PREMCOR REFINING GROUP INC - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark if the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ

The aggregate market value on February 5, 2003, of Premcor Inc.’s common stock, $0.01 par value, held by nonaffiliates of the registrant was approximately $695 million. Number of shares of registrants’ common stock (only one class for each registrant) outstanding as of March 3, 2003:

The information required by Part III of this report, to the extent not set forth herein, is incorporated herein by reference from Premcor Inc.’s definitive proxy statement for Premcor Inc.’s annual meeting of stockholders scheduled for May 20, 2003. The definitive proxy statement shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.

Certain statements in this document are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to the safe harbor provisions of this legislation. You can identify these forward-looking statements by the use of words such as “strategy,” “expects,” “intends,” “plans,” “projects,” “believes,” “estimates,” “will,” “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 could cause actual results to differ materially from our expectations contained in our forward-looking statements. These factors include, but are not limited to, changes in:

Because of these uncertainties and others, you should not place undue reliance on our forward-looking statements.

This Annual Report on Form 10-K represents a combined report for two registrants, Premcor Inc. and The Premcor Refining Group Inc., or PRG. PRG is an indirect, wholly owned subsidiary of Premcor Inc. As used in this Annual Report on Form 10-K, the terms “we,” “our,” or “us” refer to Premcor Inc. and its consolidated subsidiaries, taken as a whole, unless the context otherwise indicates. The information reflected in this Annual Report on Form 10-K is equally applicable to both companies except where indicated otherwise.

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 three refineries, which are located in Port Arthur, Texas; Memphis, Tennessee; and Lima, Ohio, with a combined crude oil volume processing capacity, known as throughput capacity, of approximately 610,000 barrels per day, or bpd. In late September 2002, we ceased refining operations at our Hartford, Illinois refinery and 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 1,200 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 year ended December 31, 2002, highly refined products, known as light products, such as transportation fuels, petrochemical feedstocks and heating oil, 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 36% 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.

We are subject to the informational requirements of the Securities Exchange Act of 1934 and, in accordance with the Exchange Act, file annual, quarterly, and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any documents filed by us at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public through the SEC’s internet site at www.sec.gov.

Our investor relations website is www.premcor.com. We make available, free of charge, under “Investor Relations—SEC Filings,” via a link to a third-party website at www.corporate-ir.net, our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, Forms 3, 4 and 5 filed via Edgar by our directors and executive officers and various other SEC filings, including amendments to these reports, as soon as reasonably practicable after we electronically file or furnish such reports to the SEC. The information on our website, or on the site of our third-party service provider, is not incorporated by reference into this report.

Our principal executive offices are located at 1700 East Putnam Avenue, Suite 500, Old Greenwich, Connecticut 06870, and our telephone number is (203) 698-7500.

Effective March 3, 2003, we completed the acquisition of our Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries, or Williams, at an adjusted purchase price of $310 million plus approximately $145 million for crude and product inventories subject to volumetric and pricing verification. 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. The transfer of certain of these assets remains subject to our obtaining certain regulatory approval and third party consents. No portion of the purchase price was held back relative to this delayed ownership transfer. See “—Refinery Operations-Memphis Refinery” for more information on the assets purchased and operations of the refinery. The purchase agreement also provides for contingent participation, or earn-out, payments that could result in additional payments of up to $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. PRG acquired the refinery and related assets utilizing a portion of the proceeds from the issuance of $525 million in senior notes and utilizing capital contributions from Premcor Inc., which were funded from a public and private offering of common stock.

In January and February 2003, Premcor Inc. completed a public offering of 13.1 million shares of common stock and a private placement of 2.9 million shares of common stock, which resulted in net proceeds of approximately $306 million. In February 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bears interest at 9½% per annum and $175 million, due in 2010, bears interest at 9¼% per annum. Concurrently, PRG amended and restated its credit agreement, which included extending its maturity date to February 2006; increasing the capacity under the agreement to the lesser of $750 million or the amount available under the defined borrowing base; increasing the sub-limit for cash borrowings to $200 million, subject to certain limitations; and modifying certain covenant requirements. In addition to the refinery acquisition, the proceeds from these transactions were also used to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures plus a premium thereon of $2.3 million and to repay PRG’s $240 million floating rate loan at par.

We currently own and operate three refineries: our Port Arthur, Texas refinery comprises our Gulf Coast operations, and our Lima, Ohio and Memphis, Tennessee refineries comprise our Midwest operations.

The aggregate crude oil throughput capacity at our refineries is 610,000 bpd. The configuration at our Port Arthur and Lima refineries is that of a single-train coking refinery, which means that each of these refineries has a single crude unit and a coker unit. The configuration at our Memphis refinery includes two crude units, which can be operated independently, and one cracking unit. The following table provides a summary of key data for our three refineries.

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.

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 National Petrochemical and Refiners Association, or NPRA, 52 refineries were operating in PADD III as of December 31, 2002, with a total crude oil throughput capacity of approximately 7.6 million bpd.

The market has historically had an excess supply of products, with the Department of Energy’s Energy Information Administration, or EIA, estimating light product demand, as of December 31, 2002, at approximately 2.2 million bpd and light product production at approximately 6.0 million bpd. Approximately 61%, or 3.6 million bpd, of light product production is exported to other regions in the United States, mainly to the eastern seaboard or Midwest markets.

Explorer, TEPPCO, Seaway, Centennial and Phillips pipelines transport Gulf Coast products 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, west coast markets and the Caribbean basin.

Our Port Arthur refinery is located on the Gulf Coast. The Gulf Coast region 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 1995. This refinery is in Port Arthur, Texas, approximately 90 miles east of Houston located 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 fluid catalytic cracking unit, a delayed coker, and an alkylation unit. It produces conventional gasoline, reformulated gasoline, low sulfur diesel fuel and jet fuel, petrochemical feedstocks and fuel grade petroleum coke.

The heavy oil upgrade project at our Port Arthur refinery increased the refinery’s capability of processing heavy sour crude oil from 20% to 80%. 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, Port Arthur Coker Company L.P., or 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 PRG, sells the refined products and intermediate products produced by the heavy oil processing facility to PRG pursuant to arm’s length pricing formulas based on public market benchmark prices. PRG then sells these products to third parties. In June 2002, PRG and Premcor Inc. completed a series of transactions, which resulted in Sabine River Holding Corp. and its subsidiaries, including PACC, becoming wholly owned subsidiaries of PRG. Prior to this date, Sabine was 90% owned by Premcor Inc. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Major Developments—Sabine Restructuring” for more detail of these transactions.

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 and pipeline delivery. 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 Enterprises LLC dba Shell Oil Products U.S.’s, or Shell’s pipeline originating in Clovelly, Louisiana. 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 P.M.I. Comercio Internacional, S.A. de C.V., an affiliate of Petroleos Mexicanos, or PEMEX, the Mexican state oil company under two 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.

The long-term crude oil supply agreement with the PEMEX affiliate provides 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 December 31, 2002, a cumulative quarterly surplus of $79.6 million existed under the agreement. 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.

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. The charter agreements have an eight-year term from the date of delivery of each ship and are renewable for two one-year periods. All three ships were delivered in late 2002. 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.

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 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 its 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 CenterPoint Energy Gas Resources Corporation, a subsidiary of CenterPoint Energy Inc., 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. We believe there are many alternative sources of natural gas available upon expiration of this contract.

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 TEPPCO pipeline also provides access to the Centennial pipeline. 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 Shell. 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 Shell’s Beaumont light products terminal. We supply all the products to the Shell 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 these 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, which are provided by us at cost.

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, 25 refineries were operating in PADD II as of December 31, 2002, 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, 2002, is approximately 4.5 million bpd, with refinery production of light products in PADD II estimated at approximately 3.0 million bpd. Net imports have supplemented PADD II refining in satisfying product demand and are currently estimated by the EIA at approximately 1.0 million bpd, with the Gulf Coast continuing to be the largest area for sourcing product, accounting for approximately 890,000 bpd.

The Explorer, TEPPCO, Seaway, Orion, Colonial and Plantation product 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 of 2002. Supply is also available via barge transport up the Mississippi River with significant deliveries into markets along the Ohio River. Barge transport serves a role in supplying inland markets that are remote from product pipeline access and in supplementing pipeline supply when they are bottlenecked or short of product.

Our Lima refinery, which we acquired from British Petroleum, or 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 fluid catalytic cracking 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 grade petroleum coke, benzene and toluene.

Our Lima refinery crude oil throughput has typically 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, which 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. The ability to transport reformulated gasoline on this TEPPCO interconnection from our Lima refinery to the Chicago market was made available in late 2002. We may utilize this connection for light products in the future to increase throughput rates closer to the 170,000 bpd capacity when economically justifiable.

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 refinery’s 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.

In March 1999, we entered into an agreement with Koch Petroleum 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 purchase 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 to Lima under the MSCG contract. 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 owned by Akzo Nobel 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.

Our Memphis refinery, which we acquired from Williams in March 2003, is located on a 223-acre site along the Mississippi River’s Lake McKellar in Memphis, Tennessee. The refinery, with a crude oil throughput capacity of approximately 190,000 bpd, primarily processes light, sweet crude oil. The refinery typically processes closer to 170,000 bpd of crude oil throughput based on the markets that are economically available for distribution of its production. While the Memphis refinery was originally constructed in 1941, due to significant investment particularly over the last four years, we believe the refinery is a modern and highly efficient refinery. The Memphis refinery includes two crude units, a fluid catalytic cracking unit, a reformer unit, an alkylation unit, an isomerization

unit, two naphtha desulfurizers, a distillate desulfurizer, and a sulfur recovery unit. The refinery can produce conventional gasoline, jet fuel, low sulfur diesel fuel, refinery grade propylene, propane, and heavy fuel oil.

The refinery’s location along the Mississippi River provides it with a cost advantage in serving numerous upriver markets due to the economic benefits of shipping crude oil for refining and subsequent product distribution versus shipping refined products from the Gulf Coast to Memphis. The refinery 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.

Feedstock and Other Supply Arrangements. Crude oil supplied to our refinery is purchased on the spot market and delivered via the Capline pipeline, which originates in St. James, Louisiana and terminates in Patoka, Illinios. We can also receive crude oil and other feedstocks by barge. We have entered into a crude oil supply agreement with MSCG through which we can arrange to purchase foreign or domestic crude oils in quantities sufficient to fulfill the crude oil requirements of the refinery. Under terms of this supply agreement, we must either cash fund crude oil purchases one week in advance of delivery or provide security to MSCG in the form of a letter of credit. This supply agreement expires in March 2005, and can be renewed based on certain notification requirements.

Energy. We purchase our electricity from the Tennessee Valley Authority, or TVA, and Memphis Light, Gas & Water, or MLG&W, under a contract that currently provides for interruptible supplies of electricity. Williams recently completed an 80-megawatt power plant that is adjacent to the refinery. This plant is designed to provide a reliable, secondary source of power and allow us to reduce our power costs by purchasing electrical power at interruptible rates. Currently, the turbine is not permitted to operate, pending completion of final environmental emissions tests. These emissions tests should be completed in the next few months. The transfer of ownership of the power plant to us was delayed pending approval from the Federal Energy Regulatory Commission. We received such approval on March 6, 2003, but it is subject to a customary 30-day rehearing period. Ownership of the power plant will transfer to us shortly after the expiration of the rehearing period. No portion of the purchase price was held back relative to this delayed ownership transfer.

Product Offtake. The principal market for the refinery’s production is the local Memphis market and secondarily the Nashville, Tennessee market. Products are distributed primarily via truck loading racks at our two product terminals, a pipeline directly to the Memphis airport, and barges. We also have the ability to deliver production to eastern, southern, and northern markets, given opportunistic market conditions, principally via barge and subsequently connecting into pipelines such as Colonial and TEPPCO.

The Memphis refinery is the sole supplier of jet fuel to the Memphis International Airport, a major air cargo thoroughfare and central hub for Federal Express. The Memphis refinery supplies Federal Express pursuant to a long-term supply agreement, which in the past has represented approximately 12% of the refinery’s production. In addition to the Federal Express supply agreement, we have a number of other supply agreements with terms in excess of one year.

Other Memphis Related Assets. Assets, other than the refinery units, that are associated with our Memphis refinery include:

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 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 fluid catalytic cracking unit, a coker unit and an alkylation unit.

In late September 2002, we ceased refining 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 continuing to operate the storage and distribution facility at the Hartford refinery site. We are pursuing all strategic options including the sale and lease of the refinery assets. 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—Factors Affecting Comparability—Refinery Restructuring and Other Charges—Hartford Refinery Closure.”

Our product marketing group sells approximately 1.7 billion gallons per year of gasoline, diesel fuel, and jet fuel to a diverse group of approximately 750 distributors and chain retailers and another 3.9 billion gallons per year to bulk customers. With the acquisition of the Memphis refinery, we will market approximately 2.4 billion additional gallons per year of gasoline, diesel fuel, and jet fuel and estimate that we will have an additional 450 customers. 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, Shell 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 all 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.

Our Alsip terminal, located approximately 17 miles from Chicago, is adjacent to our former Blue Island refinery, 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 Shell. The terminal distributes primarily reformulated gasoline and distillates. We supply the terminal with products from our Port Arthur refinery via barge and via the Shell 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, and heavy oils. An adjacent facility leases and operates some tanks in

the tank farm to store 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 Shell’s Hammond terminal. Products can be shipped out of our 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.

Our Hartford storage and distribution facility is located on our Hartford refinery site and has total storage capacity of approximately 1.5 million barrels. We supply the petroleum product storage facility with products via barge and via the Marathon/Wabash and Explorer pipelines. Product is also distributed via these means or moved through our pipeline between the facility and the Shell terminal in Hartford and then further distributed by trucks.

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 20% of net sales and operating revenues in 2002 were represented by sales of products purchased from third parties. This percentage was higher in 2002 than previous years because we purchased refined products in order to cover shortfalls resulting from the closure of our Blue Island and Hartford refineries. We believe that a portion of the production from our Memphis refinery will contribute to meeting these commitments in the future. Although third party purchases are essential to effectively market our production, the effects from these activities on our operating results are not significant.

We have crude oil supply contracts that provide for our purchase of up to approximately 370,000 bpd of crude oil from an affiliate of PEMEX and MSCG. The affiliate of PEMEX provides 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 our Port Arthur refinery with a stable and secure supply of Maya heavy sour crude oil. We acquire directly or through MSCG 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 year ended December 31, 2002:

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 primarily through waterborne delivery via our docks and also through third-party terminals. In the Midwest, our Lima refinery receives crude oil largely through the Mid-Valley pipeline, and our Memphis refinery primarily receives crude oil through the Capline pipeline.

Many of our competitors are fully integrated national or multinational oil companies engaged in various 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.

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.

As of December 31, 2002, we leased approximately 84,000 square feet of office space in our Old Greenwich, Connecticut executive offices and our St. Louis, Missouri general offices. Our office space is generally suitable and adequate for its purposes. If we require additional or alternative office space, we believe we will be able to secure space on commercially reasonable terms without undue disruption of our operations.

As of March 3, 2003, we employed approximately 1,700 people, including 305 former Williams employees, comprised of 301 Memphis refinery employees and four commercial operations employees. Approximately 59% of our employees are covered by collective bargaining agreements at our Lima, Memphis and Port Arthur refineries. The collective bargaining agreements covering employees at our Port Arthur and Memphis refinery expire 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.

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.

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.

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.

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 Memphis refinery since its acquisition in March 2003. Mr. Bram is also currently the acting refinery manager of our Lima refinery. He has been the Lima refinery’s manager 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 15 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 36 years of experience within the refining and petrochemical industry.

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;

The laws and regulations we are subject to often change 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 implementation guidelines of the 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Flows 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.”

The principal environmental risks associated with our refinery operations are air emissions, releases into soil and groundwater, wastewater excursions, and compliance with specifications for fuels mandated by environmental regulations. The primary legislative and regulatory programs that affect these areas are outlined below.

The federal 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 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 an eleven year schedule to install such technology.

The Memphis refinery requested a determination from the EPA regarding compliance with the 10 megagram per year total annual limitation for benzene emissions under the National Emission Standards for Hazardous Air Pollutants, or Benzene Waste NESHAP, since 1998. If the refinery is not in compliance with the Benzene Waste NESHAP, additional control equipment will need to be installed to upgrade the wastewater treatment system. Under the purchase agreement for the Memphis refinery, we have assumed the liability for any costs to upgrade the wastewater treatment system, and Williams retains responsibility for any penalties imposed for any non-compliance of the refinery with Benzene Waste NESHAP. We currently estimate the cost of the wastewater treatment system upgrade to be between $5 million and $15 million.

Williams has requested an applicability determination from the EPA regarding the barge loading facility located at the West Memphis terminal. If the terminal is deemed to be contiguous to the refinery by virtue of the completion of a pipeline connecting the refinery to the terminal in 2001, the barge loading facility will be subject to 40 CFR Subpart Y—National Emission Standards for Marine Tank Vessel Loading Operations. If the regulations are deemed applicable, a vapor control system will need to be installed at the terminal barge loading facility, which is expected to cost between $4 million and $6 million.

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. The federal legislature and certain 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.

Our refining operations are subject to the federal Solid Waste Disposal Act, which imposes requirements for the treatment, management, storage and disposal of solid and hazardous wastes. When feasible, waste materials are recycled through our coking operations instead of being disposed of on-site or off-site. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act of 1976 and subsequent amendments, governs current waste disposal practices, as well as 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 when their implementation becomes more accurately defined.

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, St. Louis, another of our direct market areas, has been recently designated as serious non-attainment for ozone, requiring reformulated gasoline and low sulfur diesel in this market area. Expenditures necessary to comply with existing reformulated fuels regulations are primarily discretionary. Our 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 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.

2004. As a result of the corporate pool averaging provisions of the regulations, we believe that we will be able to defer a significant portion of the investment required for compliance for one or both of the Lima and Memphis refineries until the end of 2005. In addition, delay in the requirement to meet the new sulfur standards at the Lima and Memphis refinery through 2005 may also 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 the averaging provisions of the regulations will allow for a deferral of compliance at one or both of the Lima and Memphis refineries or that sufficient allotments or credits to defer investment at our Lima and Memphis refinery will be available, or if available, that they will be cost effective. We believe, based on current estimates and on a January 1, 2004 compliance date for all three refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2004 of approximately $335 million, of which $53 million had been incurred as of December 31, 2002.

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. We estimate that capital expenditures required to comply with the on-road diesel standards at all three refineries in the aggregate through 2006 is approximately $347 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 half of 2005.

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. Certain pending proceedings involving our Port Arthur refinery allege permit violations. See “Legal Proceedings.”

Under the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and the Solid Waste Disposal Act and related state laws, certain persons may be liable for the release or threatened release of hazardous substances and solid wastes 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 as a result of past activities at the terminal properties including several significant spills and on-site waste disposal practices.

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 December 31, 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.

The Memphis refinery was constructed during World War II and also has contamination on the property. An order was originally issued in 1998 by the Tennessee Department of Environment and Conservation (TDEC) Division of Solid Waste Management to MAPCO Petroleum, Inc. (the owner of the refinery prior to Williams). This order addresses groundwater remediation of light non-aqueous phase liquids and dissolved phase hydrocarbons underlying the refinery. Williams has 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 known by them prior to the closing. We are responsible for all other environmental liabilities, including various pending clean-up and compliance matters that we estimate will cost between $9 million and $16 million and which will be recorded as part of the purchase transaction. Any claims made by us against Williams for environmental liabilities must be made within seven years. Williams was 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 insurance policy provides for a $25 million (with a $5 million limit for third party claims for offsite non-owned locations) limit per incident, with a $25 million aggregate limit per incident and a self-insured retention of $250,000 per incident. The maximum amount we can recover for environmental liabilities is limited to $50 million from Williams plus any amounts provided under the insurance policy. Williams has 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. In addition, Williams has agreed to indemnify us for any fines and penalties that result from William’s operations or ownership prior to the closing.

In January 2001, we ceased refining operations at our Blue Island refinery. The decommissioning of the facility is complete. The dismantling and tear down of the above-ground assets of the former refinery is the responsibility of a third party that purchased the assets for resale. At this time that company has failed to perform and we have notified them of their failure to comply with the contract. We are currently in discussions with state and local governmental agencies concerning remediation of the site. Related to the closure of the facility, we accrued $54.4 million for decommissioning and remediation of the site. As of December 31, 2002, we had spent $34.7 million and had a remaining reserve balance of $19.7 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—Refinery Restructuring and Other Charges—Blue Island 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 discussions with state governmental agencies concerning environmental remediation of the site. Related to the closure of the refinery, we have accrued $47.4 million for decommissioning, remediation of the site and asbestos abatement. As of December 31, 2002, we spent $17.4 million related primarily to the decommissioning of the facility and have a remaining reserve balance of $30.0 million. The accrual of $47.4 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 only 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—Factors Affecting Comparability—Refinery Restructuring and Other Charges—Hartford Refinery Closure.”

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 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-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.

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 December 31, 2002, we expended approximately $20 million to satisfy all the environmental cleanup obligations of our former retail marketing business and, as of December 31, 2002, had $23.0 million accrued to satisfy those obligations in the future.

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 in connection with bankruptcy proceedings, we would likely assume responsibility for these obligations. CRE rejected 25 of these leases in connection with bankruptcy hearings held in late January and February 2003. We plan to record an after-tax charge of approximately $3.5 million in the first quarter of 2003 representing the estimated net present value of our remaining liability under these leases, net of estimated sub-lease income. We are currently in discussions with CRE regarding their reorganization plans, the status of environmental remediation agreements, and other matters. While it is possible that we may incur additional liability for CRE lease obligations or other costs as CRE finalizes its reorganization plans, the amounts are not estimable at this time. Should any additional leases revert to us, we will attempt to reduce the potential liability by subletting or reassigning the leases.

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 December 31, 2002, we had expended $0.9 million on these obligations and have accrued $2.5 million for these obligations in the future.

On February 18, 1998, TDEC Division of Solid Waste Management issued an order to Truman Arnold Company Memphis Terminal (prior owner) to address increasing levels of petroleum in groundwater underlying the Riverside Terminal facility. Wells have been installed and recent monitoring indicated increased levels in some wells. TDEQ has requested a work plan to address the problem, which is believed to be due to a release of gasoline from a line fueling a vapor control unit located at the truck rack.

A non-hazardous land farm was operated at the Memphis Refinery up until February 2002, most recently for disposal of catalyst from the Poly Unit. The permit for the land farm allows it to be closed twelve months after it receives its last application. The cost for closing the land farm in accordance with the permit’s closure procedures is not expected to exceed $1 million.

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 $93 million, on an undiscounted basis, as of December 31, 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 $72 million for site clean-up and environmental matters associated with the Hartford and Blue Island closures and retail sites.

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 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.

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 our productivity and financial goals. We seek to implement this goal by:

Our safety performance, as measured by OSHA’s injury recording methods, has improved over the past several years. Our performance in the past year, however, has declined over the previous year and we our implementing several actions, including extensive reviews of our safe work practices and increased awareness communication, to change the trend. The Memphis refinery has had injury rates higher than the Port Arthur and Lima refineries. We intend to implement programs and provide onsite medical staff in order to improve the Memphis refinery’s safety record.

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 environmental 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 flows.

Port Arthur: Enforcement. The TNRCC conducted a site inspection of our Port Arthur refinery in the spring of 1998. In August 1998, we received a notice of enforcement alleging 47 air-related violations and 13 hazardous waste-related violations. The number of allegations was significantly reduced in an enforcement determination response from the TNRCC in April 1999. A follow-up inspection of the refinery in June 1999 concluded that only two items remained outstanding, namely that the refinery failed to maintain the temperature required by our air permit at one of its incinerators and that five process wastewater sump vents did not meet applicable air emission control requirements. The TNRCC also conducted a complete refinery inspection in the second quarter of 1999, resulting in another notice of enforcement in August 1999. This notice alleged nine air-related violations, relating primarily to deficiencies in our upset reports and emissions monitoring program, and one hazardous waste-related violation concerning spills. The 1998 and 1999 notices were combined and referred to the TNRCC’s litigation division. On September 7, 2000 the TNRCC issued a notice of enforcement regarding our alleged failure to maintain emission rates at permitted levels. In May 2001, the TNRCC 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 TNRCC are ongoing.

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 Michigan Department of Natural Resources elected not to file an appeal with the Michigan Supreme Court. As a result, the judgment became final. The Michigan Department of Natural Resources will owe us mediation sanctions, which should net us approximately $100,000.

Alleged Asbestos Exposure. We, along with numerous other defendants, have been named in approximately 25 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 require 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.

Williams responded to this same information request from the EPA at the Memphis refinery. Under the purchase agreement, Williams is not responsible for any costs we incur arising out of EPA Section 114 proceedings. The Memphis refinery has installed advanced pollution controls that reduced the amount of additional control equipment that may be required. Williams has retained responsibility for any penalties that may arise due to non-compliance of capital improvements completed under their ownership.

Legal and Environmental Reserves. As of December 31, 2002, we had accrued a total of approximately $93 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 December 31, 2002, this accrual included approximately $72 million for site clean-up and environmental matters associated with the Hartford and Blue Island refinery closures and retail sites. We are of the opinion that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity. However, an adverse outcome of any one or more of these matters could have a material effect on quarterly or annual operating results or cash flows when resolved in a future period.

There were no matters submitted to a vote of security-holders during the fourth quarter of our fiscal year ended December 31, 2002.

ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED SHAREHOLDER MATTERS

Common stock. Premcor Inc’s common stock began trading on the New York Stock Exchange on April 30, 2002 under the symbol “PCO”. Before that date, no public market for its common stock existed. As of March 3, 2003, Premcor Inc.’s common stock was held by 22 stockholders of record and an estimated 5,000 additional stockholders whose shares were held for them in street name or nominee accounts. Set forth below are the high and low closing sale prices per share of our common stock as reported on the NYSE Composite Tape. Premcor USA Inc., a direct wholly owned subsidiary of Premcor Inc., owns 100% of the common stock of PRG.

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 PRG and our other subsidiaries, which significantly restrict their ability to pay dividends directly or indirectly to us. 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.

Use of Proceeds. On April 29, 2002, Premcor Inc.’s Registration Statement on Form S-1 (File No. 333-70314) pertaining to an initial public offering of its common stock was declared effective by the Securities and Exchange Commission. A total of 20.7 million shares of Premcor Inc.’s common stock, including 2.7 million shares sold pursuant to the underwriters over-allotment option, were registered and sold in this offering at an offering price of $24.00 per share, for aggregate offering proceeds of $496.8 million. Premcor Inc. incurred $31.0 million in underwriters’ fees and $3.2 million in other fees and expenses in connection with the offering, yielding net proceeds of $462.6 million. Morgan Stanley and Credit Suisse First Boston served as managing underwriters for the offering. As of December 31, 2002, substantially all of the net proceeds from the initial public offering had been used to redeem and repurchase outstanding long-term debt securities of Premcor Inc.’s subsidiaries.

The following table presents selected financial and operating data for Premcor Inc. and PRG. The data presented is Premcor Inc. data unless otherwise noted. The results of operations and financial condition of Premcor Inc. are materially the same as PRG. The selected statement of earnings and cash flows data for the years ended December 31, 2002, 2001 and 2000 and the selected balance sheet data as of December 31, 2002 and 2001 are derived from our consolidated financial statements including the notes thereto, audited by Deloitte & Touche LLP, independent accountants, appearing elsewhere in this Annual Report on Form 10-K. The selected statement of earnings and cash flows data for the years ended December 31, 1999 and 1998, and the selected balance sheet data as of December 31, 2000, 1999, and 1998 have been derived from our consolidated financial statements, including the notes thereto, not included in this Annual Report on Form 10-K, which were audited by Deloitte & Touche LLP. The financial data for PRG has been restated to give retroactive effect to the contribution of the Sabine River Holding Corp. common stock from Premcor Inc. to PRG. The 1998 Premcor Inc. financial data reflects the financial data of its predecessor, Premcor USA. This table should be read in conjunction with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related notes included elsewhere herein.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Premcor Inc. owns all of the outstanding common stock of Premcor USA Inc., or Premcor USA, and Premcor USA owns all the outstanding common stock of The Premcor Refining Group Inc., or PRG. PRG and its indirect subsidiary, Port Arthur Coker Company, or PACC, are Premcor Inc.’s principal operating subsidiaries. This Management Discussion and Analysis of Financial Condition and Results of Operations reflects the results of operations and financial condition of Premcor Inc. and subsidiaries, which are materially the same as the results of operations and financial condition of PRG. Therefore, the discussions provided are equally applicable to Premcor Inc. and PRG except where otherwise noted.

We are an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. We own and operate three refineries with a combined crude oil throughput capacity of approximately 610,000 barrels per day, or bpd. Our refineries are located in Port Arthur, Texas; Memphis, Tennessee; and Lima, Ohio. We acquired our Memphis refinery in March 2003. We sell petroleum products in the Midwest, the Gulf Coast and the Eastern and Southeastern United States. We sell our products on an unbranded basis to approximately 1,200 distributors and chain retailers through a combination of our own product distribution system and an extensive third-party owned product distribution system, as well as in the spot market. In late September 2002, we ceased refining operations at our 70,000 bpd Hartford, Illinois refinery. We continue to operate the storage and distribution facility at the refinery in connection with our wholesale operations. We are currently pursuing all strategic options, including the sale or lease of the refinery, to mitigate the loss of jobs and refinery capacity in the Midwest.

Effective March 3, 2003, we completed the acquisition of our Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries, or Williams, at an adjusted purchase price of $310 million plus approximately $145 million for crude and product inventories subject to volumetric and pricing verification. 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. The transfer of certain of these assets remains subject to our obtaining certain regulatory approval and third party consents. No portion of the purchase price was held back relative to this delayed ownership transfer. The purchase agreement also provides for contingent participation, or earn-out, payments that could result in additional payments of up to $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. PRG acquired the refinery and related assets utilizing a portion of the proceeds from the issuance of $525 million in senior notes and utilizing capital contributions from Premcor Inc., which were funded from the proceeds from a public and private offering of common stock.

On January 30, 2003, Premcor Inc. completed a public offering of 12.5 million shares of common stock and a private placement of 2.9 million shares of common stock with Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, or Blackstone, subsidiaries of Occidental Petroleum Corporation, or Occidental, and certain Premcor executives. On February 5, 2003, Premcor Inc. sold an additional 0.6 million shares of common stock pursuant to the underwriters’ over-allotment option. Premcor Inc. received net proceeds of approximately $306 million from these transactions. On February 11, 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bear interest at 9½% per annum and $175 million, due in 2010, bear interest at 9¼% per annum. Concurrently, PRG amended and restated its credit agreement, which included extending its maturity date to February 2006; increasing the capacity under the agreement to the lesser of $750 million or the amount available under the defined borrowing base; increasing the sub-limit for cash borrowings to $200 million, subject to certain limitations; and modifying certain covenant requirements.

In addition to the Memphis refinery acquisition, the proceeds from these transactions were also used to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures plus a premium thereon of $2.3 million and to repay PRG’s $240 million floating rate loan at par.

On June 6, 2002, we completed a series of transactions, referred to as the Sabine restructuring, which resulted in Sabine River Holding Corp. and its subsidiaries, or Sabine, becoming wholly owned subsidiaries of PRG. Sabine, through 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. 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 12½% senior notes due 2009. The Sabine restructuring was accomplished according to the following steps, among others:

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 Mr. Thomas D. O’Malley, our chairman of the board and chief executive officer, and two of our directors, netted proceeds to Premcor Inc. of approximately $482 million. The proceeds from the offering were committed to retire debt of Premcor Inc.’s subsidiaries. Prior to the initial public offering, Premcor Inc.’s common equity was privately held and controlled by Blackstone. Premcor Inc.’s other principal shareholder was Occidental.

Our results over the past three years have been affected by the following events, which must be understood in order to assess the comparability of our period to period financial performance.

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. During 2002, prior to the purchase of our Memphis refinery, the portion of our target inventory position consisting of sales commitments netted against fixed price purchase commitments amounted to a net long inventory position of approximately five 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 target 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. 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. In the remainder of 2002, the cumulative economic effect of our risk management strategy was substantially equal to results as measured against a fully exposed fixed price commitment target. 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.

In 2002, we recorded refinery restructuring and other charges of $172.9 million ($168.7 million for PRG), which consisted of the following:

In 2001, we recorded refinery restructuring and other charges of $176.2 million, which consisted of a $167.2 million charge related to the closure of our Blue Island, Illinois refinery and a $9.0 million charge related to the write-off of idled coker units at our 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.

Below are further discussions of the Hartford and Blue Island refinery closures and the management team, refinery, and administrative function restructuring.

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. 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 and $4.8 million of non-cash current asset write-offs. 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 our storage and distribution facility at the refinery site to accommodate our wholesale operations. As a result of this decision, we reclassified the net book value of the storage and distribution facility 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.

Despite ceasing operations, we continue to pursue all strategic options including the sale or lease of the refinery. We have had preliminary discussions with third parties regarding a transaction for the refinery assets, but there can be no assurance that a transaction will be completed. When the final disposition of the assets is determined, the net realizable value may be less than $49.0 million and a further write-down may be required.

The total charge also included a reserve for future costs of $60.6 million, which included an initial reserve of $62.5 million and a decrease in the fourth quarter of $1.9 million. The following schedule summarizes the activity and balance of the closure reserve as of December 31, 2002:

In the fourth quarter of 2002, we completed the process unit shutdown and hydrocarbon purging and terminated all employee positions, which approximated 310 hourly (covered by collective bargaining agreements) and salaried positions. In the fourth quarter of 2002, we lowered the reserve by $1.6 million, which reflected a decrease of the site clean-up costs partially offset by a net increase for actual costs incurred for employee severance and the plant shutdown. The lower site clean-up costs reflected less work that will need to be performed since the storage and distribution facility will remain in operation. Additionally, we reclassified $0.3 million of the reserve to our pension related long-term liability. 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 assets is determined and a site remediation plan refined, further adjustments of the reserve may be necessary, and such adjustments may be material. Also in the fourth quarter of 2002, we increased our non-cash current asset write-off from $3.2 million to $4.8 million as a result of losses on the disposition of warehouse inventories and other supplies.

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. The only anticipated effect on net income and cash flow in the future will result from the final disposition of the assets and subsequent environmental site remediation. Unless there is a need to adjust the estimated net realizable value or the reserve in the future as discussed above, there should be no significant effect on net income beyond 2002. We expect to spend approximately $3 million to $4 million in 2003 related to this reserve.

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 long-term liabilities on the balance sheet together with our other post-retirement liabilities.

Blue Island Refinery Closure. In January 2001, we ceased refining 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 new regulations could not produce acceptable returns on our investment. This

closure resulted in a pretax charge of $167.2 million in 2001, which included $98.1 million of non-cash asset write-offs in excess of realizable value and a $69.1 million reserve for closure activities. We continue to utilize our storage and distribution facility at our refinery site to supply selected products to the Chicago and other Midwest markets from our operating refineries. Since our 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 cash flow will result from the environmental site remediation as discussed below. Unless there is a need to adjust the site remediation reserve in the future, there should be no significant effect on net income beyond 2001.

The shutdown of the process units was completed during the first quarter of 2001 and all 297 employee positions were terminated by the end of 2002. The following schedule summarizes the activity and balance of the closure reserve as of December 31, 2002:

We expect to spend approximately $4 million to $5 million in 2003 related to the reserve for future costs. 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 mid-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 discussed below. In 2002, we decreased the reserve for site remediation by an aggregate $2.0 million and concurrently wrote-off an asset previously recorded for the sale of emission credits. The adjustments reflected further refinement of plant closure and remediation activities relating to the continuing operations of the storage and distribution facility. 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 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. 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.

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 Blackstone.

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 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 in early 2003. The reserve related to the refineries and St. Louis restructuring was as follows:

In 2002, we redeemed the outstanding balances of our 10⁷/8% senior notes, 9½% senior notes, senior secured bank loan, and purchased a portion of our 11½% subordinated debentures. We recorded a loss on extinguishment of long-term debt of $19.5 million related to these early repayments. The 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. Related to the redemption of the 9½% senior notes and the repayment of the senior secured bank loan, PRG recorded a loss of $9.3 million, of which $0.9 million related to premiums, $7.8 million related to the write-off of deferred financing costs, and $0.6 million related to the write-off of debt guarantee fees at Sabine.

In 2001, we repurchased in the open market portions of our 9½% senior notes, 10⁷/8% senior notes and 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. Related to the repurchase of a portion of the 9½% senior notes, PRG recorded a gain of $0.8 million, which included a discount of $1.0 million offset by the write-off of deferred financing costs.

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 unit, a 417 ton per day sulfur removal unit and the expansion of the existing crude unit capacity to 250,000 bpd.

As a result of the heavy oil upgrade project, our Port Arthur refinery is able to process significant quantities of sour and heavy sour crude oil, increasing from 43,400 bpd in 2000 to 181,500 bpd in 2001. Sour and heavy sour crude oils have historically traded at a discount to West Texas Intermediate crude oil. Accordingly, our Port Arthur crude oil costs were reduced as a result of the heavy oil upgrade project. 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 2002 and 2001 demonstrate that the benefit of the lower cost crude oil slate exceeds the lower production values and higher operating costs. See “Results of Operations—2001 Compared to 2000 and 2002 Compared to 2001”.

In 1999, we sold our retail marketing division, which included all company and independently operated Clark-branded stores and the Clark trade name. 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 estimate regarding our environmental clean up obligation and workers compensation liability and a decrease in the amount of reimbursements for environmental expenditures that are collectible from state agencies under various programs. The changes in estimates were 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.

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, product pipeline capacity, and the extent of government regulation. While our net sales and operating revenues fluctuate significantly with movements in industry refined product 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.

Crude oil and other feedstock 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 in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined products, such as for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast.

In order to assess our operating performance, we compare our gross margin (net sales and operating revenue less cost of sales) against an industry gross margin benchmark. The industry gross margin is based on a crack spread. For example, one such crack spread is calculated by assuming that two barrels of benchmark light sweet crude oil is converted, or cracked, into one barrel of conventional gasoline and one barrel of high sulfur diesel fuel. This is referred to as the 2/1/1 crack spread. We calculate the benchmark margin using the market value of U.S. Gulf Coast gasoline and diesel fuel against the market value of West Texas Intermediate crude oil and refer to that benchmark as the Gulf Coast 2/1/1 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. We will also use the Gulf Coast 2/1/1 crack spread as a benchmark for our Memphis refinery operations. We utilize the Chicago 3/2/1 crack spread as a benchmark for our Lima refinery operations. As explained below, each of our refineries, depending on market conditions, has certain feedstock cost and/or product value advantages and disadvantages as compared to the benchmark.

Our Port Arthur refinery is able to process significant quantities of sour and heavy sour crude oil that has 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 crude oil for this measurement because a significant amount of our heavy sour 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 that provide for our purchase of up to approximately 370,000 bpd of crude oil from PMI Comercio Internacional, S.A. de C.V., an affiliate of Petroleos Mexicanos, the Mexican state oil company, or PEMEX and Morgan Stanley Capital Group, or MSCG. The affiliate of PEMEX provides 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 of Maya crude oil, 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 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 purposes of comparison, the $15 per barrel minimum average coker gross margin support amount equates to a WTI/Maya crude oil differential of approximately $6 per barrel using market prices 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 is 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. 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, is 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, 2002, a cumulative quarterly surplus of $79.6 million existed under the contract. As a result, to the extent that 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.

We acquire directly or through MSCG 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 premium and reformulated gasoline, low sulfur diesel fuel, jet fuel, and petrochemical products that carry a sales value significantly greater than that for the products used to calculate the Gulf Coast crack spread. In addition, products produced by our Lima refinery are generally of higher value than similar products produced on the Gulf Coast due to the fact that the Midwest consumes more product than it produces, thereby creating a competitive advantage for Midwest refiners that can produce and deliver refined products at a cost lower than importers of refined product into the region. This advantage is measured by the excess of the Chicago crack spread over the Gulf Coast crack spread.

Another important factor affecting operating results is the relative quantity of higher value transportation fuels and petrochemical products compared to the production of residual fuel oil and other by-products such as petroleum coke and sulfur. Our 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 cost 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 the Port Arthur refinery and its ability to process greater volumes of heavy sour crude oil increased significantly as a result of the heavy oil upgrade project, the refinery now has a higher operating cost structure, primarily related to energy and labor.

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, 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. During 2002, prior to the purchase of the Memphis refinery, the portion of our target inventory position consisting of sales commitments netted against fixed price purchase commitments amounted to a net long position of approximately five million barrels. We are generally leaving the titled portion of our inventory position target fully exposed to price fluctuation; 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 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.

Overview. Net loss available to common stockholders was $129.6 million ($2.65 per diluted share) in 2002 as compared to net income available to common stockholders of $142.6 million ($4.13 per diluted share) in 2001. Our operating loss was $88.8 million in 2002 as compared to operating income of $367.0 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 2002 and 2001, respectively. Operating income decreased in 2002 compared to 2001 principally due to significantly weaker market conditions in 2002 than in 2001.

Net Sales and Operating Revenues. Net sales and operating revenues increased $355.3 million, or 6%, to $6,772.8 million in 2002 from $6,417.5 million in 2001. This increase is primarily attributable to an increase in the volume of crude oil sales in 2002 as compared to 2001. We periodically sell crude oil to take advantage of substitute crude slate opportunities particularly in relation to the crude oil supply to our Lima refinery.

Gross Margin. Gross margin decreased $495.1 million to $671.0 million in 2002 from $1,166.1 million in 2001. The decrease in gross margin in 2002 as compared to 2001 was principally driven by significantly weaker market conditions in 2002 than in 2001.

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, crack spreads were 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 Gulf Coast and Chicago crack spreads were approximately 31% and 37% lower, respectively, in 2002 than in 2001.

The crude oil differentials were also significantly lower in 2002 as compared to 2001. The crude oil differential between WTI and Maya heavy sour crude oil was approximately 41% lower in 2002 than in 2001. The crude oil differential between WTI and WTS sour crude oil was approximately 51% lower in 2002 than in 2001. We believe these narrowed differentials were attributable 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 heavy sour and light/medium sour crude oils accounted for between 60% and 65% of our crude oil throughput. The overall decrease in the sour and heavy sour crude oil differentials reduced our gross margin by approximately $290 million in 2002 as compared to 2001.

In 2002, our Port Arthur refinery experienced reduced crude oil throughput for approximately 17 days in November due to repairs on the reformer unit resulting from October’s hurricane shutdown. The refinery also experienced reduced crude oil throughput rates in late September and early October due to planned delays in crude oil supply resulting from anticipated repairs at the coker unit, which proved to be minimal, and during the remainder of October due to unplanned delays in crude oil supply resulting from the impact of production and transportation interruptions caused by hurricanes Isidore and Lili. The 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. 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 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 2002, the average crude oil throughput rate at our Lima refinery was basically the same as its 2001 rate and reflected its economic capacity. Crude oil throughput at higher rates produces additional high sulfur diesel for which there is only a limited market. Our Lima refinery had slightly reduced crude oil throughput rates in late September and early October due to delays in crude oil delivery caused by the hurricanes, in May and December due to mechanical problems with downstream units, and in several months throughout the year due to poor refining market conditions. The Lima refinery’s results for 2002 were also affected by a new crude oil supply agreement which provided approximately $0.20 per barrel of cost savings in the fourth quarter of 2002.

In 2001, crude oil throughput rates at our Port Arthur refinery were below capacity because units downstream were in start-up operations during the first quarter and a lightning strike in early May 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 early in 2001. 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 a minor repairs and a shutdown of a third party sulfur plant utilized by Hartford.

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. Our safety performance as measured by OSHA’s injury recording methods have improved over the past several years; however, our performance in the past year has declined. Accordingly, we are implementing several actions, including extensive reviews of our safe work practices and increased awareness communication, to change this trend. Despite our best 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 $35.5 million, or 8%, to $432.2 million in 2002 from $467.7 million in 2001. This decrease in 2002 was principally due to significantly lower natural gas prices, lower repair and maintenance costs particularly at Port Arthur, and the closure of the Hartford refinery in the fourth quarter of 2002. This decrease was 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 $11.5 million, or 18%, to $51.8 million in 2002 from $63.3 million in 2001. This decrease was principally due to lower wages and benefits, partially offset by relocation costs associated with our new Connecticut office. The lower wages related to the elimination of administrative positions, primarily at our St. Louis based office, as part of the restructuring. 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-based Compensation Expense. We have three stock-based employee compensation plans. Prior to 2002, we accounted for stock based compensation under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation cost is reflected in 2001 or 2000 net income, as all options granted in those years had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2002, we adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, prospectively, for all employee awards granted and modified after January 1, 2002. Awards under our plans typically vest over periods ranging from three to five years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2002 is lower than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table, provided in accordance with SFAS No. 148, Accounting for Stock Based Compensation—Transition and Disclosure, illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding awards in each period.

With respect to stock option grants outstanding as of December 31, 2002, we will record future non-cash stock-based compensation expense and additional paid-in capital of $35.9 million over the applicable vesting periods of the grants.

Depreciation and Amortization. Depreciation and amortization expenses decreased $3.0 million, or 3%, to $88.9 million in 2002 from $91.9 million 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 in 2002 at our Lima refinery due to the completion of turnarounds performed in 2001, and higher amortization in 2002 at our Port Arthur refinery due to the completion of turnaround activity in early 2002.

Interest Expense and Finance Income, net. Interest expense and finance income, net decreased $37.7 million, or 27%, to $101.8 million in 2002 from $139.5 million in 2001. This decrease related primarily to lower interest expense due to the repurchase of certain debt securities in the third quarter of 2001 and in the second quarter of 2002 and lower interest rates on our floating rate debt. This decrease was partially offset by lower interest income as cash balances declined.

Income Tax (Provision) Benefit. We recorded a $81.3 million income tax benefit in 2002 compared to an income tax provision of $52.4 million in the corresponding period in 2001. The income tax benefit for 2002 included an increase of $2.8 million to the deferred tax valuation allowance, which was recorded to reflect the likelihood of not realizing the future benefit of a portion of our federal business credits and a portion of our state tax loss carryforwards. The income tax provision for 2001 included the reversal of a $30.0 million 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 December 31, 2002, we have a net deferred tax asset of $57.5 million (PRG—$19.8 million). 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 a portion of our state tax loss carryforwards and a portion of our federal business tax credits, we provided a valuation allowance of $2.8 million 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 an additional portion or all of the net deferred tax asset will not be realized, an increase to the tax valuation allowance and a corresponding income tax provision would be required at that time.

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, 2002 of approximately $479 million and $240 million (PRG—$372 million and $157 million), respectively. Our net operating loss carryforwards will begin to terminate with the year ending December 31, 2011, 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 past three years. Accordingly, future changes, even slight changes, in the ownership of Premcor Inc.’s 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.

Overview. Net income available to common stockholders increased $62.5 million to $142.6 million ($4.13 per diluted share) in 2001 from $80.1 million ($2.55 per diluted share) in 2000. Operating income increased $220.3 million to $367.0 million in 2001 from $146.7 million in 2000. This increase was principally due to the completion and operation of the heavy oil upgrade project at our Port Arthur refinery combined with strong market conditions. See “—Factors Affecting Comparability” and “—Factors Affecting Operating Results” for a detailed discussion of how the heavy oil upgrade project has affected our results.

Net Sales and Operating Revenue. Net sales and operating revenues decreased $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 refinery in January 2001.

Gross Margin. Gross margin increased $426.9 million, or approximately 58%, to $1,166.1 million in 2001 from $739.2 million in the 2000. The increase was principally due to the processing of greater quantities 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 our refineries. These gains were partially offset by the poor market conditions in the fourth quarter and plant downtime and operational issues as described below.

The improvement in crude oil discounts was reflected by the increase in the average sour and heavy sour crude oil differential to WTI. The completion of the heavy oil upgrade project at our Port Arthur refinery 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% heavy sour crude oil in 2000. The strong crude oil differentials and the increase in usage of heavy sour crude oil together contributed over $450 million to gross margin in 2001. The Gulf Coast and Chicago crack spreads remained strong through most of the first half of 2001, reaching historically high levels at times. Industry inventories remained at low levels and were further lowered by industry-wide maintenance turnarounds performed in the first quarter. In the second half of the 2001, the Gulf Coast and Chicago crack spreads were 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. The Chicago crack spread did not weaken in proportion to the Gulf Coast crack spread through the third quarter due to supply constraints in the Midwest; however, it did decrease 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 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 crude and other units. The crude oil throughput rate at our Port Arthur refinery of 229,800 bpd in 2001 was below capacity of 250,000 bpd because units downstream were in start-up operations during the first quarter and a lightning strike in early May 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 the first quarter of 2001, the Port Arthur refinery performed a planned maintenance turnaround on its alkylation unit, which had only a minor impact on production.

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 early in 2001. 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 a 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 due to its closure in late January 2001. Offsetting this decrease were higher costs at our Port Arthur refinery for the operation of the new heavy oil processing units, including higher energy costs, and additional repair and maintenance costs at our Hartford refinery.

General and Administrative Expenses. General and administrative expenses increased $10.3 million, or approximately 19%, to $63.3 million in 2001 from $53.0 million in 2000. This increase was principally due to a 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.

Depreciation and Amortization. Depreciation and amortization expenses increased $20.1 million, or approximately 28%, to $91.9 million in 2001 from $71.8 million 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 & 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 Port Arthur turnaround in 2000 and a Lima turnaround in early 2001. The increase was partially offset by the absence of depreciation and amortization for the Blue Island refinery in 2001.

Interest Expense and Finance Income, net. Interest expense and finance income, net increased $57.3 million, or approximately 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 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 loan.

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 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.

This Outlook section contains forward-looking statements that reflect our current judgment regarding the direction of our business. Even though we believe our expectations regarding future events are reasonable assumptions, forward-looking statements are not guarantees of future performance. Factors beyond our control could cause our actual results to vary materially from our expectations and are discussed on page 1 to this Annual Report on Form 10-K, “Forward-Looking Statements”.

Market. Average crack spreads and crude oil differentials have been strong for the first quarter of 2003 to-date. We believe that these unseasonably strong market conditions have been driven by higher crude oil prices resulting from war concerns and disruptions from the Venezuelan oil strike and due to lower product inventories caused by heavy maintenance schedules, product exports to South America, and cold winter weather.

Refinery Operations. As more fully described in “Factors Affecting Our Operating Results”, it is common practice in our industry to look to benchmark market indicators as a predictor of actual refining margins, such as the Gulf Coast 2/1/1 and Chicago 3/2/1. 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 appropriately reflects our product slate. 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% 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. We do not expect to receive discounts on our purchases of Maya crude oil under our long-term crude oil supply agreement in 2003. Ancillary crude costs, primarily transportation, at Port Arthur averaged $0.97 per barrel of crude oil throughput in 2002. No significant downtime is planned for the Port Arthur refinery during the first quarter of 2003 and crude oil throughput rates should meet or exceed the average 2002 crude oil throughput rate of 224,700 bpd.

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 $1.58 per barrel of crude throughput in 2002. We expect to complete a 14-day turnaround of the Lima refinery FCC unit during the first quarter of 2003. Crude oil throughput rates for the first quarter are expected to be slightly less than the average 2002 rate of 141,500 bpd.

Our Memphis refinery was acquired effective March 3, 2003. We plan to operate the refinery at a crude oil throughput rate of approximately 170,000 bpd. We also expect that the operating results 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 crack spread resulting from location premiums for refined products, partially offset by crude oil transportation costs. We expect that this location premium will approximate $0.63 per barrel in normalized market conditions.

Operating Expenses. Natural gas is the most variable component of our operating expenses. On an annual basis, our Port Arthur and Lima refineries purchase approximately 29 million mmbtu of natural gas. In a normalized natural gas pricing environment and assuming average crude oil throughput levels, our annual operating expenses should range between $360 million and $380 million. However, natural gas prices for the first quarter of 2003 to-date have been significantly higher than normalized rates. The acquisition of the Memphis refinery is expected to increase our operating expenses by approximately $110 to $120 million annually. Fluctuations in natural gas prices are not expected to have a significant impact on the operating expenses of our Memphis refinery since it does not consume large quantities of natural gas.

General and Administrative Expenses. During 2002, we restructured our general and administrative operations to reduce our overhead costs. Our restructuring activities were expected to reduce our general and administrative expenses for 2003 to approximately $38 million. With the acquisition of the Memphis refinery we expect our annualized general and administrative expense will approximate $52 million, excluding incentive compensation.

Stock-based Compensation Expense. We recognize non-cash, stock-based compensation expense computed under SFAS No. 123 for all stock options granted beginning in 2002. During the first quarter of 2003, an additional 562,500 options were granted to employees and directors. Stock-based compensation expense for 2003, for options granted in 2002 and 2003, will approximate $17 million to $18 million.

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.

Depreciation and Amortization. Depreciation and amortization expense for the fourth quarter of 2002 was $24.0 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 and the Memphis acquisition. The

Memphis refinery should increase depreciation and amortization expense by approximately $3.5 million to $4.0 million per quarter. Depreciation and amortization expense includes amortization of our turnaround costs, generally over four years.

Interest Expense. Based on our outstanding long-term debt as of February 28, 2003, which included the newly issued $525 million of senior notes and repayments of $284 million, our annual gross interest expense will be approximately $114 million. All of our outstanding debt is at fixed rates with the exception of $10 million in floating rate notes tied to LIBOR. Reported interest expense is reduced by capitalized interest.

Income Taxes. We expect our effective income tax rate for 2003 will be approximately 37% to 38%.

Capital Expenditures and Turnarounds. We plan to expend approximately $230 million to $245 million for capital expenditures and turnarounds in 2003. This amount includes expenditures at our Memphis refinery, excluding the original purchase price. We plan to fund capital expenditures with internally generated funds. If internally generated funds are insufficient, we will reduce our capital expenditure plans accordingly.

Earn-out Payments. The Memphis refinery purchase agreement provides for contingent participation, or earn-out, payments up to a maximum aggregate of $75 million over the next seven years. Earn-out payments will be calculated annually at the end of the seven 12-month periods beginning on March 3, 2003. The annual earn-out calculation will be equal to one-half of the excess of the actual daily value of the Gulf Coast 2/1/1 crack spread over a stipulated margin, at a crude oil throughput rate of 167,123 bpd. The stipulated margin is $3.25 per barrel for the first year and increases by $0.10 per barrel for each year thereafter. Any amounts we pay to Williams as a result of the earn-out agreement will be recorded as additional refinery purchase price, and depreciated or amortized accordingly.

As of December 31, 2002, we had a cash and short-term investment balance of $172.3 million of which $37.3 million was held by Premcor Inc., $121.4 million by PRG, $10.2 million by Premcor USA, and $3.4 million by Opus Energy Risk Limited, a wholly-owned captive insurance subsidiary of Premcor Inc. In addition, under an amended and restated common security agreement related to PACC’s long-term debt, PACC is required to maintain $45.0 million of cash for debt service at all times and 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 December 31, 2002, cash of $61.7 million was restricted under these requirements. The amended and restated common security agreement was a result of the Sabine restructuring and eliminated the requirements of a secured cash account structure, which restricted PACC’s cash distribution to its partners. Except for the PACC cash restrictions mentioned above, there are no restrictions limiting dividends from PACC to PRG and, under an amended working capital facility, PACC is required to dividend to PRG all excess cash over $20 million, excluding the restricted debt service amounts. Also, pursuant to the amended working capital facility, if an aggregate intercompany payable from PRG to PACC exceeds $40 million at any time, PACC shall forgive PRG such excess amount, which would take the form of a non-cash dividend. No such dividends have been made as of December 31, 2002.

As of December 31, 2001, we had a cash and short-term investment balance of $511.8 million of which $484.2 million was held by PRG, $25.5 million by Premcor USA, and $2.1 million by Premcor Inc. In addition, we had $30.8 million of cash restricted for debt service under the secured cash account structure.

Premcor Inc. maintains 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 Premcor Inc. and each of our directors and officers,

Premcor Inc. formed a captive insurance subsidiary, Opus Energy, to provide additional liability coverage for such claims. Premcor Inc. funded an initial $3.0 million in 2002 and has committed to funding $1 million annually until a loss fund of $10 million is established.

Net cash flows provided by operating activities were $15.9 million for the year ended December 31, 2002 as compared to net cash flows provided by operating activities of $439.2 million for the year ended December 31, 2001 and $124.4 million for the year ended December 31, 2000. The significantly lower cash provided from operating activities in 2002 as compared to 2001 and 2000 is mainly attributable to weak market conditions, which resulted in poor operating results. Cash flows from operating activities were mainly impacted by strong cash earnings for the years ended December 31, 2001 and 2000. Working capital as of December 31, 2002 was $320.9 million, a 1.57-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 $205 million of available cash, excluding initial public offering proceeds, to repay long-term debt.

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, 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 these leases, including payment of rent, taxes and environmental cleanup responsibilities for releases of petroleum occurring during the term of the leases. CRE rejected 25 of these leases in connection with bankruptcy hearings held in late January and February 2003. We plan to record an after-tax charge of approximately $3.5 million in the first quarter of 2003 representing the estimated net present value of our remaining liability under these leases, net of estimated sub-lease income. We are currently in discussions with CRE regarding their reorganization plans, the status of environmental remediation agreements, and other matters. While it is possible that we may incur additional liability for CRE lease obligations or other costs as CRE finalizes its reorganization plans, the amounts are not estimable at this time. As of February 28, 2003, the future minimum lease payments under the approximately 125 CRE leases that had not been rejected at that point are currently estimated as follows (in millions): 2003—$10.2, 2004—$10.5, 2005—$10.9, 2006—$11.2, 2007—$11.7, and in the aggregate thereafter—$85.8. The costs, if any, of environmental remediation for any petroleum releases that we may be contingently liable for cannot be determined at this time. Should any of these leases revert to us, we will attempt to reduce the potential liability by subletting or reassigning the leases.

As of December 31, 2002, our future minimum lease payments under non-cancelable operating leases are as follows (in millions): 2003—$34.8, 2004—$30.3, 2005—$30.0, 2006—$29.1, 2007—$27.5, and in the aggregate thereafter—$75.7. The annual lease payments increased significantly due to an eight year lease, beginning in late 2002, of three crude oil tankers that are utilized solely to transport a major portion of our crude oil requirements to our Port Arthur refinery.

Cash flows used in investing activities were $144.5 million for the year ended December 31, 2002 as compared to $152.9 million for the year ended December 31, 2001 and $375.3 million for the year ended December 31, 2000. Activity in 2002, 2001, and 2000 primarily reflected 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. Our total mandatory capital and refinery maintenance turnaround expenditures were $63.5 million, $86.6 million, and $64.7 million for the years ended December 31, 2002, 2001, and 2000, respectively. We estimate that total mandatory capital and turnaround expenditures for all three refineries will average $150 million per year over the next four years and the budget for these expenditures is approximately $105 million for 2003. We plan to fund mandatory capital expenditures with available cash and cash flow from operations and will adjust our annual expenditures accordingly.

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. In addition to the mandatory capital expenditures discussed above, we expect to incur a total of approximately $727 million, including $670 million that we expect to expend over the next four years, in order to comply with environmental regulations related to the new stringent sulfur content specifications and MACT II regulations as discussed below.

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 our Port Arthur refinery prior to January 1, 2004. As a result of the corporate pool averaging provisions of the regulations, we believe that we will be able to defer a significant portion of the investment required for compliance for one or both of the Lima and Memphis refineries until the end of 2005. In addition, delay in the requirement to meet the new sulfur standards at the Lima and Memphis refinery through 2005 may also 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 the averaging provisions of the regulations will allow for a deferral of compliance at one or both of the Lima and Memphis refineries or that sufficient allotments or credits to defer investment at our Lima and Memphis refinery will be available, or if available, that they will be cost effective. We believe, based on current estimates and on a January 1, 2004 compliance date for all three refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2004 of approximately $335 million. This estimate reflects an increase from 2001 year-end estimates of $80 million for the newly acquired Memphis refinery and $79 million for revised cost estimates at Lima and Port Arthur based on completed detailed engineering studies and refined implementation plans. Future revisions to these cost estimates may be necessary. We are reviewing the current plans for Tier 2 compliance at the Memphis refinery and believe there may be opportunities for significant cost savings based on a revised project design and deferral of compliance to 2005. We have entered into contracts totaling $126 million related to the design and construction activity at our Port Arthur and Lima refineries for the Tier 2 gasoline compliance.

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. We estimate that capital expenditures required to comply with the on-road diesel standards at all three refineries in the aggregate through 2006 is approximately $347 million, an increase from previous estimates of $100 million for the newly acquired Memphis refinery and of $20 million for revised cost 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 half 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 two years related to these new regulations. 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 would be reduced to $25 million.

Our budget for complying with Tier 2 gasoline standards, on-road diesel regulations and the MACT II regulations is approximately $120 million in 2003 and we spent $56.7 million in 2002 related to these regulations. It is our intention to fund expenditures necessary to comply with these new environmental standards with cash flow from operations. Due to the volatile economic nature of our business we are organizing our plans and associated expenditures for compliance with these regulations into “modules” that can be shifted based on available funding. This will allow us to expedite or slow down the major portions of the project without compromising compliance dates but allowing us to take advantage of phase-in periods if necessary.

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 expenditures were $28.4 million, $57.1 million, and $357.5 million for the years ended December 31, 2002, 2001, and 2000, respectively. Discretionary spending in 2001 and 2000 reflected capital expenditures of $19.0 million and $346.0 million, respectively, related to the heavy oil upgrade project at Port Arthur.

Our budget for discretionary capital expenditures is approximately $5 million for 2003. We plan to fund our discretionary capital expenditures for 2003 with available cash and cash flow from operations.

In conjunction with the work being performed to comply with the above regulations, we had been evaluating a potential project to expand the Port Arthur refinery to 300,000 – 400,000 barrels per day of crude oil throughput capacity. Although the project is feasible, we have decided not to proceed with the project at this time. We are continuing to evaluate projects to reconfigure the Lima refinery to process a heavier, more sour crude slate.

The cash and cash equivalents restricted for investment in capital additions for the years ended December 31, 2002 and 2001 reflected receipt of proceeds of $10.0 million in Ohio state revenue bonds that were restricted for solid waste and wastewater capital projects at the Lima refinery and the subsequent use of those proceeds. The cash and cash equivalents restricted for investment in capital additions for the year ended December 31, 2000 reflected the use of proceeds that were restricted for the heavy oil upgrade project.

Cash flows used in financing activities were $214.1 million for the year ended December 31, 2002 as compared to $66.3 million for the year ended December 31, 2001 and cash flows provided by financing activities of $234.8 million for the year ended December 31, 2000. Cash flows used in financing activities in 2002 were principally related to the repurchase or redemption of long-term debt substantially offset by proceeds from the initial public offering of our common stock. Cash flows used in financing activities in 2001 were principally

related to the repurchase of a portion of our long-term debt. Cash flows provided by financing activity in 2000 were primarily related to the issuance of debt and equity to fund the heavy oil upgrade project at Port Arthur.

In 2002, Premcor Inc. received total net proceeds of $482.0 million from the sale of its common stock, which consisted of net proceeds of $462.6 million from an initial public offering of 20.7 million shares of its 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 its directors, and $6.3 million from the exercise of stock options under its stock incentive plans. The proceeds from the initial public offering and concurrent sales, or IPO proceeds, were committed to reducing the long-term debt of Premcor Inc.’s subsidiaries.

In 2002, Premcor USA and PRG redeemed and repurchased in aggregate, $645.8 million in principal amount of long-term debt from Premcor Inc.’s initial public offering proceeds and approximately $205 million from available cash. PRG redeemed the remaining $150.4 million of its 9½% senior notes at par value. Premcor USA redeemed the remaining $144.4 million of its 10⁷/8% senior notes, including a $5.2 million premium, and repurchased, in the open market, $57.5 million in aggregate principal amount of its 11½% subordinated debentures at a $3.3 million premium. PACC repaid its senior secured bank loan balance of $287.6 million at a $0.9 million premium. PACC also made a scheduled $4.3 million principal payment of its 12½% Senior Notes.

In 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 10⁷/8% senior notes, and $5.9 million in face value of our 11½% exchangeable preferred stock for an aggregate purchase price of $48.5 million.

In 2002, cash and cash equivalents restricted for debt service increased by $30.9 million, of which an increase of $45.2 million related to future principal payments and is included in cash flows from financing activity and a decrease of $14.3 million related to future interest payments and is included in cash flows from operating activities. The 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 2001, cash and cash equivalents restricted for debt service increased by $30.8 million, of which an increase of $6.5 million related to future principal payments and is included in cash flows from financing activity and an increase of $24.3 million related to future interest payments and is included in cash flows from operating activities.

In 2002, Premcor Inc. made capital contributions to Premcor USA of $442.9 million and Premcor USA subsequently contributed $248.1 million to PRG, all primarily for the repayment of long-term debt. In 2001, PRG returned capital of $25.8 million to Premcor USA of which $25.0 million was utilized by Premcor USA to repurchase a portion of its long-term debt and exchangeable preferred stock and $0.8 million was for its interest payment obligations. In 2000, PRG returned capital of $35.5 million to Premcor USA to meet future interest payment obligations.

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 12½% senior notes with the Securities and Exchange Commission following the restructuring, and the waiver related to insurance coverage required under the common security agreement. In 2001, we incurred deferred financing costs of $10.2 million principally associated with the amendment of our working capital facility.

In 2001, we borrowed $10.0 million in Ohio state revenue bonds, the proceeds of which are restricted for solid waste and wastewater capital projects.

The scheduled maturities of our long-term debt after giving effect for the newly issued $525 million of senior notes, the repayment of the remaining balance of $40.1 million of Premcor USA’s subordinated debentures, and the repayment of PRG’s $240 million floating rate loan, are: (in millions) 2003—$15.0; 2004—$25.8 2005—$38.5; 2006—$46.4; 2007—$318.4; 2008 and thereafter—$726.9. 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.

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 restricted payments and investments.

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 the long-term agreement with the 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 and restated PRG credit agreement.

In February 2003, PRG amended and restated its credit agreement, which included extending its maturity date to February 2006; increasing the capacity under the agreement to the lesser of $750 million, with the ability to increase to $800 million, or the amount available under the borrowing base; increasing the sub-limit for cash borrowings to $200 million, subject to certain limitations discussed below; and modifying certain covenant requirements. This credit agreement provides for the issuance of letters of credit of up to the amounts described above less outstanding borrowings. The borrowing base includes PRG’s cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, and net obligations on swap contracts. PRG uses this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. In May 2002, the credit agreement was amended to allow for the PACC crude oil purchase obligations and thus incorporated PACC’s hydrocarbon inventory into the borrowing base calculation. As of December 31, 2002, the borrowing base was $815.3 million (2001—$620.7 million), with $597.1 million (2001—$295.3 million) of the facility utilized for letters of credit.

The credit agreement provides for direct cash borrowings of up to, but not exceeding in the aggregate, $200 million, subject to a sublimit of $75 million for working capital and general corporate purposes and a sublimit of $150 million for acquisition-related working capital. Acquisition related borrowings are subject to a defined repayment provision. Borrowings under the credit agreement are secured by a lien on substantially all of our cash and cash equivalents, receivables, crude oil and refined product inventories and trademarks. Our interest rate for any borrowings under this agreement would bear interest at a rate based on either the U.S. prime lending rate or the Eurodollar plus a defined margin at our option based on certain restrictions. As of December 31, 2002 and 2001, there were no direct cash borrowings under the credit agreement.

The credit agreement contains covenants and conditions that, among other things, limit PRG’s dividends, indebtedness, liens, investments and contingent obligations. PRG is also required to comply with certain financial covenants, including the maintenance of working capital of at least $150 million and the maintenance of tangible net worth of at least $650 million, as amended. The covenants also provide for a cumulative cash flow test that from January 1, 2003 must not be less than zero. As amended, we are no longer required to maintain minimum levels of balance sheet cash.

In 2001, PRG entered into a $20 million cash-collateralized credit facility expiring August 23, 2003, which was increased to $40 million in October 2002. This facility was arranged in support of lower interest rates on its Series 2001 Ohio Bonds. In addition, this facility can be utilized for other non-hydrocarbon purposes. As of December 31, 2002, $10.1 million (2001—$10.1 million) of the line of credit was utilized for letters of credit.

We currently expect that funds generated from operating activities together with existing cash, cash equivalents and short-term investments and availability under our working capital facility will be adequate to fund our ongoing operating requirements.

The process of preparing financial statements in accordance with generally accepted accounting principles requires that we make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from our estimates and judgments. We consider the following to be our most critical accounting policies involving management judgment.

Contingencies. We account for contingencies in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards, or 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 other reserves requires 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. 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 other assets on our balance sheet, 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, or AcSEC, 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. This SOP required companies, among other things, to expense as incurred turnaround costs. Adoption of the proposed SOP would have required that any existing unamortized turnaround costs be expensed immediately. If this proposed change were in effect at December 31, 2002, we would have been required to write-off unamortized turnaround costs of approximately $86 million. In December 2002, AcSEC discontinued discussions concerning this SOP and handed over the responsibility for any further action to the Financial Accounting Standards Board, or FASB. At its February 2003 meeting, AcSEC indefinitely suspended action on the proposed SOP. Whether there will be new accounting guidance on turnaround costs and when it would become effective is currently unclear.

Inventories. Our inventories are stated at the lower of cost or market. Cost is determined under the LIFO method for hydrocarbon inventories including crude oil, refined products, and blendstocks. The cost of warehouse stock and other inventories is determined under the first-in, first-out (“FIFO”) method. Any reserve for inventory cost in excess of market value is reversed if physical inventories turn and prices recover above cost. As of December 31, 2002 the replacement cost (market value) of our crude oil and refined product inventories exceeded its carrying value by approximately $188 million, or approximately $12 per barrel over cost. The market value of these inventories would have had to been lower by over $12 per barrel as of December 31, 2002, in order for us to have had to write-down the value of our inventory. If prices significantly decline from year-end 2002 levels, we may be required to write-down the value of our inventories in future periods.

Long-lived Assets. We account for property, plant and equipment at cost and depreciate these assets over their estimated useful lives, which range from 3 to 40 years. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be

recoverable. In 2001, we closed our Blue Island refinery and in 2002 we ceased refining operations at our Hartford refinery. Significant management judgment was required in determining the fair market value of these non-productive assets and in establishing associated environmental remediation and other reserves. As of December 31, 2002, the carrying value of the Blue Island refinery had been reduced to zero and the Hartford refinery was recorded at $49.0 million. While we believe this represents the fair market value of the Hartford refinery assets, the amount we actually realize may differ from our estimate and further adjustments may be required.

Income Taxes. In preparing our consolidated financial statements, we must assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in making this determination. At December 31, 2002, we recorded a valuation allowance of $2.8 million due to uncertainties related to our ability to realize the future benefit of a portion of our federal business credits and a portion of our state tax loss carryforwards. The valuation allowance is based on our estimates of taxable income in the various jurisdictions in which we operate and the period over which the deferred income tax assets will be recoverable. In the event actual results differ from our estimates, we may need to adjust the valuation allowance in the future.

Stock-based Compensation. Effective January 1, 2002, we adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation for all employee awards granted and modified after January 1, 2002. SFAS No. 123 states that the adoption of the fair value based method is a change to a preferable method of accounting.

Pension Plans and Postretirement Employee Benefit Plans. We have three pension plans and a postretirement health care and life insurance benefit plan that require us to use judgment in selecting the actuarial assumptions used to estimate our expense and liability for these plans. The actuarial assumptions impacting our pension plans include estimates of compensation increases, discount rates, and the expected return on plan assets. Our pension plans were initiated in 2002 and will be funded for the first time in 2003. The actuarial assumptions impacting our postretirement employee benefit plans include estimates of compensation increases, discount rates and health care cost trend rates. Our postretirement expenses increased in 2001 and 2002, principally due to the low interest rate environment that is a basis for setting the plan’s discount rate and due to increases in our assumptions for health care cost trend rates. The impact of these changes has been significant and will be recognized over the service period of the employees covered by the plans. Future changes to the actuarial assumptions impacting our pension plans and postretirement employee benefit plans could have a significant impact on our costs for these plans.

On July 20, 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 did not have a material impact on our financial position and results of operations.

remediation of soil and groundwater in and around the operating units of the refineries, wastewater treatment facilities, storage tanks, and pipelines. We are not required to perform these obligations until we permanently cease operations of the long-lived assets and therefore, consider the settlement date of the obligations to be indeterminable. Accordingly, we cannot calculate an associated asset retirement liability at this time. We adopted this standard in the first quarter of 2003, but the initial adoption did not have a material impact on our financial position or results of operations. We will measure and recognize the fair value of our asset retirement obligations at such time as a settlement date is determinable.

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 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 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 did not have a material impact on our financial position or results of operations.

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 issued on or after May 15, 2002. As permitted by the statement, we elected early adoption of SFAS No. 145 and, accordingly, have included 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 operations, 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.

In October 2002, the Emerging Issues Task Force (“EITF”) of the FASB reached a consensus on certain issues in EITF 02-3: Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities including:

Implementation of EITF 02-3 did not have a material effect on our financial statements because we mark-to-market only financial instruments and forward purchase and sale contracts considered derivatives pursuant to SFAS No. 133 and do not hold or issue derivative instruments for trading purposes.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation requires expanded disclosure of a guarantor’s obligation under certain guarantees that it has issued. It also requires that a guarantor recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure requirements are effective for interim and annual financial statements issued for periods ending after December 15, 2002. The provisions for the recognition of a liability are effective prospectively for guarantees issued or modified after December 31, 2002 and we will adopt these recognition provisions in the first quarter of 2003.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB. No. 51. This interpretation clarifies consolidation requirements for variable interest entities. It establishes additional factors beyond ownership of a majority voting interest to indicate that a company has a controlling financing interest in an entity (or a relationship sufficiently similar to a controlling financial interest that it requires consolidation). This interpretation applies immediately to variable interest entities created or obtained after January 31, 2003 and must be retroactively applied to holdings in variable interest entities acquired before February 1, 2003 in interim and annual financial statements issued for periods beginning after June 15, 2003. We do not expect that adoption of this interpretation will have a material impact on our financial statements.

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 are held for trading.

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, other feedstocks, gasoline, other refined products and natural gas. 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, the prices of these commodities fluctuate significantly, which directly impacts our net sales and operating revenues and costs of sales.

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 LIFO based inventory cost to market value when market prices drop dramatically compared to our LIFO inventory cost. These potential write-downs may be recovered in subsequent periods as our inventories turn and market prices rise.

As of December 31, 2002 the replacement cost (market value) of our crude oil and refined product inventories exceeded the carrying value by $188 million, or approximately $12 per barrel over cost. The market value of these inventories would have had to been lower by over $12 per barrel as of December 31, 2002, in order for us to have had to write-down the value of our inventory. By contrast, as of December 31, 2001, the replacement cost (market value) of our crude oil and refined product inventories exceeded the carrying value by

only $5 million, or approximately $0.32 per barrel over cost. 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 approximately $10 million. As of January 1, 2002, all of our hydrocarbon inventories are valued using the LIFO method, which are more susceptible to a material write-down when prices decline dramatically. If prices decline significantly from year-end 2002 levels, we may be required to write-down the value of our LIFO inventories in future periods.

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 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 our derivative commodity positions held as part of our price risk mitigation activities. This analysis may differ from actual results. The fair value of each derivative commodity position was based on quoted futures prices. As of December 31, 2002, a 10% change in quoted futures prices would result in an approximately $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 approximately $6 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income.

Our results are also sensitive to the fluctuations in natural gas prices due to the use of natural gas to fuel our refinery operations particularly at our Port Arthur refinery. If natural gas prices were higher on average by $1 per million btu than our operating expenses would increase by approximately $29 million annually.

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. During 2002, we repaid $645.8 million of our long-term debt, and during 2003, we issued $525 million of new senior notes and repaid $284 million of outstanding long-term debt, which included a $240 million floating rate loan. After giving effect to these transactions we have an outstanding balance, including current maturities, of $1,169.8 million. The weighted average interest rate on our fixed rate long-term debt is 9.8%. We are subject to interest rate risk on our Ohio bonds and any direct borrowings under our credit agreement. As of December 31, 2002, after giving effect to the repayment of the $240 million floating rate loan as of that date, a 1% change in interest rates on our floating rate loans, which totaled $10 million, would result in a $0.1 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 $250 million, would result in a $2.5 million change in pretax income on an annual basis. As of December 31, 2002 and 2001, there were no borrowings under our credit agreement.

The information required by this item is set forth beginning on page F-1 of this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The information required by Item 10 as to executive officers of the Company is disclosed in Part I under the caption “Executive Officers of the Registrant.” The information required by Item 10 as to the directors of the Company is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A. We are not aware of any family relationships between any director or executive officer. Each executive officer is generally elected to hold office until the next Annual Meeting of Stockholders.

The information required by Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A.

As of December 31, 2002, we had three stock-based employee compensation plans, which allowed for the issuance of Premcor Inc. common stock. See Note 18 of the Financial Statements included in Item 14(a) 1 and 2 for a description of the plans.

The remaining information required by Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A.

The information required by Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A.

Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operations of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-14 and 15d-14. Based upon that evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic SEC filings. There have not been any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of evaluation.

The consolidated financial statements and financial statement schedules of Premcor Inc. and subsidiaries and The Premcor Refining Group Inc. and subsidiaries, required by Part II, Item 8, are included in Part IV of this report. See Index to Consolidated Financial Statements and Financial Statement Schedules beginning on page F-1.

We filed the following reports on Form 8-K during the last quarter of the period covered by this report:

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

We have audited the accompanying consolidated balance sheets of Premcor Inc. and subsidiaries (the “Company”) as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for stock based compensation issued to employees.

We have audited the accompanying consolidated balance sheets of The Premcor Refining Group Inc. and subsidiaries (the “Company”) as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for stock based compensation issued to employees. Additionally, the consolidated financial statements have been restated to give retroactive effect to the contribution of Sabine River Holding Corp. common stock owned by Premcor Inc. to The Premcor Refining Group Inc. (the “Sabine Restructuring”), which has been accounted for in a manner similar to a pooling of interests as described in Notes 2 and 3 to the consolidated financial statements.

Premcor Inc., a Delaware corporation, was incorporated in April 1999. Premcor Inc. owns all of the outstanding common stock of Premcor USA Inc. (“Premcor USA”), a Delaware corporation formed in 1988. Premcor USA owns all of the outstanding common stock of The Premcor Refining Group Inc. (“PRG”), a Delaware corporation also formed in 1988. PRG and its indirect subsidiary, Port Arthur Coker Company L.P. (“PACC”), are Premcor Inc.’s principal operating subsidiaries. The information reflected in these combined consolidated footnotes for Premcor Inc. and PRG is equally applicable to both companies except where indicated otherwise.

Premcor Inc. and its subsidiaries (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. As of December 31, 2002, the Company owned and operated 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. In September 2002, the Company ceased refining operations at its 70,000 bpd Hartford, Illinois refinery. In March 2003, the Company acquired a 190,000 bpd refinery in Memphis, Tennessee bringing its combined crude oil throughput capacity to 610,000 bpd. See Note 22, Subsequent Events for more details of the acquisition.

All of the operations of the Company 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 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.

The accompanying consolidated financial statements of Premcor Inc. and PRG include the accounts of each parent company and its subsidiaries. Premcor Inc. and PRG consolidate the assets, liabilities, and results of operations of the subsidiaries in which each company has a controlling interest. All significant intercompany accounts and transactions have been eliminated. The investment in a company in which PRG owned 20 percent to 50 percent voting control was accounted for by the equity method, and the investment in a company in which Premcor Inc. owns less than 20 percent voting control is accounted for by the cost method.

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, a Delaware corporation, was incorporated in May 1999. 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. Accordingly, PRG’s historical financial statements have been restated to include the consolidated financial position, results of operations, and cash flows of Sabine for all periods presented.

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.

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. Cash and cash equivalents exclude cash that is contractually restricted for non-operational purposes such as debt service and capital expenditures. Restricted cash and cash equivalents is classified as a current or noncurrent asset based on its designated purpose.

Revenue from sales of products is recognized upon transfer of title, based upon the terms of delivery.

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 products. The results of this activity are recorded in cost of sales and net sales and operating revenue. The Company’s distribution network is an integral part of its refining business. However, due to ordinary course logistical issues concerning production schedules and product sales commitments, it is common for the Company to purchase refined products from third parties in order to balance the requirements of its product marketing activities. Although third party purchases are essential to effectively market the Company’s production, the effects from these activities on the Company’s 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. Exchanges that are settled through payment or receipt of cash are accounted for as purchases or sales.

The Company collects excise taxes on sales of gasoline and other motor fuels. Excise taxes of approximately $347.4 million, $451.0 million, and $471.1 million were collected from customers and paid to various governmental entities in 2002, 2001, and 2000, respectively. Excise taxes are not included in sales.

Inventories for the Company are stated at the lower of cost or market. Cost is determined under the LIFO inventory method for hydrocarbon inventories including crude oil, refined products, and blendstocks. The cost of warehouse stock and other inventories for the Company is determined under the First-in First-out (“FIFO”) inventory method. Any reserve for inventory cost in excess of market value is reversed if physical inventories turn and prices recover above cost.

The Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedge Activities, as amended by SFAS No. 138, 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, including futures and options contracts, used in the implementation of the Company’s price risk mitigation strategies. The Company enters into crude oil, refined products, and natural gas exchange traded futures and options contracts as well as over-the-counter swaps to limit risk related to hydrocarbon price fluctuations created by a potentially volatile market. Forward purchase and sale contracts are also considered derivatives. As of December 31, 2002 and 2001, the Company has not designated hedge accounting for any of its derivative positions, and accordingly, records unrealized gains and losses on open contracts in current cost of sales. The Company does not hold or issue derivative instruments for trading purposes.

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 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 impairment 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.

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 (“AcSEC”) issued an exposure draft of a proposed statement of position (“SOP”) entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. This SOP required companies, among other things, to expense as incurred turnaround costs. Adoption of the proposed SOP would have required that any existing unamortized turnaround costs be expensed immediately. If this proposed change were in effect at December 31, 2002, the Company would have been required to write-off unamortized turnaround costs of approximately $86 million. In December 2002, AcSEC discontinued discussions concerning this SOP and delegated responsibility for any further action to the Financial Accounting Standards Board (“FASB”). At its February 2003 meeting, AcSEC indefinitely suspended action on the proposed SOP. Whether there will be new accounting guidance on turnaround costs and when it would become effective is currently unclear.

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 operations 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.

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 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.

All of PRG’s subsidiaries, except for PACC and Port Arthur Finance Corp. (“PAFC”), are included in the consolidated U.S. federal income tax return filed by Premcor Inc. Each subsidiary computes its provision on a separate company basis with adjustments necessary to reflect the effect of consolidated tax return allocations and limitations. PACC is classified as a partnership for U.S. federal income tax purposes and, accordingly, does not pay federal income tax. PACC files a U.S. partnership return of income and its taxable income or loss flows through to its partners who report and are taxed on their distributive shares of such taxable income or loss. Accordingly, no federal income taxes have been provided by PACC. PAFC files a separate U.S. federal income tax return and computes its provision on a separate company basis.

As of December 31, 2002, the Company has three stock-based employee compensation plans, which are described more fully in Note 18, Stock Option Plans. Prior to 2002, the Company accounted for stock based compensation under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation cost is reflected in 2001 or 2000 net income, as all options granted in those years had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2002, the Company adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, prospectively, for all employee awards granted and modified after January 1, 2002. Awards under the Company’s plans typically vest over periods ranging from three to five years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2002 is lower than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table, provided in accordance with SFAS No. 148, Accounting for Stock Based Compensation—Transition and Disclosure, illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding awards in each period.

With respect to stock option grants outstanding as of December 31, 2002, the Company will record future non-cash stock-based compensation expense and additional paid-in capital of $35.9 million over the applicable vesting periods of the grants. The stock-based compensation expense principally relates to employees whose costs are classified as general and administrative expenses.

Basic earnings per share is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding during the period. Fully-diluted earnings per share equals net income available to common stockholders divided by the sum of weighted average common shares outstanding during the period plus common stock equivalents, such as stock options and warrants.

In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires fair value recognition of legal obligations to retire long-lived assets at the time the obligations are incurred. The initial recording of a liability for an asset retirement obligation will require the recording of a corresponding asset. The liability will be adjusted for accretion due to the passage of time and the asset will be depreciated. The Company has asset retirement obligations based on its legal obligations to remediate its refinery sites. These obligations principally relate to the removal of solid waste, hazardous waste and asbestos as well as the remediation of soil and groundwater in and around the operating units of the refineries, wastewater treatment facilities, storage tanks, and pipelines. The Company is not required to perform these obligations until it permanently ceases operations of the long-lived assets and therefore, considers the settlement date of the obligations to be indeterminable. Accordingly, the Company cannot calculate an associated asset retirement liability at this time. The Company will adopt this standard in the first quarter of 2003, but the initial adoption will not have a material impact on the Company’s financial position or results of operations. The Company will measure and recognize the fair value of its asset retirement obligations at such time as a settlement date is determinable.

On January 1, 2002, the Company adopted 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 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 closure.

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 issued on or after May 15, 2002. As permitted by SFAS No. 145, the Company 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 as a component of “Income (loss) from continuing operations” as opposed to as an extraordinary item, net of taxes, in its Statement of Operations. The Company reclassified a pretax gain of $8.7 million ($0.8 million for PRG) in 2001 to conform to the new classification.

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.

Implementation of EITF 02-3 did not have a material effect on the Company’s financial statements because it marks-to-market only financial instruments and forward purchase and sale contracts considered derivatives pursuant to SFAS No. 133 and does not hold or issue derivative instruments for trading purposes.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation requires expanded disclosure of a guarantor’s obligation under certain guarantees that it has issued. It also requires that a guarantor recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure requirements are effective for interim and annual financial statements issued for periods ending after December 15, 2002. The provisions for the recognition of a liability are effective prospectively for guarantees issued or modified after December 31, 2002 and the Company will adopt these recognition provisions in the first quarter of 2003.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB. No. 51. This interpretation clarifies consolidation requirements for variable interest entities. It establishes additional factors beyond ownership of a majority voting interest to indicate that a company has a controlling financing interest in an entity (or a relationship sufficiently similar to a controlling financial interest that it requires consolidation). This interpretation applies immediately to variable interest entities created or obtained after January 31, 2003 and must be retroactively applied to holdings in variable interest entities acquired before February 1, 2003 in interim and annual financial statements issued for periods beginning after June 15, 2003. The Company does not expect that adoption of this interpretation will have a material impact on its financial statements.

Certain reclassifications have been made to prior years’ financial statements to conform to classifications used in the current year.

On June 6, 2002, Premcor Inc., 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 refinery. Prior to the Sabine restructuring, Sabine was 90% owned by Premcor Inc. and 10% owned by a subsidiary of Occidental Petroleum Corporation (“Occidental”).

The Sabine restructuring was permitted by the successful consent solicitation of the holders of the PAFC 12½% Senior Notes. The Sabine restructuring was accomplished according to the following steps, among others:

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 2, 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 similar to a pooling of interests. Accordingly, PRG’s historical financial statements have been restated to include the consolidated results of operations, financial position, and cash flows of Sabine for all periods presented.

In 2002, Premcor Inc. and PRG recorded refinery restructuring and other charges of $172.9 million and $168.7 million, respectively. Premcor Inc. and PRG recorded the following:

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.

Below are further discussions of the Hartford and Blue Island refinery closures and the management team, refinery, and administrative function restructuring.

In late September 2002, the Company ceased refining 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. 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 and $4.8 million of non-cash current asset write-offs. 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, the Company announced that it would continue to operate its storage and distribution facility at the refinery site to accommodate its wholesale operations. As a result of this decision, the Company reclassified the net book value of the storage and distribution facility 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.

Despite ceasing operations, the Company continues to pursue all strategic options including the sale or lease of the refinery. The Company has had preliminary discussions with third parties regarding a transaction for the refinery assets, but there can be no assurance that a transaction will be completed. When the final disposition of the assets is determined, the net realizable value may be less than $49.0 million and a further write-down may be required.

In the fourth quarter of 2002, the Company completed the process unit shutdown and hydrocarbon purging and terminated all employee positions, which approximated 310 hourly (covered by collective bargaining agreements) and salaried positions. In the fourth quarter of 2002, the Company lowered the reserve by $1.6 million, which reflected a decrease of the site clean-up costs partially offset by a net increase for actual costs incurred for employee severance and the plant shutdown. The lower site clean-up costs reflected less work that will need to be performed since the storage and distribution facility will remain in operation. Additionally, the Company reclassified $0.3 million of the reserve to the Company’s pension related long-term liability. 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 assets is determined and a site remediation plan refined, further adjustments of the reserve may be necessary, and such adjustments may be material. Also in the fourth quarter of 2002, the Company increased its non-cash current asset write-off from $3.2 million to $4.8 million as a result of losses on the disposition of warehouse inventories and other supplies.

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. The only anticipated effect on net income and cash flow in the future will result from the final disposition of the assets and subsequent environmental site remediation. Unless there is a need to adjust the estimated net realizable value or the reserve in the future as discussed above, there should be no significant effect on net income beyond 2002.

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 one of Premcor Inc.’s major shareholders.

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 and Lima 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 was $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 long-term liabilities on the balance sheet together with the Company’s other post-retirement liabilities. Reductions at the refineries occurred in October 2002 and those at the St. Louis office will take place in early 2003. The reserve relating to the refineries and St. Louis restructuring was as follows:

In January 2001, the Company ceased refining operations at its Blue Island refinery due to economic factors and a decision that the capital expenditures necessary to produce low sulfur transportation fuels required by new regulations could not produce acceptable returns on investment. This closure resulted in a pretax charge of $167.2 million in 2001, which included $98.1 of non-cash asset write-offs in excess of realizable value and a $69.1 million reserve for closure activities. The Company continues to utilize its storage and distribution facility at the refinery site to supply selected products to the Chicago and other Midwest markets from its operating refineries. Since the Blue Island refinery operation had been only marginally profitable in recent years the reduced refining capacity resulting from the closure is not expected to have a significant negative impact on future net income or cash flow from operations. The only significant effect of the refinery closure on cash flow will result from the environmental site remediation as discussed below. Unless there is a need to adjust the site remediation reserve in the future, there should be no significant effect on net income beyond 2001.

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 mid-2003 at the earliest. The 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 discussed below. In 2002, the Company decreased the reserve for site remediation by an aggregate $2.0 million and concurrently wrote-off an asset previously recorded for the sale of emission credits. The adjustments reflected further refinement of plant closure and remediation activities relating to the continuing operations of the storage and distribution facility. As the site remediation plan is finalized and work is performed, further adjustments to 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 the 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.

In 2001, the Company recorded a pretax charge of $29.5 million, $18.0 million net of income taxes, related primarily to environmental liabilities of discontinued retail operations. This pretax charge consisted of $14.0 million representing a change in estimate relative to the Company’s clean up obligation regarding the previously discontinued retail operations, a charge of $14.0 million representing a change in estimate concerning the amount collectible from state agencies under various reimbursement programs, and a charge of $1.5 million representing workers compensation and general liability claims related to the discontinued retail operations. 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 common stock shares used to compute the Company’s basic and diluted earnings per share is as follows (in millions):

Stock options and warrants representing common stock equivalents of 1.6 million shares were excluded from diluted shares outstanding for the year ended December 31, 2002 due to their antidilutive effect as a result of the Company’s net loss. Stock options of 4.4 million, 1.9 million and 1.8 million were excluded from the diluted earnings per share calculation because their exercise price was the same or greater than the average market price of the Company’s common stock for the periods ended December 31, 2002, 2001 and 2000, respectively.

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. All of these investments are considered available-for-sale and carried at fair value. Realized gains and losses are presented in “Interest income” and are computed using the specific identification method.

At December 31, 2002, the Company maintained short-term investments totaling $4.9 million, of which $1.7 million was pledged as collateral for self-insured workers’ compensation programs at PRG (2001—$1.7 million). At December 31, 2002, a wholly owned subsidiary of Premcor Inc. held $3.2 million in investments to provide additional directors and officers liability coverage for claims made against them in their respective capacities as directors and officers. The subsidiary’s assets are restricted to payment of directors’ and officers’ liability defense costs and claims. The cost of short-term investments approximates fair value. Accordingly, unrealized gains and losses are not material.

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 12, Long-term Debt and Exchangeable Preferred Stock for the disclosure of the fair value of long-term debt.

As of December 31, 2002, the Company had open contracts of futures, swaps, and forward purchases and sales, all related to commodity derivative activity, which resulted in a net unrealized gain of $1.8 million. As of December 31, 2001, the Company had open contracts of futures and options, all related to commodity derivative activity, which resulted in a net unrealized loss of $6.9 million.

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. As of December 31, 2002, the Company increased its 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.

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.

As of December 31, 2002, the market value of crude oil, refined product, and blendstock inventories was approximately $188.3 million above carrying value (2001—$5.0 million).

As of January 1, 2002, PACC changed its method of inventory valuation from FIFO to 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 a material impact on prior periods and accordingly, prior periods have not been restated. The adoption of the LIFO method resulted in approximately $11 million less net income ($0.23 per basic and diluted share) for the year ended December 31, 2002 than if the FIFO method had been used for the same period.

Inventories recorded under LIFO include crude oil, refined products, and blendstocks of $262.6 million and $252.6 million for the years ended December 31, 2002 and 2001, respectively. A LIFO liquidation reduced the Company’s pretax earnings by $1.5 million in 2002 (2001—$19.3 million). The 2002 liquidation was due to the closure of the Hartford refinery. The 2001 liquidation was due to the closure of the Blue Island refinery and a decrease in the amount of crude oil processed by PRG at the Port Arthur refinery as PACC became the predominant crude oil processor at the refinery.

The useful lives on depreciable assets used to determine depreciation were as follows:

Construction in progress included approximately $64 million related to expenditures to conform to new federally mandated fuel specifications as discussed more fully in Note 20, Commitments and Contingencies.

Sabine and its subsidiaries 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 the Port Arthur refinery (the

“heavy oil upgrade project”). The heavy oil upgrade project became fully operational in January of 2001 and final completion of this project was achieved on December 28, 2001. Construction in progress included $33 million related to the heavy oil upgrade project as of December 31, 2001.

In 2002, the Company incurred deferred financing costs of $11.4 million related to the consent process that permitted the Sabine restructuring, the registration of the PAFC 12½% Senior Notes with the Securities and Exchange Commission following the restructuring, and a waiver related to insurance coverage required under the indenture for the PAFC 12½% Senior Notes. In 2002, the Company wrote-off $9.5 million of deferred financing costs as a result of the early repayment of long-term debt, including $1.6 million related to Premcor USA stand-alone long-term debt.

In 2001, the Company incurred deferred financing costs of $10.2 million associated with the amendment of its working capital facility issued at PRG and the issuance of tax exempt bonds through the state of Ohio. In 2001, the Company wrote-off $0.6 million of deferred financing costs related to the repurchase of a portion of its long-term debt, including $0.4 million related to Premcor USA stand-alone long-term debt and exchangeable preferred stock. In 2001, related to the adoption of SFAS No. 133, PACC recorded its interest rate cap on its Senior Secured Bank Loan at fair market value resulting in the write-down of deferred financing costs of $0.7 million.

For the Company, amortization of deferred financing costs for the year ended December 31, 2002 was $10.3 million (2001—$11.4 million, 2000—$11.0 million). For PRG, amortization of deferred financing costs for the year ended December 31, 2002 was $10.2 million (2001—$10.9 million, 2000—$10.5 million). Amortization of deferred financing costs was included in “Interest and finance expense”.

Investments in affiliates decreased in 2002 due to the write-down of Premcor Inc.’s 5% minority interest in CRE as discussed above.

Cash restricted for investment in capital additions is related to the outstanding proceeds from the Series 2001 Ohio Bonds. These proceeds are restricted to fund capital expenditure projects for solid waste and wastewater facilities at the Lima refinery.

PRG’s amended and restated credit agreement, which expires in August 2003, provides a facility for the issuance of letters of credit of up to the lesser of $650 million or the amount of a borrowing base calculated with respect to PRG’s cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, and net obligations on swap contracts. PRG uses this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. In May 2002, the credit

agreement was amended to allow for the PACC crude oil purchase obligations and thus incorporated PACC’s hydrocarbon inventory into the borrowing base calculation. Also, as amended, the $650 million limit can be increased by $50 million at the request of PRG upon securing additional commitments. As of December 31, 2002, the borrowing base was $815.3 million (2001—$620.7 million), with $597.1 million (2001—$295.3 million) of the facility utilized for letters of credit. As of December 31, 2002, $239.3 million (2001—$139.9 million) of the total letters of credit utilized under this facility supported deliveries that PRG and PACC had not taken delivery of but had made a purchase commitment. The remaining $357.8 (2001—$155.4 million) related to deliveries in which the Company had taken title and accordingly recorded purchases and accounts payable.

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 our cash and cash equivalents, receivables, crude oil and refined product inventories and trademarks. As of December 31, 2002 and 2001, there were no direct cash borrowings under the credit agreement.

The credit agreement contains covenants and conditions that, among other things, limit PRG’s dividends, indebtedness, liens, investments and contingent obligations. 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 $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, PRG 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.

In February 2003, PRG’s credit agreement was amended and restated to, among other things, increase the facility size to $750 million and extend the maturity date to February 2006. See Note 22, Subsequent Events.

In December 2001, PRG entered into a $20 million cash-collateralized credit facility expiring August 23, 2003. In October 2002, PRG expanded the facility to $40 million. This facility was arranged for required guarantees related to the Series 2001 Ohio Bonds. In addition, this facility can be utilized for other non-hydrocarbon purposes. As of December 31, 2002, $10.1 million (2001—$10.1 million) of the line of credit was utilized for letters of credit.

The estimated fair value of the Company’s long-term debt at December 31, 2002 was $926.2 million (2001—$1,331.8 million). The estimated fair value of PRG’s long-term debt at December 31, 2002 was $884.6 million (2001—$1,215.8 million). Estimated fair value was determined using quoted market prices for each debt issue.

In 2002, Premcor USA and PRG redeemed and repurchased in aggregate $645.8 million in principal amount of long-term debt from Premcor Inc.’s initial public offering proceeds and approximately $205 million of available cash. PRG redeemed the remaining $150.4 million of its 9½% Senior Notes at par value. Premcor USA redeemed the remaining $144.4 million of its 10⁷/8% Senior Notes, including a $5.2 million premium, and repurchased, in the open market, $57.5 million in aggregate principal amount of its 11½% Subordinated Debentures at a $3.3 million premium. PAFC repaid its Senior Secured Bank Loan balance of $287.6 million at a $0.9 million premium. PAFC also made a scheduled $4.3 million principal payment of its 12 ½% Senior Notes.

The 8³/8% Senior Notes and 8⁷/8% 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 8⁷/8% Senior Subordinated Notes subordinated in right of payment to all unsubordinated indebtedness of PRG. The 8³/8% Senior Notes and

8⁷/8% 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.

The 8⁵/8% Senior Notes were issued by PRG in August 1998, at a discount of 0.234% and are unsecured. The 8⁵/8% 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.

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 and restated credit agreement. The average LIBOR rate for years 2002, 2001 and 2000 was 1.79%, 3.78% and 6.54%, respectively. The Floating Rate Loan was repaid in February 2003, as described in Note 22 Subsequent Events.

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%. The current portion of the 12½% Senior Notes was $14.8 million as of December 31, 2002.

In December 2001, PRG borrowed $10 million through the state of Ohio, which had issued Ohio Water Development Authority Environmental Facilities Revenue Bonds. PRG is the sole guarantor on the principal and interest payments of these bonds. PRG is subject to a variable interest rate determined by the Trustee Bank not to exceed the maximum interest rate as defined under the indentures. For 2002 and 2003, the interest rate is 2%. PRG has the option to redeem the bonds prior to maturity during a window from April 1^st to November 30^th of any year at a redemption price of 100% of principal plus accrued interest. PRG has the option of converting from a variable interest rate to a 30-year fixed interest rate. 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.

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. On April 1, 2002, Premcor USA exchanged all of its 11½% Exchangeable Preferred Stock for 11½% Subordinated Debentures due October, 2009. The 11½% Subordinated Debentures are 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. The remaining balance of the 11½% Subordinated Debentures were redeemed in February 2003, as described in Note 22, Subsequent Events.

The aggregate stated maturities of long-term debt for the Company are (in millions): 2003—$15.0; 2004—$265.8; 2005—$38.5; 2006—$46.4; 2007—$318.4; 2008 and thereafter—$241.9. The aggregate stated maturities of long-term debt for PRG are (in millions): 2003—$15.0; 2004—$265.8; 2005—$38.5; 2006—$46.4; 2007—$318.4; 2008 and thereafter—$201.8. These stated maturities do not reflect the impact of PRG’s $525 million Senior Notes offering, which was completed in February 2003, as described in Note 22, Subsequent Events.

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, and limitations on the incurrence of liens. In order to make dividend payments, PRG must maintain a net worth, as defined, of $200 million or be permitted to incur at least $1 of additional debt as defined in the indentures, 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 Loans at 101% and 100% of face value, respectively, plus accrued interest.

An amended and restated common security agreement contains common covenants, representations, defaults and other terms with respect to the long-term debt obligations of PAFC. The original common security agreement was amended and restated as a result of the Sabine restructuring. Under the amended and restated common security agreement, PRG fully and unconditionally guaranteed, on a senior secured basis, the payment obligations under the 12½% Senior Notes. Also, under the amended and restated common security agreement, PACC is required to maintain $45.0 million of cash for debt service at all times plus an amount equal to the next scheduled principal and interest payment on its 12½% Senior Notes, prorated based on the number of months remaining until that payment is due. As of December 31, 2002, cash of $61.7 million was restricted under these requirements and classified as cash and cash equivalents restricted for debt service on the balance sheet. The amended and restated common security agreement eliminated the requirements of a secured cash account structure, which had placed significant restrictions on PACC’s cash balances. As of December 31, 2001, cash of $30.8 million was restricted for debt service under the secured cash account structure.

Except for the PACC debt service cash restrictions discussed above, there are no restrictions limiting dividends from PACC to PRG and, under the amended and restated working capital facility, PACC is required to dividend to PRG all excess cash over $20 million, excluding the restricted debt service amounts. Also, pursuant to the amended working capital facility, if an aggregate intercompany payable from PRG to PACC exceeds $40 million at any time, PACC shall forgive PRG such excess amount, which would take the form of a non-cash dividend. No such dividends have been made as of December 31, 2002.

The original 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, and the amended and restated common security agreement takes 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 December 31, 2002, PACC was in compliance with the insurance coverage requirements of the amended and restated common security agreement.

Interest and finance expense included in Premcor Inc.’s statements of operations consisted of the following:

Interest and finance expense included in PRG’s statements of operations consisted of the following:

Cash paid for interest expense in 2002 for the Company was $114.3 million (2001—$152.6 million; 2000—$141.7 million). Cash paid for interest expense in 2002 for PRG was $103.9 million (2001—$133.9 million; 2000—$122.7 million)

As a result of the early extinguishment of debt in 2002, as noted above, the Company recorded a loss on extinguishment of long-term debt of $19.5 million in 2002. The loss included premiums associated with the early repayment of long-term debt of $9.4 million, a write-off of unamortized deferred financing costs of $9.5 million, and the write-off of a prepaid premium for an insurance policy guaranteeing Sabine’s long-term debt obligations of $0.6 million. PRG recorded a loss of $9.3 million related to the early redemption of long-term debt, of which $0.9 million related to premiums, $7.8 million related to the write-off of unamortized deferred financing costs, and $0.6 million related to the write-off of a prepaid premium for an insurance policy guaranteeing Sabine’s long-term debt obligations.

In 2001, the Company repurchased in the open market $21.3 million in face value of its 9½% Senior Notes, $30.6 million in face value of its 10⁷/8% Senior Notes, and $5.9 million in face value of its 11½% Exchangeable Preferred Stock for an aggregate price of $48.5 million. As a result of these transactions, the Company recorded a gain of $8.7 million (PRG—$0.8 million), which included the write-off of deferred financing costs related to the notes.

The Company leases refinery equipment, crude oil tankers, 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, 2002, net future minimum lease payments under non-cancelable operating leases were as follows (in millions): 2003—$34.8; 2004—$30.3; 2005—$30.0; 2006—$29.1; 2007—$27.5; 2008 and thereafter—$75.7. Rental expense during 2002 was $31.5 million (2001—$26.8 million; 2000—$9.9 million).

The following related party transactions are not discussed elsewhere in the footnotes. See Note 16, Income Taxes for a discussion of intercompany transactions and balances related to a tax sharing agreement between Premcor Inc. and certain of its subsidiaries.

The Company had an agreement with an affiliate of one of Premcor Inc.’s major shareholders, Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates (“Blackstone”), under which it incurred a monitoring fee equal to $2.0 million per annum subject to increases relating to inflation. The Company recorded expenses related to the annual monitoring fee and the reimbursement of out-of-pocket costs of $0.3 million, $2.5 million and $2.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. As of December 31, 2001, the Company had a payable to the affiliate of Blackstone of $0.3 million.

As of December 31, 2002, PRG had a payable to Premcor Inc. for management fees paid by Premcor Inc. on PRG’s behalf of $8.3 million (December 31, 2001—$8.8 million). As of December 31, 2002, PRG also had a loan receivable from Premcor Inc. for $8.1 million (December 31, 2001—$7.2 million) which included both principal

and interest. PRG’s subsidiary, Premcor Investments Inc., loaned these proceeds to Premcor Inc. to allow Premcor Inc. to pay certain fees. The loan bears interest at 12% per annum.

In 2002, PRG received capital contributions from Premcor USA totaling $278.3 million, which included cash contributions of $248.1 million, which were used primarily for the early repayment of long-term debt, and a non-cash contribution of the 10% equity interest in Sabine that Premcor Inc. acquired from Occidental. In 2001 and 2000, PRG returned capital to Premcor USA of $25.8 million and $35.5 million, respectively. The capital returned in 2001 included $25.0 million that was used by Premcor USA to repurchase a portion of its long-term debt and exchangeable preferred stock. The remaining $0.8 million in 2001 and $35.5 million in 2000 were returned to Premcor USA to permit it to pay interest obligations.

The Company has an agreement with Fuel Strategies International (“FSI”) with an initial term from June 2002 to May 2003. The principal of FSI is the brother of the Company’s chairman and chief executive officer. For the year ended December 31, 2002, the Company incurred fees of $0.2 million related to this agreement. The agreement will automatically renew for additional one-year periods unless terminated by either party upon 90 days notice prior to expiration.

The Company has two qualified non-contributory cash balance defined benefit pension plans which were adopted in 2002 and cover most full-time employees. Neither of the two plans provided benefits for years prior to 2002. The Company also has a non-qualified cash balance defined benefit restoration plan, which provides benefits in excess of government limits placed on a qualified defined benefit plan. The two qualified plans are funded and contributions will meet or exceed the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) minimum funding requirements. The cash balance defined benefit restoration plan is not funded. The Company also sponsors post-retirement health care and life insurance benefit plans, which are not funded and cover most retired employees. The health care benefits are contributory. The life insurance benefits are non-contributory to a base amount and contributory for coverage over that base.

The tables which follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the year ended December 31, 2002 and also for the year ended December 31, 2001 for other postretirement benefits. Since the defined benefit pension plans were adopted in 2002, information for 2001 is not applicable.

The components of net periodic benefit costs were as follows for the years ended December 31:

In measuring the expected postretirement benefit obligation and expense, the Company assumed a rate of 12% in 2002, declining by 1% per year to an ultimate rate of 5% for the increase in the per capita cost of covered health care benefits. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

The Premcor Refining Group Retirement Savings Plan and separate Trust (the “Plan”), a defined contribution plan, covers substantially all employees of the Company. This Plan, which is subject to the provisions of ERISA, permits employees to make before-tax and after-tax contributions and provides for employer incentive matching contributions. The Company contributions to the Plan during 2002 were $8.3 million (2001—$8.4 million; 2000—$8.7 million).

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:

The following represents the approximate tax effect of each significant temporary difference giving rise to deferred tax liabilities and assets:

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:

The following represents the approximate tax effect of each significant temporary difference giving rise to deferred tax liabilities and assets:

As of December 31, 2002, the Company has made net cumulative payments of $24.8 million (PRG—$23.2 million) under the federal alternative minimum tax system which are available to reduce future regular income tax payments. As of December 31, 2002, the Company had a federal net operating loss carryforward of $478.5 million (PRG—$372.1 million). As of December 31, 2002, the Company and PRG each had federal business tax credit carryforwards in the amount of $8.3 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, 2022. 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, 2011.

The valuation allowance of the Company and PRG as of December 31, 2002 was $2.8 million (2001—nil). The increase of the deferred tax valuation allowance in 2002 is primarily the result of the Company’s and PRG’s respective analyses of the likelihood of realizing the future benefit of a portion of its federal business credits and a portion of its state tax loss carryforwards. As of December 31, 2000, the Company and PRG each 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 and PRG each reversed its remaining deferred tax valuation allowance. In calculating the reversal of their respective deferred tax valuation allowances in 2001, the Company and PRG each 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 their respective remaining deferred tax valuation allowances in 2001 was primarily the result of the Company’s and PRG’s respective analyses of the likelihood of realizing the future tax benefit of their respective federal and state tax loss carryforwards, alternative minimum tax credits and federal and state business tax credits.

During 2002, the Company received net federal cash refunds of $12.6 million (2001—$11.9 million net federal cash payments; 2000—$3.5 million net federal cash refunds). During 2002, PRG received net federal cash refunds of $12.6 million (2001—$14.5 million net federal cash payments; 2000—$0.6 million net federal

cash refunds). PRG provides for its portion of consolidated refunds and liability under its tax sharing agreement with Premcor Inc. As of December 31, 2002, PRG had an amount due to Premcor Inc. of $12.7 million and an amount due to Premcor USA of $11.8 million related to income taxes. During 2002, PRG made net state cash payments of $0.3 million (2001—$1.7 million; 2000—$1.8 million).

The Company’s income tax benefit of $81.3 million (PRG—$73.3 million) for 2002 reflected the effect of the increase in the deferred tax valuation allowance of $2.8 million (PRG—$2.8 million) The Company’s income tax provision of $52.4 million (PRG—$73.0 million) for 2001 reflected the effect of the decrease in the deferred tax valuation allowance of $30.0 million (PRG—$12.4 million). The income tax benefit of $25.8 million (PRG—$2.2 million) for 2000 reflected the effect of the decrease in the deferred tax valuation allowance of $50.8 million (PRG—$33.9 million).

Premcor Inc. had one class of outstanding common stock as of December 31, 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 sales of 850,000 shares in the aggregate to Mr. Thomas D. O’Malley and two independent directors of the Company, netted proceeds to Premcor Inc. of approximately $481.4 million. The proceeds from the offering were committed to retire debt of Premcor Inc.’s subsidiaries. In conjunction with the initial public offering of common stock, Premcor Inc. converted its previously outstanding Class F Common Stock of 6,101,010 shares to common stock on a one-for-one basis. The Class F Common Stock had voting rights limited to 19.9% of the total voting power of all of Premcor Inc.’s voting stock and was held solely by Occidental.

Also in 2002, Blackstone exercised all of its outstanding warrants purchasing 2,430,000 shares of Premcor Inc. common stock at a price of $0.01 per share. Occidental exercised its warrants purchasing 30,000 shares of Sabine common stock at a price of $0.09 per share. Upon exercise of these warrants, Occidental exercised its option to exchange each warrant share for nine shares of Premcor Inc.’s common stock, totaling 270,000 new shares of Premcor Inc. There were no warrants outstanding as of December 31, 2002. As described in the Sabine restructuring, Premcor Inc. exchanged 1,363,636 newly issued shares of its common stock with Occidental for the 10% ownership Occidental held in Sabine.

In 2000, Blackstone and Occidental contributed $57.3 million and $6.5 million based on capital contribution agreements related to the financing of the heavy oil upgrade project. As of December 31, 2001, Blackstone and Occidental had contributed $109.6 million and $12.2 million, respectively, related to these capital contribution agreements. Blackstone’s contributions under these agreements were made to Premcor Inc. and subsequently Premcor Inc. contributed the funds to Sabine. The shares of common stock were issued to Blackstone at $9.90 per share. Occidental’s contributions under these capital contribution agreements were made directly to Sabine and reflected in minority interest.

As of December 31, 2002, the Company had three stock-based employee compensation plans. In connection with the employment of Thomas D. O’Malley in 2002, the Company adopted the 2002 Special Stock Incentive Plan, which 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. Options granted under this plan vest ¹/3 on each of the first three anniversaries of the date of grant. Also in 2002, the Company adopted the 2002 Equity Incentive Plan 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 this plan, options for 1,500,000 shares of Premcor Inc. common stock may be awarded and these options vest ¹/3 on each of the first three anniversaries of the date of grant.

In 1999, the Company adopted the Premcor 1999 Stock Incentive Plan. Under this plan, employees are eligible to receive awards of options to purchase shares of the common stock of Premcor Inc. Options in an aggregate amount of 2,215,250 shares of Premcor Inc.’s common stock may be awarded under this plan. Options granted under this plan were either time vesting or performance vesting options. Time vesting options typically vest over three to five years. As of December 31, 2002, 50% of the outstanding performance vesting options vested based on the Company’s stock price following the initial public offering of common stock.

Information regarding stock option plans as of December 31, 2002, 2001 and 2000 is as follows:

Information regarding stock options granted during 2002, 2001, and 2000 is as follows:

Information regarding stock options outstanding as of December 31, 2002 is as follows:

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:

Presented below are the PRG consolidating balance sheets, statement of operations, and cash flows as required by Rule 3-10 of the Securities Exchange Act of 1934, as amended. Under Rule 3-10, the consolidating balance sheets, statement of operations, and cash flows presented below meet the requirements for financial statements of the issuer and each guarantor of the 12½% Senior Notes since the issuer and guarantors are all direct or indirect subsidiaries of PRG as well as full and unconditional guarantors.

In addition to the relationships related to the 12½% Senior Notes, there are several intercompany agreements between PACC (included in Other Guarantor Subsidiaries) and PRG that dictate their operational relationships due to the full integration of their respective Port Arthur facilities. Principally, PACC leases the crude unit and the hydrotreater from PRG and then sells to PRG the refined products and intermediate products produced by its heavy oil processing facility. PRG then sells these products to third parties. The net receivables and payables related to these transactions are shown by each company and eliminated in consolidation of PRG.

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 year ended December 31, 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.

Port Arthur: Enforcement. The Texas Commission on Environmental Quality (“TCEQ” formerly the TNRCC) 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 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 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.

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 the Company’s 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 it 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 Michigan Department of Natural Resources rejected the offer 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 appealed the decision. The appellate court rendered its decision on January 10, 2003 and affirmed the trial court’s ruling in all respects. The Michigan Department of Natural Resources

elected not to file an appeal with the Michigan Supreme Court. As a result, the judgment became final. The Michigan Department of Natural Resources will owe the Company mediation sanctions, which should net approximately $100,000 to the Company.

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 $11.9 million (December 31, 2001—$11.4 million) for the Port Arthur remediation as of December 31, 2002. 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 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.

Hartford Refinery Closure. In September 2002, the Company ceased refining operations at its Hartford refinery. In the fourth quarter of 2002, the Company completed the removal of hydrocarbons, catalyst and chemicals from the refinery processing units. The Company is also currently in preliminary discussions with state governmental agencies concerning environmental remediation of the site. Related to the closure of the refinery, the Company has accrued $47.4 million for decommissioning, remediation of the site and asbestos abatement. As of December 31, 2002, the Company spent $17.4 million related primarily to the decommissioning of the facility and had a remaining reserve balance of $30.0 million The accrual of $47.4 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 only 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 the Company has 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 the discussions with the governmental agencies will have a significant bearing on any necessary adjustments to this accrual.

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 $54.4 million for decommissioning, remediation of the site and asbestos abatement. As of December 31, 2002, the Company had spent $34.7 million and had a remaining reserve balance of $19.7 million. 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.

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 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 8 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 of any property at which such a letter was received but subsequently revoked. The Company is currently involved in the active remediation of 140 of the retail sites sold in open market and auction sales and is actively seeking to sell the remaining 8 properties. During the period from the beginning of 1999 through 2002, the Company had expended $20 million to satisfy all the environmental cleanup obligations of our former retail marketing business and as of December 31, 2002, had $23.0 million (December 31, 2001—$26.6 million) accrued, net of reimbursements of $8.6 million (December 31, 2001—$12.2 million), to satisfy those obligations in the future.

In relation to the 1999 sale, PRG assigned approximately 170 leases and subleases of retail stores to the purchaser of the retail division, CRE. PRG remains jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes representing future payments as of December 31, 2002 currently estimated as follows (in millions): 2003—$11.0, 2004—$11.3, 2005—$11.7, 2006—$12.0, 2007—$12.4, and in the aggregate thereafter—$90.8. PRG also remains contingently liable for environmental cleanup responsibilities for releases of petroleum occurring during the term of the CRE leases. The potential costs, if any, of environmental remediation related to these leases cannot be determined at this time. Should any of these leases revert to PRG, PRG will attempt to reduce the potential liability by subletting or reassigning 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, PRG may become responsible for these obligations. Subsequent to December 31, 2002, CRE rejected 25 leases in bankruptcy hearings held in late January 2003 and February 2003. See Note 22, Subsequent Events.

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, 2002, the Company had expended $0.9 million on these obligations and has accrued $2.5 million (December 31, 2001—$2.9 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, 2002, the Company had accrued a total of approximately $93 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 December 31, 2002, this accrual included approximately $72 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.

The Company expects to incur in the aggregate approximately $727 million in order to comply with environmental regulations related to the new stringent sulfur content specifications and MACT II regulations as discussed below.

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. The Company currently expects to produce gasoline under the new sulfur standards at the Port Arthur refinery prior to January 1, 2004. As a result of the corporate pool averaging provisions of the regulations, the Company believes that it will be able to defer a significant portion of the investment required for compliance for one or both of the Lima and Memphis refineries until the end of 2005. In addition, delay in the requirement to meet the new sulfur standards at the Lima and Memphis refinery through 2005 may also 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 the averaging provisions of the regulations will allow for a deferral of compliance at one or both of the Lima and Memphis refineries or that sufficient allotments or credits to defer investment at our Lima and Memphis refinery will be available, or if available, that they will be cost effective. The Company believes, based on current estimates and on a January 1, 2004 compliance date for all three refineries, that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2004 of approximately $335 million, of which $53 million had been incurred as of December 31, 2002. The Company has entered into contracts totaling $126 million related to the design and construction activity at the Port Arthur and Lima refineries for the Tier 2 gasoline compliance.

compliance by January 1, 2010. The Company estimates that capital expenditures required to comply with the on-road diesel standards at all three refineries in the aggregate through 2006 is approximately $347 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 half of 2005.

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., an affiliate of Petroleos Mexicanos (“PEMEX”), the Mexican state oil company, which supplies approximately 162,000 barrels per day of Maya crude oil. Under the terms of this agreement, PACC is obligated to buy Maya crude oil from the affiliate of PEMEX, and the affiliate of PEMEX 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 December 31, 2002, a cumulative quarterly surplus of $79.6 million (2001—$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 it pays for Maya crude oil in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls.

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%. 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.

The Company’s results of operations by quarter for the years ended December 31, 2002 and 2001 were as follows (in millions, except per share amounts):

Effective March 3, 2003, the Company completed the acquisition of a Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries (“Williams”) at an adjusted purchase price of $310 million plus approximately $145 million for crude and product inventories subject to volumetric and pricing verification. 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. The transfer of certain of these assets remains subject to the Company obtaining certain regulatory approval and third party consents. No portion of the purchase price was held back relative to this delayed ownership transfer. The purchase agreement also provides for contingent participation, or earn-out, payments that could result in additional payments of up to $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. PRG acquired the refinery and related assets utilizing a portion of the proceeds from the issuance of $525 million in senior notes and utilizing capital contributions from Premcor Inc., which were funded from the proceeds from a public and private offering of common stock.

On January 30, 2003, Premcor Inc. completed a public offering of 12.5 million shares of common stock and a private placement of 2.9 million shares of common stock with Blackstone, Occidental, and certain Premcor executives. On February 5, 2003, Premcor Inc. sold an additional 0.6 million shares of common stock pursuant to the underwriters’ over-allotment option. Premcor Inc. received net proceeds of approximately $306 million from these transactions. On February 11, 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bear interest at 9½% per annum and $175 million, due in 2010, bear interest at 9¼% per annum. Concurrently, PRG amended and restated its credit agreement, which included extending its maturity date to February 2006; increasing the capacity under the agreement to the lesser of $750 million or the amount available under the defined borrowing base; increasing the sub-limit for cash borrowings to $200 million, subject to certain limitations; and modifying certain covenant requirements.

In addition to the refinery acquisition, the proceeds from these transactions were also used to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures plus a premium thereon of $2.3 million and to repay PRG’s $240 million floating rate loan at par. The Company will recognize a pretax loss in the first quarter of 2003 of approximately $7.0 million ($4.7 million for PRG), in relation to these early repayments and the amendment of the credit facility.

The following pro forma information regarding the Company’s long-term debt gives effect to the February 2003 Senior Notes offering and the subsequent use of proceeds to retire the Premcor USA 11½% Subordinated Debentures and the PRG Floating Rate Loans, as if each had happened on December 31, 2002:

The aggregate stated maturities of long-term debt for the Company based on the effects of the above transactions are (in millions): 2003—$15.0; 2004—$25.8; 2005—$38.5; 2006—$46.4; 2007—$318.4; 2008 and thereafter—$726.9.

Subsequent to December 31, 2002, CRE rejected 25 of these leases in connection with bankruptcy hearings held in late January and February 2003. The Company will record an after-tax charge of approximately $3.5 million in the first quarter of 2003 representing the estimated net present value of the remaining liability under these leases, net of estimated sub-lease income. The Company is currently in discussions with CRE regarding their reorganization plans, the status of environmental remediation agreements, and other matters. While it is possible that the Company may incur additional liability for CRE lease obligations or other costs as CRE finalizes its reorganization plans, the amounts are not estimable at this time.

We have audited the consolidated financial statements of Premcor Inc. as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002 and have issued our report thereon dated February 14, 2003 (included elsewhere in this Annual Report on Form 10-K). Our audits also included the financial statement schedule listed in Item 14. 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.

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. As of December 31, 2002, Premcor Inc.’s non-consolidated operations include 100% equity interest in Premcor USA Inc., 100% equity interest in Opus Energy Risk Limited, and a 5% interest in Clark Retail Enterprises. As of December 31, 2001, Premcor Inc.’s non-consolidated operations include 100% equity interest in Premcor USA Inc., 90% interest in Sabine River 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 Annual Report on Form 10-K.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


By:		/S/ DENNIS R. EICHHOLZ
		Dennis R. Eichholz
		Senior Vice President—Finance and
		Controller (principal accounting officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 12, 2003

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

/S/ THOMAS D. O’MALLEY

Chief Executive Officer

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

/S/ WILLIAM E. HANTKE

Chief Financial Officer

I, Thomas D. O’Malley, Chief Executive Officer of Premcor Inc. (the “Company”), pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, do hereby certify as follows with respect to the Company:

1. The annual report on Form 10-K of the Company for the period ended December 31, 2002, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, I have executed this Certification on this 12th day of March, 2003.


By:		/S/ THOMAS D. O’MALLEY
		Chief Executive Officer

I, William E. Hantke, Chief Financial Officer of Premcor Inc. (the “Company”), pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, do hereby certify as follows with respect to the Company:

1. The annual report on Form 10-K of the Company for the period ended December 31, 2002, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, I have executed this Certification on this 12th day of March, 2003.


By:		/S/ WILLIAM E. HANTKE
		Chief Financial Officer


By:		/S/ DENNIS R. EICHHOLZ
		Dennis R. Eichholz
		Senior Vice President—Finance and
		Controller (principal accounting officer)

1. I have reviewed this annual report on Form 10-K of The Premcor Refining Group Inc.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

1. I have reviewed this annual report on Form 10-K of The Premcor Refining Group Inc.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

I, Thomas D. O’Malley, Chief Executive Officer of The Premcor Refining Group Inc. (the “Company”), pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, do hereby certify as follows with respect to the Company:

1. The annual report on Form 10-K of the Company for the period ended December 31, 2002, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, I have executed this Certification on this 12th day of March, 2003.


By:		/S/ THOMAS D. O’MALLEY
		Chief Executive Officer

I, William E. Hantke, Chief Financial Officer of The Premcor Refining Group Inc. (the “Company”), pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, do hereby certify as follows with respect to the Company:

1. The annual report on Form 10-K of the Company for the period ended December 31, 2002, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, I have executed this Certification on this 12th day of March, 2003.


By:		/S/ WILLIAM E. HANTKE
		Chief Financial Officer

Commission File Number	Exact Name of Registrant as Specified in its Charter, Principal Office Address and Telephone Number	State of Incorporation	I.R.S. Employer Identification No.

1-16827	Premcor Inc. 1700 East Putnam Avenue, Suite 500 Old Greenwich, Connecticut 06870 (203) 698-7500	Delaware	43-1851087

1-11392	The Premcor Refining Group Inc. 1700 East Putnam Avenue, Suite 500 Old Greenwich, Connecticut 06870 (203) 698-7500	Delaware	43-1491230

Title of Each Class		Name of Each Exchange on which Registered
Premcor Inc. Common Stock, $0.01 par value		New York Stock Exchange

Premcor Inc.		Yes þ		No ¨
The Premcor Refining Group Inc.		Yes þ		No ¨

		Page
PART I
Items 1 and 2.	Business and Properties	2
Item 3.	Legal Proceedings	24
Item 4.	Submission of Matters to a Vote of Security Holders	26

PART II
Item 5.	Market for the Registrant’s Common Stock and Related Shareholder Matters	27
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 8.	Financial Statements and Supplementary Data	58
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58

PART III
Item 10.	Directors and Executive Officers of the Registrant	59
Item 11.	Executive Compensation	59
Item 12.	Security Ownership of Certain Beneficial Owners and Management	59
Item 13.	Certain Relationships and Related Transactions	59
Item 14.	Controls and Procedures	59

PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	60
	Index to Financial Statements	F-1

	For the Year Ended December 31,
	2002			2001			2000
	bpd (thousands)	Percent of Total		bpd (thousands)	Percent of Total		bpd (thousands)	Percent of Total
Feedstocks
Crude oil throughput:
Sweet crude oil	—	—	%	—	—	%	3.6	1.7	%
Medium and light sour crude oil	34.3	14.7		48.3	20.0		155.1	74.9
Heavy sour crude oil	190.4	81.6		181.5	75.2		43.4	21.0

Total crude oil	224.7	96.3		229.8	95.2		202.1	97.6
Unfinished and blendstocks	8.7	3.7		11.4	4.8		5.0	2.4

Total feedstocks	233.4	100.0	%	241.2	100.0	%	207.1	100.0	%

Production
Light Products:
Conventional gasoline	82.4	32.9	%	82.9	32.7	%	73.4	34.9	%
Premium and reformulated gasoline	23.0	9.2		24.4	9.6		18.1	8.6
Diesel fuel	65.4	26.1		77.2	30.4		58.0	27.5
Jet fuel	26.5	10.5		19.7	7.8		16.6	7.9
Petrochemical feedstocks	17.8	7.1		18.3	7.2		23.7	11.3

Total light products	215.1	85.8		222.5	87.7		189.8	90.2
Petroleum coke and sulfur	28.7	11.5		26.5	10.4		11.3	5.3
Residual oil	6.8	2.7		4.8	1.9		9.5	4.5

Total production	250.6	100.0	%	253.8	100.0	%	210.6	100.0	%

	Port Arthur, Texas		Lima, Ohio		Memphis, Tennessee		Combined
Crude distillation capacity (bpd)	250,000		170,000		190,000		610,000
Crude slate capability:
Heavy sour	80	%	—	%	—	%	33	%
Medium and light sour	20		10		—		11
Sweet	—		90		100		56

Total	100	%	100	%	100	%	100	%


Production For the Year Ended December 31, 2002 (1)
Light products:
Conventional gasoline	32.9	%	53.0	%	38.0	%	39.4	%
Premium and reformulated gasoline	9.2		8.3		7.0		8.3
Diesel fuel	26.1		13.9		34.0		25.5
Jet fuel	10.5		16.0		15.0		13.3
Petrochemical feedstocks	7.1		5.4		4.0		5.7

Subtotal light products	85.8		96.6		98.0		92.2
Petroleum coke and sulfur	11.5		2.0		—		5.6
Residual oil	2.7		1.4		2.0		2.2

Total production	100.0	%	100.0	%	100.0	%	100.0	%

Sources of Crude Oil Supply
	bpd (thousands)	Percent of Total
Latin America
Mexico	187.7	44.6	%
Rest of Latin America	22.8	5.4
United States	124.2	29.5
Middle East	31.4	7.5
North Sea	24.4	5.8
Russia	14.4	3.4
Africa	13.5	3.2
Canada	2.4	0.6

Total	420.8	100.0	%

Name	Age	Position
Thomas D. O’Malley	61	Chairman of the Board and Chief Executive Officer
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	38	Senior Vice President—Corporate Development
Gregory R. Bram	38	Refinery Manager—Memphis Refinery and Acting Refinery Manager—Lima Refinery
Donovan J. Kuenzli	63	Refinery Manager—Port Arthur Refinery

	Sales Price
Quarter ended	High		Low
2002:
June 30	$	28.25	$	24.52
September 30	$	24.95	$	15.65
December 31	$	22.93	$	13.40

	Year Ended December 31,
	2002			2001			2000			1999			1998
	(in millions, except as noted)
Statement of earnings data:
Net sales and operating revenues	$	6,772.8		$	6,417.5		$	7,301.7		$	4,520.5		$	3,581.7
Cost of sales		6,101.8			5,251.4			6,562.5			4,099.8			3,113.2

Gross margin		671.0			1,166.1			739.2			420.7			468.5
Operating expenses		432.2			467.7			467.7			402.8			342.8
General and administrative expenses		51.8			63.3			53.0			51.5			51.2
Stock-based compensation		14.0			—			—			—			—
Depreciation and amortization (1)		88.9			91.9			71.8			63.1			54.5
Refinery restructuring and other charges		172.9			176.2			—			—			—
Inventory write-down (recovery) to market value		—			—			—			(105.8	)		86.6
Gain on sale of pipeline interest		—			—			—			—			(69.3	)

Operating income (loss)		(88.8	)		367.0			146.7			9.1			2.7
Interest expense and finance income, net (2)		(101.8	)		(139.5	)		(82.2	)		(91.5	)		(70.5	)
Gain (loss) on extinguishment of long-term debt (3)		(19.5	)		8.7			—			—			—
Income tax (provision) benefit		81.3			(52.4	)		25.8			12.0			25.0
Minority interest in subsidiary		1.7			(12.8	)		(0.6	)		1.4			—

Income (loss) from continuing operations		(127.1	)		171.0			89.7			(69.0	)		(42.8	)
Discontinued operations, net of taxes (4)		—			(18.0	)		—			32.6			13.1

Net income (loss)		(127.1	)		153.0			89.7			(36.4	)		(29.7	)
Preferred stock dividends		(2.5	)		(10.4	)		(9.6	)		(8.6	)		(7.6	)

Net income (loss) available to common stockholders	$	(129.6	)	$	142.6		$	80.1		$	(45.0	)	$	(37.3	)

Net income (loss) from continuing operations per share:
—basic	$	(2.65	)	$	5.05		$	2.79		$	(3.59	)	$	(2.54	)
—diluted		(2.65	)		4.65			2.55			(3.59	)		(2.54	)
Weighted average number of common shares outstanding:
—basic		49.0			31.8			28.8			21.6			19.9
—diluted		49.0			34.5			31.5			21.6			19.9
PRG:
Net sales and operating revenues	$	6,772.6		$	6,417.5		$	7,301.7		$	4,520.3		$	3,580.5
Income (loss) from continuing operations		(114.4	)		158.9			83.8			(47.0	)		(36.0	)
Cash flow data:
Cash flows from operating activities	$	15.9		$	439.2		$	124.4		$	85.5		$	(61.0	)
Cash flows from investing activities		(144.5	)		(152.9	)		(375.3	)		(321.3	)		(230.7	)
Cash flows from financing activities		(214.1	)		(66.3	)		234.8			393.9			205.5
Capital expenditures for property, plant and equipment		114.3			94.5			390.7			438.2			101.4
Capital expenditures for turnarounds		34.3			49.2			31.5			77.9			28.3
Refinery acquisition expenditures		—			—			—			—			175.0
Key operating statistics:
Production (barrels per day in thousands)		438.2			463.4			477.3			460.5			403.8
Crude oil throughput (barrels per day in thousands)		412.8			439.7			468.0			451.7			400.9
Per barrel of crude oil throughput:
Gross margin	$	4.45		$	7.27		$	4.32		$	2.55		$	3.20
Operating expenses		2.87			2.91			2.73			2.44			2.34

	As of December 31,
	2002		2001		2000		1999		1998
	(in millions)
Balance sheet data:
Premcor Inc.:
Cash, cash equivalents and short-term investments (5)	$	234.0	$	542.6	$	291.8	$	307.6	$	152.6
Working capital		320.9		482.6		325.0		305.8		382.6
Total assets		2,323.0		2,509.8		2,469.1		1,984.1		1,450.3
Long-term debt		924.9		1,472.8		1,516.0		1,340.4		983.4
Exchangeable preferred stock		—		94.8		90.6		81.1		72.5
Stockholders’ equity		704.0		294.7		152.1		14.7		2.2
PRG:
Cash, cash equivalents and short-term investments (5)	$	183.1	$	515.0	$	252.9	$	286.4	$	152.0
Working capital		243.2		429.2		261.1		267.0		361.8
Total assets		2,246.3		2,477.9		2,414.0		1,960.4		1,447.0
Long-term debt		884.8		1,328.4		1,341.0		1,165.4		808.4
Stockholder’s equity		627.8		443.8		328.7		222.3		225.0

	Initial Reserve		Adjustment to Reserve			Net Cash Outlay		Reserve as of December 31, 2002
Employee severance	$	16.6	$	(3.4	)	$	12.6	$	0.6
Plant closure/equipment remediation		12.9		4.6			17.1		0.4
Site clean-up/environmental matters		33.0		(3.1	)		0.3		29.6

	$	62.5	$	(1.9	)	$	30.0	$	30.6

	Reserve as of December 31, 2001		Adjustment to Reserve			Net Cash Outlay		Reserve as of December 31, 2002
Employee severance	$	2.1	$	—		$	2.1	$	—
Plant closure/equipment remediation		13.9		(5.2	)		8.7		—
Site clean-up/environmental matters		20.5		3.2			4.0		19.7

	$	36.5	$	(2.0	)	$	14.8	$	19.7

	Year Ended December 31,
Financial Results	2002			2001			2000
	(in millions, except per share data)
Net sales and operating revenues	$	6,772.8		$	6,417.5		$	7,301.7
Cost of sales		6,101.8			5,251.4			6,562.5

Gross margin		671.0			1,166.1			739.2
Operating expenses		432.2			467.7			467.7
General and administrative expenses		51.8			63.3			53.0
Stock-based compensation		14.0			—			—
Depreciation & amortization		88.9			91.9			71.8
Refinery restructuring and other charges		172.9			176.2			—

Operating income (loss)		(88.8	)		367.0			146.7
Interest expense and finance income, net		(101.8	)		(139.5	)		(82.2	)
Gain (loss) on extinguishment of long-term debt		(19.5	)		8.7			—
Income tax (provision) benefit		81.3			(52.4	)		25.8
Minority interest		1.7			(12.8	)		(0.6	)

Net income (loss) from continuing operations		(127.1	)		171.0			89.7
Discontinued operations		—			(18.0	)		—

Net income (loss)		(127.1	)		153.0			89.7
Preferred stock dividends		(2.5	)		(10.4	)		(9.6	)

Net income (loss) available to common stockholders	$	(129.6	)	$	142.6		$	80.1

Diluted net income (loss) available to common stockholders per share	$	(2.65	)	$	4.13		$	2.55
Diluted weighted average common shares outstanding		49.0			34.5			31.5

	Year Ended December 31,
Market Indicators	2002			2001			2000
	(dollars per barrel, except as noted)
West Texas Intermediate (WTI) crude oil	$	26.13		$	25.96		$	30.37
Crack Spreads
Gulf Coast 2/1/1		2.72			3.92			4.02
Chicago 3/2/1		5.00			7.90			5.84
Crude Oil Differentials:
WTI less Maya (heavy sour)		5.21			8.76			7.29
WTI less WTS (sour)		1.38			2.81			2.17
WTI less Dated Brent (foreign)		1.12			1.48			1.92
Natural gas (dollars per million btu)		3.17			4.22			3.94

	Year Ended December 31,
Selected Operational Data	2002			2001			2000
	(in thousands of barrels per day, except as noted)
Crude oil throughput by refinery:
Port Arthur		224.7			229.8			202.1
Lima		141.5			140.5			136.4
Hartford		46.6			65.5			64.2
Blue Island		—			3.9			65.3

Total crude oil throughput		412.8			439.7			468.0
Per barrel of crude oil throughput (in dollars):
Gross margin	$	4.45		$	7.27		$	4.32
Operating expenses		2.87			2.91			2.73

Exhibit Number		Description
3.01		Amended and Restated Certificate of Incorporation of Premcor Inc. (Incorporated by reference to Exhibit 3.1 filed with Premcor Inc.’s Registration Statement on Form S-1/A (Registration No. 333-70314)).

3.02		Amended and Restated By-Laws of Premcor Inc. (Incorporated by reference to Exhibit 3.2 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

3.03		Restated Certificate of Incorporation of The Premcor Refining Group Inc. (“PRG”) (f/k/a ClarkRefining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of February 1, 1993 (Incorporated by reference to Exhibit 3.1 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.04		Certificate of Amendment to Certificate of Incorporation of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of September 30, 1993 (Incorporated by reference to Exhibit 3.2 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.05		Certificate of Amendment of Restated Certificate of Incorporation of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of May 9, 2000 (Incorporated by reference to Exhibit 3.3 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.06		By-laws of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) (Incorporated by reference to Exhibit 3.2 filed with PRG’s Registration Statement on Form S-1 (Registration No. 33-28146)).

4.01		Second Amended and Restated Stockholders’ Agreement, dated as of November 3, 1997, between Premcor USA Inc. (f/k/a Clark USA, Inc.) and Occidental C.O.B. Partners (Incorporated by reference to Exhibit 4.19 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.02		Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Bankers Trust Company, as Trustee, including the form of 8³/8% Senior Notes due 2007 (Incorporated by reference to Exhibit 4.5 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

4.03		Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Marine Midland Bank, including the form of 8⁷/8% Senior Subordinated Notes due 2007 (Incorporated by reference to Exhibit 4.6 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

4.04		Supplemental Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Marine Midland Bank (Incorporated by reference to Exhibit 6.1 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

Exhibit Number		Description

4.05		Indenture, dated as of August 10, 1998, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Bankers Trust Company, as Trustee, including the form of the 8⁵/8% Senior Notes due 2008 (Incorporated by reference to Exhibit 4.1 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-64387)).

4.06		Stockholder Agreement, dated as of March 9, 1999, among Premcor Inc. (f/k/a Clark Refining Holdings Inc.), Blackstone Capital Partners III Merchant Banking Fund L.P and Marshall A. Cohen (Incorporated by reference to Exhibit 4.20 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.07		Stockholders’ Agreement, dated as of August 4, 1999, among Sabine River Holding Corp. (“Sabine”), Premcor Inc. (f/k/a Clark Refining Holdings Inc.), and Occidental Petroleum Corporation (Incorporated by reference to Exhibit 4.18 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.08		Indenture, dated as of August 19, 1999, among Sabine, Neches River Holding Corp. (“Neches”), Port Arthur Finance Corp. (“PAFC”), Port Arthur Coker Company L.P. (“PACC”), HSBC Bank USA, the Capital Markets Trustee, and Bankers Trust Company, as Collateral Trustee (Incorporated by reference to Exhibit 4.01 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

4.09		First Supplemental Indenture, dated as of June 6, 2002, among PRG, Sabine, Neches, PACC, PAFC, Deutsche Bank Trust Company Americas, as Collateral Trustee, and HSBC Bank USA, as Capital Markets Trustee, including the Form of 12½% Senior Secured Notes due 2009 (Incorporated by reference to Exhibit 4.1 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.10		Amended and Restated Common Security Agreement, dated as of June 6, 2002, among Sabine, PRG, PAFC, PACC, Neches, Deutsche Bank Trust Company Americas, as Collateral Trustee and Depositary Bank, and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.2 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.11		Amended and Restated Transfer Restrictions Agreement, dated as of June 6, 2002, among Premcor Inc., Sabine, Neches, PACC, PAFC, Deutsche Bank Trust Company Americas, as Collateral Trustee, and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.4 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.12		Registration Rights Agreement, dated as of April 16, 2002, between Blackstone Capital Partners III Merchant Banking Fund L.P., Blackstone Offshore Capital Partners III L.P., Blackstone Family Investment Partnership III, and Premcor Inc. (Incorporated by reference to Exhibit 4.21 filed with Premcor Inc.’s Registration Statement on Form S-1/A (Registration No. 333-70314)).

4.13		Indenture dated as of February 11, 2003, between PRG and Deutsche Bank Trust Company Americas, as Trustee, including the Form of 9¼% Senior Notes due 2010 and 9½% Senior Notes due 2013 (filed herewith).

10.01		Hydrogen Supply Agreement, dated as of August 1, 1999, between PACC and Air Products and Chemicals, Inc. (Incorporated by Reference to Exhibit 10.10 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

10.02		First Amendment, dated March 1, 2000, to the Hydrogen Supply Agreement, dated as of August 1, 1999, between PACC and Air Products and Chemicals, Inc. (Incorporated by reference to Exhibit 10.1 filed with Sabine River’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 333-92871)).

Exhibit Number		Description

10.03		Second Amendment, dated June 1, 2001, to the Hydrogen Supply Agreement, dated as of August 1, 1999, between PACC and Air Products and Chemicals, Inc. (Incorporated by reference to Exhibit 10.2 filed with Sabine River’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 333-92871)).

10.04		Assignment and Assumption Agreement, dated as of August 19, 1999, between PACC and PRG (f/k/a Clark Refining & Marketing, Inc.) (Incorporated by Reference to Exhibit 10.13 filed with Sabine River’s Registration Statement on Form S-4 (Registration No. 333-92871)).

10.05		Maya Crude Oil Sale Agreement, dated as of March 10, 1998, between PRG (f/k/a Clark Refining & Marketing, Inc.) and P.M.I. Comercio Internacional, S.A. de C.V., as amended by the First Amendment and Supplement to the Maya Crued Oil Sales Agreement, dated as of August 19, 1999 (included as Exhibit 10.06 hereto), and as assigned by PRG to PACC pursuant to the Assignment and Assumption Agreement, dated as of August 19, 1999 (included as Exhibit 10.04 hereto) (Incorporated by Reference to Exhibit 10.14 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

10.06		First Amendment and Supplement to the Maya Crude Oil Sales Agreement, dated as of August 19, 1999 (Incorporated by Reference to Exhibit 10.15 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

10.07		Guarantee Agreement, dated as of March 10, 1998, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Petroleos Mexicanos, as assigned by PRG to PACC as of August 19, 1999 pursuant to the Assignment and Assumption Agreement, dated as of August 19, 1999 (included as Exhibit 10.04 hereto) (Incorporated by Reference to Exhibit 10.16 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

10.08		Supply and Terminalling Agreement, dated November 8, 1999, by and among PRG, Equiva Trading Company, Equilon Enterprises LLC and Motiva Enterprises LLC. (Incorporated by reference to Exhibit 10.31 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

10.09		Terminal Services Agreement, dated as of January 14, 2000, between PRG and Millennium Terminal Company, L.P. (Incorporated by reference to Exhibit 10.26 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

10.10		Crude Oil Sale and Supply Agreement effective as of September 13, 2002 by and between PRG and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.4 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-11392)).

10.11		Amendment to Crude Oil Sale and Supply Agreement, dated September 13, 2002 by and between PRG and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.5 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-11392)).

10.12		Asset Purchase and Sale Agreement, dated as of November 25, 2002, among Williams Refining & Marketing, L.L.C., Williams Generating Memphis, L.L.C., Williams Memphis Terminal, Inc., Williams Petroleum Pipeline Systems, Inc., Williams Mid-South Pipelines, LLC, as Sellers, The Williams Companies, Inc., as Sellers’ Guarantor, PRG, as Purchaser, and Premcor Inc., as Purchaser’s Guarantor (Incorporated by reference to Exhibit 2.01 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.13		First Amendment to the Asset Purchase and Sale Agreement, dated as of January 16, 2003, among Williams Refining & Marketing, L.L.C., Williams Generating Memphis, L.L.C., Williams Memphis Terminal, Inc., Williams Petroleum Pipeline Systems, Inc., Williams Mid-South Pipelines, LLC, as Sellers, The Williams Companies, Inc., as Sellers’ Guarantor, PRG, as Purchaser, and Premcor Inc., as Purchaser’s Guarantor (filed herewith).

Exhibit Number		Description

10.14		Second Amendment to the Asset Purchase and Sale Agreement, dated as of February 28, 2003, among Williams Refining & Marketing, L.L.C., Williams Generating Memphis, L.L.C., Williams Memphis Terminal, Inc., Williams Petroleum Pipeline Systems, Inc., Williams Mid-South Pipelines, LLC, as Sellers, The Williams Companies, Inc., as Sellers’ Guarantor, PRG, as Purchaser, and Premcor Inc., as Purchaser’s Guarantor (filed herewith).

10.15		Crack Spread Retained Interest Agreement, dated as of November 25, 2002, between Williams Refining & Marketing, L.L.C. and PRG (Incorporated by reference to Exhibit 2.02 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.16		Amended and Restated Credit Agreement, dated as of February 11, 2003, among PRG, Deutsche Bank Securities Inc., as Lead Arranger, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, Fleet National Bank, as Syndication Agent, and the other financial institutions party thereto (filed herewith).

10.17		Form of Change-In-Control, Severance and Retention Agreement between Premcor Inc. and six of its officers and other key employees (other than its executive officers) (Incorporated by reference to Exhibit 10.12 filed with the PRG Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11392)).

10.18		Premcor Inc. Senior Executive Retirement Plan (Incorporated by reference to Exhibit 10.15 filed with the PRG Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 1-11392)).

10.19		Amendment to the Premcor Inc. Senior Executive Retirement Plan dated as of February 28, 2003 (filed herewith).

10.20		Termination Agreement, dated as of January 31, 2002, between Premcor Inc. and William C. Rusnack (Incorporated by reference to Exhibit 10.39 filed with Premcor Inc’s Registration Statement on Form S-1 (Registration No. 333-70314)).

10.21		Termination Agreement, dated as of January 31, 2002, between Premcor Inc. and Ezra C. Hunt (Incorporated by reference to Exhibit 10.40 filed with Premcor Inc’s Registration Statement on Form S-1 (Registration No. 333-70314)).

10.22		Premcor Inc. 2002 Special Stock Incentive Plan (Incorporated by reference to Exhibit 10.20 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11392)).

10.23		Employment Agreement, dated as of January 30, 2002, of Thomas D. O’Malley (Incorporated by reference to Exhibit 10.13 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11392)).

10.24		First Amendment to Employment Agreement, dated March 18, 2002, of Thomas D. O’Malley (Incorporated by reference to Exhibit 10.14 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11392)).

10.25		Letter Agreement, dated November 13, 2002, amending Employment Agreement of Thomas D. O’Malley (Incorporated by reference to Exhibit 10.26 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.26		Amended and Restated Employment Agreement, dated as of June 1, 2002, of William E. Hantke (Incorporated by reference to Exhibit 10.3 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 1-11392)).

10.27		Amended and Restated Employment Agreement, dated as of June 1, 2002, of Henry M. Kuchta (Incorporated by reference to Exhibit 10.4 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 1-11392)).

Exhibit Number		Description

10.28		Amended and Restated Employment Agreement, dated as of June 1, 2002, of Joseph D. Watson (Incorporated by reference to Exhibit 10.6 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 1-11392)).

10.29		Form of Indemnity Agreement ((Incorporated by reference to Exhibit 10.36 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.30		Employment Agreement, dated as of September 16, 2002, of James R. Voss ((Incorporated by reference to Exhibit 10.37 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.31		Employment Agreement, dated as of October 1, 2002, of Michael D. Gayda ((Incorporated by reference to Exhibit 10.38 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.32		Separation Agreement and General Release, dated as of November 1, 2002, between Premcor Inc. and Jeffry N. Quinn ((Incorporated by reference to Exhibit 10.39 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.33		Form of Letter Agreement, dated as of October 28, 2002, amending Employment Agreements of James R. Voss and Michael D. Gayda and Amended and Restated Employment Agreements of William E. Hantke, Henry M. Kuchta and Joseph D. Watson ((Incorporated by reference to Exhibit 10.40 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.34		Form of Letter Agreement, dated as of November 13, 2002, amending Employment Agreements of Thomas D. O’Malley, James R. Voss and Michael D. Gayda and Amended and Restated Employment Agreements of William E. Hantke, Henry M. Kuchta and Joseph D. Watson ((Incorporated by reference to Exhibit 10.41 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-99981)).

10.35		Second Amendment to the Premcor Pension Plan, dated as of December 27, 2002 (filed herewith).

10.36		Third Amendment to the Premcor Pension Plan, dated as of February 28, 2003 (filed herewith).

10.37		Third Amendment to the Premcor Retirement Savings Plan, dated December 30, 2002 (filed herewith).

10.38		Fourth Amendment to the Premcor Retirement Savings Plan, dated as of February 28, 2003 (filed herewith).

10.39		Fifth Amendment to the Premcor Retirement Savings Plan, dated as of February 28, 2003 (filed herewith).

10.40		Amended and Restated Letter Agreement, dated as of November 6, 2002, between Premcor Inc. and Wilkes McClave III (filed herewith).

10.41		Amended and Restated Letter Agreement, dated as of November 6, 2002, between Premcor Inc. and Jefferson F. Allen (filed herewith).

18		Preferability letter, dated May 8, 2002, from Deloitte & Touche LLP concerning PACC’s change in method of accounting for crude oil and blendstock inventories from first-in first-out (“FIFO”) to last-in first-out (“LIFO”) (Incorporated by reference to Exhibit 18 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11392))

Exhibit Number		Description

21		Subsidiaries of the Registrant (Incorporated by reference to Exhibit 21 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-102087)).

23		Consent of Deloitte & Touche (filed herewith).

		Page
Financial Statements:
Premcor Inc.:
Independent Auditors’ Report		F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001		F-3
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000		F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001and 2000		F-5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2002, 2001 and 2000		F-6

The Premcor Refining Group Inc.:
Independent Auditors’ Report		F-7
Consolidated Balance Sheets as of December 31, 2002 and 2001 (as restated)		F-8
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 (as restated) and 2000 (as restated)		F-9
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 (as restated) and 2000 (as restated)		F-10
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2002, 2001 (as restated) and 2000 (as restated)		F-11

Notes to Consolidated Financial Statements (Premcor Inc. and The Premcor Refining Group Inc. Combined)		F-12

Financial Statement Schedules:
Schedule I—Condensed Financial Information of Premcor Inc.		F-54
Schedule II—Valuation and Qualifying Accounts		F-59

	December 31,
	2002			2001
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	167.4		$	510.1
Short-term investments		4.9			1.7
Cash and cash equivalents restricted for debt service		61.7			30.8
Accounts receivable, net of allowance of $3.2 and $1.3		269.1			148.3
Inventories		287.3			318.3
Prepaid expenses and other		45.9			52.3
Assets held for sale		49.3			—

Total current assets		885.6			1,061.5
PROPERTY, PLANT AND EQUIPMENT, NET		1,262.6			1,299.6
DEFERRED INCOME TAXES		57.5			—
OTHER ASSETS		117.3			148.7

	$	2,323.0		$	2,509.8


LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	466.2		$	366.4
Accrued expenses and other		57.2			95.4
Accrued taxes other than income		26.3			35.7
Current portion of long-term debt		15.0			81.4

Total current liabilities		564.7			578.9
LONG-TERM DEBT		909.9			1,391.4
DEFERRED INCOME TAXES		—			16.7
OTHER LONG-TERM LIABILITIES		144.4			109.1
COMMITMENTS AND CONTINGENCIES		—			—

MINORITY INTEREST		—			24.2

EXCHANGEABLE PREFERRED STOCK OF SUBSIDIARY ($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, 150,000,000 authorized, 58,043,935 issued and outstanding in 2002 and 53,000,000 authorized, 25,720,589 issued and outstanding in 2001; Class F Common, $0.01 par value, 7,000,000 authorized, 6,101,010 issued and outstanding in 2001		0.6			0.3
Paid-in capital		862.3			323.7
Accumulated deficit		(158.9	)		(29.3	)

Total common stockholders’ equity		704.0			294.7

	$	2,323.0		$	2,509.8

	For the Year Ended December 31,
	2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(127.1	)	$	153.0		$	89.7
Discontinued operations		—			18.0			—
Adjustments:
Depreciation		48.8			53.2			37.1
Amortization		50.6			50.3			45.5
Deferred income taxes		(79.2	)		52.0			(24.2	)
Stock-based compensation		14.0			—			—
Minority interest		(1.7	)		12.8			0.6
Refinery restructuring and other charges		110.3			118.5			—
Write-off of deferred financing costs		9.5			0.6			—
Write-off of equity investment		4.2			—			—
Other, net		6.8			0.9			(0.2	)
Cash provided by (reinvested in) working capital:
Accounts receivable, prepaid expenses and other		(114.4	)		89.1			(54.6	)
Inventories		31.0			60.0			(126.1	)
Accounts payable, accrued expenses, taxes other than income, and other		52.2			(136.5	)		156.6
Cash and cash equivalents restricted for debt service		14.3			(24.3	)		—

Net cash provided by operating activities of continuing operations		19.3			447.6			124.4
Net cash used in operating activities of discontinued operations		(3.4	)		(8.4	)		—

Net cash provided by operating activities		15.9			439.2			124.4

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(114.3	)		(94.5	)		(390.7	)
Expenditures for turnaround		(34.3	)		(49.2	)		(31.5	)
Cash and cash equivalents restricted for investment in capital additions		7.3			(9.9	)		46.6
Proceeds from sale of assets		—			0.7			0.5
Other		(3.2	)		—			(0.2	)

Net cash used in investing activities		(144.5	)		(152.9	)		(375.3	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			10.0			182.6
Long-term debt and capital lease payments		(645.8	)		(59.3	)		(7.3	)
Cash and cash equivalents restricted for debt repayment		(45.2	)		(6.5	)		—
Proceeds from issuance of common stock, net		488.3			—			57.3
Deferred financing costs		(11.4	)		(10.2	)		(4.3	)
Other		—			(0.3	)		6.5

Net cash provided by (used in) financing activities		(214.1	)		(66.3	)		234.8

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(342.7	)		220.0			(16.1	)
CASH AND CASH EQUIVALENTS, beginning of period		510.1			290.1			306.2

CASH AND CASH EQUIVALENTS, end of period	$	167.4		$	510.1		$	290.1

	Common Stock			Class F Common					Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total
	Shares	Par Value		Shares		Par Value			Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Total
BALANCE, December 31, 1999	19,843,889	$	0.2	6,101,010		$	0.1		$	266.4	$	(252.0	)	$	14.7
Net income	—		—	—			—			—		80.1			80.1
Stock issuance	5,876,700		—	—			—			57.3		—			57.3

BALANCE, December 31, 2000	25,720,589		0.2	6,101,010			0.1			323.7		(171.9	)		152.1
Net income	—		—	—			—			—		142.6			142.6

BALANCE, December 31, 2001	25,720,589		0.2	6,101,010			0.1			323.7		(29.3	)		294.7
Stock issuance	21,550,000		0.3	—			—			481.4		—			481.7
Conversion of Class F to common	6,101,010		0.1	(6,101,010	)		(0.1	)		—		—			—
Acquisition of minority interest	1,363,636		—	—			—			30.5		—			30.5
Exercise of stock options, including tax benefits	608,700		—	—			—			7.0		—			7.0
Exercise of stock warrants	2,700,000		—	—			—			—		—			—
Stock-based compensation	—		—	—			—			19.7		—			19.7
Net loss	—		—	—			—			—		(129.6	)		(129.6	)

BALANCE, December 31, 2002	58,043,935	$	0.6	—		$	—		$	862.3	$	(158.9	)	$	704.0

	Number of Common Shares	Common Stock		Paid-in Capital			Retained Earnings			Total
	(as restated for years ended December 31, 2001 and 2000, see Note 2)

BALANCE, December 31, 1999	100	$	—	$	246.2		$	(23.9	)	$	222.3
Stock issuance	—		—		58.1			—			58.1
Capital contribution returned	—		—		(35.5	)		—			(35.5	)
Net income	—		—		—			83.8			83.8

BALANCE, December 31, 2000	100		—		268.8			59.9			328.7
Capital contribution returned	—		—		(25.8	)		—			(25.8	)
Net income	—		—		—			140.9			140.9

BALANCE, December 31, 2001	100		—		243.0			200.8			443.8
Capital contributions, net	—		—		278.3			—			278.3
Stock-based compensation	—		—		19.7			—			19.7
Tax benefit on stock options exercised	—		—		0.4			—			0.4
Net loss	—		—		—			(114.4	)		(114.4	)

BALANCE, December 31, 2002	100	$	—	$	541.4		$	86.4		$	627.8

	Initial Reserve		Adjustment to Reserve			Net Cash Outlay		Reserve as of December 31, 2002
Employee severance	$	16.6	$	(3.4	)	$	12.6	$	0.6
Plant closure/equipment remediation		12.9		4.6			17.1		0.4
Site clean-up/environmental matters		33.0		(3.1	)		0.3		29.6

	$	62.5	$	(1.9	)	$	30.0	$	30.6

	Premcor Inc.						PRG
	December 31,						December 31,
	2002			2001			2002			2001
Real property	$	8.3		$	8.3		$	8.3		$	8.3
Process units, buildings, and oil storage and movement		1,228.4			1,344.3			1,227.0			1,343.0
Office equipment, furniture, and autos		46.4			24.4			46.4			24.4
Construction in progress		146.6			121.8			146.6			121.8
Accumulated depreciation		(167.1	)		(199.2	)		(166.6	)		(198.8	)

	$	1,262.6		$	1,299.6		$	1,261.7		$	1,298.7

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

	Pension Benefits			Other Postretirement Benefits
	2002			2002			2001
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	—		$	61.7		$	42.1
Service costs		6.1			2.1			1.3
Interest costs		—			4.8			3.4
Participants’ contribution		—			0.8			0.7
Plan amendments		—			—			0.7
Curtailment gain		—			(4.0	)		(1.6	)
Actuarial loss		0.3			12.4			17.9
Special termination benefits		—			2.5			—
Benefits paid		(0.4	)		(3.5	)		(2.8	)

Benefit obligation at end of year		6.0			76.8			61.7

CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year		—			—			—
Employer contributions		0.5			2.7			2.1
Participant contributions		—			0.8			0.7
Benefits paid		(0.4	)		(3.5	)		(2.8	)

Fair value of plan assets at end of year		0.1			—			—

RECONCILIATION OF FUNDED STATUS:
Funded status		(5.9	)		(76.8	)		(61.7	)
Unrecognized actuarial loss		0.3			25.0			17.7
Unrecognized prior service cost		—			0.5			0.6

Accrued benefit liability	$	(5.6	)	$	(51.3	)	$	(43.4	)


WEIGHTED AVERAGE ASSUMPTIONS:
Discount rate		6.75	%		6.75	%		7.25	%
Expected return on plan assets		8.50	%		N/A			N/A
Rate of compensation increase		4.00	%		4.00	%		4.00	%

	Pension Benefits		Other Postretirement Benefits
	2002		2002		2001	2000
Service costs	$	5.6	$	2.1	$1.3	$1.3
Interest costs		—		4.8	3.4	2.9
Recognized actuarial loss		—		1.0	—	—

Net periodic benefit cost .	$	5.6	$	7.9	$4.7	$4.2

	1% Increase		1% Decrease
Effect on total service and interest costs	$	1.2	$	(0.8	)
Effect on postretirement benefit obligation	$	12.4	$	(9.9	)

	Options Outstanding				Options Exercisable
Exercise Price	Options Outstanding	Weighted Average Exercise Price		Remaining Contractual Life (in years)	Options Exercisable	Weighted Average Exercise Price
$ 9.90–$12.90	3,213,480	$	9.98	8.4	362,580	$	9.90
$15.00–$15.92	87,500		14.38	6.0	62,500		15.00
$15.93–$18.93	12,500		18.50	9.7	—		—
$18.94–$23.34	960,000		22.44	6.4	—		—
$23.35–$25.00	316,000		24.02	9.3	5,000		24.00

	4,589,480		13.66	8.6	430,080		10.81

	PRG		PAFC		Other Guarantor Subsidiaries		Eliminations			Consolidated PRG
ASSETS	(in millions)

CURRENT ASSETS:
Cash and cash equivalents	$	119.7	$	—	$	—	$	—		$	119.7
Short-term investments		1.7		—		—		—			1.7
Cash and cash equivalents restricted for debt service		—		—		61.7		—			61.7
Accounts receivable		268.7		—		0.3		—			269.0
Receivable from affiliates		32.9		29.2		50.7		(99.7	)		13.1
Inventories		259.7		—		27.6		—			287.3
Prepaid expenses and other		43.7		—		2.0		—			45.7
Assets held for sale		49.3		—		—		—			49.3

Total current assets		775.7		29.2		142.3		(99.7	)		847.5

PROPERTY, PLANT AND EQUIPMENT, NET		651.3		—		610.4		—			1,261.7
DEFERRED INCOME TAXES		67.0		—		—		(47.2	)		19.8
INVESTMENT IN AFFILIATE		330.9		—		—		(330.9	)		—
OTHER ASSETS		101.4		—		15.9		—			117.3
NOTE RECEIVABLE FROM AFFILIATE		2.3		235.9		—		(238.2	)		—

	$	1,928.6	$	265.1	$	768.6	$	(716.0	)	$	2,246.3


LIABILITIES AND STOCKHOLDER’S EQUITY

CURRENT LIABILITIES:
Accounts payable	$	342.9	$	—	$	123.3	$	—		$	466.2
Payable to affiliates		117.7		—		20.1		(96.8	)		41.0
Accrued expenses and other		40.9		14.4		0.4		—			55.7
Accrued taxes other than income		21.1		—		5.3		—			26.4
Current portion of long-term debt		0.2		14.8		—		—			15.0
Current portion of notes payable to affiliate		—		—		2.9		(2.9	)		—

Total current liabilities		522.8		29.2		152.0		(99.7	)		604.3

LONG-TERM DEBT		633.9		235.9		—		—			869.8
DEFERRED INCOME TAXES		—		—		47.2		(47.2	)		—
OTHER LONG-TERM LIABILITIES		144.1		—		0.3		—			144.4
NOTE PAYABLE TO AFFILIATE		—		—		238.2		(238.2	)		—
COMMITMENTS AND CONTINGENCIES		—		—		—		—			—

COMMON STOCKHOLDER’S EQUITY:
Common stock		—		—		0.1		(0.1	)		—
Paid-in capital		541.4		—		206.0		(206.0	)		541.4
Retained earnings		86.4		—		124.8		(124.8	)		86.4

Total common stockholder’s equity		627.8		—		330.9		(330.9	)		627.8

	$	1,928.6	$	265.1	$	768.6	$	(716.0	)	$	2,246.3

	2002 Quarter Ended
	March 31 (b)			June 30			September 30			December 31		Total
Net sales and operating revenues	$	1,228.3		$	1,679.0		$	1,899.8		$	1,965.7	$	6,772.8
Operating income (loss) (a)	$	(128.4	)	$	(15.2	)	$	(18.8	)	$	73.6	$	(88.8	)
Net income (loss) available to common stockholders (a)	$	(99.7	)	$	(40.1	)	$	(24.5	)	$	34.7	$	(129.6	)

Earnings per share:
Basic	$	(3.14	)	$	(0.82	)	$	(0.43	)	$	0.60	$	(2.65	)
Diluted	$	(3.14	)	$	(0.82	)	$	(0.43	)	$	0.60	$	(2.65	)

	2001 Quarter Ended
	March 31			June 30		September 30		December 31			Total
Net sales and operating revenues	$	1,686.4		$	1,818.3	$	1,666.2	$	1,246.6		$	6,417.5
Operating income (loss) (a)	$	(36.2	)	$	323.4	$	105.0	$	(25.2	)	$	367.0
Net income (loss) available to common stockholders (a)	$	(31.7	)	$	174.5	$	44.3	$	(44.5	)	$	142.6

Earnings per share:
Basic	$	(1.00	)	$	5.49	$	1.39	$	(1.40	)	$	4.48
Diluted	$	(1.00	)	$	5.06	$	1.28	$	(1.40	)	$	4.13