000 barrel per stream day hydrocracker, a 417 long tons per day sulfur complex and related assets at PRG’s Port Arthur, Texas refinery (the “heavy oil upgrade project”). The heavy oil upgrade project became fully operational in January of 2001 and reached what is defined in the construction contract and financing documents as substantial reliability in September of 2001. Final completion of this project was achieved on December 28, 2001.
 
On September 27, 2001, the Company filed a registration statement on Form S-1 under the Securities Act of 1933, as amended, with the United States Securities and Exchange Commission in connection with a proposed initial public offering of its common stock. The Company retained Morgan Stanley & Co. Incorporated as the lead underwriter of this offering. Earlier in the year, the Company had retained the investment firm Credit Suisse First Boston and The Blackstone Group L.P. to serve as its financial advisors to assist the Company in its review of alternatives to maximize the value of the Company. No assurance was given that this review would result in any specific transaction. At the current time, the Company is not actively pursuing a specific transaction to maximize its value other than the proposed initial public offering of its common stock.
 
All of the operations of Premcor USA and Sabine are in the United States. These operations are related to the refining of crude oil and other petroleum feedstocks into petroleum products and are all considered part of

F-7

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

one business segment. The Company’s earnings and cash flows from operations are primarily dependent upon processing crude oil and selling quantities of refined petroleum products at margins sufficient to cover operating expenses. Crude oil and refined petroleum products are commodities, and factors largely out of the Company’s control can cause prices to vary, in a wide range, over a short period of time. This potential margin volatility can have a material effect on the financial position, current period earnings, and cash flows.
 
2.    Summary of Significant Accounting Policies
 
Principles of Consolidation
 
The accompanying consolidated financial statements include the accounts of Premcor USA and Sabine. Through Sabine, the consolidated financial statements include the accounts of Sabine’s wholly owned subsidiary Neches River Holding Corp. (“Neches”), and through Neches’s 99% limited partnership interest and Sabine’s 1% general partnership interest in PACC, 100% of PACC and PACC’s wholly owned subsidiary, Port Arthur Finance Corp. (“PAFC”). Through Premcor USA, the consolidated financial statements include the accounts of The Premcor Pipeline Co. and PRG, including its wholly owned subsidiaries Premcor P.A. Pipeline Company and Premcor Investments Inc.
 
The Company consolidates the assets, liabilities, and results of operations of subsidiaries in which the Company has a controlling interest. Investments in companies in which the Company owns 20 percent to 50 percent voting control are accounted for by the equity method, and investments in companies in which the Company owns less than 20 percent voting control are accounted for by the cost method. All significant intercompany accounts and transactions have been eliminated.
 
Use of Estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
 
Cash and Cash Equivalents
 
The Company considers all highly liquid investments, such as time deposits, money market instruments, commercial paper and United States and foreign government securities, purchased with an original maturity of three months or less, to be cash equivalents.
 
Revenue Recognition
 
Revenue from sales of products is recognized upon transfer of title, based upon the terms of delivery.
 
Supply and Marketing Activities
 
The Company engages in the buying and selling of crude oil to supply its refineries. Purchases of crude oil are recorded in “cost of sales”. Sales of crude oil where the Company bears risk on market price, timing, and other non-controllable factors are recorded in “net sales and operating revenue”; otherwise, the sales of crude oil are recorded against “cost of sales”. The Company also engages in the buying and selling of refined products to facilitate the marketing of its refined product production. The results of this activity are recorded in cost of sales

F-8

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

and sales. Our distribution network is an integral part of our refining business. However, due to ordinary course logistical issues concerning production schedules and product sales commitments, it is common for us to purchase refined products from third parties in order to balance the requirements of our product marketing activities. Although third party purchases are essential to effectively market our production, the effects from these activities on our operating results are not significant.
 
Refined product exchange transactions that do not involve the payment or receipt of cash are not accounted for as purchases or sales. Any resulting volumetric exchange balances are accounted for as inventory in accordance with the last-in, first-out (“LIFO”) inventory method for Premcor USA and the first-in, first-out (“FIFO”) inventory method for Sabine. Exchanges that are settled through payment or receipt of cash are accounted for as purchases or sales.
 
Excise Taxes
 
The Company collects excise taxes on sales of gasoline and other motor fuels. Excise taxes of approximately $451.0 million, $471.1 million, and $386.0 million were collected from customers and paid to various governmental entities in 2001, 2000, and 1999, respectively. Excise taxes are not included in sales.
 
Inventories
 
Inventories for the Company are stated at the lower of cost or market. Cost is determined under the LIFO method for Premcor USA for hydrocarbon inventories including crude oil, refined products, and blendstocks. Sabine determines cost under the FIFO method for hydrocarbon inventories including crude oil and refined products. The cost of warehouse stock and other inventories for Premcor USA and Sabine is determined under the FIFO method. Any reserve for inventory cost in excess of market value is reversed if physical inventories turn and prices recover above cost.
 
Hedging Activity
 
The Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedge Activities, as amended, effective January 1, 2001. The adoption of SFAS No. 133 did not have a material impact on the Company’s 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. The Company considers all futures and options contracts to be part of its risk management strategy. Unrealized gains and losses on open contracts are recognized in current cost of sales unless the contract can be identified as a price risk hedge of specific inventory positions or open commitments, in which case hedge accounting is applied under the provisions of SFAS No. 133.
 
Property, Plant, and Equipment
 
Property, plant, and equipment additions are recorded at cost. Depreciation of property, plant, and equipment is computed using the straight-line method over the estimated useful lives of the assets or group of assets, beginning for all Company-constructed assets in the month following the date in which the asset first achieves its design performance. The Company capitalizes the interest cost associated with major construction projects based on the effective interest rate on aggregate borrowings.
 
Expenditures for maintenance and repairs are expensed as incurred. Expenditures for major replacements and additions are capitalized. Upon disposal of assets depreciated on an individual basis, the gains and losses are

F-9

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

reflected in current operating income. Upon disposal of assets depreciated on a group basis, unless unusual in nature or amount, residual cost less salvage is charged against accumulated depreciation.
 
The Company reviews long-lived assets for impairments whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the undiscounted future cash flows of an asset to be held and used in operations is less than the carrying value, the Company would recognize a loss for the difference between the carrying value and fair market value.
 
Deferred Turnaround
 
A turnaround is a periodically required standard procedure for maintenance of a refinery that involves the shutdown and inspection of major processing units which occurs approximately every three to five years. Turnaround costs include actual direct and contract labor, and material costs incurred 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 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 the turnaround costs is presented as “Amortization” in the consolidated statements of operations.
 
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants 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 will 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 require that any existing unamortized turnaround costs be expensed immediately. If this proposed change were in effect at December 31, 2001, the Company would have been required to write-off unamortized turnaround costs of approximately $98 million. Unamortized turnaround costs will change in 2002 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.
 
Environmental Costs
 
Environmental liabilities and reimbursements for underground storage remediation are recorded on an undiscounted basis when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Subsequent adjustments to estimates, to the extent required, may be made as more refined information becomes available.
 
Income Taxes
 
The Company provides for deferred taxes under the asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities. Deferred taxes are classified as current or noncurrent depending on the classification of the assets and liabilities to which the temporary differences relate. Deferred taxes arising from temporary differences that are not related to a specific asset or liability are classified as current or noncurrent depending on the periods in which the temporary differences are

F-10

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

expected to reverse. The Company records a valuation allowance if it is more likely than not that some portion or all of net deferred tax assets will not be realized by the Company.
 
Stock Based Compensation Plan
 
The Company accounts for stock-based compensation issued to employees in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (“APB Opinion No. 25”) which generally requires recognizing compensation cost based upon the intrinsic value at the date granted of the equity instrument awarded. The Financial Accounting Standards Board (“FASB”) issued SFAS No. 123, Accounting for Stock-Based Compensation, which encourages, but does not require, companies to recognize compensation expense for grants of stock, stock options and other equity instruments based on the fair value of those instruments, but alternatively allows companies to disclose such impact in their footnotes. The Company has elected to adopt the footnote disclosure method of SFAS No. 123.
 
Earnings Per Share
 
Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the year. In arriving at net income available to common stockholders, preferred stock dividends were deducted in each year presented. Diluted earnings per share reflects the potential dilution that could occur if all outstanding warrants are exercised. The diluted earnings per share exclude shares related to employee stock options due to their antidilutive effect. These shares were antidilutive because the exercise price of the options was the same or greater than the average market price of the common shares.
 
New Accounting Standards
 
In June 2001, the FASB issued SFAS No. 141 Business Combinations and SFAS No. 142 Goodwill and Other Intangible Assets. SFAS No. 141, 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. The implementation of SFAS No. 141 and SFAS No. 142 are not expected to have a material impact on our financial position and results of operations.
 
In July 2001, the FASB approved SFAS No. 143 Accounting for Assets 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 implementation of SFAS No. 143 is not expected to have a material impact on the Company’s financial position or results operations.
 
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business (as

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

previously defined in that Opinion). The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years, with early application encouraged. The implementation of SFAS No. 144 is not expected to have a material impact on the Company’s financial position or results of operations.
 
Gain on Extinguishment of Long-Term Debt
 
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections. SFAS 145 rescinds SFAS No. 4, Reporting Gains and Losses from the Extinguishment of Debt; SFAS No. 44, Accounting for Intangible Assets of Motor Carriers; and SFAS No. 64, Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements. SFAS No. 145 also amends SFAS No. 13, Accounting for Leases, as it relates to sale-leaseback transactions and other transactions structured similar to a sale-leaseback as well as amends other pronouncements to make various technical corrections. The provisions of SFAS No. 145 as they relate to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. The provision of this statement related to the amendment to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions of this statement shall be effective for financial statements on or after May 15, 2002. In the second quarter of 2002, as permitted by the pronouncement, the Company has elected early adoption of SFAS No. 145. Accordingly, the Company has included the gain on extinguishment of long-term debt in “Income from continuing operations” as opposed to as an extraordinary item, net of taxes, below “Income from continuing operations” in its Statement of Operations.
 
Reclassifications
 
Certain reclassifications have been made to prior years’ financial statements to conform to classifications used in the current year.
 
3.    Refinery Restructuring and Other Charges
 
Refinery restructuring and other charges consisted of a $167.2 million charge related to the January 2001 closure of the Company’s Blue Island, Illinois refinery and a $9.0 million charge related to the write-off of idled coker units at the Port Arthur refinery.
 
Blue Island Closure
 
In January 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 recently adopted Environmental Protection Agency regulations could not produce acceptable returns on investment. This closure resulted in a pretax charge of $167.2 million in 2001. The Company continues to utilize its petroleum products storage facility at the refinery site to supply selected products to the Chicago and other Midwest markets from the Company’s operating refineries. Since the Blue Island refinery operation had been only marginally profitable in recent years and since we will continue to operate a petroleum products storage and distribution business from the Blue Island site, our reduced refining capacity resulting from the closure is not expected to have a significant negative impact on net income or cash flow from operations. The only significant effect on net income and cash flow will result from the actual shutdown process and subsequent environmental site remediation as discussed below. Unless there is a need to adjust the closure reserve in the future, there should be no significant effect on net income beyond 2001.

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
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. The Company is currently in discussions with federal, state, and local governmental agencies 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 investigation is completed and the site remediation plan is finalized, it is not possible to estimate the completion date for remediation, but the Company anticipates that the remediation activities will continue for an extended period of time.
 
A pretax charge of $150.0 million was recorded in the first quarter of 2001 and an additional charge of $17.2 million was recorded in the third quarter of 2001. The original charge included $92.5 million of non-cash asset write-offs in excess of realizable value and a reserve for future costs of $57.5 million, consisting of $12.0 million for severance, $26.4 million for the ceasing of operations, preparation of the plant for permanent closure and equipment remediation, and $19.1 million for site remediation and other environmental matters. The third quarter charge of $17.2 million included an adjustment of $5.6 million to the asset write-off to reflect changes in realizable asset value and an increase of $11.6 million related to an evaluation of expected future expenditures as detailed below. The Company expects to spend approximately $16 million in 2002 related to the remaining $36.5 million reserve for future costs, with the majority of the remainder to be spent over the next several years. The following schedule summarizes the restructuring reserve balance and net cash activity as of December 31, 2001:
 
    
Initial Reserve
   
Reserve Adjustment
   
Net Cash Outlay
   
Reserve as of December 31, 2001
Employee severance
   
$
  12.0
   
$
  0.7
   
$
  10.6
   
$
  2.1
Plant closure/equipment remediation
   
 
26.4
   
 
6.3
   
 
18.8
   
 
13.9
Site clean-up/environmental matters
   
 
19.1
   
 
4.6
   
 
3.2
   
 
20.5
    
  
  
  
    
$
  57.5
   
$
  11.6
   
$
  32.6
   
$
  36.5
    
  
  
  
 
The site clean-up and environmental reserve takes into account costs that are reasonably foreseeable at this time. As the site remediation plan is finalized and work is performed, further adjustments of the reserve may be necessary. In the second quarter of 2002, the Company expects to finalize procurement of environmental risk insurance policies which allow it to better estimate and, within the limits of the policy, cap its cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The Company expects to finalize this coverage in the second quarter of 2002. The Company believes this insurance program also provides the governmental agencies assurance that, once begun, remediation of the site will be completed in a timely and prudent manner.
 
The Blue Island refinery employed 297 employees, both hourly (covered by collective bargaining agreements) and salaried, the employment of 293 of whom was terminated during 2001.
 
Port Arthur Refinery Assets
 
In September 2001, the Company incurred a charge of $5.8 million related to the write-off of the net asset value of the idled coker units at the Port Arthur refinery. The Company has determined that an alternative use of the coker units is not probable at this time. The Company also accrued $3.2 million for future environmental clean-up costs related to the site.
 
4.    Acquisitions and Dispositions
 
In December 1999, the Company sold 15 refined product terminals to Motiva Enterprises L.L.C., Equilon Enterprises L.L.C. (“Equilon”) and a subsidiary of Equilon for net cash proceeds of approximately $34 million.

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company now has exchange and throughput agreements with an affiliate of the buyer at many of these terminal locations as well as new locations for the distribution of refined products.
 
In July 1999, the Company sold its retail marketing division to Clark Retail Enterprises (“CRE”) for net cash proceeds of $215 million. The Company holds approximately a five percent equity interest in CRE after acquiring an interest as part of the transaction. The retail marketing division sold included all Company and independently operated Clark branded stores and the Clark trade name. In general, the buyer assumed unknown environmental liabilities at the retail stores they acquired up to $50,000 per site, as well as responsibility for any post closing contamination. Subject to certain risk sharing arrangements, the Company retained responsibility for all pre-existing, known contamination. The retail marketing operations were classified as a discontinued operation and the results of operations were excluded from continuing operations in the consolidated statements of operations and statements of cash flows. The net sales revenue from the retail marketing operation for the year ended December 31, 1999 was $485.1 million.
 
In 2001, the Company recorded an additional pretax charge of $29.5 million (net of income taxes—$18.0 million) related to the environmental and other liabilities of the discontinued retail operations. In the first quarter of 2001, the Company recorded a charge of $14.0 million representing a change in estimate relative to the Company’s clean up obligation regarding the previously discontinued retail operations. In the fourth quarter of 2001, the Company recorded an additional environmental charge of $14.0 million, which was also a change in estimate concerning the amount collectible from state agencies under various reimbursement programs. More complete information concerning site by site clean up plans, changing postures of state regulatory agencies, and fluctuations in the amounts available under the state reimbursement programs prompted the change in estimates. The charge also included $1.5 million for workers compensation and general liability claims related to the discontinued retail operations.
 
5.    Financial Instruments
 
Short-term Investments
 
Short-term investments include United States government security funds, maturing between three and twelve months from date of purchase. The Company invests only in AA-rated or better fixed income marketable securities or the short-term rated equivalent. The Company’s short-term investments are all considered available-for-sale and are carried at fair value. Realized gains and losses are presented in “Interest income” and are computed using the specific identification method. As of December 31, 2001, short-term investments consisted of United States government debt securities of $1.7 million and were pledged as collateral for the Company’s self-insured workers compensation programs (2000—$1.7 million). For the years ended December 31, 1999, 2000 and 2001, there were no material unrealized or realized gains or losses on short-term investments.
 
Fair Value Financial Instruments
 
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature of these items. See Note 10—“Long-Term Debt” for disclosure of fair value of long-term debt.
 
Derivative Financial Instruments
 
The Company enters into crude oil and refined products futures and options contracts to limit risk related to hydrocarbon price fluctuations created by a potentially volatile market. As of December 31, 2001, the Company’s open futures contracts represented 7.9 million barrels of crude oil and refined products, and had

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

terms extending into October 2002. These contracts reflected a contract value of $175.2 million and a fair market value of $167.5 million. The weighted average price for these future contracts in 2001 was $22.17 per barrel. As of December 31, 2000, the Company’s open futures contracts represented 4.8 million barrels of crude oil and refined products and had terms extending into January 2002. These contracts reflected a contract value of $142.4 million and a fair market value of $140.0 million. The weighted average price for these futures contracts was approximately $29.72 per barrel.
 
As of December 31, 2001, the Company’s open options contracts represented 1.2 million barrels of crude oil and refined products, and had terms extending into March 2002. These contracts reflected a contract value of $1.7 million and a fair market value of $0.9 million with a weighted average price of $1.42 per barrel. As of December 31, 2000, the Company’s open option contracts represented 1.2 million barrels of crude oil and refined products and had terms extending into December 2001. These contracts reflected a contract value of $4.7 million and a fair market value of $4.3 million with a weighted average price of $3.92 per barrel. The net unrealized gains or losses on the futures and options contracts were recognized as a component of operating income since the Company has not elected hedge accounting for these contracts.
 
Concentration of Credit Risk
 
Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of trade receivables. Credit risk on trade receivables is minimized as a result of the credit quality of the Company’s customer base and industry collateralization practices. The Company conducts ongoing evaluations of its customers and requires letters of credit or other collateral as appropriate. Trade receivable credit losses for the three years ended December 31, 2001 were not material.
 
The Company currently has a supply agreement with CRE, and the Company’s billings to CRE totaled $813.8 million in 2001 of which $648.3 million were product sales and $165.5 million were federal excise and state motor fuel taxes that the Company collected and then remitted to governmental agencies (2000—total billings of $1,224.9 million, product sales of $972.0 million, federal excise and state motor fuel taxes of $252.9 million; 1999—total billings of $482.5 million, product sales of $355.9 million, federal excise and state motor fuel taxes of $126.6 million). The taxes were not included in “Net sales and operating revenue,” “Cost of sales,” or “Operating expenses.” The Company had a receivable of $7.4 million due from CRE as of December 31, 2001 (2000—$33.1 million).
 
The Company does not believe that it has a significant credit risk on its derivative instruments which are transacted through the New York Mercantile Exchange or with counterparties meeting established collateral and credit criteria.
 
6.    Inventories
 
The carrying value of inventories consisted of the following:
 
    
December 31,
    
2000
   
2001
Crude oil
   
$
169.9
   
$
77.0
Refined products and blendstocks
   
 
184.7
   
 
218.7
Warehouse stock and other
   
 
23.7
   
 
22.6
    
  
    
$
  378.3
   
$
  318.3
    
  

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
Inventories recorded under LIFO include crude oil, refined products, and blendstocks of $297.6 million and $252.6 million for the years ended December 31, 2000 and 2001, respectively. A LIFO liquidation reduced the Company’s pretax earnings by $19.3 million in 2001. The 2001 liquidation was due to the closure of the Blue Island refinery and the decrease in the amount of crude oil processed by PRG at the Port Arthur refinery as Sabine became the predominant crude oil processor at the refinery. A LIFO liquidation increased pretax earnings by $54.6 million in 1999 due to an overall reduction in refining-related inventories and the sale of the retail marketing operations.
 
As of December 31, 2001, the market value of crude oil, refined product, and blendstock inventories was approximately $4.9 million above carrying value (2000—$100.8 million).
 
7.    Property, Plant, and Equipment
 
Property, plant, and equipment consisted of the following:
 
    
December 31,
  
    
2000
     
2001
  
Real property
   
$
8.3
 
   
$
8.3
 
Process units, buildings, and oil storage and movement
   
 
833.1
 
   
 
1,344.3
 
Office equipment, furniture, and autos
   
 
23.3
 
   
 
24.4
 
Construction in progress
   
 
698.8
 
   
 
121.8
 
Accumulated depreciation
   
 
(215.2
)
   
 
(199.2
)
    
  
    
$
  1,348.3
 
   
$
  1,299.6
 
    
  
 
The useful lives on depreciable assets used to determine depreciation were as follows:
 
Process units, buildings, and oil storage and movement
   
15 to 40 years; average 27 years
Office equipment, furniture and autos
   
3 to 12 years; average 7 years
 
Construction in progress included $646 million and $33 million related to the heavy oil upgrade project at the Port Arthur refinery as of December 31, 2000 and 2001, respectively.
 
8.    Other Assets
 
Other assets consisted of the following:
 
    
December 31,
    
2000
   
2001
Deferred financing costs
   
$
35.1
   
$
32.6
Deferred turnaround costs
   
 
94.1
   
 
97.9
Deferred tax asset (see Note 14—“Income Taxes”)
   
 
23.8
   
 
—
Investment in affiliate
   
 
4.3
   
 
4.3
Cash restricted for investment in capital additions
   
 
—
   
 
9.9
Other
   
 
3.7
   
 
4.0
    
  
    
$
  161.0
   
$
  148.7
    
  
 
The Company incurred deferred financing costs in 2001 of $10.2 million (2000—$4.3 million, 1999—$7.5 million) associated with the amendment of its working capital facility at PRG and the issuance of tax exempt

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

bonds through the state of Ohio. Premcor USA and PRG wrote-off $0.6 million of their deferred financing costs related to the repurchase of a portion of their senior notes in September 2001 (see Note 10—“Long-Term Debt”). In 2001, related to the adoption of SFAS No. 133, PACC recorded its interest rate cap on its bank senior loan agreement at fair market value resulting in the write-down of deferred financing costs of $0.7 million.
 
Amortization of deferred financing costs for the year ended December 31, 2001 was $11.4 million (2000—$11.0 million, 1999—$7.4 million) and was included in “Interest and finance expense”.
 
Cash restricted for investment in capital additions is related to the outstanding proceeds from the Series 2001 Ohio Bonds (see Note 10—“Long Term Debt”). These proceeds are restricted to fund capital expenditure projects for solid waste and wastewater facilities at the Lima, Ohio refinery.
 
9.    Working Capital Facilities
 
In August 2001, PRG amended and restated its secured revolving credit facility for a period of two years through August 2003. This new credit agreement provides for the issuance of letters of credit of up to the lesser of $650 million or the amount available under a borrowing base calculated with respect to cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, and net obligations on swap contracts. PRG uses the facility primarily for the issuance of letters of credit to secure purchases of crude oil. As of December 31, 2001, $295.3 million (2000—$377.3 million) of the line of credit was utilized for letters of credit, of which $139.9 million supported deliveries that PRG had not taken title to at December 31, 2001, but had made a purchase commitment. The remaining $155.4 million related to deliveries in which the Company had taken title and accordingly recorded to inventory and accounts payable as well as a portion of letters of credit related to nonhydrocarbons.
 
PRG’s credit agreement contains covenants and conditions that, among other things, limit dividends, indebtedness, liens, investments and contingent obligations. It also requires that PRG maintain its property and insurance, pay all taxes, comply with all applicable laws, and provide periodic information to, and conduct periodic audits on behalf of the lenders. PRG is also required to comply with certain financial covenants including the maintenance of working capital of at least $150 million, the maintenance of tangible net worth of at least $150 million, the maintenance of minimum levels of balance sheet cash as defined in the agreement of at least $75 million at all times and a cumulative cash flow test that from July 1, 2001 must not be less than zero. The credit agreement also limits the amount of future additional indebtedness that may be incurred by PRG subject to certain exceptions. Direct cash borrowings under the credit facility are limited to $50 million. There were no direct cash borrowings under the facility as of December 31, 2001 and 2000.
 
In December 2001, PRG entered into a $20 million cash-collateralized credit facility expiring August 23, 2003. This facility was arranged in order for PRG to receive a first year interest rate of 2% on its Series 2001 Ohio Bonds (see Note 10—“Long-Term Debt”). In addition, this facility can be utilized for other non-hydrocarbon purposes. As of December 31, 2001, $10.1 million of the line of credit was utilized for letters of credit related to the Series 2001 Ohio Bonds.
 
PAFC has a $35 million working capital facility which is primarily used for the issuance of letters of credit for the purchases of crude oil other than the Maya crude oil to be received under a long-term crude oil supply agreement with PMI Comercio Internacional, S.A. de C.V (“PEMEX”), an affiliate of Petroleos Mexicanos, the Mexican state oil company. As of December 31, 2001, none of the line of credit was utilized for letters of credit (2000—$29.3 million).

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
In order to provide security to PEMEX for PACC’s obligation to pay for shipments of Maya crude oil under the long-term crude oil supply agreement, PACC obtained from Winterthur International Insurance Company Limited (“Winterthur”), an oil payment guaranty insurance policy for the benefit of PEMEX. This oil payment guaranty insurance policy is in the amount of $150 million and will be a source of payment to PEMEX if PACC fails to pay PEMEX for one or more shipments of Maya crude oil. Under the senior debt documents, any payments by Winterthur on this policy are required to be reimbursed by PACC. This reimbursement obligation to Winterthur has an equal and ratable claim on all of the collateral for holders of PACC’s senior debt, except in specified circumstances in which it has a senior claim to these parties. As of December 31, 2001, $79.5 million (2000—$62.1 million) of crude oil purchase commitments were outstanding related to this policy.
 
Under senior debt covenants, PACC was required to establish a debt service reserve account and at the time the heavy oil upgrade processing facility achieved substantial reliability, deposit or cause the deposit of an amount equal to the next semiannual payment of principal and interest. In lieu of depositing funds into this reserve account at substantial reliability, PACC arranged for Winterthur to provide a separate debt service reserve insurance policy in the maximum amount of $60 million for a period of approximately five years from substantial reliability of the heavy oil processing facility. Payments will be made under this policy to pay debt service to the extent that PACC does not have sufficient funds available to make a debt service payment on any scheduled semiannual payment date during the term of the policy. The term of the policy commenced at substantial reliability of the heavy oil processing facility and ends on the tenth semiannual payment date after substantial reliability, unless it terminates early because the debt service reserve account is funded to the required amount. The maximum liability of Winterthur under its policy is reduced as PACC makes deposits into the debt service reserve account. On the sixth semiannual payment date after substantial reliability, and on each of the next four semiannual payment dates, PACC is required to deposit, out of available funds for that purpose, $12 million into the debt service reserve account. Under a secured account structure (See Note 10—“Long-Term Debt”), until the debt service reserve account contains the required amount, PACC is required to make deposits into the debt service reserve account equal to all of PACC’s excess cash flow that remains after PACC applies 75% of excess cash flow to prepay the bank senior loan agreement. Once the debt service reserve account contains the required amount, the Winterthur policy will terminate.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
10.    Long-Term Debt
 
    
December 31,
    
2000
   
2001
8 5/8% Senior Notes due August 15, 2008 (“8 5/8% Senior Notes”)(1)
   
$
109.8
   
$
109.8
8 3/8% Senior Notes due November 15, 2007 (“8 3/8% Senior Notes”)(1)
   
 
99.5
   
 
99.6
8 7/8% Senior Subordinated Notes due November 15, 2007 (“8 7/8% Senior Subordinated Notes”)(1)
   
 
174.1
   
 
174.2
Floating Rate Term Loan due November 15, 2003 and 2004 (“Floating Rate Loan”)(1)
   
 
240.0
   
 
240.0
9½% Senior Notes due September 15, 2004 (“9½% Senior Notes”)(1)
   
 
171.7
   
 
150.4
10 7/8% Senior Notes due December 1, 2005(“10 7/8% Senior Notes”)(2)
   
 
175.0
   
 
144.4
12½% Senior Secured Notes due January 15, 2009(“12½% Senior Notes”)(3)
   
 
255.0
   
 
255.0
Bank Senior Loan Agreement (3)
   
 
287.6
   
 
287.6
Ohio Water Development Authority Environmental Facilities Revenue Bonds due December 1, 2031(“Series 2001 Ohio bonds”)
   
 
—
   
 
10.0
Obligations under capital leases(1)
   
 
3.3
   
 
1.8
    
  
    
 
1,516.0
   
 
1,472.8
Less current portion
   
 
1.5
   
 
81.4
    
  
    
$
  1,514.5
   
$
  1,391.4
    
  
(1)
 
Issued or borrowed by PRG
(2)
 
Issued by Premcor USA
(3)
 
Issued or borrowed by PAFC
 
The estimated fair value of long-term debt as of December 31, 2001 was $1,331.8 million (2000—$1,195.5 million), determined using quoted market prices for these issues.
 
In September 2001, PRG and Premcor USA repurchased in the open market $21.3 million in face value of its 9½% Senior Notes, $30.6 million in face value of its 10 7/8% Senior Notes, and $5.9 million in face value of its 11½% Exchangeable Preferred Stock (See Note 15—“Exchangeable Preferred Stock”) for an aggregate purchase price of $48.5 million. As a result of these transactions, the Company recorded a gain of $8.7 million, which included the write-off of deferred financing costs related to the debt issues.
 
The 8 5/8% Senior Notes were issued by PRG in August 1998, at a discount of 0.234% and are unsecured. The 8 5/8% Senior Notes are redeemable at the option of the Company beginning August 2003, at a redemption price of 104.312% of principal, which decreases to 100% of principal amount in 2005. Up to 35% in aggregate principal amount of the notes originally issued are redeemable at the option of the Company out of the net proceeds of one or more equity offerings at any time prior to August 15, 2002, at a redemption price equal to 108.625% of principal.
 
The 8 3/8% Senior Notes and 8 7/8% Senior Subordinated Notes were issued by PRG in November 1997, at a discount of 0.734% and 0.719%, respectively. These notes are unsecured, with the 8 7/8% Senior Subordinated Notes subordinated in right of payment to all unsubordinated indebtedness of PRG. The 8 3/8% Senior Notes and 8 7/8% Senior Subordinated Notes are redeemable at the option of PRG beginning November 2002, at a redemption price of 104.187% of principal and 104.437% of principal, respectively, which decreases to 100% of principal in 2004 and 2005, respectively.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
PRG borrowed $125.0 million in November 1997, and an additional $115.0 million in August 1998, under a floating rate term loan agreement expiring in 2004. In 2003, $31.3 million of the outstanding principal amount is due with the remainder of the outstanding principal due in 2004. The Floating Rate Loan is a senior unsecured obligation of the Company and bears interest at the London Interbank Offer Rate (“LIBOR”) plus a margin of 2.75%. The loan may be repaid subject to certain restrictive covenants as stated in the amended working capital facility agreement.
 
The 9½% Senior Notes were issued by PRG in September 1992 and are unsecured. The 9½% Senior Notes are currently redeemable at PRG’s option at a redemption price of 100% of principal subject to certain restrictive covenants as stated in the secured revolving credit facility agreement. Under the indenture agreement for the 9½% Senior Notes, PRG is required to redeem $62.9 million of the 9½% Senior Notes on September 15, 2003 at 100% of principal.
 
In December 2001, PRG borrowed $10 million through the state of Ohio, which had issued Series 2001 Ohio bonds. PRG is the sole guarantor on the principal and interest payments of these bonds. PRG will bear a 2% interest rate for the first year commencing December 2001. Following the first year, PRG will be subject to a variable interest rate determined by the Trustee Bank not to exceed the maximum interest rate as defined under the indentures. PRG has the option of converting from a variable interest rate to a 30-year fixed interest rate. In the initial year, PRG has the option to redeem the bonds prior to maturity on or after May 1, 2002 through November 30, 2002 at a redemption price of 100% of principal plus accrued interest. Following the initial year, PRG has the option to redeem the bonds prior to maturity on or after April 1st of that year through November 30th of that year at a redemption price of 100% of principal plus accrued interest. If PRG decides to convert the bonds to a 30-year fixed interest rate, PRG has the option to redeem the bonds at a redemption price of 101%, declining to 100% the next year, of the principal plus accrued interest if the length of the fixed rate period is greater than 10 years. If the fixed rate period on the bonds is less than 10 years, there is no call provision.
 
The 10 7/8% Senior Notes were issued by Premcor USA in December 1995 and are unsecured. These notes are currently redeemable at Premcor USA’s option at a redemption price of 103.625% of principal, which decreases to 100% of principal in 2003.
 
PRG and Premcor USA note indentures contain certain restrictive covenants including limitations on the payment of dividends, limitations on the payment of amounts to related parties, limitations on the incurrence of debt, incurrence of liens and the maintenance of a minimum net worth. In order to make dividend payments PRG and Premcor USA must maintain a minimum net worth (as defined) of $150 million and $220 million, respectively, possess a cumulative earnings calculation (as defined) of greater than zero after a dividend payment is made, and not be in default of any covenants. In the event of a change of control of PRG, or Premcor USA, as defined in the indentures, the respective company is required to tender an offer to redeem its outstanding notes and floating rate term loans at 101% and 100% of face value, respectively, plus accrued interest.
 
The 12½% Senior Notes were issued by PAFC in August 1999 on behalf of PACC at par and are secured by substantially all of the assets of PACC. The 12½% Senior Notes are redeemable at the Company’s option at any time at a redemption price equal to 100% of principal plus accrued and unpaid interest plus a make-whole premium which is based on the rates of treasury securities with average lives comparable to the average life of the remaining scheduled payments plus 0.75%.
 
In August 1999, PAFC entered into a Bank Senior Loan Agreement provided by commercial banks and institutional lenders. The Company had access to $325 million under the Bank Senior Loan Agreement, of which

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

it drew $287.6 million as of December 31, 2001. The Bank Senior Loan Agreement is split into a Tranche A of $106.5 million with a term of 7½ years and a Tranche B of $181.1 million with a term of eight years. The interest rates on the bank senior loan agreement are based on LIBOR plus 4¾% for Tranche A and on LIBOR plus 5¼% for Tranche B. The ability to draw the unused portion of the loan expired in September 2001 when the heavy oil processing facility achieved substantial reliability. As required under the PAFC indentures, PACC entered into a transaction in April 2000 for $0.9 million that capped LIBOR at 7½% for a varying portion of the principal outstanding on their bank senior loan agreement. As of December 31, 2001, the cap had a market value of under $0.1 million. The cap is for a term from April 2000 through January 2004.
 
Under a common security agreement governing the PAFC debt, which contains common covenants, representations, defaults and other terms with respect to the 12½% Senior Notes, the bank senior loan agreement and the guarantees thereof by PACC, Sabine, and Neches, PACC is subject to restrictions on the making of distributions to Sabine and Neches. The common security agreement contains provisions that require the Company to maintain a secured account structure that reserves cash balances to be used for operations, capital expenditures, tax payments, major maintenance, interest, and debt repayments. This secured account structure must be funded and paid before PACC can make any restricted payments including dividends, except for $100,000 in distributions to Sabine and Neches each year to permit them to pay directors’ fees, accounting expenses, and other administrative expenses. In January 2002, PACC made a $59.7 million prepayment of its Bank Senior Loan Agreement pursuant to the common security agreement and secured account structure.
 
The common security agreement also requires that PACC carry insurance coverage with specified terms. However, due to the effects of the events of September 11, 2001 on the insurance market, coverage meeting such terms, particularly as it relates to deductibles, waiting periods and exclusions, was not available on commercially reasonable terms and, as a result, PACC’s insurance program was not in full compliance with the required insurance coverage at December 31, 2001. However, the requisite parties to the common security agreement have waived the noncompliance provided that PACC obtain a reduced deductible limit for property damage by April 19, 2002, obtain additional contingent business interruption insurance by June 26, 2002 and continue to monitor the insurance market on a quarterly basis to determine if additional insurance coverage required by the common security agreement is available on commercially reasonable terms, and if so, promptly obtain such insurance. The Company believes that PACC will be able to comply with all of the conditions of the waiver.
 
The scheduled maturities of long-term debt during the next five years are (in millions): 2002—$81.4; 2003—$126.2; 2004—$343.6; 2005—$210.4; 2006—$54.4; 2007 and thereafter—$658.2.
 
Interest and finance expense
 
Interest and finance expense included in the consolidated statements of operations, consisted of the following:
 
    
For The Year Ended December 31,
  
    
1999
     
2000
     
2001
  
Interest expense
   
$
108.3
 
   
$
149.0
 
   
$
147.7
 
Finance costs
   
 
18.0
 
   
 
12.7
 
   
 
16.0
 
Capitalized interest
   
 
(22.8
)
   
 
(62.1
)
   
 
(5.3
)
    
  
  
Interest and finance expense
   
$
  103.5
 
   
$
    99.6
 
   
$
  158.4
 
    
  
  
 
Cash paid for interest expense in 2001 was $152.6 million (2000—$141.7 million; 1999—$93.5 million).

F-21

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
11.    Lease Commitments
 
The Company leases refinery equipment, catalyst, tank cars, office space, and office equipment from unrelated third parties with lease terms ranging from 1 to 8 years with the option to purchase some of the equipment at the end of the lease term at fair market value. The leases generally provide that the Company pay taxes, insurance, and maintenance expenses related to the leased assets. As of December 31, 2001, net future minimum lease payments under non-cancelable operating leases were as follows (in millions): 2002—$8.0, 2003—$7.4; 2004—$6.0, 2005—$5.7, 2006—$5.3, and $3.6 in the aggregate thereafter. Rental expense during 2001 was $9.1 million (2000—$9.9 million; 1999—$12.6 million).
 
12.    Related Party Transactions
 
As of December 31, 2001, the Company had a payable to an affiliate of Blackstone of $0.3 million (December 31, 2000—$2.8 million). The Company has an agreement with this affiliate of Blackstone under which it receives a monitoring fee equal to $2.0 million per annum subject to increases relating to inflation and in respect to additional acquisitions by the Company. The Company recorded expenses related to the annual monitoring fee and the reimbursement of out-of-pocket costs of $2.0 million, $2.2 million and $2.5 million for the years ended December 31, 1999, 2000 and 2001, respectively. In 1999, the Company paid $8.0 million in advisory fees to an affiliate of Blackstone in connection with the structuring and construction of the heavy oil processing facility. Affiliates of Blackstone may in the future receive customary fees for advisory services rendered to the Company. Such fees will be negotiated from time to time with the independent members of the Company’s board of directors on an arm’s-length basis and will be based on the services performed and the prevailing fees then charged by third parties for comparable services.
 
13.    Employee Benefit Plans
 
Postretirement Benefits Other Than Pensions
 
The Company provides health insurance in excess of social security and an employee paid deductible amount, and life insurance to most retirees once they have reached a specified age and specified years of service.
 
The following table sets forth the changes in the benefit obligation for the unfunded postretirement health and life insurance plans for 2000 and 2001:
 
    
December 31,
  
    
2000
     
2001
  
Change in Benefit Obligation
                  
Benefit obligation at beginning of year
   
$
39.6
 
   
$
42.1
 
Service costs
   
 
1.3
 
   
 
1.3
 
Interest costs
   
 
2.9
 
   
 
3.4
 
Participants’ contribution
   
 
—
 
   
 
0.7
 
Plan amendments
   
 
—
 
   
 
0.7
 
Curtailment gain
   
 
—
 
   
 
(1.6
)
Actuarial loss
   
 
0.1
 
   
 
17.9
 
Benefits paid
   
 
(1.8
)
   
 
(2.8
)
    
  
Benefit obligation at end of year
   
 
42.1
 
   
 
61.7
 
Unrecognized net gain (loss)
   
 
(0.1
)
   
 
(17.7
)
Unrecognized prior service benefit
   
 
0.2
 
   
 
(0.6
)
    
  
Accrued postretirement benefit liability
   
$
  42.2
 
   
$
  43.4
 
    
  

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
The components of net periodic postretirement benefit costs were as follows:
 
    
For the Year Ended December 31,
    
1999
     
2000
   
2001
Service costs
   
$
1.5
 
   
$
1.3
   
$
1.3
Interest costs
   
 
2.8
 
   
 
2.9
   
 
3.4
Amortization of prior service costs
   
 
(0.1
)
   
 
—
   
 
—
    
  
  
Net periodic postretirement benefit cost
   
$
4.2
 
   
$
 4.2
   
$
 4.7
    
  
  
 
In measuring the expected postretirement benefit obligation, the Company assumed a discount rate of 7.25% (2000—7.75%), a rate of increase in the compensation level of 4.00% (2000—4.00%), and a health care cost trend ranging from 12.00% in 2002 declining to an ultimate rate of 5.00% in 2009. The effect of increasing the average health care cost trend rates by one percentage point would increase the accumulated postretirement benefit obligation as of December 31, 2001, by $8.4 million and increase the annual aggregate service and interest costs by $0.7 million. The effect of decreasing the average health care cost trend rates by one percentage point would decrease the accumulated postretirement benefit obligation, as of December 31, 2001, by $6.9 million and decrease the annual aggregate service and interest costs by $0.5 million.
 
Employee Savings Plan
 
The PRG Inc. Retirement Savings Plan and separate Trust (the “Plan”), a defined contribution plan, covers substantially all employees of the Company. Under the terms of the Plan, the Company matches the amount of employee contributions, subject to specified limits. Company contributions to the Plan during 2001 were $8.4 million (2000—$8.7 million; 1999—$8.4 million).
 
14.    Income Taxes
 
The income tax provision (benefit) is summarized as follows:
 
    
1999
     
2000
     
2001
  
Income (loss) from continuing operations before income taxes and minority interest
   
$
(82.4
)
   
$
  64.5
 
   
$
 236.2
 
    
  
  
Income tax provision (benefit):
                           
Current provision (benefit)—Federal
   
$
(17.9
)
   
$
(0.9
)
   
$
(0.2
)
   —State
   
 
(2.3
)
   
 
(0.7
)
   
 
0.6
 
    
  
  
    
 
(20.2
)
   
 
(1.6
)
   
 
0.4
 
    
  
  
Deferred provision (benefit)—Federal
   
 
    8.1
 
   
 
(24.2
)
   
 
53.0
 
     —State
   
 
0.1
 
   
 
—
 
   
 
(1.0
)
    
  
  
    
 
8.2
 
   
 
(24.2
)
   
 
52.0
 
    
  
  
Income tax provision (benefit)
   
$
(12.0
)
   
$
(25.8
)
   
$
52.4
 
    
  
  

F-23

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
A reconciliation between the income tax provision (benefit) computed on pretax income at the statutory federal rate and the actual provision (benefit) for income taxes is as follows:
 
    
1999
     
2000
     
2001
  
Federal taxes computed at 35%
   
$
(28.9
)
   
$
22.6
 
   
$
82.7
 
State taxes, net of federal effect
   
 
(0.2
)
   
 
    2.9
 
   
 
2.9
 
Valuation allowance
   
 
  17.1
 
   
 
(50.8
)
   
 
(30.0
)
Other items, net
   
 
—
 
   
 
(0.5
)
   
 
(3.2
)
    
  
  
Income tax provision (benefit)
   
$
(12.0
)
   
$
(25.8
)
   
$
52.4
 
    
  
  
 
The following represents the approximate tax effect of each significant temporary difference giving rise to deferred tax liabilities and assets:
 
    
December 31,
  
    
2000
     
2001
  
Deferred tax liabilities:
                  
Property, plant and equipment
   
$
 112.4
 
   
$
 155.0
 
Turnaround costs
   
 
32.7
 
   
 
34.1
 
Inventory
   
 
5.7
 
   
 
4.3
 
Other
   
 
3.0
 
   
 
2.4
 
    
  
    
 
153.8
 
   
 
195.8
 
    
  
Deferred tax assets:
                  
Alternative minimum tax credit
   
 
24.1
 
   
 
25.6
 
Environmental and other future costs
   
 
22.1
 
   
 
43.3
 
Tax loss carryforwards
   
 
146.3
 
   
 
96.5
 
Organizational and working capital costs
   
 
4.0
 
   
 
3.7
 
Other
   
 
11.1
 
   
 
10.0
 
    
  
    
 
207.6
 
   
 
179.1
 
    
  
Valuation allowance
   
 
(30.0
)
   
 
—
 
    
  
Net deferred tax asset (liability)
   
$
23.8
 
   
$
(16.7
)
    
  
 
As of December 31, 2001, the Company has made net cumulative payments of $25.6 million under the federal alternative minimum tax system which are available to reduce future regular income tax payments. As of December 31, 2001, the Company had a federal net operating loss carryforward of $245.9 million and federal business tax credit carryforwards in the amount of $5.4 million. Such operating losses and tax credit carryforwards have carryover periods of 15 years (20 years for losses and credits originating in 1998 and years thereafter) and are available to reduce future tax liabilities through the year ending December 31, 2021. The tax credit carryover periods will begin to terminate with the year ending December 31, 2003 and the net operating loss carryover periods will begin to terminate with the year ending December 31, 2012.
 
The valuation allowance as of December 31, 2001 was nil (2000—$30.0 million). As of December 31, 2000, the Company provided a valuation allowance to reduce its deferred tax assets to amounts that were more likely than not to be realized. During the first quarter of 2001, the Company reversed its remaining deferred tax valuation allowance. In calculating the reversal of its remaining deferred tax valuation allowance, the Company assumed as future taxable income future reversals of existing taxable temporary differences, future taxable income exclusive of reversing temporary differences and available tax planning strategies. The reversal of the

F-24

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

remaining deferred tax valuation allowance is primarily the result of 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.
 
During 2001, the Company made net federal cash payments of $11.9 million (2000—$3.5 million net cash refunds; 1999—$0.3 million net cash payments). Each member of the Premcor Inc. and Subsidiaries consolidated group provides for its portion of such consolidated refunds and liability under its tax sharing agreement with the other members of the consolidated group. During 2001, the Company made net state cash payments of $1.7 million (2000—$1.8 million net cash payments; 1999—$0.4 million net cash refunds).
 
The income tax provision of $52.4 million for 2001 reflected the effect of the decrease in the deferred tax valuation allowance of $30.0 million. The income tax benefit of $25.8 million for 2000 reflected the effect of the decrease in the deferred tax valuation allowance of $50.8 million. The income tax benefit of $12.0 million for 1999 reflected the effect of intraperiod tax allocations resulting from the utilization of current year operating losses to offset the net gain on the operations and sale of the discontinued retail division, offset by the write-down of a net deferred tax asset.
 
15.    Exchangeable Preferred Stock of Subsidiary
 
In October 1997, Premcor USA converted a portion of its common stock to 63,000 shares ($1,000 liquidation preference per share) of 11½% Senior Cumulative Exchangeable Preferred Stock. The Exchangeable Preferred Stock is redeemable at Premcor USA’s option, in whole or part, on or after October 1, 2002 at the redemption price of 105.75% of principal. Premcor USA is required, subject to certain conditions, to redeem all of the Exchangeable Preferred Stock on October 1, 2009. The Exchangeable Preferred Stock is exchangeable, subject to certain conditions, at the option of Premcor USA into 11½% Subordinated Debentures due 2009. As of December 31, 2001, all dividends had been paid by issuing additional shares of exchangeable preferred stock except $0.3 million paid in cash in September 2001 as it related to the repurchase of a portion of the exchangeable preferred stock. In March 2002, the Company gave notice of the intention to exchange the 11½% Exchangeable Preferred Stock for 11½% Subordinated Debentures due October 2009.
 
16.    Stockholders’ Equity
 
Premcor Inc. has outstanding Common Stock and Class F Common Stock. The Class F Common Stock has voting rights limited to 19.9% of the total voting power of all of Premcor Inc.’s voting stock and is currently held solely by Occidental. The Class F Common Stock is convertible into Common Stock by any stockholder of this class other than Occidental. All other non-voting rights including dividend, liquidation, and dissolution are determined on a share-for-share basis.
 
In August 1999, Blackstone and Occidental signed capital contribution agreements related to the financing of the heavy oil upgrade project totaling $135.0 million. Blackstone agreed to contribute $121.5 million, and Occidental agreed to contribute $13.5 million. Funding of the capital contributions occurred on a pro-rata basis as proceeds were received from borrowings under the bank senior loan agreement. In the third quarter of 2001, the Company decided not to borrow the remaining loan commitment under the bank senior loan agreement and consequently forfeited the remaining $13.2 million outstanding capital contributions. The ability to draw any remaining funds under the bank senior loan agreement and receive the remaining capital contributions expired in

F-25

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September of 2001 upon the achievement of substantial reliability of the heavy oil upgrade project. As of December 31, 2001, Blackstone and Occidental contributed $109.6 million and $12.2 million, respectively, of their commitments. Occidental’s contributions under the capital contribution agreement were made directly to Sabine.
 
In 1999, in addition to the contributions related to the capital contribution agreement, Blackstone contributed $8.1 million to enable the purchase of the equity interest in CRE and to enable the payment of certain fees owed by the Company. All Blackstone shares were Common Stock issued at $9.90 per share. In 1999, Premcor Inc. also issued 65,656 shares of Common Stock to a member of its board of directors for $0.6 million for services rendered to the Company. In 1999, Premcor USA settled a lawsuit with its previous minority interest holder for $3.6 million, which was recorded as a reduction in paid-in capital.
 
In August 1999, Premcor Inc. issued warrants to Blackstone to purchase 2,430,000 shares of Common Stock at a price of $0.01 per share. The warrants may be exercised at any time in whole or part. Sabine issued warrants to Occidental to purchase 30,000 shares of Sabine’s common stock at a price of $0.09 per share. The warrants, which do not expire, may be exercised at any time in whole or part. Upon exercise of these warrants, Occidental has the option to exchange each warrant share for nine shares of Premcor Inc.’s Class F Common Stock. None of the warrants were exercised as of December 31, 2001.
 
17.    Stock Option Plans
 
In 1999, the Premcor USA Long-Term Performance Plan was replaced with the Premcor Inc. Stock Incentive Plan (“Incentive Plan”). Under the Incentive Plan, employees of PRG and its subsidiaries are eligible to receive awards of options to purchase shares of the common stock of Premcor Inc. The Incentive Plan is intended to attract and retain executives and other selected employees whose skills and talents are important to the operations of Premcor Inc. and its subsidiaries. Options on an aggregate amount of 2,215,250 shares of Premcor Inc.’s common stock may be awarded under the Incentive Plan, either from authorized, unissued shares which have been reserved for such purpose or from authorized, issued shares acquired by or on behalf of the Company. The current aggregate amount of stock available to be awarded is subject to a stock dividend or split, reorganization, recapitalization, merger, consolidation, spin-off, combination or exchange of stock.
 
Summarized below is the status of the Incentive Plan as of December 31, 1999, 2000 and 2001:
 
    
1999
   
2000
   
2001
    
Shares
   
Weighted Average Exercise Price
   
Shares
     
Weighted Average Exercise Price
   
Shares
     
Weighted Average Exercise Price
Options outstanding, beginning of period
   
 
—
   
$
—
   
 
1,905,000
 
   
$
10.31
   
 
1,782,300
 
   
$
10.25
Granted
   
 
1,905,000
   
 
10.31
   
 
207,300
 
   
 
9.90
   
 
200,000
 
   
 
9.90
Forfeited
   
 
—
   
 
—
   
 
(330,000
)
   
 
10.36
   
 
(176,250
)
   
 
9.90
    
         
         
      
Options outstanding, end of period
   
 
1,905,000
   
 
10.31
   
 
1,782,300
 
   
 
10.25
   
 
1,806,050
 
   
 
10.25
    
         
         
      
Exercisable at end of period
   
 
482,125
   
 
11.51
   
 
458,500
 
   
 
11.26
   
 
560,500
 
   
 
11.01
Weighted average fair value of options granted
   
$
4.10
          
$
3.65
 
          
$
3.10
 
       

F-26

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
Summarized below is information about the stock options outstanding under the Incentive Plan as of December 31, 2001:
 
Exercise Price
   
Options Outstanding at 12/31/01
   
Options Exercisable at 12/31/01
   
Remaining Contractual Life
$9.90
   
1,683,550
   
438,000
   
81 months
$15.00
   
122,500
   
122,500
   
38 months
    
  
    
$9.90 – $15.00
   
1,806,050
   
560,500
     
    
  
    
 
The fair value of these options was estimated on the grant date using the Black-Scholes option-pricing model with the following weighted average assumptions:
 
    
1999
   
2000
   
2001
Assumed risk-free rate
   
5.92%
   
5.82%
   
4.95%
Expected life
   
8.7 years
   
7.9 years
   
7.6 years
 
For these respective years, the expected dividends were assumed to be zero and the expected volatility was assumed to be 1% since the stock underlying the options is not publicly traded.
 
Pursuant to SFAS No. 123 Accounting for Stock Based Compensation, the Company has elected to account for its stock option plan under APB Opinion No. 25 Accounting for Stock Issued to Employees and adopt the disclosure only provisions of SFAS No. 123. Under APB Opinion No. 25, no compensation costs are recognized because the option exercise price is equal to the fair market price of the common stock on the date of the grant. Under SFAS No. 123, stock options are valued at grant date using the Black Scholes valuation model and compensation costs are recognized ratably over the vesting period. Had compensation costs been determined as prescribed by SFAS No. 123, the Company’s net earnings would have been impacted by less than $1.0 million for each of the years ended December 31, 1999, 2000, and 2001.
 
Options granted under the plan are either time vesting or performance vesting options. The time vesting options vest in one of the following three manners: (i) 50% at date of grant and 25% on each January 1 thereafter, (ii) 1/3 on the first, second and third anniversaries of the date of grant, or (iii) 1/4 on the first, second, third and fourth anniversaries of the date of grant. The performance vesting options fully vest on and after the seventh anniversary of the date of option; provided, however, that following a public offering of the common stock or upon a change in control, the vesting is accelerated based on the achievement of certain share prices of the common stock. The accelerated vesting schedule is as follows:
 
AVERAGE CLOSING PRICE PER SHARE
OF CAPITAL STOCK FOR ANY
180 CONSECUTIVE DAYS; OR
CHANGE IN CONTROL PRICE
     
% OF SHARES WITH
RESPECT TO
WHICH OPTION
IS EXERCISABLE
Below $12.00
     
    0%
$12.00 – $14.99
     
  10%
$15.00 – $17.99
     
  20%
$18.00 – $19.99
     
  30%
$20.00 – $24.99
     
  50%
$25.00 – $29.99
     
  75%
Above $29.99
     
100%

F-27

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
The change in control price is defined as the highest price per share received by any holder of the common stock from the purchaser(s) in a transaction or series of transactions that result in a change in control. All options expire no more than ten years after the date of grant.
 
In the event of a “change of control” of PRG, the Board with respect to any award may take such actions that result in (i) the acceleration of the award, (ii) the payment of a cash amount in exchange for the cancellation of an award and/or (iii) the requiring of the issuance of substitute awards that will substantially preserve the value, rights, and benefits of any affected awards.
 
18.    Commitments and Contingencies
 
Legal and Environmental
 
As a result of its activities, the Company is the subject of a number of legal and administrative proceedings, including proceedings related to environmental matters. All such matters that could be material or to which a governmental authority is a party and which involve potential monetary sanctions of $100,000 or greater are described below.
 
Port Arthur: Enforcement.    The Texas Commission on Environmental Quality (“TCEQ”) conducted a site inspection of the Port Arthur refinery in the spring of 1998. In August 1998, the Company 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 TCEQ 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 the air permit at one of its incinerators and that five process wastewater sump vents did not meet applicable air emission control requirements. The TCEQ 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 the Company’s upset reports and emissions monitoring program, and one hazardous waste-related violation concerning spills. The 1998 and 1999 notices were combined and referred to the TCEQ’s litigation division. On September 7, 2000 the TCEQ issued a notice of enforcement regarding the Company’s alleged failure to maintain emission rates at permitted levels. In May 2001, the TCEQ proposed an order covering some of the 1998 hazardous waste allegations, the incinerator temperature deficiency, the process wastewater sumps, and all of the 1999 and 2000 allegations, and proposing the payment of a fine of $562,675 and the implementation of a series of technical provisions requiring corrective actions. Negotiations with the TCEQ are ongoing.
 
Lima: Finding of Violation.    On July 10, 2001, the Ohio Environmental Protection Agency issued a finding of violation by the Company of state and federal laws regarding releases of annual benzene quantities into wastewater streams in excess of that allowed and downtime for the Company’s continuous emission control monitors that exceeded the allowed 5%. The Company has settled this action, paid a fine of $120,000 and implemented preventative programs to ensure future compliance.
 
Hartford: Federal Enforcement.    In February 1999, the federal government filed 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 Company settled this action in July 2001 by agreeing to install a wet gas scrubber on the fluid catalytic cracking unit and low nitrogen oxide burners, and agreeing to pay a civil penalty of $2 million. As a result of the planned closure of the Hartford refinery in September 2002, we do not anticipate making these capital expenditures.
 
Blue Island: Federal and State Enforcement.    In September 1998, the federal government filed a complaint, United States v. Clark Refining & Marketing, Inc., alleging that the Blue Island refinery violated federal environmental laws relating to air, water and solid waste. The Illinois Attorney General intervened in the

F-28

Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

case. The State of Illinois and Cook County had also brought an action, several years earlier, People ex rel. Ryan v. Clark Refining & Marketing, Inc., also alleging violations under environmental laws. In the first quarter of 2002, PRG reached an agreement to settle both cases, subject to final approval by the state and federal courts. The consent order in the federal case requires the payment of $6.25 million as a civil penalty and requires limited ongoing monitoring at the now-idled refinery. The consent order in the state case requires an ongoing tank inspection program along with enhanced reporting obligations and requires that the parties enter a process to complete an appropriate site remediation program at the Blue Island refinery. The consent orders dispose of both the federal and state cases. It is anticipated that both the state and federal courts will approve the proposed settlement early in the second quarter of 2002.
 
Blue Island: Criminal Matters.    In June 2000, PRG pled guilty to one felony count of violating the Clean Water Act and one count of conspiracy to defraud the United States at the Blue Island refinery. These charges arose out of the discovery, during an Environmental Protection Agency (“EPA”) investigation at the site conducted in 1996, that two former employees had allegedly falsified certain reports regarding wastewater sent to the municipal wastewater treatment facility. As part of the plea agreement, PRG agreed to pay a fine of $2 million and was placed on probation for three years beginning September 22, 2000. The Company does not anticipate that the probation of PRG will have a significant adverse impact on its business on an ongoing basis. The primary remaining condition of probation is an obligation not to commit future environmental crimes. If PRG were to commit a crime in the future, it would be subject not only to prosecution for that new violation, but also to a separate charge that it had violated a condition of its probation. Any violation of probation charge would be brought before the same judge who entered the original sentence, and that judge would have the authority to enter a new and potentially more severe sentence for the offense to which PRG pled guilty in June 2000. One of the former employees pled guilty to a misdemeanor charge and was placed on one-year probation and the other former employee was found guilty on felony charges and sentenced to 21 months in prison related to these events.
 
Blue Island: Class Action Matters.    In October 1994, the Company’s Blue Island refinery experienced an accidental release of used catalyst into the air. In October 1995, a class action, Rosolowski v. Clark Refining & Marketing, Inc., et al., was filed against the Company seeking to recover damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. The complaint underlying this action was later amended to add allegations of subsequent events that allegedly diminished property values. In June 2000, the Company’s Blue Island refinery experienced an electrical malfunction that resulted in another accidental release of used catalyst into the air. Following the 2000 catalyst release, two cases were filed purporting to be class actions, Madrigal et al. v. The Premcor Refining Group Inc. and Mason et al. v. The Premcor Refining Group Inc. Both cases seek damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. These cases have been consolidated for the purpose of conducting discovery, which is currently proceeding.
 
Sashabaw Road Retail Location: State Enforcement.    In July 1994, the Michigan Department of Natural Resources brought an action alleging that one of the Company’s retail locations caused groundwater contamination, necessitating the installation of a new $600,000 drinking water system. The Michigan Department of Natural Resources sought reimbursement of this cost. Although this site may have contributed to contamination in the area, the Company maintained that numerous other sources were responsible and that a total reimbursement demand from the Company would be excessive. Mediation resulted in a $200,000 finding against the Company. The Company made an offer of judgment equal to the mediation finding. The offer was rejected by the Michigan Department of Natural Resources and the matter was tried in November 1999, resulting in a judgment against the Company of $110,000 plus interest. Since the judgment was over 20% below the previous settlement offer, under applicable state law the Company is entitled to recover its legal fees. Both the Michigan Department of Natural Resources and the Company have appealed the decision.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 
New Source Review Permit Issues.    New Source Review requirements under the Clean Air Act apply to newly constructed facilities, significant expansions of existing facilities, and significant process modifications and requires new major stationary sources and major modifications at existing major stationary sources to obtain permits, perform air quality analysis and install stringent air pollution control equipment at affected facilities. The EPA has commenced an industry-wide enforcement initiative regarding New Source Review. The current EPA initiative, which includes sending numerous refineries information requests pursuant to Section 114 of the Clean Air Act, appears to target many items that the industry has historically considered routine repair, replacement, maintenance or other activity exempted from the New Source Review requirements.
 
The Company has responded to an information request from the EPA regarding New Source Review compliance at its Port Arthur and Lima refineries, both of which were purchased within the last seven years. The Company believes that any costs to respond to New Source Review issues at those refineries prior to our purchase are the responsibility of the prior owners and operators of those facilities. The Company responded to the request in late 2000, providing information relating to the Company’s period of ownership, and the Company is awaiting a response.
 
In July 2001, the Company settled a lawsuit with the EPA and the State of Illinois that resolved, among other historic compliance issues, a New Source Review issue resulting from repairs made to the fluid catalytic cracking unit at the Hartford refinery in 1994.
 
The federal and state enforcement action at the Blue Island refinery, which has been settled with the EPA and the State of Illinois also included New Source Review issues. The Company believes that a resolution of the Blue Island litigation will include a resolution of these issues and that the EPA’s Section 114 request will not be material to the Company’s financial condition or results of operations.
 
Port Arthur: Natural Resource Damage Assessment.    In 1999, Premcor USA Inc. and Chevron were notified by 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 prior to January 1, 2000. The Company is cooperating with the government agencies in this investigation. The Company has entered into an agreement with Chevron pursuant to which Chevron will indemnify the Company for any future claims in consideration of a payment of $750,000, which we paid in October 2001.
 
Port Arthur and Lima Refineries.    The original refineries on the sites of the Port Arthur and Lima refineries began operating in the late 1800s and early 1900s, prior to modern environmental laws and methods of operation. There is contamination at these sites, which the Company believes will be required to be remediated. Under the terms of the Company’s 1995 purchase of the Port Arthur refinery, Chevron Products Company, the former owner, retained liability for all required investigation and remediation relating to pre-purchase contamination discovered by June 1997, except with respect to certain areas on or around which active processing units are located, which are the Company’s responsibility. Less than 200 acres of the 4,000-acre refinery site are occupied by active operating units. Extensive due diligence efforts prior to the acquisition and additional investigation after the acquisition documented contamination for which Chevron is responsible. In June 1997, the Company entered into an agreed order with Chevron and the TCEQ, that incorporates this contractual division of the remediation responsibilities into an agreed order. The Company has accrued $11.4 million (December 31, 2000—$8.6 million) for the Port Arthur remediation as of December 31, 2001. Under the terms of the purchase of the Lima refinery, BP PLC (“BP”), the former owner, indemnified the Company for all pre-existing environmental liabilities, except for contamination resulting from releases of hazardous substances in or on sewers, process units and other equipment at the refinery as of the closing date, but only to the extent the presence of these hazardous substances was as a result of normal operations of the refinery and does not constitute a violation of any environmental law. Although the Company is not primarily responsible for the

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

majority of the currently required remediation of these sites, the Company may become jointly and severally liable for the cost of investigating and remediating a portion of these sites in the event that Chevron or BP fails to perform the remediation. In such event, however, the Company believes it would have a contractual right of recovery from these entities. The cost of any such remediation could be substantial and could have a material adverse effect on the Company’s financial position.
 
Blue Island Refinery Decommissioning and Closure.    In January 2001, the Company ceased operations at its Blue Island, Illinois refinery although the Company continues to operate the adjacent Alsip terminal. The decommissioning, dismantling and tear down of the facility is underway. The Company is currently in discussions with federal, state and local governmental agencies concerning remediation of the site. The governmental agencies have proposed a remediation process patterned after national contingency plan provisions of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). The Company has proposed to the agencies a site investigation and remediation that incorporates certain elements of the CERCLA process and the State of Illinois’ site remediation program. Related to the closure of the facility, we accrued $56.4 million for decommissioning, remediation of the site and asbestos abatement. As of December 31, 2001, the Company had spent $22.0 million. In the second quarter of 2002, the Company expects to finalize procurement of environmental risk insurance policies. This program will allow the Company to better estimate and, within the limits of the policy, cap the Company’s cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a self insured retention of $250,000 per incident. The Company believes this insurance program also provides the governmental agencies financial assurance that, once begun, remediation of the site will be completed in a timely and prudent manner.
 
Former Retail Sites.    In 1999, the Company sold its former retail marketing business, which the Company operated from time to time on a total of 1,150 sites. During the normal course of operations of these sites, releases of petroleum products from underground storage tanks have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the underground storage tank regulations under the Resource Conservation and Recovery Act has been delegated to the states that administer their own underground storage tank programs. The Company’s obligation to remediate such contamination varies, depending upon the extent of the releases and the stringency of the laws and regulations of the states in which the releases were made. A portion of these remediation costs may be recoverable from the appropriate state underground storage tank reimbursement fund once the applicable deductible has been satisfied. The 1999 sale included 672 sites, 225 of which had no known pre-closure contamination, 365 of which had known pre-closure contamination of varying extent, and 80 of which had been previously remediated. The purchaser of the retail division assumed pre-closure environmental liabilities of up to $50,000 per site at the sites on which there was no known contamination. The Company is responsible for any liability above that amount per site for pre-closure liabilities, subject to certain time limitations. With respect to the sites on which there was known pre-closing contamination, the Company retained liability for 50% of the first $5 million in remediation costs and 100% of remediation costs over that amount. The Company retained any remaining pre-closing liability for sites that had been previously remediated.
 
Of the remaining 478 former retail sites not sold in the 1999 transaction described above, the Company has sold all but 11 in open market sales and auction sales. The Company generally retains the remediation obligations for sites sold in open market sales with identified contamination. Of the retail sites sold in auctions, the Company agreed to retain liability for all of these sites until an appropriate state regulatory agency issues a letter indicating that no further remedial action is necessary. However, these letters are subject to revocation if it is later determined that contamination exists at the properties and the Company would remain liable for the remediation

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

of any property at which such a letter was received but subsequently revoked. The Company is currently involved in the active remediation of 139 of the retail sites sold in open market and auction sales and is actively seeking to sell the remaining 11 properties. During the period from the beginning of 1999 through 2001, the Company had expended $17 million to satisfy the obligations described above and as of December 31, 2001, had $26.6 million (December 31, 2000—$6.1 million) accrued, net of reimbursements of $12.2 million (December 31, 2000—$3.1 million), to satisfy those obligations in the future.
 
Former Terminals.    In December 1999, the Company sold 15 refined product terminals to a third party, but retained liability for environmental matters at four terminals and, with respect to the remaining eleven terminals, the first $250,000 per year of environmental liabilities for a period of six years up to a maximum of $1.5 million. As of December 31, 2001, the Company had expended $0.5 million on these obligations and has accrued $2.9 million (December 31, 2000—$3.1 million) for these obligations in the future including additional investigative and administrative costs.
 
Legal and Environmental Reserves.    As a result of its normal course of business, the Company is a party to a number of legal and environmental proceedings. As of December 31, 2001, the Company had accrued a total of approximately $77 million (December 31, 2000—$34 million), on an undiscounted basis, for legal and environmental-related obligations that may result from the matters noted above and other legal and environmental matters. 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.
 
Environmental Product Standards
 
Reformulated Fuels.    EPA regulations also require that reformulated gasoline and low sulfur diesel intended for all on-road consumers be produced for ozone non-attainment areas, including Chicago, Milwaukee and Houston, which are in the Company’s direct market areas. In addition, because St. Louis is a voluntary participant in the EPA’s ozone reduction program, reformulated gasoline and low sulfur diesel is also required in the St. Louis market area, another of the Company’s direct market areas. Expenditures necessary to comply with existing reformulated fuels regulations are primarily discretionary. The Company’s decision of whether or not to make these expenditures is driven by market conditions and economic factors. The reformulated fuels programs impose restrictions on properties of fuels to be refined and marketed, including those pertaining to gasoline volatility, oxygenate content, detergent addition and sulfur content. The restrictions on fuel properties vary in markets in which the Company operates, depending on attainment of air quality standards and the time of year. The Port Arthur and Hartford refineries can produce up to approximately 60% and 25%, respectively, of gasoline production in reformulated gasoline. Each refinery’s maximum reformulated gasoline production may be limited by the clean fuels attainment of the Company’s total refining system. The Port Arthur refinery’s diesel production complies with the current on-road sulfur specification of 500 parts per million, or ppm.
 
Tier 2 Motor Vehicle Emission Standards.    In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the sulfur content of gasoline at any refinery not exceed 30 ppm during any calendar year by January 1, 2006. These requirements will be phased in beginning on January 1, 2004. It is the Company’s intent to meet these specifications from the Port Arthur and Lima refineries on a timely basis. However, the Company has concluded that there is no economically viable manner of reconfiguring the Hartford refinery to produce fuels which meet these new specifications and the new diesel fuel specifications discussed below. Modifications will be required at the Port Arthur and Lima refineries as a result of the Tier 2 standards.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company believes, based on current estimates, that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2005 of approximately $176 million at those refineries. The Company’s current estimate represents a decrease from our preliminary estimates due to the decision to close the Hartford refinery. More than 95% of the total investment to meet the Tier 2 gasoline specifications is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003.
 
Low Sulfur Diesel Standards.    In January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Refining industry groups have filed two lawsuits, which may delay implementation of the on-road diesel rule beyond 2006. The EPA has estimated that the overall cost to fuel producers of the reduction in sulfur content would be approximately $0.04 per gallon. The EPA has also announced its intention to review the sulfur content in diesel fuel sold to off-road consumers. If regulations are promulgated to regulate the sulfur content of off-road diesel, the Company expects the sulfur requirement to be either 500 ppm, which is the current on-road limit, or 15 ppm, which will be the future on-road limit. It is the Company’s intent to meet these specifications from the Port Arthur and Lima refineries on a timely basis. However, the Company has concluded that there is no economically viable manner of reconfiguring our Hartford refinery to produce fuels which meet these new specifications and the new gasoline fuel specifications discussed above. The Company estimates capital expenditures in the aggregate through 2006 required to comply with the diesel standards at our Port Arthur and Lima refineries, utilizing existing technologies, is approximately $225 million. More than 90% of the projected investment is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. The Company has initiated a project at the Port Arthur refinery to comply with these new diesel fuel specifications in conjunction with an expansion of this refinery to 300,000 bpd. The Company is also evaluating potential projects to reconfigure our Lima refinery to process a more sour and heavier crude slate. The Company believes these projects, combined with the low sulfur gasoline and diesel fuel investments, will offer a reasonable return on capital.
 
Maximum Available Control Technology.    In September 1998, the EPA proposed regulations to implement Phase II of the petroleum refinery Maximum Achievable Control Technology rule under the federal Clean Air Act, referred to as MACT II, which regulates emissions of hazardous air pollutants from certain refinery units. Finalization of the MACT II regulations has been delayed in an attempt to harmonize the MACT II requirements with Tier 2 gasoline and low sulfur diesel requirements. If the MACT II regulations are finalized and implemented as proposed, in order to comply, the Company expects to spend approximately $45 million in the three years following their finalization with the greatest concentration of spending likely in 2003 and 2004.
 
Other Commitments
 
Crude Oil Purchase Commitment.    In 1999, the Company sold crude oil linefill in the pipeline system supplying the Lima refinery. An agreement is in place that requires the Company to repurchase approximately 2.7 million barrels of crude oil in this pipeline system on September 30, 2002 at the then current market prices. The Company has hedged the price risk related to the repurchase obligations through the purchase of exchange-traded futures contracts.
 
Long-Term Crude Oil Contract
 
PACC is party to a long-term crude oil supply agreement with PEMEX which supplies approximately 160,000 barrels per day of Maya crude oil. The long-term crude oil supply agreement includes a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstock.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

This price adjustment mechanism contains a formula that represents an approximation for the coker gross margin and provides for a minimum average coker gross margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The agreement expires in 2011.
 
On a monthly basis, the actual coker gross margin is calculated and compared to the minimum. Coker gross margins exceeding the minimum are considered a “surplus” while coker gross margins that fall short of the minimum are considered a “shortfall.” On a quarterly basis, the surplus and shortfall determinations since the beginning of the contract are aggregated. Pricing adjustments to the crude oil the Company purchases are only made when there exists a cumulative shortfall. When this quarterly aggregation first reveals that a cumulative shortfall exists, the Company receives a discount on crude oil purchases in the next quarter in the amount of the cumulative shortfall. If thereafter, the cumulative shortfall incrementally increases, the Company receives additional discounts on crude oil purchases in the succeeding quarter equal to the incremental increase, and conversely, if thereafter, the cumulative shortfall incrementally decreases, the Company repays discounts previously received, or a premium, on crude oil purchases in the succeeding quarter equal to the incremental decrease. Cash crude oil discounts received by the Company in any one quarter are limited to $30 million, while the Company’s repayment of previous crude oil discounts, or premiums, are limited to $20 million in any one quarter. Any amounts subject to the quarterly payment limitations are carried forward and applied in subsequent quarters.
 
As of December 31, 2001, as a result of the favorable market conditions related to the value of Maya crude oil versus the refined products derived from it, a cumulative quarterly surplus of $110.0 million existed under the contract. As a result, to the extent the Company experiences quarterly shortfalls in coker gross margins going forward, the price the Company pays for Maya crude oil in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls.
 
19.    Subsequent Events
 
In February 2002, the Company hired Thomas D. O’Malley as chairman, chief executive officer, and president and William E. Hantke as executive vice president and chief financial officer. Accordingly, in 2002 the Company will recognize severance expenses related to the resignation of the officers who previously held these positions. Also in conjunction with this management change, two new stock incentive plans were approved by the Board of Directors.
 
The 2002 Special Stock Incentive Plan was adopted in connection with the employment of Thomas D. O’Malley and allows for the issuance of stock options of Premcor Inc.’s common stock. Under this plan, 3,400,000 shares of Premcor Inc.’s common stock may be awarded for stock options granted. As of March 2002, 2,200,000 stock options had been granted at an exercise price of $10 per share. The 2002 Equity Incentive Plan was adopted to award key employees, directors, and consultants with various stock options, stock appreciation rights, restricted stock, performance-based awards and other common stock based awards of Premcor Inc.’s common stock. Under the 2002 Equity Incentive Plan, 1,500,000 shares of Premcor Inc.’s common stock may be awarded for stock options granted under this plan, of which 350,000 stock options were granted at an exercise price of $10 per share as of March 2002.
 
The Company approved a plan to discontinue refining operations at the Hartford refinery in October 2002. Although the Hartford refinery has contributed to the Company’s earnings in the past, the Company has concluded that there is no economically viable manner of reconfiguring the refinery to produce fuels which meet new gasoline and diesel fuel standards mandated by the federal government. The Company plans to record a pretax charge to earnings of approximately $120 million in the first quarter of 2002 which includes a $65 million non-cash asset write-down and $55 million related primarily to accruals for employee severance, other shutdown costs and future environmental expenses. The actual cash payment of these future expenses would occur over several years following the shutdown.

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INDEPENDENT AUDITORS’ REPORT
 
To the Board of Directors of Premcor Inc.:
 
We have audited the consolidated financial statements of Premcor Inc. as of December 31, 2000 and 2001, and for each of the three years in the period ended December 31, 2001 and have issued our report thereon dated February 11, 2002 (included elsewhere in this Registration Statement). Our audits also included the financial statement schedule listed in Item 16(b) of this Registration Statement. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
 
DELOITTE & TOUCHE LLP
 
St. Louis, Missouri
February 11, 2002

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PREMCOR INC.
 
SCHEDULE I—CONDENSED INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY BALANCE SHEETS
(dollars in millions except share data)
 
    
December 31,
    
2000
   
2001
ASSETS
              
CURRENT ASSETS:
              
Cash
   
$
—
   
$
2.1
Receivables from affiliates
   
 
16.4
   
 
28.4
Income taxes receivable
   
 
—
   
 
13.7
    
  
Total current assets
   
 
16.4
   
 
44.2
INVESTMENTS IN AFFILIATED COMPANIES
   
 
332.3
   
 
475.4
    
  
    
$
348.7
   
$
519.6
    
  
LIABILITIES AND STOCKHOLDERS’ EQUITY
              
CURRENT LIABILITIES:
              
Payable to affiliates
   
$
11.2
   
$
40.8
Income taxes payable
   
 
1.3
   
 
—
    
  
Total current liabilities
   
 
12.5
   
 
40.8
COMMON STOCKHOLDERS’ EQUITY:
              
Common, $0.01 par value per share, 53,000,000 authorized, 25,720,589 issued and outstanding in 2000 and 2001; Class F Common, $0.01 par value per share, 7,000,000 authorized, 6,101,010 issued and outstanding in 2000 and 2001
   
 
0.3
   
 
0.3
Paid-in capital
   
 
327.2
   
 
327.2
Retained earnings
   
 
8.7
   
 
151.3
    
  
Total common stockholders’ equity
   
 
336.2
   
 
478.8
    
  
    
$
  348.7
   
$
  519.6
    
  
 
 
See accompanying note to non-consolidated financial statements.

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PREMCOR INC.
 
SCHEDULE I—CONDENSED INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY STATEMENTS OF OPERATIONS
(dollars in millions)
 
      
For the Period From
April 27, 1999
(Inception) to
December 31, 1999
     
For the Year Ended
December 31,
         
2000
   
2001
REVENUES:
                         
Equity in net income (loss) of affiliates
     
$
(71.4
)
   
$
80.2
   
$
142.9
EXPENSES:
                         
General and administrative expenses
     
 
—
 
   
 
0.1
   
 
0.2
Interest expense
     
 
—
 
   
 
—
   
 
0.2
      
  
  
INCOME (LOSS) BEFORE INCOME TAXES
     
 
(71.4
)
   
 
80.1
   
 
142.5
Income tax benefit
     
 
—
 
   
 
—
   
 
0.1
      
  
  
NET INCOME (LOSS)
     
$
  (71.4
)
   
$
  80.1
   
$
  142.6
      
  
  
 
 
See accompanying note to non-consolidated financial statements.

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PREMCOR INC.
 
SCHEDULE I—CONDENSED INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY STATEMENTS OF CASH FLOWS
(dollars in millions)
 
      
For the Period From April 27, 1999 (Inception) to December 31, 1999
     
For the Year Ended December 31,
  
         
2000
     
2001
  
Cash flows from operating activities:
                             
Net income (loss)
     
$
  (71.4
)
   
$
80.2
 
   
$
142.6
 
Adjustments:
                             
Equity in net income (loss) of affiliates
     
 
71.4
 
   
 
(80.2
)
   
 
(142.9
)
Other
     
 
—
 
   
 
0.8
 
   
 
(0.2
)
Cash provided by (reinvested in) working capital
                             
Receivables from and payables to affiliates
     
 
(3.9
)
   
 
(1.3
)
   
 
17.6
 
Income taxes payable
     
 
—
 
   
 
1.3
 
   
 
(15.0
)
      
  
  
Net cash provided by (used in) operating activities
     
 
(3.9
)
   
 
0.8
 
   
 
2.1
 
      
  
  
CASH FLOWS FROM INVESTING ACTIVITIES:
                             
Investment in affiliates
     
 
(56.4
)
   
 
(58.1
)
   
 
—
 
      
  
  
Net cash used in investing activities
     
 
(56.4
)
   
 
(58.1
)
   
 
—
 
      
  
  
CASH FLOWS FROM FINANCING ACTIVITIES
                             
Proceeds from issuance of common stock
     
 
60.3
 
   
 
57.3
 
   
 
—
 
      
  
  
Net cash provided by financing activities
     
 
60.3
 
   
 
57.3
 
   
 
—
 
      
  
  
NET INCREASE IN CASH AND CASH EQUIVALENTS
     
 
—
 
   
 
—
 
   
 
2.1
 
CASH AND CASH EQUIVALENTS, beginning of period
     
 
—
 
   
 
—
 
   
 
—
 
      
  
  
CASH AND CASH EQUIVALENTS, end of period
     
$
—
 
   
$
—
 
   
$
2.1
 
      
  
  
 
 
See accompanying note to non-consolidated financial statements.

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PREMCOR INC.
 
SCHEDULE I—CONDENSED INFORMATION OF THE REGISTRANT
NOTE TO NON-CONSOLIDATED FINANCIAL STATEMENTS
 
FOR THE PERIOD FROM APRIL 27, 1999 (INCEPTION) TO DECEMBER 31, 1999
AND THE YEARS ENDED DECEMBER 31, 2000 AND 2001
 
1.    Basis of Presentation
 
Premcor Inc. was formed pursuant to an April 27, 1999 Share Exchange Agreement wherein all shares of Premcor USA Inc. were exchanged on a one-for-one basis for shares of Premcor Inc. The accompanying financial statement schedule has been prepared for the period beginning from the inception of Premcor Inc.
 
These non-consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, except that they are prepared on a non-consolidated basis for the purpose of complying with Article 12 of Regulation S-X. Accordingly, they do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements. Premcor Inc.’s non-consolidated operations include 100% equity interest in Premcor USA Inc., 90% interest in Sabine Holding Corp., and a 5% interest in Clark Retail Enterprises.
 
For further information, refer to the consolidated financial statements, including the notes thereto, included in this Registration Statement.

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Table of Contents
PREMCOR INC.
 
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
(dollars in millions)
 
      
Balance at beginning of year
   
Charged
to expense
   
Net cash outlays
       
Balance at end of year
Asset Reserve:
                                  
Accounts Receivable
     
$
  1.3
   
$
—
   
$
—
 
     
$
  1.3
Liability Reserve:
                                  
Blue Island refinery closure reserve
     
$
—
   
$
  69.1
   
$
(32.6
)
     
$
  36.5

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Table of Contents
INDEPENDENT ACCOUNTANTS’ REPORT
 
To the Board of Directors of Premcor Inc.:
 
We have reviewed the accompanying condensed consolidated balance sheet of Premcor Inc. and its subsidiaries (the “Company”) as of September 30, 2002, the related condensed consolidated statements of operations for the nine months ended September 30, 2001 and 2002, and the related condensed consolidated statements of cash flows for the nine months then ended. 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 condensed consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 10 to the condensed consolidated financial statements, the Company changed its method of accounting for stock based compensation issued to employees.
 
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, 2001, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 11, 2002 (March 29, 2002 as to Note 15, April 15, 2002 as to Notes 10 and 19 and August 5, 2002 as to Note 2), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
DELOITTE & TOUCHE LLP
 
St. Louis, Missouri
November 6, 2002

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Table of Contents
PREMCOR INC. AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share data)
 
    
December 31,
2001
     
September 30,
2002
  
           
(unaudited)
  
ASSETS
                  
CURRENT ASSETS:
                  
Cash and cash equivalents
   
$
510.1
 
   
$
156.3
 
Short-term investments
   
 
1.7
 
   
 
1.7
 
Cash and cash equivalents restricted for debt service
   
 
30.8
 
   
 
51.9
 
Accounts receivable, net of allowance of $1.3 and $3.2
   
 
148.3
 
   
 
200.0
 
Inventories
   
 
318.3
 
   
 
367.3
 
Prepaid expenses and other
   
 
52.3
 
   
 
30.7
 
Assets held for sale
   
 
—
 
   
 
61.2
 
    
  
Total current assets
   
 
1,061.5
 
   
 
869.1
 
PROPERTY, PLANT AND EQUIPMENT, NET
   
 
1,299.6
 
   
 
1,213.7
 
DEFERRED INCOME TAXES
   
 
—
 
   
 
78.8
 
OTHER ASSETS
   
 
148.7
 
   
 
130.9
 
    
  
    
$
  2,509.8
 
   
$
  2,292.5
 
    
  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                  
CURRENT LIABILITIES:
                  
Accounts payable
   
$
366.4
 
   
$
441.4
 
Accrued expenses
   
 
95.4
 
   
 
92.2
 
Accrued taxes other than income
   
 
35.7
 
   
 
28.2
 
Current portion of long-term debt
   
 
81.4
 
   
 
15.6
 
    
  
Total current liabilities
   
 
578.9
 
   
 
577.4
 
LONG-TERM DEBT
   
 
1,391.4
 
   
 
909.7
 
DEFERRED INCOME TAXES
   
 
16.7
 
   
 
—
 
OTHER LONG-TERM LIABILITIES
   
 
109.1
 
   
 
146.8
 
COMMITMENTS AND CONTINGENCIES
   
 
—
 
   
 
—
 
MINORITY INTEREST
   
 
24.2
 
   
 
—
 
EXCHANGEABLE PREFERRED STOCK
($0.01 par value per share; 250,000 shares authorized; 92,284 shares issued and outstanding in 2001)
   
 
94.8
 
   
 
—
 
COMMON STOCKHOLDERS’ EQUITY:
                  
Common, $0.01 par value per share, 53,000,000 authorized, 25,720,589 issued and outstanding in 2001 and 150,000,000 authorized, 57,473,935 issued and outstanding in 2002; Class F Common, $0.01 par value, 7,000,000 authorized, 6,101,010 issued and outstanding in 2001
   
 
0.3
 
   
 
0.6
 
Paid-in capital
   
 
323.7
 
   
 
851.6
 
Accumulated deficit
   
 
(29.3
)
   
 
(193.6
)
    
  
Total common stockholders’ equity
   
 
294.7
 
   
 
658.6
 
    
  
    
$
  2,509.8
 
   
$
  2,292.5
 
    
  
 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
PREMCOR INC. AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; amounts in millions, except per share data)
 
    
For the Nine Months Ended September 30,
  
    
2001
     
2002
  
NET SALES AND OPERATING REVENUES
   
$
  5,170.9
 
   
$
  4,807.1
 
EXPENSES:
                  
Cost of sales
   
 
4,133.7
 
   
 
4,342.8
 
Operating expenses
   
 
355.8
 
   
 
338.2
 
General and administrative expenses
   
 
45.3
 
   
 
40.8
 
Stock option compensation expense
   
 
—
 
   
 
9.9
 
Depreciation
   
 
39.6
 
   
 
35.7
 
Amortization
   
 
28.1
 
   
 
29.2
 
Refinery restructuring and other charges
   
 
176.2
 
   
 
172.9
 
    
  
    
 
4,778.7
 
   
 
4,969.5
 
OPERATING INCOME (LOSS)
   
 
392.2
 
   
 
(162.4
)
Interest and finance expense
   
 
(121.6
)
   
 
(89.4
)
Gain (loss) on extinguishment of long-term debt
   
 
8.7
 
   
 
(19.5
)
Interest income
   
 
15.3
 
   
 
7.9
 
    
  
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST
   
 
294.6
 
   
 
(263.4
)
Income tax (provision) benefit
   
 
(78.7
)
   
 
99.9
 
Minority interest
   
 
(12.4
)
   
 
1.7
 
    
  
INCOME (LOSS) FROM CONTINUING OPERATIONS
   
 
203.5
 
   
 
(161.8
)
Loss from discontinued operations, net of income tax benefit of $5.5
   
 
(8.5
)
   
 
—
 
    
  
NET INCOME (LOSS)
   
 
195.0
 
   
 
(161.8
)
Preferred stock dividends
   
 
(7.9
)
   
 
(2.5
)
    
  
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
   
$
187.1
 
   
$
(164.3
)
    
  
Basic net income (loss) per common share:
                  
Income (loss) from continuing operations
   
$
6.15
 
   
$
(3.57
)
Discontinued operations
   
 
(0.27
)
   
 
—
 
    
  
Net income (loss)
   
$
5.88
 
   
$
(3.57
)
    
  
Weighted average common shares outstanding
   
 
31.8
 
   
 
46.0
 
Diluted net income (loss) per common share:
                  
Income (loss) from continuing operations
   
$
5.67
 
   
$
(3.57
)
Discontinued operations
   
 
(0.25
)
   
 
—
 
    
  
Net income (loss)
   
$
5.42
 
   
$
(3.57
)
    
  
Weighted average common shares outstanding
   
 
34.5
 
   
 
46.0
 
Pro forma for adoption of SFA No. 123:
                  
Income (loss) from continuing operations
   
$
203.1
 
   
$
(161.9
)
Net income (loss) available to common stockholders
   
$
186.7
 
   
$
(164.4
)
Net income (loss) per common share
                  
Basic
   
$
5.87
 
   
$
(3.57
)
Diluted
   
$
5.41
 
   
$
(3.57
)
 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
PREMCOR INC. AND SUBSIDIARIES
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, amounts in millions)
 
    
For the Nine Months Ended September 30,
  
    
2001
     
2002
  
CASH FLOWS FROM OPERATING ACTIVITIES:
                  
Net income (loss)
   
$
195.0
 
   
$
(161.8
)
Discontinued operations
   
 
8.5
 
   
 
—
 
Adjustments:
                  
Depreciation
   
 
39.6
 
   
 
35.7
 
Amortization
   
 
37.1
 
   
 
36.9
 
Deferred income taxes
   
 
71.2
 
   
 
(100.5
)
Inventory write-down to market
   
 
8.7
 
   
 
—
 
Stock option compensation expense
   
 
—
 
   
 
9.9
 
Minority interest
   
 
12.4
 
   
 
(1.7
)
Refinery restructuring and other charges
   
 
125.3
 
   
 
103.6
 
Write-off of deferred financing costs
   
 
0.6
 
   
 
9.5
 
Write-off of equity investment
   
 
—
 
   
 
4.2
 
Other, net
   
 
0.4
 
   
 
15.8
 
Cash provided by (reinvested in) working capital—
                  
Accounts receivable, prepaid expenses and other
   
 
41.9
 
   
 
(30.1
)
Inventories
   
 
(12.0
)
   
 
(49.0
)
Accounts payable, accrued expenses, and taxes other than income
   
 
(105.4
)
   
 
64.5
 
Cash and cash equivalents restricted for debt service
   
 
(30.6
)
   
 
24.1
 
    
  
Net cash provided by (used in) operating activities of continuing operations
   
 
392.7
 
   
 
(38.9
)
Net cash used in operating activities of discontinued operations
   
 
(2.5
)
   
 
(3.3
)
    
  
Net cash provided by (used in) operating activities
   
 
390.2
 
   
 
(42.2
)
    
  
CASH FLOWS FROM INVESTING ACTIVITIES:
                  
Expenditures for property, plant and equipment
   
 
(57.8
)
   
 
(64.1
)
Expenditures for turnaround
   
 
(41.3
)
   
 
(33.4
)
Cash and cash equivalents restricted for investment in capital additions
   
 
—
 
   
 
5.5
 
Other
   
 
0.6
 
   
 
0.2
 
    
  
Net cash used in investing activities
   
 
(98.5
)
   
 
(91.8
)
    
  
CASH FLOWS FROM FINANCING ACTIVITIES:
                  
Long-term debt and capital lease payments
   
 
(58.9
)
   
 
(645.2
)
Proceeds from the issuance of common stock, net
   
 
—
 
   
 
482.0
 
Cash and cash equivalents restricted for debt repayment
   
 
—
 
   
 
(45.2
)
Deferred financing costs
   
 
(9.6
)
   
 
(11.4
)
Preferred stock dividend
   
 
(0.3
)
   
 
—
 
    
  
Net cash used in financing activities
   
 
(68.8
)
   
 
(219.8
)
    
  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
   
 
222.9
 
   
 
(353.8
)
CASH AND CASH EQUIVALENTS, beginning of period
   
 
290.1
 
   
 
510.1
 
    
  
CASH AND CASH EQUIVALENTS, end of period
   
$
  513.0
 
   
$
  156.3
 
    
  
 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2002
(tabular dollar amounts in millions of U.S. dollars)
 
1.    Basis of Preparation and Recent Developments
 
Premcor Inc. (individually, “Premcor Inc.” and collectively with its subsidiaries, the “Company”), a Delaware corporation, was incorporated in April 1999. Premcor Inc. owns all of the outstanding common stock of Premcor USA Inc. (“Premcor USA”). Premcor USA owns all of the outstanding common stock of The Premcor Refining Group Inc. (“PRG”). Following the completion of the restructuring described in Note 3, referred to as the Sabine restructuring, PRG owns all of the outstanding common stock of Sabine River Holding Corp. (“Sabine”). Sabine is the 1% general partner of Port Arthur Coker Company L.P. (“PACC”), a limited partnership, and the 100% owner of Neches River Holding Corp. (“Neches”), which is the 99% limited partner of PACC. PACC is the 100% owner of Port Arthur Finance Corp. (“PAFC”). The restructuring of Sabine as a wholly owned subsidiary of PRG constituted an exchange of ownership interest between entities under common control, and therefore was accounted for similar to a pooling of interests.
 
The Company is an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. The Company owns and operates two refineries with a combined crude oil throughput capacity of 420,000 barrels per day (“bpd”). The refineries are located in Port Arthur, Texas and Lima, Ohio. The Company ceased operations at its 70,000 bpd Hartford, Illinois refinery in late September consistent with the Company’s plan which was announced in February 2002.
 
On May 3, 2002, Premcor Inc. completed an initial public offering of 20.7 million shares of common stock. The initial public offering, plus the concurrent purchases of 850,000 shares in the aggregate by Thomas D. O’Malley, the Company’s chairman of the board, chief executive officer and president, and two independent directors of the Company, netted proceeds to Premcor Inc. of approximately $482 million. The proceeds from the offering were committed to retire debt of Premcor Inc.’s subsidiaries. See Note 8 Long-term Debt for details on the use of these proceeds. Prior to the initial public offering, Premcor Inc.’s common equity was privately held and controlled by Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates (“Blackstone”). Premcor Inc.’s other principal shareholder was a subsidiary of Occidental Petroleum Corporation (“Occidental”). As a result of these sales of Premcor Inc.’s common stock and the Sabine restructuring described in Note 3, Blackstone’s ownership was reduced to approximately 48% and Occidental’s ownership was reduced to approximately 13%.
 
The accompanying unaudited condensed consolidated financial statements of the Company and its subsidiaries are presented pursuant to the rules and regulations of the United States Securities and Exchange Commission in accordance with the disclosure requirements for Form 10-Q. In the opinion of the management of the Company, the unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) necessary to fairly state the results for the interim periods presented. Operating results for the nine months ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002. These unaudited financial statements should be read in conjunction with the audited financial statements and notes for the years ended December 31, 2001 and 2000. Certain reclassifications have been made to prior periods in order to conform to the current period presentation.
 
2.    New and Proposed Accounting Standards
 
On January 1, 2002, the Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 142, Goodwill and Other Intangible Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long- Lived Assets. The adoption of these standards did not have a material impact on the Company’s financial position

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

and results of operations; however, SFAS No. 144 was utilized in the accounting for the Company’s closure of the Hartford, Illinois refinery. See Note 4, Refinery Restructuring and Other Charges for details of the Hartford refinery shutdown.
 
In July 2001, the Financial Accounting Standards Board (“FASB”) issued 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 that 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 and believes that implementation will not have a material impact.
 
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections. SFAS 145 rescinds SFAS No. 4, Reporting Gains and Losses from the Extinguishment of Debt; SFAS No. 44, Accounting for Intangible Assets of Motor Carriers; and SFAS No. 64, Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements. SFAS No. 145 also amends SFAS No. 13, Accounting for Leases, as it relates to sale-leaseback transactions and other transactions structured similar to a sale-leaseback as well as amends other pronouncements to make various technical corrections. The provisions of SFAS No. 145 as they relate to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. The provision of this statement related to the amendment to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions of this statement shall be effective for financial statements on or after May 15, 2002. As permitted by SFAS No. 145, the Company has elected early adoption of the rescission of SFAS No. 4. Accordingly, the Company has included the gain or loss on extinguishment of long-term debt in “Income from continuing operations” as opposed to as an extraordinary item, net of taxes, below “Income from continuing operations” in its Statement of Operations.
 
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires the recognition of liabilities at fair value that are associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Such liabilities include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activities. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company will adopt SFAS No. 146 for all restructuring, discontinued operations, plant closings or other exit or disposal activities initiated after December 31, 2002.
 
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants 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 will 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 require that any existing unamortized turnaround costs be expensed immediately. If this proposed change were in effect at September 30, 2002, the Company would have been required to write-off unamortized turnaround costs of approximately $97 million. Unamortized turnaround costs will change in 2002 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 income tax, in the consolidated statements of operations.

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PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
3.    Sabine Restructuring
 
On June 6, 2002, PRG and Sabine completed a series of transactions (“the Sabine restructuring”) that resulted in Sabine and its subsidiaries becoming wholly owned subsidiaries of PRG. Sabine, through its principal operating subsidiary, PACC, owns and operates a heavy oil processing facility, which is operated in conjunction with PRG’s Port Arthur, Texas refinery. Prior to the Sabine restructuring, Sabine was 90% owned by Premcor Inc. and 10% owned by Occidental.
 
The Sabine restructuring was permitted by the successful consent solicitation of the holders of PAFC’s 12 1/2% Senior Notes. The Sabine restructuring was accomplished according to the following steps, among others:
 
 
•
 
Premcor Inc. contributed $225.6 million in proceeds from its initial public offering of common stock to Sabine. Sabine used the proceeds from the equity contribution, plus cash on hand, to prepay $221.4 million of its Bank Senior Loan Agreement and to pay a dividend of $141.4 million to Premcor Inc.;
 
 
•
 
Commitments under Sabine’s senior secured bank loan, working capital facility, and certain insurance policies were terminated and related guarantees were released;
 
 
•
 
PRG’s existing working capital facility was amended and restated to, among other things, permit letters of credit to be issued on behalf of Sabine;
 
 
•
 
Occidental exchanged its 10% interest in Sabine for 1,363,636 newly issued shares of Premcor Inc. common stock;
 
 
•
 
Premcor Inc. contributed its 100% ownership interest in Sabine to Premcor USA and Premcor USA, in turn, contributed its 100% ownership interest in Sabine to PRG; and
 
 
•
 
PRG fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations under the PAFC 12½% Senior Notes.
 
Premcor Inc.’s acquisition of Occidental’s 10% ownership in Sabine was accounted for under the purchase method. The purchase price was based on the exchange of 1,363,636 shares of Premcor Inc. common stock for the 10% interest in Sabine and was valued at $30.5 million or approximately $22 per share. The purchase price of the 10% minority interest in Sabine exceeded the book value by $8.0 million. Based on an appraisal of the Sabine assets, the excess of the purchase price over the book value of the minority interest, along with a $5.0 million deferred income tax adjustment, was recorded as an investment in property, plant and equipment and will be depreciated over the remaining useful lives of the related Sabine assets. The income tax adjustment reflected the temporary difference between the book and tax basis of property, plant and equipment related to the excess of the purchase price over book value. Because the purchase price did not exceed the fair value of the underlying assets, no goodwill was recognized.
 
As discussed in Note 1, the contribution of Premcor Inc.’s 100% ownership interest in Sabine to PRG was an exchange of ownership interest between entities under common control, and therefore was accounted for at the book value of Sabine, similar to a pooling of interests.

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
4.    Refinery Restructuring and Other Charges
 
In 2002, the Company recorded refinery restructuring and other charges of $172.9 million, which consisted of the following:
 
 
•
 
a $137.4 million charge related to the shutdown of refining operations at the Hartford, Illinois refinery,
 
 
•
 
a $32.4 million charge related to the restructuring of the Company’s management team, refinery operations and administrative functions,
 
 
•
 
income of $5.0 million related to the unanticipated sale of a portion of the Blue Island refinery assets previously written off,
 
 
•
 
a $2.5 million charge related to the termination of certain guarantees at PACC as part of the Sabine restructuring,
 
 
•
 
a $1.4 million loss related to idled assets held for sale, and
 
 
•
 
a $4.2 million write-down of Premcor Inc.’s 5% interest in Clark Retail Group, Inc., the sole stockholder of Clark Retail Enterprises, Inc. (“CRE”). Premcor Inc. acquired an interest in Clark Retail Group, Inc. when PRG sold its retail business to CRE in 1999. Clark Retail Group, Inc. and CRE filed a petition to reorganize under Chapter 11 of the U.S. bankruptcy laws in October 2002.
 
In 2001, refinery restructuring and other charges of $176.2 million consisted of a $167.2 million charge related to the January 2001 closure of the Blue Island, Illinois refinery and a $9.0 million charge related to the write-off of idled coker units at the Port Arthur refinery. The write-off of the Port Arthur coker units included a charge of $5.8 million related to the net asset value of the idled cokers and a charge of $3.2 million for future environmental clean-up costs related to the coker unit site.
 
Hartford Refinery Closure
 
In late September 2002, the Company ceased operations at its Hartford refinery after concluding there was no economically viable method of reconfiguring the refinery to produce fuels meeting new gasoline and diesel fuel specifications mandated by the federal government. Despite ceasing operations, the Company continues to pursue all options, including the sale of the refinery, to mitigate the loss of jobs and refinery capacity in the Midwest.
 
Since the Hartford refinery operation had been only marginally profitable over the last 10 years and since substantial investment would be required to meet new required product specifications in the future, the Company’s reduced refining capacity resulting from the shutdown is not expected to have a significant negative impact on net income or cash flow from operations. The only anticipated effect on net income and cash flow in the future will result from the actual shutdown process, including recovery of realizable asset value, and subsequent environmental site remediation, which will occur over a number of years. Unless there is a need to adjust the shutdown reserve in the future as discussed below, there should be no significant effect on net income beyond 2002.
 
A pretax charge of $137.4 million was recorded in 2002, which included $70.7 million of non-cash long-lived asset write-offs to reduce the refinery assets to their estimated net realizable value of $61.0 million. The net realizable value was determined by estimating the value of the assets in a sale or operating lease transaction and was recorded as a current asset on the balance sheet. In October 2002, we announced that we would continue to operate the Hartford terminal facility to accommodate our wholesale petroleum product distribution business. As a result, we reclassified the net book value of the terminal assets from assets held for sale to property, plant and equipment. This reduced the estimated net realizable value of the remaining refinery assets to $49.0 million. The Company has had preliminary discussions with third parties regarding a transaction for the refinery assets such a transaction, but there can be no assurance that one will be completed. In the event that a sale or lease transaction is not completed, the net realizable value may be less than $49.0 million and a further write-down may be

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Table of Contents

PREMCOR INC. AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

required. In the second quarter of 2002, the Company completed an evaluation of its warehouse stock, catalysts, chemicals, and additives inventories, and the Company determined that a portion of these inventories would not be recoverable upon the closure or sale of the refinery. Accordingly, the Company wrote-down these assets by $3.2 million.
 
The total charge also included a reserve for future costs of $62.5 million as itemized below. The Hartford restructuring reserve balance and net cash activity as of September 30, 2002 is as follows:
 
    
Initial Reserve
   
Net Cash Outlay
     
Reserve as of September 30, 2002
Employee severance
   
$
16.6
   
$
0.2
     
$
16.4
Plant closure/equipment remediation
   
 
12.9
   
 
5.6
     
 
7.3
Site clean-up/environmental matters
   
 
33.0
   
 
—
     
 
33.0
    
  
    
    
$
  62.5
   
$
  5.8
     
$
  56.7
    
  
    
 
Management adopted an exit plan that details the shutdown of the process units at the refinery and the subsequent environmental remediation of the site. The Company expects the majority of the process unit shutdown and hydrocarbon purging to be finalized in the fourth quarter of 2002. The Company terminated approximately 300 of 315 employees, both hourly (covered by collective bargaining agreements) and salaried, in October 2002. The site clean-up and environmental reserve takes into account costs that are reasonably foreseeable at this time. As the final disposition of the refinery is determined and a site remediation plan refined, further adjustments of the reserve may be necessary, and such adjustments may be material. The Company expects to spend approximately $20 million to $30 million in 2002 related to employee severance and the process unit shutdown and hydrocarbon purge.
 
Finally, the total charge included a $1.0 million reserve related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. This liability was recorded in “Other Long-term Liabilities” on the balance sheet together with the Company’s other post-retirement liabilities.
 
Management, Refinery Operations and Administrative Restructuring
 
In February 2002, the Company began the restructuring of its executive management team and subsequently its administrative functions with the hiring of Thomas D. O’Malley as chairman, chief executive officer, and president and William E. Hantke as executive vice president and chief financial officer. In the first quarter of 2002, as a result of the resignation of the officers who previously held these positions, the Company recognized severance expense of $5.0 million and non-cash compensation expense of $5.8 million resulting from modifications of stock option terms. In addition, the Company incurred a charge of $5.0 million for the cancellation of a monitoring agreement with an affiliate of Blackstone.
 
In the second quarter of 2002, the Company commenced a restructuring of its St. Louis-based general and administrative operations and recorded a charge of $6.5 million for severance, outplacement and other restructuring expenses relating to the elimination of 107 hourly and salaried positions. In the third quarter of 2002, the Company announced plans to reduce its non-represented workforce at its Port Arthur, Texas and Lima, Ohio refineries and make additional staff reductions at its St. Louis administrative office. The Company recorded a charge of $10.1 million for severance, outplacement, and other restructuring expenses relating to the elimination of 140 hourly and salaried positions. Included in this charge is $1.3 million related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. This liability was recorded in “Other Long-term Liabilities” on the balance sheet together with the Company’s other post-

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

retirement liabilities. Reductions at the refineries occurred in October 2002 and those at the St. Louis office will take place by the end of the first quarter of 2003. The reserve relating to the refineries and St. Louis restructuring is as follows:
 
    
Initial Reserve
   
Additional Reserve
   
Net Cash Outlay
     
Reserve at September 30, 2002
Refineries and St. Louis restructuring
   
$
  6.5
   
$
  8.8
   
$
  4.6
     
$
  10.7
 
The Company expects to spend approximately $11 million to $13 million in 2002 related to these refinery and St. Louis restructuring activities.
 
Blue Island Refinery Closure Reserve
 
In 2001, the Company recorded a pretax charge of $167.2 million related to the January 2001 closure of the Blue Island, Illinois refinery. The Blue Island restructuring reserve balance and net cash activity as of September 30, 2002 is as follows:
 
      
Reserve as of December 31, 2001
   
Net Cash Outlay
     
Reserve as of
September 30, 2002
Employee severance
     
$
2.1
   
$
2.1
     
$
—
Plant closure/equipment remediation
     
 
13.9
   
 
8.1
     
 
5.8
Site clean-up/environmental matters
     
 
20.5
   
 
3.9
     
 
16.6
      
  
    
      
$
  36.5
   
$
  14.1
     
$
  22.4
      
  
    
 
The Company expects to spend approximately $15 million to $16 million in 2002 related to the reserve for future costs, with the remainder to be spent over the next several years. The Company is currently in discussions with governmental agencies concerning a remediation program, which it believes will likely lead to a final consent order and remediation plan. The Company does not expect these discussions to be concluded until 2003 at the earliest. The Company’s site clean-up and environmental reserve takes into account costs that are reasonably foreseeable at this time, based on studies performed in conjunction with obtaining the insurance policy mentioned below. As the site remediation plan is finalized and work is performed, further adjustments of the reserve may be necessary.
 
In 2002, environmental risk insurance policies covering the Blue Island refinery site were procured and bound, with final policies expected to be issued within the first quarter of 2003. This insurance program will allow the Company to quantify and, within the limits of the policy, cap its cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self-insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a $100,000 deductible per incident. The Company believes this program also provides governmental agencies financial assurance that, once begun, remediation of the site will be completed in a timely and prudent manner.
 
5.    Gain or Loss on Extinguishment of Long-Term Debt
 
In the nine months ended September 30, 2002, the Company recorded a loss on extinguishment of long-term debt of $19.5 million related to the repurchase of certain long-term debt as described in Note 8 Long-term Debt. The loss recorded for the nine months ended September 30, 2002 included premiums associated with the early repayment of long-term debt of $9.4 million, a write-off of unamortized deferred financing costs related to this

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

debt of $9.5 million, and the write-off of a prepaid premium for an insurance policy guaranteeing the interest and principal payments on Sabine’s long-term debt of $0.6 million.
 
In the nine months ended September 30, 2001, the Company repurchased in the open market $21.3 million in face value of its 9 1/2% Senior Notes, $30.6 million in face value of its 10 7/8% Senior Notes, and $5.9 million in face value of its 11 1/2% Exchangeable Preferred Stock. As a result of these transactions, the Company recorded a gain of $8.7 million, which included discounts of $9.3 million offset by the write-off of deferred financing costs related to the notes.
 
6.    Inventories
 
The carrying value of inventories consisted of the following:
 
    
December 31, 2001
   
September 30, 2002
Crude oil
   
$
77.0
   
$
93.1
Refined products and blendstocks
   
 
218.7
   
 
253.4
Warehouse stock and other
   
 
22.6
   
 
20.8
    
  
    
$
 318.3
   
$
 367.3
    
  
 
The market value of crude oil, refined products and blendstock inventories at September 30, 2002 was approximately $150 million (December 31, 2001—$5 million) above carrying value.
 
As of January 1, 2002, PACC changed its method of inventory valuation from first-in first-out (“FIFO”) to last-in first-out (“LIFO”) for crude oil and blendstock inventories. Management believes this change is preferable in that it achieves a more appropriate matching of revenues and expenses. The adoption of this inventory accounting method on January 1, 2002 did not have an impact on pretax earnings. The adoption of the LIFO method resulted in approximately $12.0 million less net income ($0.26 per basic and diluted share) for the nine months ended September 30, 2002 than if the FIFO method had been used for the same periods. Cost for warehouse stock continues to be determined under the FIFO method.
 
7.    Other Assets
 
Other assets consisted of the following:
 
    
December 31, 2001
   
September 30, 2002
Deferred turnaround costs
   
$
97.9
   
$
96.5
Deferred financing costs
   
 
32.6
   
 
27.0
Cash restricted for investment in capital additions
   
 
9.9
   
 
4.4
Investment in affiliates
   
 
4.7
   
 
0.5
Other
   
 
3.6
   
 
2.5
    
  
    
$
 148.7
   
$
 130.9
    
  
 
Amortization of deferred financing costs for the nine months ended September 30, 2002 was $7.5 million (2001—$8.8 million) and was included in “Interest and finance expense”. In 2002, the Company incurred deferred financing costs of $1.1 million for fees to obtain a waiver related to insurance coverage required under PACC’s common security agreement with certain bondholders and $10.3 million related to the consent solicitation process of the Sabine restructuring and subsequent registration of the PACC senior notes with the Securities & Exchange Commission. In the second quarter of 2002, the Company wrote-off $9.5 million of deferred financing costs as a result of the early repayment of long-term debt.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
8.    Long-term Debt and Exchangeable Preferred Stock
 
Long-term debt and exchangeable preferred stock consisted of the following:
 
    
December 31,
2001
   
September 30,
2002
8 5/8% Senior Notes due August 15, 2008
(“8 5/8% Senior Notes”)(1)
   
$
109.8
   
$
109.8
8 3/8% Senior Notes due November 15, 2007
(“8 3/8% Senior Notes”)(1)
   
 
99.6
   
 
99.6
8 7/8% Senior Subordinated Notes due November 15, 2007
(“8 7/8% Senior Subordinated Notes”)(1)
   
 
174.2
   
 
174.4
Floating Rate Term Loan due November 15, 2003 and 2004
(“Floating Rate Loan”)(1)
   
 
240.0
   
 
240.0
9 1/2% Senior Notes due September 15, 2004
(“9 1/2% Senior Notes”)(1)
   
 
150.4
   
 
—
12 1/2% Senior Notes due January 15, 2009
(“12 1/2% Senior Notes”)(2)
   
 
255.0
   
 
250.7
Bank Senior Loan Agreement(2)
   
 
287.6
   
 
—
10 7/8% Senior Notes due December 1, 2005
(“10 7/8% Senior Notes”)(3)
   
 
144.4
   
 
—
11 1/2% Subordinated Debentures due October 1, 2009
(“11 1/2% Subordinated Debentures”)(3)
   
 
—
   
 
40.1
Ohio Water Development Authority Environmental Facilities Revenue Bonds due December 01, 2031 (“Series 2001 Ohio Bonds”)(1)
   
 
10.0
   
 
10.0
Obligations under capital leases(1)
   
 
1.8
   
 
0.7
    
  
    
 
1,472.8
   
 
925.3
Less current portion of debt
   
 
81.4
   
 
15.6
    
  
Total long-term debt
   
$
 1,391.4
   
$
 909.7
    
  
Exchangeable Preferred Stock (3)
   
$
94.8
   
$
 —
    
  
(1)
 
Issued or borrowed by PRG
(2)
 
Issued or borrowed by PAFC
(3)
 
Issued or borrowed by Premcor USA
 
In 2002, Premcor Inc. contributed $442.9 million of its initial public offering proceeds to its subsidiaries for the early redemption and repurchase of a portion of their outstanding long-term debt. In June 2002, PRG redeemed the remaining $150.4 million of its 9½% Senior Notes at par, and Premcor USA redeemed the remaining $144.4 million of its 10 7/8% Senior Notes, including a $5.2 million premium, from capital contributions received from Premcor Inc.
 
On April 1, 2002, Premcor USA exchanged all of its 11½% Exchangeable Preferred Stock for 11½% Subordinated Debentures. In 2002, Premcor USA purchased, in the open market, $57.5 million in aggregate principal amount of its 11½% Subordinated Debentures at a $3.3 million premium from capital contributions received from Premcor Inc.
 
In 2002, PACC made a $4.3 million principal payment on its 12½% Senior Notes. In January 2002, PACC made a $66.2 million principal payment on its Bank Senior Loan Agreement, of which $59.7 million represented a mandatory prepayment pursuant to the common security agreement and related secured account structure. In

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

June 2002, as part of the Sabine restructuring, PACC prepaid the remaining balance of $221.4 million on the Bank Senior Loan Agreement at a $0.9 million premium, with cash on hand and an $84.2 million net capital contribution from Premcor Inc.
 
Prior to the Sabine restructuring, the common security agreement required that PACC carry insurance coverage with specified terms. Due to the effects of the events of September 11, 2001 on the insurance market, coverage meeting such terms was not available on commercially reasonable terms, and as a result, PACC’s insurance program was not in full compliance with the required insurance coverage at December 31, 2001. PACC received a waiver from the requisite parties. Subsequently, the common security agreement has been amended and restated as part of the Sabine restructuring and the new provisions regarding insurance coverage take into consideration a changing economic environment and its effects on the insurance markets in general. Under the amended and restated common security agreement, PACC has some specific insurance requirements, but principally must ensure that coverage is consistent with customary standards in its industry. There is also a provision that allows for thirty days notice to requisite parties of any inability to comply with the specific terms without any event of a default. As of September 30, 2002, PACC was in compliance with the insurance coverage requirements of the amended and restated common security agreement.
 
9.    Working Capital Facility
 
In March 2002, PRG received a waiver regarding the maintenance of the tangible net worth covenant related to its $650 million working capital credit agreement, which allows for the exclusion of $120 million of the pretax restructuring charge related to the closure of the Hartford refinery.
 
As part of the Sabine restructuring, Sabine terminated its insurance policy that guaranteed its Maya crude oil purchase obligations and its $35 million bank working capital facility that supported Sabine’s non-Maya crude oil purchase obligations. In May 2002, PRG amended its $650 million working capital facility principally to allow for the inclusion of Sabine crude oil purchase obligations. As amended, the $650 million limit of the facility can be increased by $50 million, up to the borrowing base limitation, at the request of PRG and upon securing additional commitments. Also under the amendment, the borrowing base calculation was amended to include PACC inventory and the tangible net worth covenant was increased to $400 million from $150 million.
 
10.    Stock Option Plans
 
In conjunction with the management change discussed in Note 4 above, Premcor Inc. adopted two new stock incentive plans. The 2002 Special Stock Incentive Plan was adopted in connection with the employment of Thomas D. O’Malley and allows for the issuance of options for the purchase of Premcor Inc. common stock. Under this plan, options on 3,400,000 shares of Premcor Inc. common stock may be awarded. As of September 30, 2002, options for 2,950,000 shares of Premcor Inc. common stock had been granted, options for 2,200,000 shares at an exercise price of $10 per share and options for 750,000 shares at an exercise price of $22.50 per share. Options granted under this plan vest 1/3 on each of the first three anniversaries of the date of grant. The options for 750,000 shares referenced above were granted to Mr. O’Malley pursuant to his employment agreement.
 
The 2002 Equity Incentive Plan was adopted to award key employees, directors, and consultants with various stock options, stock appreciation rights, restricted stock, performance-based awards and other common stock based awards of Premcor Inc. common stock. Under the 2002 Equity Incentive Plan, options for 1,500,000 shares of Premcor Inc. common stock may be awarded. As of September 30, 2002, options for 1,036,000 shares of Premcor Inc. common stock were granted as follows: options for 435,000 shares at an exercise price of $10 per share and options for 601,000 shares at an exercise price ranging from $18.50 per share to $26 per share.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Options granted under this plan vest 1/3 on each of the first three anniversaries of the date of grant. These options included options for 100,000 shares granted to two directors pursuant to agreements with the Company.
 
During the second quarter of 2002, the Company elected to adopt the fair value based expense recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). The Company previously applied the intrinsic value based expense recognition provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). SFAS No. 123 provides that the adoption of the fair value based method is a change to a preferable method of accounting. As provided by SFAS No. 123, the stock option compensation expense is calculated based only on stock options granted in the year of election and thereafter. The fair value of these options was estimated on the grant date using the Black-Sholes option-pricing model with the following weighted average assumptions as of September 30, 2002: a) assumed risk-free rate of 5.06% per annum, b) expected life of 3.7 years, c) expected volatility of 38.9%, and d) no expected dividends. All stock options granted prior to January 1, 2002 continue to be accounted for under APB No. 25.
 
In the period of adoption of SFAS No. 123, the adoption of this fair value based method increased the Company’s net loss by $0.6 million (less than $0.01 per basic share) and $0.8 million (less than $0.01 per basic share) for the three-month and six-month periods ended June 30, 2002, respectively. The effects of the adoption of SFAS No. 123 on loss from continuing operations, net loss available to common stockholders, and net loss per share for the three-month period ended March 31, 2002 are as follows:
 
Loss from continuing operations and net loss available to common
stockholders:
         
As reported
   
$
 (99.5
)
Revised for adoption of SFAS No. 123
   
$
(99.7
)
Net loss per common share (in whole dollars):
         
As reported
   
$
(3.13
)
Revised for adoption of SFAS No. 123
   
$
(3.14
)
 
Since nonvested awards issued to employees prior to January 1, 2002 continue to be accounted for using the intrinsic value based provisions of APB No. 25, employee stock-based compensation expense determined using the fair value based method applied prospectively is not necessarily indicative of future expense amounts when the fair value based method will apply to all outstanding nonvested awards. With respect to all stock option grants outstanding at September 30, 2002, the Company will record future non-cash stock option compensation expense and additional paid-in capital of $40.4 million over the applicable vesting periods of the grants.
 
11.    Interest and Finance Expense
 
Interest and finance expense included in Premcor Inc.’s statements of operations consisted of the following:
 
    
For the Nine Months Ended September 30,
  
    
2001
       
2002
  
Interest expense
   
$
113.5
 
     
$
83.4
 
Financing costs
   
 
11.9
 
     
 
10.6
 
Capitalized interest
   
 
(3.8
)
     
 
(4.6
)
    
    
    
$
 121.6
 
     
$
 89.4
 
    
    
 
The Company’s cash paid for interest for the nine months ended September 30, 2002 was $95.6 million (2001—$120.9 million), respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
12.    Income Taxes
 
The Company received net cash income tax refunds during the nine months ended September 30, 2002 of $12.4 million (2001—$13.6 million net cash income tax payments).
 
The income tax provision on the income from continuing operations before income taxes for the nine months ended September 30, 2001 of $78.7 million for the Company included the effect of a reversal during the first quarter of 2001 of the remaining deferred tax valuation allowance of $30.0 million. The reversal of the remaining deferred tax valuation allowance resulted from the analysis of the likelihood of realizing the future tax benefit of federal and state tax loss carryforwards, alternative minimum tax credits and federal and state business tax credits.
 
13.    Discontinued Operations
 
In 2001, the Company recorded a pretax charge of $14.0 million, $8.5 million net of income taxes, related to environmental liabilities of discontinued retail operations. This charge represented an increase in estimates regarding the Company’s environmental clean-up obligation and was prompted by the availability of new information concerning site by site clean-up plans and changing postures of state regulatory agencies.
 
14.    Earnings per share
 
The diluted share base for the nine months ended September 30, 2002 excluded incremental common stock equivalents of 2,027,715. These common stock equivalents were excluded due to their antidilutive effect as a result of the Company’s net loss available to common stockholders. The dilutive shares related to employee stock options and shareholder warrants. The diluted weighted average shares outstanding for the nine months ended September 30, 2001 reflected the potential dilution that could have occurred if all outstanding warrants were exercised. In the second quarter of 2002, all outstanding shareholder warrants were exercised. In the earnings per share calculation, net income (loss) available to common stockholders includes the deduction of preferred stock dividends when applicable.
 
15.    Commitments and Contingencies
 
Legal and Environmental
 
As a result of its activities, the Company is the subject of a number of material pending legal proceedings, including proceedings related to environmental matters. Set forth below is an update of developments during the nine months ended September 30, 2002 with respect to any such proceedings and with respect to any environmental proceedings that involve monetary sanctions of $100,000 or more and to which a governmental authority is a party.
 
Blue Island: Federal and State Enforcement.    In September 1998, the federal government filed a complaint, United States v. Clark Refining & Marketing, Inc., alleging that the Blue Island refinery violated federal environmental laws relating to air, water and solid waste. The Illinois Attorney General intervened in the case. The State of Illinois and Cook County had also brought an action, several years earlier, People ex rel. Ryan v. Clark Refining & Marketing, Inc., also alleging violations under environmental laws. In 2002, the Company reached an agreement to settle both cases. The consent order in the state case was formally approved and entered by the state court judge on April 8, 2002, and the federal court approved the settlement on June 12, 2002. The

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

consent order in the federal case required payments totaling $6.25 million as civil penalties, which the Company paid on July 12, 2002, and requires limited ongoing monitoring at the now-idled refinery. The Company had previously accrued for this obligation in its legal and environmental reserves. The consent order in the state case requires an ongoing tank inspection program along with enhanced reporting obligations. The consent orders dispose of both the federal and state cases.
 
Legal and Environmental Reserves.    As a result of its normal course of business, the Company is a party to a number of legal and environmental proceedings. As of September 30, 2002, the Company had accrued a total of approximately $99 million (December 31, 2001—$77 million), on an undiscounted basis, for legal and environmental-related obligations that may result from the matters noted above and other legal and environmental matters. As of September 30, 2002, this accrual included approximately $78 million (December 31, 2001—$53 million) for site clean-up and environmental matters associated with the Hartford and Blue Island refinery closures and retail sites. 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.
 
Environmental Standards for Products
 
Tier 2 Motor Vehicle Emission Standards.    In February 2000, the Environmental Protection Agency (“EPA”) promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 ppm during any calendar year by January 1, 2006, phasing in beginning on January 1, 2004. The Company currently expects to produce gasoline under the new sulfur standards at the Port Arthur refinery prior to January 1, 2004 and, as a result of the corporate pool averaging provisions of the regulations, will not be required to meet the new sulfur standards at the Lima refinery until July 1, 2004, a six month deferral. A further delay in the requirement to meet the new sulfur standards at the Lima refinery through 2005 may be possible through the purchase of sulfur allotments and credits which arise from a refiner producing gasoline with a sulfur content below specified levels prior to the end of 2005, the end of the phase-in period. There is no assurance that sufficient allotments or credits to defer investment at the Lima refinery will be available, or if available, at what cost. The Company believes, based on current estimates and on a January 1, 2004 compliance date for both the Port Arthur and Lima refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures for the Lima and Port Arthur refineries in the aggregate through 2005 of approximately $255 million. More than 95% of the total investment to meet the Tier 2 gasoline specifications is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003 and early 2004.
 
Low Sulfur Diesel Standards.    In January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Regulations for off-road diesel requirements are pending. The Company estimates capital expenditures in the aggregate through 2006 required to comply with the diesel standards at its Port Arthur and Lima refineries, utilizing existing technologies, of approximately $245 million. More than 95% of the projected investment is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. Since the Lima refinery does not currently produce diesel fuel to on-road specifications, the Company is considering an acceleration of the low-sulfur diesel investment at the Lima refinery in order to capture this incremental product value. If the investment is accelerated, production of the low-sulfur fuel is possible by the first quarter of 2005.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
Maximum Achievable Control Technology.    On April 11, 2002, the EPA promulgated regulations to implement Phase II of the petroleum refinery Maximum Achievable Control Technology rule under the federal Clean Air Act, referred to as MACT II, which regulates emissions of hazardous air pollutants from certain refinery units. The Company expects to spend approximately $45 million over the next three years related to these new regulations with most of the expenditures occurring in 2003 and 2004.
 
Other Commitments
 
Crude Oil Purchase Commitment.    In 1999, the Company sold crude oil linefill in the pipeline system supplying the Lima refinery to Koch Supply and Trading L.P. or Koch. As part of the agreement with Koch, the Company was required to repurchase approximately 2.7 million barrels of crude oil in this pipeline system in September 2002. On October 1, 2002, Morgan Stanley Capital Group Inc. (“MSCG”), purchased the 2.7 million barrels of crude oil from Koch in lieu of the Company’s purchase obligation. The Company has agreed to purchase those barrels of crude oil from MSCG upon termination of the agreement with them, at then current market prices as adjusted by certain predetermined contract provisions. The initial term of the contract continues until October 1, 2003, and thereafter, automatically renews for additional 30-day periods unless terminated by either party. The Company has hedged the economic price risk related to the repurchase obligation through the purchase of exchange-traded futures contracts.
 
Long-Term Crude Oil Contract.    PACC is party to a long-term crude oil supply agreement with PMI Comercio Internacional, S.A. de C.V. (“PMI”), an affiliate of Petroleos Mexicanos, the Mexican state oil company, which supplies approximately 167,000 barrels per day of Maya crude oil. Under the terms of this agreement, PACC is obligated to buy Maya crude oil from PMI, and PMI is obligated to sell Maya crude oil to PACC. An important feature of this agreement is a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstocks. This price adjustment mechanism contains a formula that represents an approximation of the coker gross margin and provides for a minimum average coker margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The agreement expires in 2011.
 
On a monthly basis, the coker gross margin, as defined under this agreement, is calculated and compared to the minimum. Coker gross margins exceeding the minimum are considered a “surplus” while coker gross margins that fall short of the minimum are considered a “shortfall.” On a quarterly basis, the surplus and shortfall determinations since the beginning of the contract are aggregated. Pricing adjustments to the crude oil the Company purchases are only made when there exists a cumulative shortfall. When this quarterly aggregation first reveals that a cumulative shortfall exists, the Company receives a discount on its crude oil purchases in the next quarter in the amount of the cumulative shortfall. If thereafter, the cumulative shortfall incrementally increases, the Company receives additional discounts on its crude oil purchases in the succeeding quarter equal to the incremental increase. Conversely, if thereafter, the cumulative shortfall incrementally decreases, the Company repays discounts previously received, or a premium, on its crude oil purchases in the succeeding quarter equal to the incremental decrease. Cash crude oil discounts received by the Company in any one quarter are limited to $30 million, while the Company’s repayment of previous crude oil discounts, or premiums, are limited to $20 million in any one quarter. Any amounts subject to the quarterly payment limitations are carried forward and applied in subsequent quarters.
 
As of September 30, 2002, a cumulative quarterly surplus of $61.7 million existed under the contract. As a result, to the extent the Company experiences quarterly shortfalls in coker gross margins going forward, the price it pays for Maya crude oil in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 
Insurance Expenses.    The Company purchases insurance intending to protect against risk of loss from a variety of exposures common to the refining industry, including property damage, business interruptions, third party liabilities, workers compensation, marine activities, and directors and officers legal liability, among others. The Company employs internal risk management measurements, actuarial analysis, and peer benchmarking to assist in determining the appropriate limits, deductibles, and coverage terms for the Company. The Company believes the insurance coverages it currently purchases are consistent with customary insurance standards in the industry. The Company’s major insurance policies renewed on October 1, 2002 with a one-year term. Due primarily to the continuing effects of the events of September 11, 2001 on the insurance market, certain coverage terms, including terrorism coverage, were restricted or eliminated at renewal, certain deductibles were raised, certain coverage limits were lowered, and overall premium rates increased by 23%. Higher insurance premium expenses will be reflected in the Company’s results beginning in the fourth quarter. While the Company intends to continue purchasing insurance coverages consistent with customary insurance standards in the industry, future losses could exceed insurance policy limits or, under adverse interpretations, be excluded from coverage.

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