PREMCOR INC - 10-K Annual Report

Commission

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Exact Name of Registrant as Specified in its

Charter, Principal Office Address and Telephone

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Incorporation

I.R.S. Employer
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Premcor Inc.

1700 East Putnam Avenue, Suite 400

Old Greenwich, Connecticut 06870

(203) 698-7500

The Premcor Refining Group Inc.

1700 East Putnam Avenue, Suite 400

Old Greenwich, Connecticut 06870

(203) 698-7500

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 þ No ¨

The aggregate market value of Premcor Inc.’s common stock held by nonaffiliates of the registrant was approximately $750 million based on the last sales price quoted as of June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter. Number of shares of registrants’ common stock (only one class for each registrant) outstanding as of March 1, 2004:

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 18, 2004. 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.

This Annual Report on Form 10-K contains both historical and 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 forward-looking statements are not historical facts, but only predictions and generally can be identified by use of statements that include phrases such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “foresee” or other words or phrases of similar import. Similarly, statements that describe our objectives, plans or goals also are forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those currently anticipated. Factors that could materially affect these forward-looking statements include, but are not limited to, changes in:

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date of this report and we undertake no obligation to publicly update these forward-looking statements to reflect new information, future events or otherwise. In light of these risks, uncertainties and assumptions, the forward-looking events might or might not occur. We cannot assure you that projected results or events will be achieved.

This Annual Report on Form 10-K represents information for two registrants, Premcor Inc. and The Premcor Refining Group Inc., or PRG. PRG is an indirect, wholly owned subsidiary of Premcor Inc. and is the principal operating subsidiary of Premcor Inc. PRG owns and operates our three refineries. 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. 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, 2003, highly refined products, known as light products, such as transportation fuels, petrochemical feedstocks and heating oil, accounted for approximately 93% 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 42% 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 approximately 80% low cost, heavy sour crude oil, substantially all of which is 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, or SEC. 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 website address is www.premcor.com. We make available on this website under “Investor Relations”, free of charge, 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. We also make available on our website the Board of Directors Guidelines, the Code of Business Conduct and Ethics of Premcor Inc., the Charter of the Nominating and Corporate Governance Committee of Premcor Inc., the Charter of the Audit Committee of Premcor Inc., and the Charter of the Compensation Committee of Premcor Inc. This information is also available by written request to Investor Relations at our executive office address listed below. 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 400, Old Greenwich, Connecticut 06870, and our telephone number is (203) 698-7500.

In January 2004, we announced our intention to purchase the assets of Motiva Enterprises LLC’s Delaware City Refining Complex located in Delaware City, Delaware, subject to the satisfaction of certain conditions, including execution of a definitive agreement and obtaining regulatory approvals. There is no assurance we will enter into a definitive agreement or consummate the transaction. The assets to be purchased include a heavy crude oil refinery capable of processing in excess of 180,000 barrels per day (bpd), a 2,400 tons-per-day (tpd) petroleum coke gasification unit, a 160 megawatt (MW) cogeneration facility, and related assets. The asset purchase price is expected to be $800 million, plus the value of petroleum inventories at closing. We expect the inventories will be approximately $100 million. We expect to finance the purchase with equal parts equity and debt. As part of the financing we are considering the assumption or refinancing of Motiva’s obligations associated with $365 million of tax-exempt bonds issued by the Delaware Economic Development Authority (DEDA) in connection with the gasification and cogeneration facilities. Our assumption of the tax-exempt bonds would be subject to the consent of the DEDA and other parties involved in the financing. There is also a contingent purchase provision that may result in an additional $25 million payment per year up to a total of $75 million over a three-year period depending on the level of industry refining margins during that period, and a gasifier performance provision that may result in an additional $25 million payment per year up to a total of $50 million over a two-year period depending on the achievement of certain performance criteria at the gasification facility.

The Delaware City refinery is a high-conversion heavy crude oil refinery. Major process units include a crude unit, a fluid coking unit, a fluid catalytic cracking unit, a hydrocracking unit with a hydrogen plant, a continuous catalytic reformer, an alkylation unit, and several hydrotreating units. Primary products include regular and premium conventional and reformulated gasoline, low-sulfur diesel, and home heating oil. The refinery’s production is sold in the U.S. Northeast via pipeline, barge, and truck distribution. The refinery’s petroleum coke production is sold to third parties or gasified to fuel the cogeneration facility, which is designed to supply electricity and steam to the refinery as well as outside electrical sales to third parties.

We currently own and operate three refineries. Our Port Arthur, Texas refinery is located in the Gulf Coast region, and our Lima, Ohio and Memphis, Tennessee refineries are located in the Midwest region.

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. Both Port Arthur and Lima also have cracking units. 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 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, also known as the Petroleum Administration Defense District III, 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, 54 refineries were operating in PADD III as of December 31, 2003, with a total crude oil throughput capacity of approximately 7.7 million bpd. The Gulf Coast region accounts for 47% of total domestic refining capacity and is one of the most competitive markets in the United States.

This 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, 2003, at approximately 2.7 million bpd and light product production at approximately 6.4 million bpd. Approximately 58%, or 3.7 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. 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 the eastern seaboard, West Coast markets and the Caribbean basin.

We acquired the Port Arthur refinery from Chevron Products Company in 1995. This refinery is located in Port Arthur, Texas, approximately 90 miles east of Houston, on a 3,600-acre site, of which fewer 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.

We are currently in the process of expanding our Port Arthur refinery. The expansion project includes increasing Port Arthur’s crude oil throughput capacity from its current rate of 250,000 bpd to approximately 325,000 bpd, and expanding the coker unit capacity from its current rated capacity of 80,000 bpd to 105,000 bpd, which will further increase our ability to process lower cost, heavy sour crude oil. The project is estimated to cost between $200 million and $220 million and is expected to be completed by the beginning of 2006.

In the first quarter of 2001, we completed a heavy oil upgrade project at our Port Arthur refinery that increased the refinery’s capability of processing heavy sour crude oil from 20% to 80%. The heavy oil upgrade 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 project also 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 large 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 that resulted in Sabine River Holding Corp. and its subsidiaries, including PACC, becoming wholly owned subsidiaries of PRG. Prior to the transactions, Sabine had been 90% owned by Premcor Inc.

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. 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 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, 2003, a cumulative quarterly surplus of $203.2 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.

We have 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 to transport Maya crude oil from the loading port in Mexico or other Caribbean locations 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. In 2003, our charter rate under this agreement was favorable compared to market rates.

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.

We contract with Huntsman Petrochemical Corporation, or Huntsman, to purchase certain products to be used as refinery gasoline blendstocks. Under one of these contracts we purchase Huntsman’s production of pyrolysis gasoline, or pygas, which is produced from its Port Arthur ethylene cracker and transported by dedicated pipeline from Huntsman to our refinery. We are also currently purchasing C4 raffinate from Huntsman to use as a gasoline blendstock in our alkylation process. Both of these agreements expire on December 31, 2004, and the pygas agreement allows us to terminate the agreement if the product is not meeting certain specifications or if Huntsman does not provide a set minimum of C-4 raffinate. We will enter into a new contract or seek alternative options upon termination of the agreements.

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 have an agreement under which 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 produce excess power, we sell the excess to Entergy. Entergy has exercised its right to terminate the agreement because of impending deregulation. The agreement will stay in effect on a month-to-month basis until deregulation occurs or other arrangements are made. Deregulation has not occurred as of early 2004, and it is possible that it will not occur in the grid in which our refinery is located. 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 September 2004. The contract provides for 60,000 million btus of natural gas per day on a firm basis, which is the approximate 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 will enter into a new contract or seek alternative options upon termination of the agreement.

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 the 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 that 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. All of our petroleum coke is sold to multiple customers generally under 12-month term agreements.

Other Arrangements. Within our Port Arthur refinery, Chevron Phillips Chemical Company, L.P. operates a 164-acre petrochemical facility to manufacture olefins 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 and propylene fractionator. By-products from the petrochemical facility are sold to the refinery for use primarily as fuel gas. We changed our gasoline blending operations to compensate for the recent shutdown of Chevron Phillips Chemical Company’s aromatic extraction unit, which resulted in approximately $1 million of capital expenditures in 2003.

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, 26 refineries were operating in PADD II as of December 31, 2003, with a total crude oil throughput capacity of approximately 3.5 million bpd.

Production of light, or premium, petroleum products 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, 2003, is approximately 4.1 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 1.1 million bpd, with the Gulf Coast continuing to be the largest area for sourcing product, accounting for approximately 1.0 million bpd.

The Explorer, TEPPCO, Seaway, Orion, Colonial, Plantation, and Centennial product pipelines are the primary pipeline systems for transporting Gulf Coast refinery output to PADD II. 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 production, mainly high-sulfur diesel fuel, 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 have utilized these new transportation connections in 2003.

Feedstock and Other Supply Arrangements. The crude oil supplied to our refinery is purchased on a spot basis and delivered via the Marathon and Mid-Valley pipelines. The Millennium pipeline 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. All deliveries to Lima, whether domestic or foreign, are accomplished on a daily ratable basis.

In March 1999, we entered into an agreement with Koch Petroleum Group L.P., or Koch, in which we sold Koch our crude oil linefill in the Mid-Valley pipeline and the West Texas Gulf pipeline, which amounted to 2.7 million barrels. On October 1, 2002, Morgan Stanley Capital Group Inc., or MSCG, purchased the 2.7 million

barrels of crude oil from Koch and we entered into an agreement with MSGC to purchase the barrels of crude oil from them in October 2003. The agreement with MSCG was terminated in June 2003, and we purchased the 2.7 million barrels of crude oil from MSCG at a net cost of approximately $80 million.

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 2003 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.

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, Illinois and other locations.

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. We will enter into a new contract or seek alternative options upon termination of the agreement.

Our Memphis refinery, which we acquired from The Williams Companies, Inc. and certain of its subsidiaries, or Williams, in March 2003, is located on a 248-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, the refinery is a modern and highly efficient refinery due to significant investment particularly over the last four years. 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, reformulated gasoline, jet fuel, high and 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, Illinois. 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. Availability of crude supply is not guaranteed under this arrangement. We rely solely on the spot crude oil market for supply and have the ability to arrange purchases through MSCG. The benefit of the MSCG arrangement is that it provides payment and credit terms that are generally more favorable to us than normal industry terms. This supply agreement with MSCG expires in February 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. We

own an 80-megawatt power plant adjacent to the refinery. This plant is fueled with natural gas and is designed to provide a reliable, secondary source of power, allowing us to reduce our power costs by affording us the flexibility to purchase electrical power at interruptible rates.

Product Offtake. The principal market for the refinery’s production is the local Memphis or Mid-South market and secondarily the Lower Ohio River and St. Louis markets. 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 primary 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 supply agreement, which represented approximately 13% of the refinery’s production in 2003. The Federal Express agreement expires in August of 2004, and we are reviewing our options, including a new agreement with Federal Express. 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:

We own a 400-acre site near the Mississippi River in Hartford, Illinois, approximately 17 miles northeast of St. Louis, Missouri, on which stands a refinery we previously operated. 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 that meet new gasoline and diesel fuel specifications mandated by the federal government. In the third quarter of 2003, we sold certain processing units and ancillary assets at our Hartford refinery for $40 million to ConocoPhillips, who owns a refinery adjacent to our Hartford site. We are continuing to operate the storage and distribution facility at the Hartford refinery site. In conjunction with the sale of the refinery assets, we entered into an agreement to lease certain portions of the Hartford property to ConocoPhillips. We also entered into service agreements with ConocoPhillips to provide each other services in conjunction with ConocoPhillips’ refining operations and our remaining storage and distribution operations and environmental remediation efforts on the site. The services include wastewater treatment, water supplies, firewater, emergency response, electricity, grounds maintenance, sewer system and other services. For a discussion of the pretax charge to earnings that we recorded in 2002 as a result of the closure of our Hartford refinery and in 2003 as a result of the sale of the assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability—Refinery Restructuring and Other Charges—Refinery Closures and Asset Sale.”

Our product marketing group sells approximately 2.6 billion gallons per year of gasoline, diesel fuel, and jet fuel to a diverse group of approximately 1,200 distributors and chain retailers and another 4.4 billion gallons per year to bulk customers. 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 some of 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 and Memphis refineries 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 space in 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 from our Port Arthur and Memphis refineries 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 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. Just over 20% of net sales and operating revenues in 2003 were represented by sales of products purchased from third parties. This percentage has increased slightly over the last two years because we purchased refined products in order to cover shortfalls resulting from the closure of our Blue Island and Hartford refineries. 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 200,000 bpd of crude oil from an affiliate of PEMEX. 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, 2003:

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 we do not have any 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.

As of December 31, 2003, we leased approximately 109,000 square feet of office space in our Old Greenwich, Connecticut executive offices and our St. Louis, Missouri general offices. The lease on our St. Louis general office for 46,500 square feet will be terminating in stages during the first half of 2004 in connection with

the consolidation of our administrative activities in our Connecticut office. 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 1, 2004, we employed approximately 1,770 people, approximately 56% of whom are covered by collective bargaining agreements at our Lima, Memphis and Port Arthur refineries and West Memphis terminal. The collective bargaining agreements covering employees at our Port Arthur and Memphis refineries expire in January 2006, the agreement covering employees at our Lima refinery expires in April 2006, and the agreement covering employees at our West Memphis terminal expires in December 2006. Our relationships with the relevant unions have been good, and we have never experienced a work stoppage as a result of labor disagreements.

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 certain 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 Liabilities” and “Legal Proceedings.”

The principal environmental risks associated with our refinery operations are air emissions, releases into soil and groundwater, wastewater discharges, 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.

The Environmental Protection Agency, or EPA, is in the process of revising the non-attainment classification of many cities and urban areas. All of our refineries are located in areas that will be reclassified. These reclassifications will take several years to complete. We anticipate we will have to install some additional pollution controls at the refineries, but we cannot determine the impact of the reclassifications until further regulations are promulgated.

At the Port Arthur 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 tenth year of an eleven year schedule to install such technology.

At the Memphis refinery, we notified the EPA that we will sample wastewater streams at the Memphis refinery to determine the applicable provisions of the National Emission Standards for Hazardous Air Pollutants, or Benzene Waste NESHAP. Based on the results of the sampling and the applicable provisions of 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 responsibility 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 approximately $15 million.

Also at Memphis, Williams previously 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 approximately $4 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 states in which we operate have 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, in the past and in limited circumstances, produced gasoline containing MTBE at our Port Arthur refinery and our closed Blue Island and Hartford refineries, and we have sold MTBE to third parties for use as a blendstock for gasoline. We have not manufactured MTBE in any of our refineries.

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 appraised when their implementation becomes more accurately defined.

Reformulated Fuels. EPA regulations also require that reformulated gasoline 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 designated as serious non-attainment for ozone, requiring reformulated gasoline 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.

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 produce gasoline under the new sulfur standards at our Port Arthur refinery, and we expect to comply with the gasoline standards at our Memphis refinery in the second quarter of 2004. As a result of the corporate pool averaging provisions of the regulations and our possession of what we believe, based on current information, to be sufficient sulfur credits, we intend to defer a significant portion of the investment required for compliance at our Lima refinery until the end of 2005. We believe, based on current estimates, that compliance with the new Tier 2 gasoline specifications will require us to make capital expenditures in the aggregate through 2005 of approximately $315 million, of which $194 million has been incurred as of December 31, 2003. Future revisions to this cost estimate, and the estimated time during which costs are incurred, may be necessary.

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 fourth quarter 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 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.

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 and other laws 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 substances 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 certain 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 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, generally 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 active processing units, which areas are our responsibility. Less than 200 acres of the 3,600-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 recorded a liability for our portion of the Port Arthur remediation.

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 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. We recorded a liability for various on-going remediation matters as part of our acquisition accounting. Any claims made by us against Williams for environmental liabilities must be made within seven years. Williams obtained, at their expense, a ten-year fully prepaid $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 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. We have been in discussions with state and local governmental agencies concerning remediation of the site and expect a consent order setting forth the agreement for remediation of the site to have been filed with the court in the first half of 2004. We have recorded a liability for the environmental remediation of the refinery site based on costs that are reasonably foreseeable at this time, taking into consideration studies performed in conjunction with the insurance policies discussed below. In 2002, Premcor obtained environmental risk insurance policies covering the Blue Island refinery site. This insurance program will allow us to quantify and, within the limits of the policies, 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. The responsibility for the dismantling and environmental remediation of the refinery’s above ground assets had been assumed by a third party in connection with its purchase of the assets for resale. The third party has defaulted on its obligation and we recorded a liability of $4.1 million in the fourth quarter of 2003 to provide for our estimated cost to dismantle and remediate the remaining above ground refinery equipment. 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—Refinery Closures and Asset Sale.”

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 have recorded a liability for the environmental remediation of the refinery site based on costs that are reasonably foreseeable at this time, and we are also currently in discussions with state governmental agencies concerning environmental remediation of the site. In addition, state and federal governmental agencies are investigating a petroleum hydrocarbon plume underlying a portion of the Village of Hartford. See “—Legal Proceedings” for details of the pending lawsuits related to the hydrocarbon plume. 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—Refinery Closures and Asset Sale.”

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 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 approximately 670 sites, 225 of which had no known preclosure contamination, 365 of which had known preclosure contamination of varying extent, and 80 of which had been previously remediated. The purchaser of our retail division assumed preclosure 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 preclosure liabilities, subject to certain time limitations. With respect to the sites on which there was known preclosing 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 preclosing liability for sites that had been previously remediated. The bankruptcy discussed below may have an affect on these liabilities.

Of the remaining 478 former retail sites not sold in the 1999 transaction described above, we have sold all but 5 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 for which a letter was received and 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 properties. During the period from the beginning of 1999 through December 31, 2003, we expended approximately $22 million to satisfy all the environmental cleanup obligations of our former retail marketing business and, as of December 31, 2003, had $21.2 million accrued to satisfy those obligations in the future.

In connection with 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 remained jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. We may also be contingently liable for environmental obligations at these sites. In October 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. In bankruptcy hearings throughout 2003, CRE rejected, and subject to certain defenses, we became primarily obligated for, approximately 36 of the previously assigned leases. During the third quarter of 2003, CRE conducted an orderly sale of its remaining retail assets, including most of the leases and subleases previously assigned by us to CRE except those that were rejected by CRE. We recorded an after-tax charge of $7.2 million in 2003, representing the estimated net present value of our remaining liability under the 36 rejected leases, net of estimated sublease income, and other direct costs. The primary obligation under the non-rejected leases and subleases was transferred in the CRE sale process to various unrelated third parties; however, we will likely remain jointly and severally liable on the assigned leases, and the remaining unassigned leases could be rejected. A portion of the $21.2 million liability discussed above was established pursuant to an environmental indemnity agreement with CRE in connection with our 1999 sale of retail assets. The environmental indemnity obligation as it relates to the CRE retail properties was not extended to the buyers of CRE’s retail assets in the recent bankruptcy proceedings and, as a result, we intend to review our environmental liability accordingly upon the final disposition of the bankruptcy proceedings.

In December 1999, we sold 15 refined product terminals to a third party group, 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.

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. We have been working with TDEC to continue remediation of the groundwater. 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 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 certain legal and environmental proceedings. The legal proceedings 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 $98 million, primarily on an undiscounted basis, as of December 31, 2003 for all legal and environmental contingencies and obligations, including those items described under “—Environmental Matters—Environmental Remediation” and “—Legal Proceedings.” An adverse outcome of any one or more of these matters could have a material effect on our operating results and cash flows when resolved in a future period.

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 believe that a superior safety record is inherently tied to our productivity and financial goals. All of our refineries have advanced safety and health programs that meet or exceed OSHA requirements. We maintain comprehensive safety management systems including policies, procedures, recordkeeping, internal reviews, training, incident reviews and corrective actions. Each employee at the refineries and terminals is responsible for safe work conditions and has the authority to stop unsafe acts or conditions. We utilize several methods to track safety performance at the refineries. These methods include monitoring results for field audits, tracking “near miss” events or conditions, equipment malfunctions, first aids and medical treatments. We maintain close communication with the communities where our refineries are located through various organizations and informational materials.

The following is a summary of potentially 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.

Village of Hartford, Illinois Litigation. In May 2003, the Attorney General’s office for the State of Illinois filed a lawsuit against us and a former owner of the Hartford refinery for injunctive relief, cost recovery and penalties related to subsurface contamination in the area of the refinery and facilities owned by other companies. The case, entitled People of the State of Illinois, ex rel. v. The Premcor Refining Group, Inc. et al., is filed in the Circuit Court for the Third Judicial Circuit, Madison County, Illinois. The Attorney General’s office also sent notices to other companies with current or former operations in the area of the state’s intent to sue those companies as well. We, along with other companies, have met with the state and U. S. EPA regarding the issues in the Village of Hartford, and those discussions are ongoing.

In July 2003, approximately 12 residents of the Village of Hartford, Illinois filed a lawsuit against us and a prior owner of the Hartford refinery alleging personal injury and property damage due to releases from the refinery and related pipelines. The plaintiffs are seeking class certification and unspecified damages. The case, entitled Sparks, et al. v. The Premcor Refining Group, Inc., et al. has been removed to the United States District Court for the Southern District of Illinois.

Lawsuits by Residents of Port Arthur, Texas. In June 2003, approximately 700 residents of Port Arthur, Texas filed a lawsuit against us and five other companies alleging personal injuries and property damage from emissions from refining and chemical facilities in the area. The plaintiffs are seeking class certification, unspecified damages and the establishment of a trust fund for health concerns. The case is entitled Marion L Aaron, et al. Premcor Refining Group Inc. et al. and is filed in Judicial District Court of Jefferson County, Texas.

Methyl-Tertiary Butyl Ether Products Liability Litigation. During the fourth quarter of 2003 and continuing, we have been named in approximately 35 cases, along with dozens of other companies, filed in approximately 12 states concerning the use of methyl-tertiary butyl ether, or MTBE. The cases contain allegations that MTBE is defective. The cases are in various procedural stages with defendants attempting to remove the cases to federal court and consolidate them in the Southern District of New York under the rules for Multi-District Litigation, or MDL. The cases are before the Judicial Panel on MDL Docket No. 1358, In Re: Methyl-Tertiary Butyl Ether Products Liability Litigation.

Port Arthur: Enforcement. The Texas Commission on Environmental Quality, or TCEQ, conducted a site inspection of our Port Arthur refinery in the spring of 1998. In August 1998, we received a notice of enforcement alleging 47 air-related violations and 13 hazardous waste-related violations. The number of allegations was significantly reduced in an enforcement determination response from the TCEQ in April 1999. A follow-up inspection of the refinery in June 1999 concluded that only two items remained outstanding, namely that the refinery failed to maintain the temperature required by our air permit at one of its incinerators and that five process wastewater sump vents did not meet applicable air emission control requirements. The TCEQ also conducted a complete refinery inspection in the second quarter of 1999, resulting in another notice of enforcement in August 1999. This notice alleged nine air-related violations, relating primarily to deficiencies in our upset reports and emissions monitoring program, and one hazardous waste-related violation concerning spills. The 1998 and 1999 notices were combined and referred to the TCEQ’s litigation division. On September 7, 2000 the TCEQ issued a notice of enforcement regarding our alleged failure to maintain emission rates at permitted levels. In May 2001, the TCEQ proposed an order covering some of the 1998 hazardous waste allegations (i.e. the incinerator temperature deficiency and the process wastewater sumps) and all of the 1999 and 2000 allegations, and proposing the payment of a fine of $562,675 and the implementation of a series of technical provisions requiring corrective actions. We dispute the allegations and the proposed penalty, and negotiations with the TCEQ 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. All three cases are pending in Circuit Court of Cook County, Illinois.

People of the State of Illinois v. The Premcor Refining Group Inc.; Circuit Court of Cook County, Illinois. In this case the Illinois Attorney General’s office filed suit alleging violations of environmental standards and other causes of action arising from operations at the former Blue Island refinery. The case was only recently served on us and the time for a responsive pleading has not occurred. We have been in discussions with the Attorney General’s office to resolve these issues.

People of the State of Illinois v. Clark Retail Enterprises, Inc. et al.; Circuit Court of Tazewell, Illinois. In this case the Illinois Attorney General’s office filed suit alleging violations of environmental standards and other common law actions arising from operations of a retail site in Morton, Illinois. We have filed a motion to dismiss the lawsuit and are in discussions with the Attorney General’s office and the Illinois EPA on disposition of the site.

Alleged Asbestos Exposure. We, along with numerous other defendants, have been named in certain 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 and Port Arthur refineries. Some of the cases 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 information requests 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.

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. The EPA recently issued a new Section 114 information request to the Memphis refinery, to which both Williams and we have responded.

There were no matters submitted to a vote of security holders during the fourth quarter of our fiscal year ended December 31, 2003.

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 senior vice president—finance and controller of our company 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.

Donald F. Lucey has served as senior vice president—commercial for PRG since February 2004 and as vice president—commercial for PRG from April 2002 to February 2004. Mr. Lucey has served as vice president— commercial for Premcor Inc. since April 2002. Prior to joining us, Mr. Lucey worked at Tosco Corporation, subsequently at Phillips Petroleum Company, managing Atlantic Basin fuel oil activities. Prior to joining Tosco, Mr. Lucey worked with Phibro Energy in their fuel oil products and solid fuels departments both in the United States and abroad. Mr. Lucey has held various positions in the oil industry and other commodity industries since 1976.

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 senior vice president—corporate development, treasurer and assistant secretary of our company since July 2003. Mr. Watson served as our senior vice president—corporate development from September 2002 to July 2003 and 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 as 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.

Mr. O’Malley, our chairman of the board and chief executive officer, is the cousin by marriage of Mr. Lucey, PRG’s senior vice president—commercial.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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 1, 2004, Premcor Inc.’s common stock was held by 29 stockholders of record and an estimated 8,000 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 for each quarter of 2003 and 2002, as reported on the NYSE Composite Tape. Premcor USA Inc., a direct wholly owned subsidiary of Premcor Inc., owns 100% of the outstanding 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.

Purchases of Common Stock. We did not repurchase any of our common stock in 2003 and we have no plans to do so in the foreseeable future.

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, 2003, 2002 and 2001 and the selected balance sheet data as of December 31, 2003 and 2002 are derived from our audited consolidated financial statements including the notes thereto appearing elsewhere in this Annual Report on Form 10-K. The selected statement of earnings and cash flow data for the years ended December 31, 2000 and 1999, and the selected balance sheet data as of December 31, 2001, 2000, and 1999 have been derived from our audited consolidated financial statements, including the notes thereto, not included in this Annual Report on Form 10-K. 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 data below reflects the closure of our Blue Island refinery in January 2001, the closure of our Hartford refinery in September 2002, and the acquisition of our Memphis refinery in March 2003. 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 in this report.

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

This Annual Report on Form 10-K represents information for two registrants, Premcor Inc. and its indirectly wholly owned subsidiary, The Premcor Refining Group Inc., or PRG. PRG is the principal operating company and together with its wholly owned subsidiary, Sabine River Holding Corp. and its subsidiaries, or Sabine, owns and operates three refineries. Sabine’s principal operating company is Port Arthur Coker Company L.P., or PACC. All of our employees, with the exception of certain executives, are employed by PRG and PACC. The results of operations for Premcor Inc. principally reflect the results of operations of PRG, except for certain pipeline operations, general and administrative costs, interest income, and interest expense at stand-alone Premcor Inc. and/or its other subsidiaries. This Management’s Discussion and Analysis of Financial Condition and Results of Operations reflects the results of operations and financial condition of Premcor Inc. and subsidiaries and the discussions provided are equally applicable to Premcor Inc. and PRG except where indicated otherwise.

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.

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 and condition.

Effective March 3, 2003, we completed the acquisition of the Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries, or Williams. The purchase price of $474 million included $310 million for the refinery, supply and distribution assets, approximately $159 million for crude and product inventories, and approximately $5 million in transaction fees. 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; use of crude oil tankage at St. James, Louisiana; and an 80-megawatt power plant adjacent to the refinery.

The acquisition of the Memphis refinery assets was accounted for using the purchase method, and the results of operations of these assets have been included in our results from the date of acquisition. In the third quarter of 2003, we adjusted the purchase price allocation based on independent appraisals and other evaluations. The adjusted purchase price allocation is as follows:

As part of the purchase agreement, we assumed liabilities of $15.5 million that related to capital lease obligations, cancellation fees related to Tier 2 technology that we will not utilize, and environmental remediation activity. Williams assigned several leases to us including two capitalized leases that relate to the leasing of crude oil and product pipelines that are within the Memphis refinery system connecting the refinery to storage facilities and other third party pipelines. Both capital leases have 15-year terms with approximately 14 years of their terms remaining.

The purchase agreement also provides for contingent participation, or earn-out, payments up to a maximum aggregate of $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. The earn-out payments will be calculated annually at the end of the seven 12-month periods beginning on April 1, 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 level, at a crude oil throughput rate of 167,123 bpd. The stipulated margin level is $3.25 per barrel for the first year and increases by $0.10 per barrel for each year thereafter. The actual daily value of the Gulf Coast 2/1/1 crack spread, as defined by the agreement, averaged $3.65 per barrel for the nine-month period from April 1, 2003 through December 31, 2003. Any amounts we pay to Williams as a result of the earn-out agreement will be recorded as goodwill. As of December 31, 2003, we recorded $14.2 million in goodwill related to the earn-out agreement, which reflected an estimate of our April 1, 2004 payment. Such goodwill will not be amortized, but will be subject to an annual impairment evaluation.

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 of a public and private offering of common stock. Certain of the Memphis pipeline assets and related liabilities were acquired or assumed by The Premcor Pipeline Co., an indirect subsidiary of Premcor Inc. PRG also amended and restated its credit agreement to allow for the acquisition. See “—Liquidity and Capital Resources—Cash Flows from Financing Activities” for additional details of the financings.

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 net income, as all options granted in 2001 and earlier 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. With respect to stock option grants outstanding as of December 31, 2003, we will record future non-cash stock-based compensation expense and additional paid-in capital of $24.6 million over the applicable vesting periods of the grants.

In 2003, we recorded refinery restructuring and other charges of $38.5 million, which included a $20.8 million charge related to closure costs and asset write-offs related to the sale of certain Hartford refinery assets and the Blue Island refinery closure, a $10.2 million charge related to environmental remediation and litigation costs associated with closed and previously-owned facilities, and a net $7.5 million charge related to our planned closure of the St. Louis administrative office. These activities and transactions are described more fully below.

In 2002, we recorded refinery restructuring and other charges of $172.9 million ($168.7 million for PRG), which consisted of a $137.4 million charge related to the ceasing of refinery operations at our Hartford, Illinois refinery, $32.4 million charge related to the 2002 management, refinery operations, and administrative restructuring, a $2.5 million charge related to the termination of certain guarantees at PACC as part of the Sabine restructuring, a $1.4 million charge related to idled assets, and a $4.2 million charge related to the write-down of Premcor Inc.’s interest in Clark Retail Enterprises, Inc., or CRE, partially offset by a benefit of $5.0 million related to the unanticipated sale of a portion of previously written-off Blue Island refinery assets.

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, refinery, and administrative function restructurings.

Refinery Closures and Asset Sale. 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. The closure resulted in a pretax charge of $137.4 million in 2002, which included a $70.7 million non-cash, write-down of long-lived assets to their estimated fair value of $49.0 million; a $4.8 million non-cash write-down of current assets; a $60.6 million charge related to employee severance, plant closure/equipment remediation, and site clean-up and environmental matters; and a $1.3 million charge related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. In January 2001, we ceased refining operations at our

Blue Island, Illinois refinery. This closure resulted in a pretax charge of $167.2 million in 2001, which included a $98.1 million non-cash write-down of long-lived and current assets and a $69.1 million liability for employee severance and plant closure/equipment remediation, and site clean-up/environmental matters. Employee severance and plant closure/decommissioning activities have been completed at both sites. We continue to utilize our storage and distribution facilities at both refinery sites.

In 2003, we sold certain of the processing units and ancillary assets at the Hartford refinery to ConocoPhillips for $40 million. We have also entered into agreements with ConocoPhillips to integrate certain of our remaining facilities with the assets they purchased from us and to receive from and provide to ConocoPhillips certain services on an on-going basis. The $20.8 million charge in 2003 primarily related to the sale transaction and subsequent agreements and included the write-down of the refinery assets held for sale, the write-off of certain storage and distribution assets included in property, plant and equipment, and certain other costs of the sale.

In the future, we expect the only significant effect on cash flows related to our closed refinery facilities will result from the environmental site remediation at both sites and equipment dismantling at our Blue Island site. We are currently in discussions with governmental agencies concerning remediation programs for both sites and anticipate that the discussions will likely lead to final consent orders. We expect a consent order setting forth the agreement for remediation of the Blue Island site to have been filed with the court in the first half of 2004. Our site clean-up and environmental liability takes into account costs that are reasonably foreseeable at this time. As the site remediation plans are finalized and work is performed, further adjustments of the liability may be necessary and such adjustments may be material. In 2003, we recorded a charge of $10.2 million related to our environmental remediation activity. This charge included estimated survey, design, and clean-up costs in relation to the Village of Hartford, costs related to the default of a third party to provide certain dismantling activity at our Blue Island site, and revised estimates for remediation activity at a previously owned terminal that resulted from further analysis of the site in 2003.

In 2002, we obtained environmental risk insurance policies covering the Blue Island refinery site. This insurance program allows us to quantify and, within the limits of the policies, 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 2002, we restructured our executive management team resulting in the recognition of severance expense of $5.0 million and non-cash stock-based compensation expense of $5.8 million. In addition, we incurred a charge of $5.0 million for the cancellation of a monitoring agreement with one of our common stock owners. See “—Related Party Transactions—Blackstone” for more details of the agreement. 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 was $1.3 million related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. Reductions at the refineries occurred in October 2002 and those at the St. Louis office occurred in 2003.

As a result of the Memphis refinery acquisition, the number of positions to be eliminated at the St. Louis office was reduced by 25 and we recorded a reduction in the restructuring liability of $1.6 million in the first

quarter of 2003. In May 2003, we announced that we would be closing the St. Louis office and moving the administrative functions to the Connecticut office over the next twelve months. The office move is expected to cost $15.1 million, which includes $6.4 million of severance related benefits and $8.7 million of other costs such as training, relocation, and the movement of physical assets. The severance related costs will be amortized over the future service period of the affected employees and the other costs will be expensed as incurred.

The following table summarizes the expected expenses associated with the administrative restructuring and provides a reconciliation of the administrative restructuring liability as of December 31, 2003 (in millions):

In 2003, we redeemed the remaining principal balance of our 11¹/2% subordinated debentures; repaid our $240 million floating rate loan; redeemed the outstanding balances of our 8⁷/8% senior subordinated notes, 8⁵/8% senior notes, and 8³/8% senior notes; purchased in the open market a portion of PACC’s 12¹/2% senior notes; and amended our credit agreement in conjunction with the Memphis acquisition. We recorded a loss on extinguishment of long-term debt of $27.5 million, which included cash premiums associated with the early repayment of long-term debt of $17.2 million, a write-off of unamortized deferred financing costs of $9.4 million related to this debt and the amended credit agreement, and a write-off of unamortized note discounts of $0.9 million. PRG recorded a loss on extinguishment of long-term debt of $25.2 million which excluded the cash premium paid in relation to the redemption of 11¹/2% subordinated debentures, which were held by PRG’s parent company.

In 2002, we redeemed the outstanding balances of our 10⁷/8% senior notes, 9¹/2% senior notes, senior secured bank loan, and purchased a portion of our 11¹/2% 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 9¹/2% 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 9¹/2% 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. 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 related to the repurchase of a portion of the 9¹/2% senior notes.

In connection with the 1999 sale of our retail assets to Clark Retail Enterprises, Inc., or CRE, we assigned approximately 170 leases and subleases of retail stores to CRE. Subject to certain defenses, we remain jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. We may also be contingently liable for environmental obligations at these sites. In October 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. In bankruptcy hearings throughout 2003, CRE rejected, and subject to certain defenses, we became primarily obligated for, approximately 36 of the previously assigned leases. During the third quarter of 2003, CRE conducted an orderly sale of its remaining retail assets, including most of the leases and subleases previously assigned by us to CRE except those that were rejected by CRE. We recorded an after-tax charge of $7.2 million in 2003, representing the estimated net present value of our remaining liability under the 36 rejected leases, net of the sublease income, and other direct costs. The primary obligation under the non-rejected leases and subleases was transferred in the CRE sale process to various unrelated third parties; however, we will likely remain jointly and severally liable on the assigned leases and the remaining unassigned leases could be rejected. Total payments on leases and subleases upon which we will likely remain jointly and severally liable are currently estimated as follows: (in millions) 2004—$9, 2005—$9, 2006—$9, 2007—$8, 2008—$8 and in the aggregate thereafter—$50.

We recorded a liability for the estimated cost of environmental remediation of our former retail store sites. A portion of this liability was established pursuant to an indemnity agreement with CRE in connection with its 1999 purchase of our retail assets. This indemnity obligation does not extend to the buyers of CRE’s retail assets and, as a result, we will review our environmental liability accordingly upon the final disposition of the CRE bankruptcy. The following table reconciles the activity and balance of the liability for the lease obligations as well as our environmental liability for previously owned and leased retail sites:

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 some of our previously owned retail sites. 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 depend 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 are 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 utilize the Gulf Coast 2/1/1 crack spread as a benchmark for our Port Arthur and Memphis refinery operations. We utilize the Chicago 3/2/1 crack spread as a benchmark for our Lima refinery operations. Our actual results will vary as our crude oil and product slates differ from the benchmarks and for other ancillary costs that are not included in the benchmarks, such as crude oil and product grade differentials, transportation costs, storage and credit fees, inventory fluctuations and price risk management activities. 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 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 200,000 bpd of crude oil from PMI Comercio International, S.A. de C.V., an affiliate of Petroleos Mexicanos, the Mexican state oil company, or PEMEX. 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 ten-year historical market prices, which slightly exceeded 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, 2003, a cumulative quarterly surplus of $203.2 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 Morgan Stanley Capital Group, or MSCG, as an intermediary 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. 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 Memphis 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. Availability of crude supply is not guaranteed under this arrangement. We rely solely on the spot crude oil market for supply and have the ability to arrange purchases through MSCG. The benefit of the MSCG arrangement is that it provides payment and credit terms that are generally more favorable to us than normal industry terms. This supply agreement with MSCG expires in February 2005, and can be renewed based on certain notification requirements.

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 higher 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. Our Memphis refinery also benefits from location premiums for refined products.

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 and Memphis refineries produce a product slate that is of higher value than the products used to calculate the crack spreads. Our Lima and Memphis refineries benefit from mid-continental locations, in addition to the fact that they produce a greater percentage of high value transportation fuels as a result of processing a predominantly sweet crude oil slate. In contrast to our Lima and Memphis refineries, approximately 15% of Port Arthur’s product slate is lower value petroleum coke, sulfur, and residual oils, which

negatively impacts the refinery’s gross margin against the benchmark crack spread. Less than 5% of the product slate at Lima and Memphis is the lower value residual oils or petroleum coke.

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.

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. Our inventory investment includes both titled inventory and fixed price purchase and sale commitments. Because our titled inventory is valued under the last-in, first-out inventory costing method, price fluctuations on our titled inventory have very little effect on our financial results unless the market value of our titled inventory is reduced below cost.

Although benchmark market indicators such as the Gulf Coast 2/1/1 and Chicago 3/2/1 are useful in predicting refining gross margin, changes in absolute hydrocarbon prices, the “structure” of the hydrocarbon futures market and our specific price risk mitigation activities have an effect on our results that does not correlate with the benchmark market indicators. In order to supply our refineries with crude oil on a timely basis, we enter into purchase contracts that fix the price of crude oil from one to several weeks in advance of receiving and processing that crude oil. In addition, it is common as part of our marketing activities to fix the price of a portion of our product sales in advance of producing and delivering that refined product. Prior to delivery of the related crude oil and production of the related refined products, these fixed price purchase and sale commitments will change in value as prices rise and fall. Our results are measured by recording these commitments at market value. With the acquisition of our Memphis refinery and the related increase in our domestic crude oil requirements, the average level of our open fixed price purchase commitments is approximately 10 million barrels as of December 31, 2003. Since the average level of our open fixed price sale commitments is approximately 2 million barrels, on a net basis, we carry an average level of open fixed price purchase commitments of approximately 8 million barrels. As a result, a $1 per barrel increase in absolute price levels increases the value of our net fixed price purchase commitments and our pretax operating results by approximately $8 million. A $1 per barrel decline in absolute price levels would produce the opposite effect.

To mitigate the absolute price risk while holding these fixed price purchase and sale commitments, we may purchase futures contracts on the New York Mercantile Exchange, or NYMEX, that correspond volumetrically with all or a portion of our fixed price purchase and sale commitments. These futures contracts are normally held in the current, or prompt, contract month on the NYMEX in order to achieve the best correlation with the change in the value of the fixed price commitment. As prices change, the effect of the change on the value of the futures contract tends to offset the effect of the change on the value of the fixed price commitment. Since the volumetric level of our fixed price commitments is a net purchase and is relatively constant, to mitigate price risk it is typical to carry an offsetting net short futures position. Since this net short futures position is held in the prompt contract month on the NYMEX, it is necessary to exchange the prompt month NYMEX futures contract for the following month contract prior to its expiration. When the contract price of the following month contract is less than the contract price of the prompt month contract (a “backwardated” market structure), a loss is realized on the exchange as the prompt month contract is “purchased” at a value higher than the following month contract is “sold.” When the contract price of the following month contract is greater than the contract price of the prompt month contract (a “contango” market structure), the converse is true and a gain is realized on the exchange.

Also affecting our operating results is the safety, reliability and the environmental performance of our refinery operations. 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.

Overview. Net income available to common stockholders was $116.6 million ($1.58 per diluted share) in 2003 as compared to a net loss available to common stockholders of $129.6 million ($2.65 per diluted share) in 2002. Our operating income was $330.4 million in 2003 as compared to an operating loss of $88.8 million in the corresponding period in 2002. The increase in the results of 2003 compared to the results in 2002 was principally due to stronger market conditions, higher crude oil throughput rates, and a lower restructuring charge.

The results of operations for 2003 include the operations of our Memphis refinery beginning March 3, 2003, the date of acquisition. The results of operations for 2002 include the operations of our Hartford refinery. We ceased refining operations at our Hartford refinery in late September 2002.

Net Sales and Operating Revenues. Net sales and operating revenues increased $2,897.9 million, or 49%, to $8,803.9 million in 2003 from $5,906.0 million in 2002. The increase was principally due to higher overall refined product prices and additional sales volume from the Memphis refinery, partially offset by the closure of the Hartford refinery. Refined product prices increased significantly in December 2002, with these prices remaining above more historical levels throughout 2003.

In December 2003, the Financial Accounting Standards Board, or FASB, published Emerging Issues Task Force, or EITF, Issue No. 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes. The task force reached a consensus that determining whether realized gains and losses on physically settled derivative contracts “not held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based

solely on the terms of the individual contracts. In accordance with EITF 03-11, cost of sales includes the net effect of the buying and selling of crude oil to supply our refineries. Prior period operating revenues and cost of sales have been reclassified to conform to the fourth quarter application of EITF 03-11, effective as of the beginning of the year. The current period presentation and prior period reclassifications have no effect on current or previously reported gross margin or net income (loss). See Note 2 to the Consolidated Financial Statements in Item 15 to this Annual Report on Form 10-K for additional information on the prior period reclassifications.

Gross Margin. Gross margin increased $413.7 million, or 62%, to $1,084.7 million in 2003 from $671.0 million in 2002. The increase in gross margin in 2003 was principally driven by significantly stronger market conditions including stronger crack spreads and crude oil differentials. These market benefits were partially offset by the effects on our price risk management activities of an extremely volatile and backwardated hydrocarbon market in the first half of 2003.

Average crack spreads and crude oil differentials were stronger in 2003 as compared to 2002. The Gulf Coast 2/1/1 and Chicago 3/2/1 crack spreads were approximately 49% and 28% higher, respectively, in 2003 than in 2002. The crack spreads were volatile in 2003, but, we believe, were positively affected during 2003 due to low product inventory levels, the effects from the Northeastern black-out in August, and the strong gasoline demand during the summer driving season. The WTI less Maya and WTI less WTS crude oil differentials were approximately 32% and 98% higher, respectively, in 2003 than in 2002. In 2003, we believe the crude oil differentials were impacted by the overall volatility of the crude oil market, which we believe was affected by, among other things, crude supply concerns related to the war with Iraq, workers’ strikes in Venezuela, and political turmoil in Nigeria. A strong heavy sour and sour crude oil differential has a significant positive impact on Port Arthur’s gross margin because its crude oil throughput is approximately 80% heavy sour crude oil and approximately 20% light and medium sour crude oils. Our Lima and Memphis refineries partially benefited from the stronger WTI less Dated Brent crude oil differential as a portion of their crude oil in 2003 was purchased in the foreign market.

During 2003, absolute hydrocarbon prices were volatile and at historically high levels, and the market structure for crude oil was significantly backwardated, until easing considerably in the third quarter. In order to protect against the negative valuation effects of a possible precipitous decline in absolute price levels, we chose to carry net short NYMEX futures contracts to offset a portion of our net fixed purchase commitment price risk. Due to the backwardated crude oil market structure, this price risk mitigation strategy carried a cost as discussed in “—Factors Affecting Our Operating Results”. Including the effects of our price risk mitigation activities, our operating results in 2003 were negatively affected by approximately $28 million from a decline in the value of our net fixed price purchase commitments. By comparison, in 2002, our operating results were principally affected by having our fixed price purchase commitments largely exposed to price risk early in year, but generally fully offset with net short NYMEX futures contracts beginning during the second quarter. Our operating results in 2002 benefited by approximately $34 million from the change in the value of our net fixed price purchase commitments. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Risk” for a description of our price risk management strategies and policies.

Port Arthur refinery. In 2003, the average crude oil throughput rate at our Port Arthur refinery was approximately 234,700 bpd. The rate was restricted due to a weakened margin environment at certain times during the year, a 31-day planned turnaround maintenance of the hydrocracker unit in the third quarter, and a high crude oil purchasing environment throughout the year. The crude oil throughput rate was regularly supplemented with more economic intermediate feedstocks in order to keep downstream units operating at full rates and to take advantage of the strong crack spreads. Otherwise, the crude oil throughput rates were at or above capacity and the refinery ran well.

In 2002, the average crude oil throughput rate at our Port Arthur refinery was approximately 224,700 bpd. In 2002, our Port Arthur refinery experienced reduced crude oil throughput rates related to crude oil supply delays resulting from the impact of production and transportation interruptions caused by hurricanes Isidore and Lili and subsequent repairs on the reformer unit resulting from October’s hurricane shutdown. The Port Arthur refinery operations were also affected by the February 2002 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.

Lima refinery. In 2003, the average crude oil throughput rate at our Lima refinery was approximately 139,500 bpd. The 2003 rate was restricted due to a scheduled maintenance turnaround of the isocracker unit in the fourth quarter and a planned maintenance turnaround of the FCC unit in the first quarter. In the third quarter of 2003, the refinery ran well with only limited restriction in the crude oil throughput rate early in the quarter when refining margins weakened. In 2002, the average crude oil throughput rate at our Lima refinery was approximately 141,500 bpd. 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.

Memphis refinery. Our Memphis refinery was acquired effective March 3, 2003 and averaged approximately 152,500 bpd of crude oil throughput for the period from March 3, 2003 through December 31, 2003. The crude oil throughput rate was primarily restricted due to the maintenance turnaround of the FCC unit in the fourth quarter. The crude oil throughput rate was restricted earlier in the year due to a high crude oil purchasing environment and planned downtime on a diesel hydrotreater unit. The crude oil throughput rate was supplemented with more economic intermediate feedstocks at times in order to keep downstream units operating at full rates and to take advantage of the strong crack spreads.

Operating Expenses. Operating expenses increased $92.7 million, or 21%, to $524.9 million in 2003 from $432.2 million in 2002. Expenses for natural gas resulted in a $44 million increase in operating expenses in 2003 as compared to 2002. High natural gas prices were a major contributor to this increase, resulting in an estimated $51 million increase in 2003 as compared to 2002. The effects of the higher natural gas prices were partially offset by a reduction in natural gas usage due to planned downtime for maintenance turnarounds and more focused efforts on utilizing alternative energy options. The increase in operating expenses also reflected $106 million related to the addition of Memphis refinery operations beginning in March 2003, partially offset by $56 million related to the absence of Hartford refinery operations in 2003.

General and Administrative Expenses. General and administrative expenses increased $15.3 million, or 30%, to $67.1 million in 2003 from $51.8 million in 2002. The increase is mainly attributable to a $9.8 million accrual for incentive compensation and increases in costs for certain employee benefit programs, insurance, legal fees, Sarbanes-Oxley Act compliance and non-recurring tax consulting and ERP system improvement costs. In addition, cost reduction measures initiated in 2002 as a result of the restructuring of our St. Louis general office were partially offset by additional administrative activities required in connection with the acquisition of our Memphis refinery in March 2003.

Stock-Based Compensation Expense. Stock-based compensation expense increased $3.6 million, or 26%, to $17.6 million in 2003 from $14.0 million in 2002. The increase related to the grant of additional options in 2002 and 2003.

Depreciation and Amortization. Depreciation and amortization increased $17.3 million, or 19%, to $106.2 million in 2003 from $88.9 million in 2002. This increase was principally due to capital expenditure activity and the addition of the Memphis refinery in 2003.

Interest Expense and Finance Income, net. Interest expense and finance income, net increased by $13.3 million, or 13%, to $115.1 million in 2003 from $101.8 million in 2002. The increase was primarily due to additional interest expense related to a net increase in long-term debt of $527 million and lower interest income, partially offset by lower financing costs and higher capitalized interest in 2003.

Income Tax (Provision) Benefit. We recorded an income tax provision of $64.0 million in 2003 compared to an income tax benefit of $81.3 million in the corresponding period in 2002. Our effective tax rate was 34.1% in 2003 as compared to 38.7% in 2002. Our subsidiaries are subject to different statutory tax rates. These differing tax rates and the differing amount of taxable income or loss recognized by each subsidiary impact our consolidated effective tax rate. The decrease in our 2003 consolidated effective tax rate in 2003 as compared to 2002 resulted from a higher percentage of our 2003 consolidated income being recognized by Sabine, which has a lower effective tax rate than other subsidiaries.

As of December 31, 2003, we have a net deferred tax liability of $0.6 million (PRG—$22.9 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, in 2002 we provided a valuation allowance of $2.8 million related to our deferred tax assets. The likelihood of realizing our deferred tax assets 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 our deferred tax assets 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, 2003 of approximately $420 million and $192 million (PRG—$361 million and $129 million), respectively. Our regular tax net operating loss carryforwards will begin to expire with the year ending December 31, 2018, to the extent they have not been used to reduce taxable income prior to such time. Approximately 50% of the regular tax net operating carryforwards will have expired as of December 31, 2020, with a full 100% expiring by December 31, 2022, to the extent they have not been used to reduce regular taxable income prior to such time. Our alternative minimum tax net operating loss carryforwards will begin to expire with the year ending December 31, 2012, to the extent they have not been used to reduce alternative minimum taxable income prior to such time. Approximately 16% of the alternative minimum tax net operating carryforwards will expire as of December 31, 2012, with an additional 40% having expired as of December 31, 2019 and a full 100% expiring by December 31, 2022, to the extent they have not been used to reduce alternative minimum taxable income prior to such time. If we experience an ownership change of more than 50% during any three-year testing period as defined in Section 382 of the Internal Revenue Code, the timing and extent of the utilization of our net operating loss carryforwards, other losses and tax credits could be affected. 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. We expect a change in control as defined above in connection with the financing of the Delaware City refinery thus causing the realization of net operating loss carryforwards, other losses and tax credits to extend further in the future. However, we do not expect this change in control to impact our overall ability to realize our net operating loss carryforwards, other losses and tax credits in the future. Therefore, we do not anticipate the need for an additional valuation allowance as a result of this expected change in control.

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 decreased $79.0 million, or 1%, to $5,906.0 million in 2002 from $5,985.0 million in 2001. This decrease was primarily attributable to the closure of our Hartford refinery in late September 2002.

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 was 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.

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. Stock-based compensation expense totaled $14.0 million for 2002, due to the grant of 4,031,00 options during the year. In 2002, we adopted the fair value recognition provisions of SFAS No. 123. Prior to 2002, we accounted for stock-based compensation under the recognition and measurement provisions of APB Opinion No. 25. No stock-based compensation cost was reported in 2001, as all options granted in 2001 and earlier had an exercise price equal to the market value of the underlying common stock on the date of grant.

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.

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 the first page of this Annual Report on Form 10-K, under the heading “Forward-Looking Statements”.

Market. Market conditions for the first two months of the first quarter of 2004 have been strong. The Gulf Coast 2/1/1 crack spread has averaged approximately $5.70 per barrel, the Chicago 3/2/1 crack spread has averaged approximately $6.65 per barrel, and the WTI/Maya differential has averaged approximately $9.30 per barrel. We believe the market outlook for 2004 as a whole will be favorable for the U.S. refining industry due to an increasingly tight supply and demand balance for oil products. We expect that the continuing recovery of the economy will support strong demand for refined products and that more stringent requirements on fuel sulfur content mandated by the Federal Environmental Protection Agency will result in a tighter supply of refined products. The phase-in of the low-sulfur fuel requirements began on January 1, 2004 and will continue through 2010.

It is common practice in our industry to look to benchmark market indicators as a proxy predictor for 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 crude oil and product grade differentials, ancillary crude and product costs such as transportation, storage and credit fees, inventory fluctuations and price risk management activities.

Refinery Operations. 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, sulfur, 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 in 2004 under our long-term crude oil supply agreement. Ancillary crude costs, primarily transportation, at Port Arthur averaged $0.70 per barrel of crude oil throughput in the year ended December 31, 2003. In 2004, we expect our full year crude oil throughput rate to approximate 220,000 bpd. This throughput rate reflects a maintenance turnaround of the reformer unit in the first quarter and maintenance turnaround of the crude, coker, hydrocracker, and hydrotreater units in the later part of the year. Based on current market conditions, the scheduled maintenance turnaround of the reformer unit, which began in late December 2003 and was completed on February 6, 2004, and subsequent mechanical issues after the reformer unit start-up, we expect the crude oil throughput rate at our Port Arthur refinery to approximate 205,000 bpd to 215,000 bpd in the first quarter of 2004.

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 $1.40 per barrel of crude throughput in the year ended December 31, 2003. In 2004, we expect our full year crude oil throughput rate to approximate 139,000 bpd. This throughput rate reflects a month-long full refinery maintenance turnaround that will begin in early March. Based on current market conditions and the full refinery turnaround in March, we expect the crude oil throughput rate at our Lima refinery to approximate 100,000 bpd to 110,000 bpd in the first quarter of 2004.

Our Memphis refinery was acquired effective March 3, 2003 and averaged approximately 152,500 bpd of crude oil throughput for the period from March 3, 2003 through December 31, 2003. We 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 of approximately $0.63 per barrel, resulting from location premiums for refined products, partially offset by crude oil transportation costs. In 2004, we expect our full year crude oil throughput rate to approximate 160,000 bpd. Based on current market conditions, we expect the crude oil throughput rate at our Memphis refinery to approximate 140,000 bpd to 150,000 bpd in the first quarter of 2004. The crude oil throughput rate will be supplemented with more economic intermediate feedstocks in order to keep downstream units operating at full rates and to take advantage of strong crack spreads.

Operating Expenses. Natural gas is the most variable component of our operating expenses. On an annual basis, our Port Arthur, Memphis and Lima refineries purchase approximately 29 million mmbtu of natural gas, with most of these purchases relating to our Port Arthur refinery. In a $4.70 per mmbtu natural gas price environment and assuming average crude oil throughput levels, our annual operating expenses should range between $520 million and $550 million. It is also important to note that, under contracts that expire in September 2004, we contract for the purchase of natural gas on a calendar month basis and set the price at the beginning of the month. Therefore, our natural gas costs reflect the price of natural gas on the day the contract is set, and not the average price for the period. We are reviewing options to mitigate our exposure to natural gas price fluctuations.

General and Administrative Expenses. We expect first quarter general and administrative expense, excluding incentive compensation expense, will range from $13 million to $15 million. Our incentive compensation expense for 2004 will be based solely on our achievement of earnings per share results in excess of a minimum of $2.00 per share. In administering the plan, our Board of Directors typically exclude refinery restructuring charges and other special items, stock-based compensation expense, and bonus accruals in determining the threshold earnings per share level.

Stock-based Compensation Expense. We recognize non-cash, stock-based compensation expense computed under Statement of Financial Accounting Standard, or SFAS, No. 123 Accounting for Stock-Based Compensation for all stock options granted beginning in 2002. Stock-based compensation expense in 2004, for options granted in 2002 through 2004, will approximate $19 million to $20 million.

Depreciation and Amortization. Depreciation and amortization in the fourth quarter of 2003 was $29.2 million. This quarterly rate will increase in future periods based upon the completion and placing into service of our capital expenditure activity. Capital activity is generally depreciated over a 25-year life. 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 December 31, 2003, our annual gross interest expense will be approximately $133 million and amortization of deferred financing costs will be approximately $9 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, which we estimate will be approximately $25 million to $30 million in 2004.

Income Taxes. We expect our effective income tax rate for 2004 will range from approximately 35% to 38%.

Capital Expenditures and Turnarounds. Capital expenditures and turnarounds for the year ended December 31, 2003 totaled $261.3 million. This amount excludes the purchase price of the Memphis refinery. We plan to expend approximately $500 million to $520 million for turnarounds and capital expenditures, excluding capitalized interest, in 2004. Approximately $113 million of these expenditures relate to turnaround activity. We plan to fund capital expenditures with internally generated funds and cash on hand. If internally generated funds and cash on hand are insufficient, we will reduce our capital expenditure plans accordingly.

We are continuing to evaluate a project to reconfigure the Lima refinery to process a more sour and heavier crude slate. We are also evaluating a similar project at our Memphis refinery. These initiatives are in a very preliminary stage.

Delaware City Refinery Acquisition. In January 2004, we announced our plans to acquire Motiva Enterprises LLC’s 180,000 bpd Delaware City Refining Complex located in Delaware City, Delaware. See “—Recent Developments in 2004” above. We expect to complete the acquisition in the second quarter of 2004 at a purchase price of $800 million, plus the value of the petroleum inventories. We expect the inventories will be approximately $100 million. We expect to finance the purchase price with equal parts equity and debt. We intend to enter into long-term crude oil supply agreements as well as off-take agreements in relation to the operations of this refinery. These agreements will have market based pricing mechanisms. The refinery is capable of processing more than 180,000 barrels per day, thus adding approximately 30 percent to our capacity base. We will utilize the New York Harbor Reformulated Gasoline 3/2/1, or NYH RFG 3/2/1, crack spread as a benchmark for the Delaware City refinery operations. Our actual results will vary as our crude oil and product slates differ from the NYH RFG 3/2/1 slate and for other ancillary costs. Operating expenses will be impacted by the level of production of the petroleum coke gasification unit.

As of December 31, 2003, we had a cash and short-term investment balance of $432.6 million of which $378.6 million was held by PRG, $48.0 million was held by Premcor Inc., and $6.0 million was held by other Premcor Inc. subsidiaries. As of December 31, 2002, we had a cash and short-term investment balance of $172.3 million of which $121.4 million was held by PRG, $37.3 million was held by Premcor Inc., and $13.6 million was by other Premcor Inc. subsidiaries.

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. Cash was restricted under these requirements totaling $66.6 million and $61.7 million as of December 31, 2003 and 2002, respectively. 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. Non-cash dividends of $174.7 million were made in 2003. No such dividends were made in 2002.

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 Risk Limited, in 2002 to provide additional liability coverage for such claims. Premcor Inc. funded $4.0 million as of December 31, 2003, 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 $182.4 million for the year ended December 31, 2003 as compared to net cash flows provided by operating activities of $15.9 million for the year ended December 31, 2002 and $439.2 million for the year ended December 31, 2001. Cash flows from operating activities were mainly impacted by strong cash earnings for the years ended December 31, 2003 and 2001. The significantly lower cash provided from operating activities in 2002 is mainly attributable to weak market conditions, which resulted in poor operating results. Working capital as of December 31, 2003 was $860.1 million, a 1.87-to-1 current ratio, versus $320.9 million as of December 31, 2002, a 1.57-to-1 current ratio. The increase in working capital was primarily due to strong operating results, the Memphis refinery acquisition, and cash proceeds from our June 2003 debt offering.

Working capital experienced some significant fluctuations as of December 31, 2003 as compared to December 31, 2002. Our accounts receivable, prepaid expenses, and inventory balances increased primarily due to the acquisition of and subsequent activity at our Memphis refinery. Inventories also increased due to the purchase of a 2.7 million barrel crude oil linefill for our Lima refinery from Morgan Stanley Capital Group Inc, or MSCG. Under an agreement with MSCG we were obligated to purchase the barrels in October 2003; however, we terminated the agreement in June 2003 and purchased the crude oil at a net cost of approximately $80 million. Our accounts receivable and accounts payable balances increased due to greater buying and selling activity related to the supply of domestic crude oil for our Lima and Memphis refineries. Our accrued expenses and accrued taxes other than income tax balances increased due to Memphis refinery activity. Accrued expenses were further affected by higher accrued interest due to changes in interest payment dates under our new long-term debt commitments, an accrual for the Memphis acquisition earn-out payment due in 2004, accrued bonuses for 2003 under our incentive compensation plans, and accruals related to the lease obligations under the rejected CRE leases.

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.

Cash flows used in investing activities were $710.3 million for the year ended December 31, 2003 as compared to $144.5 million for the year ended December 31, 2002 and $152.9 million for the year ended December 31, 2001. The cash flows used in investing activities in 2003 reflected the acquisition of the Memphis refinery, including a subsequent contingency payment, of $490.2 million and proceeds from the sale of certain processing units and ancillary assets at our Hartford refinery of $40 million. Aside from these items, activity in 2003, 2002, and 2001 primarily reflected capital expenditures including turnarounds.

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, regulations pertaining to new product standards, and regulations pertaining to occupational safety and health issues. Our total mandatory capital and refinery maintenance turnaround expenditures, excluding expenditures for new product standards discussed below, were $100.7 million, $63.5 million, and $86.6 million for the year ended December 31, 2003, 2002, and 2001, respectively. We estimate that total mandatory capital and turnaround expenditures, excluding expenditures for new product standards, for all three refineries will average $150 million per year over the next four years and the budget for these expenditures is approximately $235 million for 2004. 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 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 expenditures discussed above, we expect to incur total expenditures of approximately $645 million, including $444 million that we expect to expend through 2006, in order to comply with environmental regulations related to the new stringent sulfur content specifications. The total costs have been revised from an aggregate of $682 million reported in the 2002 Annual Report on Form 10-K for gasoline and diesel fuel specification requirements and include further refinement of the plans and in particular a more detailed plan for the newly acquired Memphis refinery.

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 produce gasoline under the new sulfur standards at our Port Arthur refinery, and we expect to comply with the gasoline standards at our Memphis refinery in the second quarter of 2004. As a result of the corporate pool averaging provisions of the regulations and our possession of what we believe, based on current information, to be sufficient sulfur credits, we intend to defer a significant portion of the investment required for compliance at our Lima refinery until the end of 2005. We believe, based on current estimates, that compliance with the new Tier 2 gasoline specifications will require us to make capital expenditures in the aggregate through 2005 of approximately $315 million, of which $194 million had been incurred as of December 31, 2003. Future revisions to this cost estimate, and the estimated time during which costs are incurred, may be necessary. As of December 31, 2003, we have outstanding contract commitments of $89 million related to the design and construction activity at our 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 $330 million. Future revisions to the cost estimate, and the estimated time during which costs are incurred, may be necessary. 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 fourth quarter of 2005.

In 2004, we expect to make expenditures of approximately $175 million for compliance with Tier 2 gasoline standards and on-road diesel regulations, excluding capitalized interest. We spent $144.4 million and $56.7 million in 2003 and 2002, respectively, 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 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. 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.

In 2003, we announced plans to expand our Port Arthur, Texas refinery. The plans include increasing Port Arthur’s crude oil throughput capacity from its current rate of 250,000 bpd to approximately 325,000 bpd, and expanding the coker unit capacity from its current rated capacity of 80,000 bpd to 105,000 bpd, which will further increase our ability to process lower cost, heavy sour crude oil. This project is estimated to cost between $200 million and $220 million and is expected to be completed by the beginning of 2006. This project will be funded primarily from the proceeds of the $300 million in senior notes issued in June 2003, which are described below in “—Cash Flows from Financing Activities.” Our discretionary capital expenditures were $16.2 million, $28.4 million, and $57.1 million for the year ended December 31, 2003, 2002, and 2001, respectively. Our budget for discretionary capital expenditures is approximately $100 million for 2004, which includes approximately $80 million related to the Port Arthur expansion project. We plan to fund mandatory and discretionary capital expenditures with available cash and cash flow from operations and will adjust our annual expenditures accordingly.

The following table summarizes the capital expenditures described above for the following years (in millions):

Cash flows provided by financing activities were $787.2 million for the year ended December 31, 2003, as compared to cash flows used in financing activities of $214.1 million for the year ended December 31, 2002 and $66.3 million for the year ended December 31, 2001.

In 2003, Premcor Inc. received net proceeds of approximately $306 million from a public offering of 13.1 million shares of common stock and a private offering of 2.9 million shares of common stock with Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, a subsidiary of Occidental Petroleum Corporation, and certain Premcor executives. In February 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bear interest at 9¹/2% per annum and $175 million, due in 2010, bear interest at 9¹/4% per annum. A portion of the net proceeds of these transactions was utilized to redeem the remaining $40.1 million principal balance of Premcor USA’s 11¹/2% subordinated debentures at a $2.3 million premium; to repay PRG’s $240 million floating rate loan at par; and to purchase, in the open market, $14.7 million in face value of a portion of the 12¹/2% senior notes at a $2.7 million premium. In June 2003, PRG completed an offering of $300 million in senior notes, due 2015, bearing interest at 7¹/2% per annum. In November 2003, PRG issued $385 million in aggregate principal amount of senior and senior subordinated notes, which consisted of $210 million of senior notes due 2011, bearing interest at 6³/4% per annum and $175 million of senior subordinated notes due 2012, bearing interest at 7³/4% per annum. PRG used the proceeds from these notes to redeem its 8³/8% senior notes, 8⁵/8% senior notes, and 8⁷/8% senior subordinated notes which totaled $385 million in the aggregate at a $12.2 million premium. PACC made $14.2 million of scheduled principal payments on its 12¹/2% senior notes in 2003. In 2003, we incurred deferred financing costs of $29.9 million related to the issuance of our new bonds and the amendment of our credit agreement.

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. 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 9¹/2% 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 11¹/2% 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 12¹/2% Senior Notes. In 2002, we incurred deferred financing costs of $11.4 million primarily related to the consent process that permitted the Sabine restructuring.

In 2001, we repurchased in the open market $21.3 million in face value of our 9¹/2% senior notes, $30.6 million in face value of our 10⁷/8% senior notes, and $5.9 million in face value of our 11¹/2% exchangeable preferred stock for an aggregate purchase price of $48.5 million. In 2001, we incurred deferred financing costs of $10.2 million principally associated with the amendment of our credit agreement.

Cash and cash equivalents restricted for debt repayment reflected changes to the portion of restricted cash that related to future principal payments. The change in restricted cash related to future interest payments is included in cash flows from operating activities.

In 2003, Premcor Inc. made capital contributions to Premcor USA of $297.5 million (2002—$442.9 million) and Premcor USA subsequently contributed $263.3 million (2002—$248.1 million) to PRG, all primarily for the acquisition of the Memphis refinery in 2003 and for the repayment of long-term debt. In 2001, PRG returned capital of $25.8 million to Premcor USA.

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.

We have substantial indebtedness that has affected our financial flexibility historically and may significantly affect our financial flexibility in the future. As of December 31, 2003, we had total long-term debt, including current maturities, of $1,452.1 million (PRG—1,441.8 million) and cash, short-term investments and cash restricted for debt service of $499.2 million (PRG—$445.2 million). We had stockholders’ equity of $1,145.2 million, resulting in a total debt to total capitalization ratio of 56%. PRG had stockholder’s equity of $1,026.6 million, resulting in a total debt to total capitalization ratio of 59%. We may also incur additional indebtedness in the future, although our ability to do so will be restricted by the terms of our existing indebtedness. The level of our indebtedness has several important consequences for our future operations, including that:

Our long-term debt instruments subject us to significant financial and other restrictive covenants. Covenants contained in various indentures and credit 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, consummate certain asset sales or asset swaps, enter into certain transactions with affiliates, make certain payments to Premcor Inc. or to other subsidiaries or affiliates, enter into sale and leaseback transactions, conduct businesses other than our current businesses, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Our credit agreement also requires our subsidiaries to satisfy or maintain certain financial condition tests, as more fully described below in “—Credit Agreements”. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and they may not meet such tests. In addition, PRG’s credit agreement currently limits the amount of future additional indebtedness that may be incurred by PRG and its subsidiaries to $15 million. Accordingly, it may be necessary for us to obtain a waiver or amendment of our credit agreement to incur additional indebtedness in excess of the PRG credit agreement limitation. There is no assurance that such waiver or amendment can be obtained, or obtained on a timely basis.

PRG’s credit agreement, which was amended and restated in February 2003, provides for letter of credit issuances of up to the lesser of $785 million or an amount available under a defined borrowing base, less outstanding borrowings. The facility may be increased to $800 million under certain circumstances. PRG utilizes this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. The borrowing base includes PRG’s cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, net obligations on swap contracts and PACC’s eligible hydrocarbon inventory. The credit agreement expires in February 2006. As of December 31, 2003, the borrowing base was $1,348.9 million (December 31, 2002 — $815.3 million), with $602.1 million (December 31, 2002—$597.1 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 sublimits 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 PRG’s cash and cash equivalents, receivables, crude oil and refined product inventories and trademarks and PACC’s hydrocarbon inventory. PRG’s 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 rate plus a defined margin, at our option based on certain restrictions. As of December 31, 2003 and 2002, 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. The covenants also provide for a cumulative cash flow test that from January 1, 2003 to February 10, 2006 must not be less than zero.

PRG also has a $40 million cash-collateralized credit facility expiring in May 2004. This facility was arranged in support of lower interest rates on the Series 2001 Ohio Bonds. In addition, this facility can be utilized for other non-hydrocarbon purposes. As of December 31, 2003, $18.0 million (December 31, 2002—$10.1 million) of the line of credit was utilized for letters of credit. With the expiration of this facility in May, we have the option to extend the expiration date of the current facility, replace the facility, or transfer the existing letters of credit to the $785 million credit facility. We also have the ability to fix the interest rate on the Ohio bonds in which case additional security would no longer be required.

In the table below, we summarize the payment schedule for our contractual obligations as of December 31, 2003 (in millions):

Certain purchase obligations under long-term contracts cannot be estimated due to the variable terms related to volumes and prices. See the description of our purchase obligations and other long-term liabilities below.

Operating Leases. We lease refinery equipment, crude oil tankers, catalyst, tank cars, office space, and office equipment from unrelated third parties with lease terms ranging from 1 to 10 years with the option to purchase some of the equipment at the end of the lease term at fair market value. We lease some land in relation to our Memphis refinery operations with terms that extend 29 years and 47 years. The leases generally provide that we pay taxes, insurance, and maintenance expenses related to the leased assets. We are also subject to remaining payments on 28 leases that were rejected from the CRE bankruptcy as described above in “—Factors Affecting Comparability—Discontinued Operations”. The terms of these leases range from 1 to 13 years. Certain of these properties are being subleased.

Capital Expenditure Commitments. As of December 31, 2003, we have entered into contracts totaling $89 million related to the design and construction activity at our refineries for Tier 2 gasoline compliance. We will make these expenditures in 2004.

Purchase Obligations. We enter into contracts for the purchase of goods and services on a regular basis in relation to the purchase of crude oil, natural gas, and other production and utility related items. With the exception of the long-term crude oil contract discussed below, our crude oil purchase contracts have terms ranging from one to three months and are based on market prices or a formula reflecting a differential to a market index. We also enter into contracts related to the supply of other feedstocks and blendstocks used in our refining processes and the terms of these contracts are usually under one year or can be cancelled within one year.

We are party to a long-term crude oil supply agreement with an affiliate of PEMEX, which currently 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. The pricing of the crude oil is based on then current market prices. The volume of crude oil is adjusted semiannually based on a formula specified in the contract. Future obligations can be further affected by a price adjustment mechanism designed to provide us with a minimum average coker margin over the first eight years of the contract as described in “—Factors Affecting our Operating Results”. The price adjustment mechanism expires in 2009 and the agreement expires in 2011.

We also have certain contracts related to the fuel supply for our refineries. Our natural gas contracts provide firm delivery amounts but also provide flexibility in volumes at certain pricing formula levels. These contracts are based on market prices or a formula reflecting a differential to a market index. These contracts are also short term in nature or can be canceled with notice. We purchase hydrogen at our Port Arthur refinery under a 20-year

contract that provides minimum volumes and the flexibility to purchase additional volumes if necessary. Under this contract we are required to purchase minimum volumes on a quarterly basis or make payments equal to what would be due for these minimum volumes. We made payments totaling $61 million in 2003 in relation to this hydrogen supply contract and we would need to make minimum payments of approximately $51 million on an annual basis under the minimum requirements of the contract. Minimum requirements would be waived in the case of certain events occurring beyond our control.

We also contract for certain services under long-term contracts, some of which have minimum contract volumes or dollar amounts. We have a contract with Millennium Pipeline Company, L.P. for the transportation of crude oil over its Millennium pipeline system as a source for transporting foreign crude oil to our Lima refinery. The contract expires in May 2005 and will automatically renew for one-year periods unless notice is given six months prior to a renewal date. We are obligated to transport certain minimum amounts of crude oil on the Millennium pipeline or pay an amount equal to the transportation rate for each barrel of crude oil below the commitment amount. The minimum amounts are determined on an annual basis. Under this contract we made payments totaling $11 million in 2003, and we would need to make minimum payments of approximately $10 million on an annual basis if we did not meet any of our committed volumes. We also have a contract allowing us to store and throughput petroleum products at certain third party terminal locations, which expires in April 2009. We are obligated to meet certain minimum dollar amounts related to throughput activity on an annual basis under this agreement or make payments for the amounts below the commitment level. Under this contract we made payments totaling $10 million in 2003, and our minimum payments would equate to approximately $10 million on an annual basis if we did not meet our committed amounts. We also have a ten-year contract expiring in 2011 for the operation and maintenance of a petroleum coke handling system at our Port Arthur refinery. We are obligated to meet certain minimum dollar amounts related to petroleum coke handling fees on an annual basis. Under this contract our minimum payments would equate to approximately $7 million on an annual basis.

Other Long-term Liabilities. We have several pension benefit and postretirement benefit plans as further described in “—Critical Accounting Judgments and Estimates—Pension Benefit and Postretirement Employee Benefit Plans”, for which we have obligations extending into the future. In 2004, we expect to contribute $9 million to our pension plans and to make payments of $3 million related to our obligations under our other post retirement benefit plans.

Environmental and Legal Liabilities. As a result of our normal course of business, the closure of two of our refineries, and continuing obligations related to our previously owned retail operations, we are party to certain legal proceedings and environmental-related obligations. In relation to these matters and obligations, we have accrued, on primarily an undiscounted basis, $98 million as of December 31, 2003 (December 31, 2002—$93 million). We expect to spend approximately $10 million to $15 million in 2004 related to the environmental remediation activities.

Upon closure of our Blue Island and Hartford refineries we recorded a liability for environmental remediation obligations associated with their closure. The environmental obligations take into account costs that are reasonably foreseeable at this time. In relation to the Blue Island liability, we are currently in discussions with governmental agencies concerning a remediation program and expect to have a final plan in place in 2004. In relation to the Hartford liability, we are in preliminary stages of producing a remediation plan. As the remediation plans are finalized and as work is performed, adjustments of the liabilities may be necessary. We have other environmental remediation activity related to previously owned assets and currently operating assets for which we have also recorded a liability and which may require adjustments in the future as more information becomes available.

The following related party transactions are not discussed elsewhere in the Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As of December 31, 2003, PRG had a payable to Premcor Inc. for management fees paid by Premcor Inc. on PRG’s behalf of $0.1 million (2002—$8.3 million). As of December 31, 2003, PRG also had a loan receivable from Premcor Inc. for $8.9 million (2002—$8.1 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.

As of December 31, 2003, PRG had an amount due to affiliates of $41.2 million (2002—$24.5 million) related to income taxes and its tax sharing agreement with Premcor Inc. and its predecessor.

As of December 31, 2003, PRG had a receivable from The Premcor Pipeline Co. of $5.9 million related to amounts that PRG paid on behalf of The Premcor Pipeline Co. As of December 31, 2003, PRG had a payable to The Premcor Pipeline Co. of $2.0 million (2002—$8.4 million) for pipeline tariffs and fees due to The Premcor Pipeline Co for use of pipelines and storage for the Memphis operations.

These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.

We entered into an agreement with Fuel Strategies International (“FSI”) effective June 2002. Pursuant to this agreement, FSI provides monthly, consulting services related to our petroleum coke and commercial operations. The agreement automatically renews for additional one-year periods unless terminated by either party upon 90 days notice prior to expiration. The principal of FSI is the brother of our chairman and chief executive officer. For the years ended December 31, 2003 and 2002, we incurred fees of $0.4 million and $0.2 million, respectively, related to this agreement.

We 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 we incurred a monitoring fee equal to $2.0 million per annum subject to increases relating to inflation. The monitoring agreement was terminated effective March 31, 2002. We recorded expenses related to the annual monitoring fee and the reimbursement of out-of-pocket costs of $0.3 million and $2.5 million for the years ended December 31, 2002 and 2001, respectively.

The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in our consolidated financial statements. The SEC has defined a company’s most critical accounting policies as those that are most important to the portrayal of the company’s financial condition and results of operations that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates of matters that are inherently uncertain. These judgments and estimates often involve future events. Based on this definition, we have identified the critical accounting policies and judgments addressed below. In addition, management has discussed these accounting policies and judgments with the Audit Committee of our Board of Directors. Although we believe that our estimates and assumptions are reasonable, they are based upon information available at the time of the valuations. Actual results may differ significantly from estimates under different assumptions or conditions. The following critical accounting judgments and estimates are based on our accounting practices during 2003.

Contingencies. We account for contingencies in accordance with the 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 liabilities 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.

Environmental Matters. Accruals for environmental matters are recorded on a site by site basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated as specifically defined in SOP 96-1, Environmental Remediation Liabilities. To determine our ultimate liability at these sites, we have used third party engineers and attorneys to assist in the evaluation of several factors, including the extent of contamination, currently enacted laws and regulations, existing technology, the most appropriate remedy, and identification of other potentially responsible parties, among other factors. Actual settlement of our liability for environmental matters could differ from our estimates due to a number of uncertainties, such as the extent of contamination at a particular site, the final remedy, the financial viability of other potentially responsible parties, and the final apportionment of responsibility among the potentially responsible parties. Actual amounts could also differ from our estimates as a result of changes in future litigation costs to pursue the matter to ultimate resolution including both legal and remediation costs.

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.

In 2003, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants (“AcSEC”) approved a statement of position (“SOP”) entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. Final approval by the Financial Accounting Standards Board of the SOP is pending. This SOP requires companies, among other things, to expense as incurred certain turnaround costs. Adoption of the SOP would require that any existing unamortized turnaround costs be expensed immediately, as a cumulative effect of an accounting change, net of income taxes, in the consolidated statement of operations. If this proposed change were in effect at December 31, 2003, we would have been required to write-off unamortized pretax turnaround costs of approximately $76 million. As the SOP is currently proposed, the provisions of the SOP would be effective for fiscal years beginning after December 15, 2004. We are currently assessing the impact of other provisions of this SOP, in particular the provisions that relate to the capitalization of certain project costs and the adoption of component accounting for property, plant and equipment.

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, 2003 the replacement cost (market value) of our crude oil and refined product inventories exceeded its carrying value by approximately $174 million, or approximately $7 per barrel over cost. If the market value of these inventories had been lower by over $7 per barrel as of December 31, 2003, we would have had to write-down the value of our inventory. If prices significantly decline from year-end 2003 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. If we have changes in events or circumstances,

including reductions in anticipated cash flows generated by our operations or a determination to abandon or divest certain assets, such assets could be impaired which would result in a non-cash charge to earnings. If such circumstances arise, we recognize an impairment for the difference between the carrying amount and the fair value of the asset, if the carrying amount of the asset does not exceed the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We use the present value of the expected cash flows from that asset to determine fair value. In 2001, we closed our Blue Island refinery and in 2002 we ceased refining operations at our Hartford refinery. These assets were reduced to their fair value when we announced our exit plans. We also recorded liabilities associated with estimated refinery closure and decomissioning costs, and employee severance expenses. We also established environmental liabilities in accordance with AICPA Statement of Position 96-1 Environmental Remediation Liabilities. As of December 31, 2003, the carrying value of the Blue Island and Hartford refinery assets, excluding assets that continue to be utilized for our supply and distribution operations at both sites, has been reduced to zero.

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. As of December 31, 2003, we had 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. We determine the fair value of our stock options using the Black-Scholes Option Pricing Model. The model requires that we make certain assumptions as to the expected lives of our options, the expected volatility of our stock price, expected dividend rates and the risk-free-rate of return at the date of each grant. Judgment is required in selecting these assumptions and management believes its method for selecting these assumptions is reasonable and consistently applied.

Pension Benefit and Postretirement Employee Benefit Plans. We have four defined benefit pension plans and two postretirement health care and life insurance benefit plans that require us to use judgment in selecting the actuarial assumptions used to estimate our expense and liability for these plans. Based on the actuarially determined amounts we record a liability for the cost of the plans less any plan assets. The plan assets are comprised of total contributions to the plan and investment income earned. The expense associated with these plans is recorded to operating expenses and general and administrative expenses depending on the plan. As of December 31, 2003, we have a liability of $57.9 million for our postretirement plan obligations and a net liability of $9.2 million for our pension plan obligations, which reflects plan assets of $3.7 million.

The weighted-average assumptions used in the actuarially determined liability for our pension plans (December 31 measurement date) and postretirement health care plans (September 30 measurement date) are as follows:

In addition to these assumptions for the health care plans, we utilize a health care cost trend rate that currently reflects a 12% increase in 2004, declining by 1% per year to an ultimate rate of 5% in 2011.

Our discount rate is based on the yield of a published long-term corporate bond index that has a duration equivalent to our obligations under the plans. The discount rate is sensitive to changes in interest rates and a decrease in the discount rate will increase the estimated liability of the plans and increase future expenses related to the plans. Our expected rate of return on plan assets of 8.5% is based on an inflation assumption of 3% and real rate of return of 5.5%. This real rate of return was derived using an asset allocation model developed by our investment consultant and takes into consideration historical, long-term equity and fixed income securities experience. In order to achieve this return, our pension plan investment policy statement established a long-term asset allocation structure of 60% in equity securities and 40% in fixed income securities. The actual return on our plan assets is subject to our investment mix and general market conditions. The average rate of compensation increase reflects our expectations of average pay increases over the periods benefits are earned. The health care cost trend rate is based on an assessment of overall health care cost increases and our company’s experience. We review all of these assumptions on an annual basis.

Presented below is a table that demonstrates how a 0.5% decrease in the discount rate assumption and a 0.5% increase in the health care cost trend rate assumption would effect our benefit liabilities as of December 31, 2003 and our 2004 expenses (in millions):

Because our pension asset funds are newly funded, a 0.5% decrease in our expected return on plan assets would not have a material impact on our expenses at this time.

Two of our pension plans are qualified and funded based on requirements under the Employment Retirement Income Security Act of 1974, as amended, or ERISA. We made contributions of $4.9 million to these plans in 2003. Our Senior Executive Retirement Plan will be funded beginning in 2004. We expect to contribute approximately $9 million in 2004 for all pension-related plans. As established by our benefit committee, we have a pension plan investment policy statement, which designates a long-term asset allocation structure of 60% in equity securities and 40% in fixed income securities to reach our investment goals. We established our investment policy at the same time that we were restructuring our refining assets and corporate infrastrucuture. As a result, the need to maintain asset liquidity delayed full implementation of the investment strategy for the long- term horizon. When the plans were initially funded in September 2003, an amount estimated to cover the cash flow needs of upcoming benefit payments during fourth quarter 2003 and early 2004 was invested in a money market instrument. The balance of the funding was invested on a 60% equity and 40% fixed income basis, consistent with our long-term investment strategy.

Our benefit committee recognizes that even though the investments are subject to short-term volatility, it is critical that a long-term investment focus be maintained. This prevents ad-hoc revisions to the philosophy and policies in reaction to short-term market fluctuations. In order to preserve this long-term view, the committee will review performance of the investment funds quarterly and will review the asset allocation, including rebalancing, and investment policy statement annually. To assure a rational, systematic, and cost-effective approach to rebalancing, the committee has chosen certain “trigger points” as the maximum upper and lower limits for a specified asset class. If the percentage of the plan’s assets in a particular asset class has deviated from the target beyond a trigger point, the committee will rebalance the portfolio to bring all asset classes in line with the adopted guideline percentages.

Medicare Act provides Medicare coverage for prescription drugs up to a certain amount above a deductible and then provides no Medicare coverage until expenses reach a higher threshold. The law also provides federal subsidy to sponsors of retiree health care benefit plans. Companies that sponsor postretirement benefit plans are evaluating potential changes to their postretirement plans in order to take advantage of this new coverage and they are evaluating the accounting treatment of the various options provided by the act and of any changes to their plans. The FASB has issued a FASB Staff Position, or FSP, that provides additional options to companies for the recognition of plan changes and requires certain disclosures pending further consideration of the underlying accounting principles.

Refinery Restructuring and Other Charges. We have closed refineries and undertaken major restructurings of our general and administrative operations in recent years. In order to identify and calculate the associated costs of these activities, management makes assumptions regarding estimates of shut-down costs, equipment dismantling costs, the fair value of assets held for sale or disposal, employee severance costs, work force transition costs and other contractual arrangements. Prior to January 1, 2003, such costs were estimated and recorded as a liability on the date we made a commitment to an exit plan in accordance with EITF 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring). Restructuring liabilities are evaluated on a quarterly basis and adjusted as additional information becomes available or based on changes in circumstances. Effective January 1, 2003, we adopted SFAS 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. We report activities associated with closed refineries and administrative restructuring as “Refinery restructuring and other charges” in the consolidated statement of operations.

For a description of the new accounting standards that affect us, see Note 2 to our Consolidated Financial Statements included in Item 15 of this Form 10-K. The adoption of these standards has not had a material effect on our consolidated 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. 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 one to several 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 2003, with the acquisition of our Memphis refinery, our average fixed price purchase commitments when offset by our fixed price sale commitments increased to a net long inventory position of approximately 8 million barrels. As of December 31, 2003, if the market price of these net fixed price commitments had been lower by $1 per barrel, we would have recorded

additional cost of sales of approximately $8 million, based on our treatment of these contracts as derivatives. An increase in the market price would reduce cost of sales by a like amount. We may actively mitigate some or all of the price risk related to our fixed price purchase and sale commitments. These risk management decisions are based on many factors including the relative level and volatility of absolute hydrocarbon prices and the extent to which the futures market is in backwardation or contango. When the contract price of the following month futures contract is less than the contract price of the current, or prompt, month contract, a “backwardated” market structure exists, and when the contract price of the following month futures contract is greater than the contract price of the prompt month contract, a “contango” market structure exists. The cost of our risk management activities generally increases in a backwardated market. As we look ahead to 2004, we are reviewing our risk management program as we believe the cost of the program may exceed the benefit derived from this added layer of risk protection during less volatile oil market conditions.

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. 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 policies. 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 futures and options derivative positions. This analysis may differ from actual results. The fair value of each position was based on quoted futures prices. As of December 31, 2003, a $1 change in quoted futures prices would result in an approximate $10 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income. As of December 31, 2002, a $1 change in quoted futures prices would result in an approximately $2 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income.

Our results may also 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, 2003 the replacement cost (market value) of our crude oil and refined product inventories exceeded the carrying value by $174 million, or approximately $7 per barrel over cost. If the market value of these inventories had been lower by over $7 per barrel as of December 31, 2003, we would have had to write-down the value of our inventory. 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. If the market value of these inventories had been lower by over $12 per barrel as of December 31, 2002, we would have had to write-down the value of our inventory. Most of our hydrocarbon inventories are valued using the LIFO method, which are susceptible to a material write-down when prices decline dramatically. If prices decline significantly from year-end 2003 levels, we may be required to write-down the value of our LIFO inventories in future periods.

Our results are also sensitive to the fluctuations in natural gas prices due to the use of natural gas to fuel our refinery operations. Based on our average annual consumption of approximately 29 million mmbtu of natural gas, a $1 change per mmbtu in the price of natural gas would generally change our natural gas costs by $29 million. Our sensitivity to a change in the price of natural gas would also be impacted by our method of purchasing natural gas. We contract for the purchase of natural gas on a calendar month basis and set the price at the beginning of the month. Therefore, our natural gas costs will reflect the price of natural gas on the day the contract is set, and not the average price for the period. We are reviewing options to mitigate our exposure to natural gas price fluctuations.

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. We have an outstanding balance of long- term debt, including current maturities, of $1,452.1 million (PRG—$1,441.8 million). The weighted average interest rate on our fixed rate long-term debt is 8.9% (PRG—8.8%). We are subject to interest rate risk on our Ohio bonds and any direct borrowings under our credit agreement. As of December 31, 2003 and 2002, 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, 2003 and 2002, there were no cash 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

Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, evaluated, summarized and reported accurately within the time periods specified in the Securities and Exchange Commission’s (SEC) rules and forms. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. An evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operations of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation as of the end of the period covered by this report, the CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic SEC filings. The conclusions of the CEO and CFO from this evaluation were communicated to the Audit Committee. In connection with this evaluation, there were no breaches of such controls that would require disclosure to the Audit Committee or our auditors.

Changes in Internal Controls. There were no significant changes in our internal controls or in other factors that could significantly affect these internal controls in the last fiscal quarter of 2003. There were no significant deficiencies or material weaknesses; therefore, there were no corrective actions to be taken.

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”, and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for the 2004 Annual Meeting of Stockholders. Each executive officer is generally elected to hold office until the next Annual Meeting of Stockholders. The information required by Item 10 as to the directors of the Company is incorporated herein by reference to matters appearing under the headings “Nominees for Election”, “Audit Committee”, “Nominating and Corporate Governance Committee”, “Section 16(a) Beneficial Ownership Reporting Compliance”, and “Code of Business Conduct and Ethics” in the Proxy Statement for the 2004 Annual Meeting of Stockholders.

The information appearing under the headings “Compensation of Directors”, “Executive Compensation”, “ Employment Agreements”, “Compensation Committee Interlocks and Insider Participation”, “Compensation Committee Report on Executive Compensation” and “Stockholder Return Performance Presentation” of the Proxy Statement for the 2004 Annual Meeting of Stockholders is incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCK HOLDER MATTERS

The information appearing under the headings “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Executive Officers” in the Proxy Statement for the 2004 Annual Meeting of Stockholders is incorporated by reference.

Equity Compensation Plans. Premcor has three stock-based compensation plans pursuant to which options for the purchase of Premcor Inc. common stock may be granted. See Note 19 to the Consolidated Financial Statements included in Item 15 of this Form 10-K for further information on the plans. A proposal to increase the number of shares authorized under one of our plans is being submitted for consideration by our shareholders. See our Proxy Statement for the 2004 Annual Meeting of Stockholders for additional information.

The following is a summary of the shares reserved for issuance pursuant to our stock-based compensation plans as of December 31, 2003:

The information appearing under the heading “Related Party Transactions” in the Proxy Statement for the 2004 Annual Meeting of Stockholders is incorporated by reference.

The information appearing under the heading “Appointment of Independent Auditor” in the Proxy Statement for the 2004 Annual Meeting of Stockholders is incorporated by reference.

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:

We have audited the accompanying consolidated balance sheets of Premcor Inc. and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2003. 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 the 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 and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 in 2002.

We have audited the accompanying consolidated balance sheets of The Premcor Refining Group Inc. and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule 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 the 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 in 2002. Additionally, the consolidated financial statements were restated in 2002 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 was accounted for in a manner similar to a pooling of interests as described in Note 4 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. (together with its consolidated subsidiaries, “PRG”), a Delaware corporation also formed in 1988.

Premcor Inc., together with its consolidated subsidiaries (the “Company”), is an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products. The Premcor Refining Group Inc. and its indirect subsidiary, Port Arthur Coker Company L.P. (“PACC”), are Premcor Inc.’s principal operating subsidiaries. All of the Company’s employees, with the exception of certain executives, are employed by these two operating subsidiaries. PRG owns and operates three refineries with a combined crude oil throughput capacity of 610,000 barrels per day (“bpd”). The refineries are located in Port Arthur, Texas; Memphis, Tennessee; and Lima, Ohio. PACC owns and operates a heavy oil processing facility, which is operated in conjunction with the Port Arthur refinery. The information reflected in these combined consolidated footnotes for Premcor Inc. and PRG is equally applicable to both companies except where indicated otherwise.

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, 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 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.

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 were $1.3 million, $0.1 million, and nil for the years ended December 31, 2003, 2002 and 2001, respectively.

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.

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 13, Long-term Debt for the disclosure of the fair value of long-term debt.

Inventories for the Company are stated at the lower of cost or market. Cost is determined under the Last-in First-out (“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 uses several strategies to minimize the impact on profitability of volatility in crude oil 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 the Company uses 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 the related markets. These strategies are designed to minimize, on a short-term basis, the Company’s 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 policies. These types of transactions are treated as derivatives for accounting purposes. The results of these price risk mitigation activities affect cost of sales and inventory costs.

The Company enters into purchase contracts that fix the price of crude oil from one to several weeks in advance of receiving and processing that crude oil in order to supply refineries with crude oil on a timely basis. In addition, as part of the Company’s marketing activities, it is common to fix the price of a portion of the Company’s product sales in advance of producing and delivering that refined product. These types of transactions normally qualify as derivatives for accounting purposes.

Derivatives are recorded on the balance sheet as either assets or liabilities measured at their fair value. As of December 31, 2003 and 2002, the Company had not designated hedge accounting for any of its derivative

positions, and accordingly, the derivative positions were recorded at fair value and the unrealized gains and losses on the derivative positions were recognized in cost of sales. The cash flow changes resulting from these transactions were recorded in cash flows from operating activities in the statement of cash flows. The Company does not hold or issue derivative instruments for trading purposes.

Property, plant, and equipment additions are recorded at cost. The Company capitalizes costs associated with the preliminary, preacquisition, and development/construction stages of a major construction project. The Company also capitalizes significant costs incurred in the acquisition and development of software for internal use, including the costs of software, materials, consultants, and payroll related costs for employees incurred in the development stage once final selection of the software is made. The Company capitalizes the interest cost associated with major construction and software development projects based on the effective interest rate on aggregate borrowings.

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. Upon disposal of assets, any gains or losses are reflected in current operating income.

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.

The Company has asset retirement obligations based on its legal obligations to perform some remedial activity at its refinery sites. The Company is not required to perform these obligations in some circumstances 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 measure and recognize the fair value of its asset retirement obligations at such time as a settlement date is determinable.

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 statements of operations.

In 2003, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants (“AcSEC”) approved a statement of position (“SOP”) entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. Final approval by the Financial Accounting Standards Board of the SOP is pending. This SOP requires companies, among other things, to expense as incurred certain turnaround costs. Adoption of the SOP would require that any existing unamortized turnaround costs be expensed immediately, as a cumulative effect of an accounting change, net of income taxes, in the consolidated statement of operations. If this proposed change were in effect at December 31, 2003, the Company would have been required to write-off unamortized turnaround costs of approximately $76 million. As the SOP is currently proposed, the provisions of the SOP would be effective for fiscal years beginning after December 15, 2004. The Company is currently assessing the impact of other provisions of this SOP, in particular the provisions that relate to the capitalization of certain project costs and the adoption of component accounting for property, plant and equipment.

The Company capitalizes costs associated with the issuance of new debt securities and credit facilities and amortizes the costs over the period of the maturity of the debt or over the life of the credit facility. The deferred financing costs are included in the Company’s balance sheet in other assets. The amortization of these costs is included in interest and finance expense in the statement of operations.

Environmental remediation liabilities and reimbursements for underground storage tank remediation are recorded on an undiscounted basis when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. The Company has used third party engineers and attorneys to assist in the evaluation of several factors, including the extent of contamination, currently enacted laws and regulations, existing technology, the most appropriate remedy, and identification of other potentially responsible parties, among other factors, to estimate its environmental remediation liability. The actual settlement of the Company’s liability for environmental matters could differ from its estimates due to a number of uncertainties, such as the extent of contamination at a particular site, the final remedy, the financial viability of other potentially responsible parties, and the final apportionment of responsibility among the potentially responsible parties. Actual amounts could also differ from the estimates as a result of changes in future litigation costs to pursue the matter to ultimate resolution including both legal and remediation costs. Subsequent adjustments to the liability may be required, as more information becomes available.

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.

The Company recognizes settlement costs related to litigation when the costs are probable and can be reasonably estimated. The Company recognizes other costs associated with litigation, legal guidance and related items as these costs are incurred.

Revenue from sales of products is recognized upon delivery of the product or settlement of the underlying contract, which is the point at which title of the product is transferred.

In December 2003, the Financial Accounting Standards Board (“FASB”) published Emerging Issues Task Force (“EITF”) Issue No. 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes. The task force reached a consensus that determining whether realized gains and losses on physically settled derivative contracts “not held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. In accordance with EITF 03-11, cost of sales includes the net effect of the buying and selling of crude oil to supply the Company’s refineries. Prior period operating revenues and cost of sales have been reclassified to conform to the fourth quarter application of EITF 03-11, effective as of the beginning of the year. The current period presentation and prior period reclassifications have no effect on current or previously reported operating income (loss) or net income (loss).

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 revenues. 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 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 petroleum products. Excise taxes of approximately $710.9 million, $347.4 million, and $451.0 million were collected from customers and paid to various governmental entities related to activities in 2003, 2002, and 2001, respectively. The increase in the amount collected and paid for 2003 activity is primarily related to the operations of the newly acquired Memphis refinery. Excise taxes are not included in net sales and operating revenues.

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 tax provision on a separate company basis.

As of December 31, 2003, the Company has three stock-based employee compensation plans, which are described more fully in Note 19, 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, as all options granted in that year 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, 2003, the Company will record future non-cash stock-based compensation expense and additional paid-in capital of $24.6 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 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. The adoption of this interpretation did not have a material impact on the Company’s financial statements.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. This interpretation, as revised by Interpretation No. 46-R in December 2003, 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 financial 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 ending after March 15, 2004. The adoption of this interpretation did not have a material impact on the Company’s financial statements.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts. More specifically, SFAS No. 149, among other things, clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative, clarifies when a derivative contains a financing component, and amends the definition of an “underlying” to conform to recently issued standards. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except for certain aspects of the standard that relate to previously issued guidance, which should continue to be applied in accordance with the previously set effective dates. Also, this standard is effective for existing and new contracts entered into after June 30, 2003 as they relate to forward purchases or sales of when-issued securities or other securities that do not yet exist. The adoption of this standard did not have a material impact on the Company’s financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires classification of a financial instrument that is within its scope as a liability, or an asset in some circumstances. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and shall otherwise be effective at the beginning of the first interim period beginning after June 15, 2003, except for mandatorily redeemable financial instruments of a nonpublic entity. For instruments created before the issuance of SFAS No. 150 and still existing at the beginning of the interim period of adoption, this standard shall be implemented by reporting the cumulative effect of a change in an accounting principle. The adoption of this standard did not have a material impact on the Company’s financial statements.

In December 2003, the FASB published EITF 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes. As described above, the Company applied EITF 03-11 in the fourth quarter of 2003, effective as of the beginning of the year. Prior period operating revenue and cost of sales have been reclassified and there was no effect on current or previously reported operating income (loss) or net income (loss).

In December 2003, the FASB issued a revised SFAS No. 132, Employers’ Disclosures about Pensions and Other Post Retirement Benefits. The standard revises employers’ disclosures about pension plans and other post retirement plans, but it does not change the measurement or recognition of pension or other postretirement plans. The standard also requires interim disclosures for publicly traded entities. The Company has adopted the revised disclosure requirements of SFAS No. 132 as of December 31, 2003 and will include the interim disclosure requirements in the first fiscal quarter of 2004.

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

Effective March 3, 2003, the Company completed the acquisition of the Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries, or Williams. The purchase price of $474 million included $310 million for the refinery, supply and distribution assets, approximately $159 million for crude and product inventories, and approximately $5 million in transaction fees. 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; use of crude oil tankage at St. James, Louisiana; and an 80-megawatt power plant adjacent to the refinery.

The acquisition of the Memphis refinery assets was accounted for using the purchase method, and the results of operations of these assets have been included in the Company’s results from the date of acquisition. In the third quarter of 2003, the Company adjusted the purchase price allocation based on independent appraisals and other evaluations. The adjusted purchase price allocation is as follows:

As part of the purchase agreement, the Company assumed liabilities of $15.5 million that related to capital lease obligations, cancellation fees related to Tier 2 technology that the Company will not utilize, and environmental remediation activity. Williams assigned several leases to the Company, including two capitalized leases that relate to the leasing of crude oil and product pipelines that are within the Memphis refinery system connecting the refinery to storage facilities and other third party pipelines. Both capital leases have 15-year terms with approximately 14 years of their terms remaining.

The purchase agreement also provides for contingent participation, or earn-out, payments up to a maximum aggregate of $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. The earn-out payments will be calculated annually at the end of the seven 12-month periods beginning on April 1, 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 level, at a crude oil throughput rate of 167,123 bpd. The stipulated margin level is $3.25 per barrel for the first year and increases by $0.10 per barrel for each year thereafter. The actual daily value of the Gulf Coast 2/1/1 crack spread, as defined by the agreement, averaged $3.65 per barrel for the nine-month period from April 1, 2003 through December 31, 2003. Any amounts the Company pays to Williams as a result of the earn-out agreement will be recorded as goodwill. As of December 31, 2003, the Company recorded $14.2 million in goodwill related to the earn-out agreement, which reflected an estimate of the April 1, 2004 payment. Such goodwill will not be amortized, but will be subject to an annual impairment evaluation and the Company expects to be able to deduct the full amount for tax purposes.

liabilities were acquired or assumed by The Premcor Pipeline Co., an indirect subsidiary of Premcor Inc. PRG also amended and restated its credit agreement to allow for the acquisition.

On June 6, 2002, Premcor Inc., PRG and Sabine River Holding Corp. (“Sabine”) completed a series of transactions (“the Sabine restructuring”) that resulted in Sabine and its subsidiaries becoming wholly owned subsidiaries of PRG. Sabine indirectly owns PACC through its 100% ownership of PACC’s general and limited partners. 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 12¹/2% Senior Notes. PACC owns all the outstanding common stock of PAFC. 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 the 2001 historical financial statements have been restated to reflect the consolidation of these companies.

In 2003, the Company recorded refinery restructuring and other charges of $38.5 million, which included a $20.8 million charge related to closure costs and asset write-offs related to the sale of certain Hartford refinery assets and the Blue Island refinery closure, a $10.2 million charge related to environmental remediation and litigation costs associated with closed and previously-owned facilities and a net $7.5 million charge related to the planned closure of the St. Louis administrative office. These activities and transactions are described more fully below.

In 2002, the Company recorded refinery restructuring and other charges of $172.9 million ($168.7 million for PRG), which consisted of a $137.4 million charge related to the ceasing of refinery operations at the Hartford, Illinois refinery, $32.4 million charge related to the 2002 management, refinery operations, and administrative restructuring, a $2.5 million charge related to the termination of certain guarantees at PACC as part of the Sabine restructuring, a $1.4 million charge related to idled assets, and a $4.2 million charge related to the write-down of Premcor Inc.’s interest in Clark Retail Enterprises, Inc., (“CRE”), partially offset by a benefit of $5.0 million related to the unanticipated sale of a portion of previously written-off Blue Island refinery assets.

In 2001, the Company 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 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, refinery, and administrative function restructurings.

Refinery Closures and Asset Sale. 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. The closure resulted in a pretax charge of $137.4 million in 2002, which included a $70.7 million non-cash, write-down of long-lived assets to their estimated fair value of $49.0 million; a $4.8 million non-cash write-down of current assets; a $60.6 million charge related to employee severance, plant closure/equipment remediation, and site clean-up and environmental matters; and a $1.3 million charge related to post-retirement benefits that were extended to certain employees who were nearing the retirement requirements. In January 2001, the Company ceased refining operations at its Blue Island, Illinois refinery. This closure resulted in a pretax charge of $167.2 million in 2001, which included a $98.1 million non-cash write-down of long-lived and current assets and a

$69.1 million liability for employee severance and plant closure/equipment remediation, and site clean-up/environmental matters. Employee severance and plant closure/decommissioning activities have been completed at both sites. The Company continues to utilize its storage and distribution facilities at both refinery sites.

In 2003, the Company sold certain of the processing units and ancillary assets at the Hartford refinery to ConocoPhillips for $40 million. The Company also entered into agreements with ConocoPhillips to integrate certain of its remaining facilities with the ConocoPhillips assets and to receive from and provide to ConocoPhillips certain services on an on-going basis. The $20.8 million charge in 2003 primarily related to the sale transaction and subsequent agreements and included the write-down of the refinery assets held for sale, the write-off of certain storage and distribution assets included in property, plant and equipment, and certain other costs of the sale.

In the future, the Company expects the only significant effect on cash flows related to the closed refinery facilities will result from the environmental site remediation at both sites and equipment dismantling at the Blue Island site. The Company is currently in discussions with governmental agencies concerning remediation programs for both sites and anticipates that the discussions will likely lead to final consent orders. The site clean-up and environmental liability takes into account costs that are reasonably foreseeable at this time. As the site remediation plans are finalized and work is performed, further adjustments of the liability may be necessary and such adjustments may be material. In 2003, the Company recorded a charge of $10.2 million related to environmental remediation activity. This charge included estimated survey, design, and clean-up costs in relation to the Village of Hartford, costs related to the default of a third party to provide certain dismantling activity at the Blue Island site, and revised estimates for remediation activity at a previously owned terminal that resulted from further analysis of the site in 2003.

In 2002, the Company obtained environmental risk insurance policies covering the Blue Island refinery site. This insurance program allows the Company to quantify and, within the limits of the policy, cap its cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self-insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a $100,000 deductible.

Management, Refinery Operations and Administrative Restructuring. In 2002, the Company restructured its executive management team resulting in the recognition of severance expense of $5.0 million and non-cash stock-based compensation expense of $5.8 million. In addition, the Company incurred a charge of $5.0 million for the cancellation of a monitoring agreement with one of the owners of Premcor Inc.’s common stock. See Note 20, Related Party Transactions for more details of the agreement. 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 the Port Arthur, Texas and Lima, Ohio refineries and make additional staff reductions at the 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. Reductions at the refineries occurred in October 2002 and those at the St. Louis office occurred in 2003.

As a result of the Memphis refinery acquisition, the number of positions to be eliminated at the St. Louis office was reduced by 25 and the Company recorded a reduction in the restructuring liability of $1.6 million in the first quarter of 2003. In May 2003, the Company announced that it would be closing the St. Louis office and moving the administrative functions to the Connecticut office over the next twelve months. The office move is expected to cost $15.1 million, which includes $6.4 million of severance related benefits and $8.7 million of

other costs such as training, relocation, and the movement of physical assets. The severance related costs will be amortized over the future service period of the affected employees and the other costs will be expensed as incurred.

In connection with the 1999 sale of PRG’s retail assets to CRE, PRG assigned approximately 170 leases and subleases of retail stores to CRE. Subject to certain defenses, PRG remained jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. PRG may also be contingently liable for environmental obligations at these sites. In October 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. In bankruptcy hearings throughout 2003, CRE rejected, and subject to certain defenses, PRG became primarily obligated for approximately 36 of the previously assigned leases. During the third quarter of 2003, CRE conducted an orderly sale of its remaining retail assets, including most of the leases and subleases previously assigned by PRG to CRE except those that were rejected by CRE. The Company recorded an after-tax charge of $7.2 in 2003, representing the estimated net present value of its remaining liability under the 36 rejected leases, net of estimated sublease income, and other direct costs. The primary obligation under the non-rejected leases and subleases was transferred in the CRE sale process to various unrelated third parties; however, the Company will likely remain jointly and severally liable on the assigned leases and the remaining unassigned leases could be rejected. Total payments on leases and subleases upon which the Company will likely remain jointly and severally liable are currently estimated as follows: (in millions) 2004—$9, 2005—$9, 2006—$9, 2007—$8, 2008—$8 and in the aggregate thereafter—$50.

The Company recorded a liability for the estimated cost of environmental remediation of its former retail store sites. A portion of this liability was established pursuant to an indemnity agreement with CRE in connection with its 1999 purchase of the Company’s retail assets. This indemnity obligation does not extend to the buyers of CRE’s retail assets and, as a result, the Company will review its environmental liability accordingly upon the final disposition of the CRE bankruptcy.

The following table reconciles the activity and balance of the liability for the lease obligations as well as the Company’s environmental liability for previously owned and leased retail sites:

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 shares used to compute the Company’s basic and diluted earnings per share is as follows (in millions):

Stock options for 4.2 million and 4.4 million, and 1.9 million common shares for the year ended December 31, 2003, 2002, and 2001, respectively, were excluded from the diluted earnings per share calculation because they were anti-dilutive. Additional 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.

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.

As of December 31, 2003, the Company maintained short-term investments totaling $5.9 million (2002—$4.9 million), of which $1.7 million was pledged as collateral for self-insured workers’ compensation programs at PRG. As of December 31, 2003, a wholly owned subsidiary of Premcor Inc. held $4.2 million in investments to provide additional directors and officers liability coverage for claims made against them in their respective capacities as directors and officers of the Company (2002—$3.2 million). 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.

As of December 31, 2003, the Company had open contracts of futures, over-the-counter options, and forward purchases and sales, all related to commodity derivative activity, which resulted in an unrealized gain of $13.0 million and an unrealized loss of $18.8 million. 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, 2003, the market value of crude oil, refined product, and blendstock inventories was approximately $174 million above carrying value (2002—$188 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 $600.2 million and $262.6 million for the years ended December 31, 2003 and 2002, respectively. A LIFO liquidation increased the Company’s pretax earnings by $2.2 million in 2003. A LIFO liquidation reduced the Company’s pretax earnings by $1.5 million in 2002 (2001—$19.3 million). The 2003 liquidation was due to a decrease in crude oil inventory at PACC caused by ordinary timing differences in the delivery of large crude tankers. The 2002 liquidation was due to the closure of the Hartford refinery and ordinary timing differences in the delivery of crude oil at PACC. 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:

As of December 31, 2003, process units, buildings, and oil storage and movement included $10.5 million (2002—$9.4 million) of assets related to capitalized leases. As of December 31, 2003, construction in progress included approximately $100 million (2002—$64 million) related to expenditures to conform to new federally mandated fuel specifications as discussed more fully in Note 22, Commitments and Contingencies.

In 2003, the Company incurred deferred financing costs of $29.9 million related to three separate issuances of debt. In 2003, the Company wrote-off $9.4 million of unamortized deferred financing costs related to the purchase of a portion of its 12¹/2% Senior Notes due January 15, 2009, the early repayment of certain debt, and the amendment of its credit agreement.

In 2002, the Company incurred deferred financing costs of $11.4 million primarily related to the consent process that permitted the Sabine restructuring. 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.

For the year ended December 31, 2003, amortization of deferred financing costs was $9.1 million (2002—$10.3 million, 2001—$11.4 million) for the Company. For PRG, amortization of deferred financing costs for the year ended December 31, 2003 was $9.1 million (2002—$10.2 million, 2001—$10.9 million). Amortization of deferred financing costs is included in “Interest and finance expense”.

PRG’s credit agreement, which was amended and restated in February 2003, provides for letter of credit issuances of up to the lesser of $785 million or an amount available under a defined borrowing base, less outstanding borrowings. The facility may be increased to $800 million under certain circumstances. PRG utilizes this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. The borrowing base includes PRG’s cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, net obligations on swap contracts and PACC’s eligible hydrocarbon inventory. The credit agreement expires in February 2006. As of December 31, 2003, the borrowing base was $1,348.9 million (December 31, 2002—$815.3 million), with $602.1 million (December 31, 2002—$597.1 million) of the facility utilized for letters of credit. As of December 31, 2003, $208.5 million (2002—$239.3 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 $393.6 (2002—$357.8 million) related to deliveries in which the Company had taken title and accordingly recorded purchases and accounts payable.

PRG also has a $40 million cash-collateralized credit facility expiring in May 2004. This facility was arranged in support of lower interest rates on the Ohio Water Development Authority Environmental Facilities Revenue Bonds due December 1, 2031 (“Ohio Bonds”). In addition, this facility can be utilized for other non-hydrocarbon purposes. As of December 31, 2003, $18.0 million (December 31, 2002—$10.1 million) of the line of credit was utilized for letters of credit.

PRG’s long-term debt, including current maturities, as of December 31, 2003 was $1,441.8 million and is the same as the Premcor Inc. long-term debt as noted in the table above except that it excludes the $10.3 million of capital lease obligations. The Premcor Pipeline Co. assumed these lease obligations as part of the Memphis refinery acquisition. PRG’s long-term debt, including current maturities, as of December 31, 2002 was $884.8 million and is the same as the Premcor Inc. long-term debt as noted in the table above except that it excludes the $40.1 million in 11¹/2% Subordinated Debentures issued by Premcor USA.

The estimated fair value of the Company’s long-term debt at December 31, 2003 was $1,578 million (2002—$926 million). The estimated fair value of PRG’s long-term debt at December 31, 2003 was $1,567 million (2002—$885 million). Estimated fair value was determined using quoted market prices for each debt issue.

The 12¹/2% 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 12¹/2% 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. The make-whole premium would be equal to the excess, if positive, of the present value of all interest and unpaid principal payments discounted at a defined rate over the unpaid principal amount of the notes. PRG has fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations under the 12¹/2% Senior Notes. The current portion of the 12¹/2% Senior Notes was $24.2 million as of December 31, 2003.

The 9¹/4% Senior Notes and 9¹/2% Senior Notes were issued at par by PRG in February 2003 and are unsecured. The 9¹/4% Senior Notes and 9¹/2% Senior Notes are redeemable at the option of PRG beginning February 2007 and February 2008, respectively, at a redemption price of 104.625% of principal and 104.75% of principal, respectively, which decreases to 100% of principal in 2010 and 2011, respectively. In addition, PRG may utilize proceeds from one or more equity offerings to redeem up to 35% in aggregate principal amount of the 9¹/4% Senior Notes and 9¹/2% Senior Notes at any time prior to February 2006 at redemption prices of 109.25% of principal and 109.5% of principal, respectively.

The 7¹/2% Senior Notes were issued at par by PRG in June 2003 and are unsecured. The 7¹/2% Senior Notes are redeemable at the option of PRG beginning June 2008, at a redemption price of 103.75% of principal, which decreases to 100% of principal in 2011. In addition, PRG may utilize proceeds from one or more equity offerings to redeem up to 35% in aggregate principal amount of the 7¹/2% Senior Notes at any time prior to June 2006 at a redemption price equal to 107.5% of principal.

The 6³/4% Senior Notes and 7³/4% Senior Subordinated Notes were issued at par by PRG in November 2003. These notes are unsecured, with the 7³/4% Senior Subordinated Notes subordinated in right of payment to all unsubordinated indebtedness of PRG. The 6³/4% Senior Notes may not be redeemed prior to their maturity. The 7³/4% Senior Subordinated Notes are redeemable at the option of PRG beginning February 2008, at a redemption price of 103.875% of principal, which decreases to 100% of principal in 2010. In addition, PRG may utilize proceeds from one or more equity offerings to redeem up to 35% in aggregate principal amount of the 7³/4% Senior Subordinated Notes at any time prior to February 2006 at a redemption price equal to 107.75% of principal.

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’s cash collateral 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 2003 and 2002, the interest rate was under 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 also has the option of converting from a variable interest rate to a fixed interest rate with a maturity of not later than December 1, 2031. If PRG decides to convert the bonds to a 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. The bonds have no call provisions for the first 10 years. In order to provide support of the lower interest rate on the Ohio Bonds, PRG issued a letter of credit for the principal amount outstanding. The supporting credit facility expires in May 2004, and PRG has the option to extend the expiration date of the current facility, replace the facility or transfer the existing letter of credit to the $785 million credit facility. PRG also has the ability to fix the interest rate on the Ohio Bonds in which case additional security would no longer be required.

In February 2003, the Company redeemed the $40.1 million principal balance of Premcor USA Inc.’s 11¹/2% Subordinated Debentures at a $2.3 million premium and repaid PRG’s Floating Rate Term Loan at par using a portion of the proceeds from the common stock offerings described in Note 18, Stockholders Equity and the senior notes issued in February 2003. In May 2003, PRG purchased in the open market $14.7 million in face value of the 12¹/2% Senior Notes at a $2.7 million premium. In 2003, PACC made $14.2 million of scheduled

principal payments on its 12¹/2% Senior Notes. In December 2003, PRG redeemed the aggregate principal balance of the 8³/8% Senior Notes, 8⁵/8% Senior Notes, and 8⁷/8% Senior Subordinated Notes with the proceeds of the senior notes and senior subordinated notes issued in November 2003.

The aggregate stated maturities of long-term debt for the Company are (in millions): 2004—$24.5; 2005—$36.6; 2006—$44.1; 2007—$41.3; 2008—$48.5; 2009 and thereafter—$1,257.1.

PRG 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, as defined in the indentures, that results in a ratings decline, the Company is required to tender an offer to redeem its outstanding notes at 101% of face value, 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. Under the amended and restated common security agreement, PACC is required to maintain $45.0 million of cash for annual debt service at all times plus an amount equal to the next scheduled principal and interest payment on its 12¹/2% Senior Notes, prorated based on the number of months remaining until that payment is due. As of December 31, 2003, cash of $66.6 million (2002—$61.7 million) was restricted for current debt service under these requirements and classified as cash and cash equivalents restricted for debt service on the balance sheet.

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 credit agreement, PACC is required to dividend to PRG all excess cash over $20 million, excluding the restricted debt service amounts. Also, pursuant to the amended credit agreement, 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. Non-cash dividends of $174.7 million were made in 2003. No such dividends were made in 2002.

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 2003 for the Company was $110.4 million (2002—$114.3 million; 2001—$152.6 million). Cash paid for interest expense in 2003 for PRG was $107.4 million (2002—$103.9 million; 2001—$133.9 million).

As a result of the early extinguishment of debt in 2003, as noted above, and amendments to the credit agreement in conjunction with the Memphis acquisition, the Company recorded a loss on extinguishment of long-term debt of $27.5 million, which included cash premiums associated with the early repayment of long-term debt of $17.2 million, a write-off of unamortized deferred financing costs of $9.4 million related to this debt and the amended credit agreement, and a write-off of unamortized note discounts of $0.9 million. PRG recorded a loss on extinguishment of long-term debt of $25.2 million which excluded the cash premium paid in relation to the redemption of 11¹/2% subordinated debentures, which were held by Premcor USA.

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 PACC’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 PACC’s long-term debt obligations.

In 2001, the Company repurchased in the open market $21.3 million in face value of its 9¹/2% Senior Notes, $30.6 million in face value of its 10⁷/8% Senior Notes, and $5.9 million in face value of its 11¹/2% 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 10 years years with the option to purchase some of the equipment at the end of the lease term at fair market value. The Company leases some land in relation to its Memphis refinery operations with terms that extend 29 years and 47 years. The leases generally provide that the Company pay taxes, insurance, and maintenance expenses related to the leased assets. The Company is also subject to remaining payments on 28 leases that were rejected from the CRE bankruptcy as described above in Note 6, Discontinued Operations. The terms of these leases range from 1 to 13 years. Certain of these properties are being subleased. As of December 31, 2003, net future minimum lease payments under non-cancelable operating leases were as follows (in millions): 2004—$35.4; 2005—$34.4; 2006—$32.1; 2007—$29.7; 2008—$28.3; 2009 and thereafter—$63.0. Total future rental receipts are $6.6 million as of December 31, 2003. Rental expense during 2003 was $49.0 million (2002—$31.5 million; 2001—$26.8 million).

Legal and environmental liabilities reflected the long-term portion of these liabilities and are more fully discussed in Note 22, Commitments and Contingencies. The postretirement and pension benefit obligations are discusses in Note 16, Employee Benefit Plans.

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 and a non-qualified senior executive retirement plan (“SERP”). 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 two non-qualified plans were not funded as of December 31, 2003. The Company uses a December 31 measurement date for its pension plans.

The Company also sponsors postretirement 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. In addition to these health care plans, health care benefits are provided under the SERP. The postretirement portion of the SERP is non-contributory and was not funded as of December 31, 2003. The Company uses a September 30 measurement date for its other post retirement benefits.

Information concerning the SERP was not included in our previously reported 2002 disclosure because the plan was suspended at the time. The SERP was reinstated in April 2003, effective as of July 1, 2002. The Company has included the SERP in the 2003 and 2002 information reported below. The following table provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, funded status of plans, accumulated benefit obligations for pension plans, and the assumptions used to determine the benefit obligation for the year ended December 31:

The following table provides the components of net periodic benefit cost and the assumptions used to determine the net benefit cost for the year ended December 31:

In measuring the expected postretirement benefit obligation and expense, the Company assumed a health care cost rate increase of 12% in 2004, declining by 1% per year to an ultimate rate of 5% in 2011. 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 Company expects to begin funding the pension benefit portion of the SERP in 2004 and expects to contribute a total of $9 million to its pension plans. The Company expects to make payments of $3 million for its obligations under its other post retirement benefit plans in 2004.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003, or Medicare Act, was signed into law in December 2003. Detailed regulations necessary to implement this act are still pending. The Medicare Act provides Medicare coverage for prescription drugs up to a certain amount above a deductible and then provides no Medicare coverage until expenses reach a higher threshold. The law also provides federal subsidy to sponsors of retiree health care benefit plans. Companies that sponsor postretirement benefit plans are evaluating potential changes to their postretirement plans in order to take advantage of this new coverage and they are evaluating the accounting treatment of the various options provided by the act and of any changes to their plans. The FASB has issued a FASB Staff Position, or FSP, that provides additional options to companies for the recognition of plan changes and requires certain disclosures pending further consideration of the underlying accounting principles.

The guiding principles in implementing the Company’s investment policy with respect to its qualified employee pension plans are 1) preserve the long-term corpus of the fund, 2) maximize total return within prudent risk parameters, and 3) act in the exclusive interest of the participants of the plans. In order to accumulate and maintain the financial reserves to meet its obligations, the goal of the Company’s investment strategy is to achieve an expected total return of at least 8.5%, based upon an inflation assumption of 3% and real rate of return of 5.5%. This return goal was derived using an asset allocation model developed by the Company’s investment consultant. This expected return on the plan assets takes into account historical, long-term equity and fixed

income securities experience. In order to achieve this return, the Company’s pension plan investment policy statement established a long-term asset allocation structure of 60% in equity securities and 40% in fixed income securities. In determining the Company’s philosophy towards risk, the Company’s benefit committee considered its fiduciary obligations; statutory requirements; the pension plans’ purpose and characteristics, financial condition, liquidity needs, sources of contributions and income; and general business conditions. Based on these factors, neither an aggressive nor a conservative investment approach appeared to be warranted at the time.

The Company’s benefit committee recognizes that even though its investments are subject to short-term volatility, it is critical that a long-term investment focus be maintained. This prevents ad-hoc revisions to its philosophy and policies in reaction to short-term market fluctuations. In order to preserve this long-term view, the committee will review performance of its investment funds quarterly and will review its asset allocation, including rebalancing, and investment policy statement annually. To assure a rational, systematic, and cost-effective approach to rebalancing, the committee has chosen certain “trigger points” as the maximum upper and lower limits for a specified asset class. If the percentage of the plan’s assets in a particular asset class has deviated from the target beyond a trigger point, the Company will rebalance the portfolio to bring all asset classes in line with the adopted guideline percentages.

The Company established its investment policy at the same time that it has been restructuring its refining assets and corporate infrastrucuture. As a result, the need to maintain asset liquidity delayed full implementation of the investment strategy for the long- term horizon. When the plans were initially funded in September 2003, an amount estimated to cover the cash flow needs of upcoming benefit payments during fourth quarter 2003 and early 2004 was invested in a money market instrument. The balance of the funding was invested on a 60% equity and 40% fixed income basis, consistent with the Company’s long- term investment strategy.

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 2003 were $8.1 million (2002—$8.3 million; 2001—$8.4 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, 2003, the Company has made net cumulative payments of $25.8 million (PRG—$22.4 million) under the federal alternative minimum tax system which are available to reduce future regular income tax payments. As of December 31, 2003, the Company had regular federal tax and alternative minimum tax net operating loss carryforwards of $419.6 million and $192.0 million (PRG—$360.9 million and $129.1 million), respectively. As of December 31, 2003, the Company had federal business tax credit carryforwards in the amount of $14.6 million (PRG—$14.6 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 began to terminate with the year ended December 31, 2003 and the net operating loss carryover periods will begin to terminate with the year ending December 31, 2018. Approximately 50% of the regular federal tax net operating carryforwards will have expired as of December 31, 2020, with a full 100% expiring by December 31, 2022, to the extent they have not been used to reduce regular taxable income prior to such time. The Company’s alternative minimum tax net operating loss carryforwards will begin to expire with the year ending December 31, 2012, to the extent they have not been used to reduce alternative minimum taxable

income prior to such time. Approximately 16% of the alternative minimum tax net operating carryforwards will expire as of December 31, 2012, with an additional 40% having expired as of December 31, 2019 and a full 100% expiring by December 31, 2022, to the extent they have not been used to reduce alternative taxable income prior to such time. If the Company experiences an ownership change of more than 50% during any three-year testing period as defined in Section 382 of the Internal Revenue Code, the timing and extent of the utilization of its net operating loss carryforwards, other losses and tax credits could be affected. Premcor Inc. has had significant changes in the ownership of its 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.

The valuation allowance of the Company and PRG as of December 31, 2003 was $2.8 million (2002—$2.8 million). The increase of the deferred tax valuation allowance in 2002 was 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. During 2001, the Company and PRG each reversed its remaining deferred tax valuation allowance based on this same type of analysis.

During 2003, the Company made net federal cash payments of $3.7 million (2002—$12.6 million net federal cash refunds; 2001—$11.9 million net federal cash payments). During 2003, PRG neither made nor received any net federal cash payments or refunds (2002—$12.6 million net federal cash refunds; 2001—$14.5 million net federal cash payments). PRG provides for its portion of consolidated refunds and liability under its tax sharing agreement with Premcor Inc. As of December 31, 2003, PRG had an amount due to affiliates of $41.2 million related to income taxes and its tax sharing agreement with Premcor Inc. and its predecessor. During 2003, PRG neither made nor received any net state cash payments or refunds (2002—$0.3 million net state cash payments; 2001—$1.7 million net state cash payments).

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).

As of December 31, 2003, Premcor Inc. had one class of outstanding 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 (“Blackstone”), a subsidiary of Occidental Petroleum Corporation (“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 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. 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. In relation to 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.

As of December 31, 2003, 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 under either a schedule of ¹/3 on each of the first three anniversaries of the date of grant or a schedule of ¹/5 on each of the first five anniversaries of the date of grant. Also in 2002, the Company adopted the 2002 Equity Incentive Plan to award key employees, directors, consultants, and affiliates 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 under either a schedule of ¹/3 on each of the first three anniversaries of the date of grant or a schedule of ¹/5 on each of the first five 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, 2003, 50% of the outstanding performance vesting options were 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, 2003, 2002 and 2001 is as follows:

Information regarding stock options granted during 2003, 2002, and 2001 is as follows:

Information regarding stock options outstanding as of December 31, 2003 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:

The following related party transactions are not discussed elsewhere in the footnotes. See Note 17, Income Taxes for a discussion of intercompany transactions and balances related to a tax sharing agreement between Premcor Inc. and certain of its subsidiaries.

As of December 31, 2003, PRG had a payable to Premcor Inc. for management fees paid by Premcor Inc. on PRG’s behalf of $0.1 million (December 31, 2002—$8.3 million). As of December 31, 2003, PRG also had a loan receivable from Premcor Inc. for $8.9 million (December 31, 2002—$8.1 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. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.

In 2003, PRG received capital contributions from Premcor USA totaling $263.3 million, primarily for the acquisition of the Memphis refinery and for early long-term debt payments. In 2002, PRG received capital contributions from Premcor USA totaling $278.3 million, which included cash contributions of $248.1 million that 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, PRG returned capital to Premcor USA of $25.8 million, which was utilized for the repurchase of a portion of its long-term debt and exchangeable preferred stock and interest obligations. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.

As of December 31, 2003, PRG had a receivable from The Premcor Pipeline Co. of $5.9 million related to amounts that PRG paid on behalf of The Premcor Pipeline Co. As of December 31, 2003, PRG had a payable to The Premcor Pipeline Co. of $2.0 million (December 31, 2002—$8.4 million) for pipeline tariffs and fees due to The Premcor Pipeline Co for use of pipelines and storage for the Memphis operations. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.

The Company entered into an agreement with Fuel Strategies International (“FSI”) effective June 2002. Pursuant to this agreement, FSI provides monthly, consulting services related to the Company’s petroleum coke and commercial operations. The agreement automatically renews for additional one-year periods unless terminated by either party upon 90 days notice prior to expiration. The principal of FSI is the brother of the Company’s chairman and chief executive officer. For the years ended December 31, 2003 and 2002, the Company incurred fees of $0.4 million and $0.2 million, respectively, related to this agreement.

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 monitoring agreement was terminated effective March 31, 2002. The Company recorded expenses related to the annual monitoring fee and the reimbursement of out-of-pocket costs of $0.3 million and $2.5 million for the years ended December 31, 2002 and 2001, respectively.

21. CONSOLIDATING FINANCIAL STATEMENTS OF PRG AS CO-GUARANTOR OF PAFC’S 12¹/2% SENIOR NOTES

As a result of the Sabine restructuring, PRG, PACC, Sabine, and various other subsidiaries of Sabine are full and unconditional guarantors of PAFC’s 12¹/2% Senior Notes. The guarantors have guaranteed the punctual payment of principal and interest on the notes, the performance by PAFC of its obligations under the note indenture and amended and restated common security agreement, and that the guarantor obligation will be as if they were a principal debtor and obligor, not merely a surety. As of December 31, 2003, the maximum potential amounts of future payments under the guarantee were $221.8 million in principal payments and $93 million in future interest payments. See Note 13, Long-term Debt, for additional information on the collateralization of the 12¹/2% Senior Notes and the indenture and amended and restated common security agreement governing the relationships between PAFC and the guarantors.

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 condensed 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 notes since the issuer and guarantors are all direct or indirect wholly owned subsidiaries of PRG, and all guarantees are full and unconditional on a joint and several basis.

In addition to the relationships related to the 12¹/2% 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 the consolidation of PRG.

As a result of its activities, the Company is the subject of certain potentially material pending legal proceedings, including proceedings related to environmental matters. Set forth below is information 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.

Village of Hartford, Illinois Litigation. In May 2003, the Attorney General’s office for the State of Illinois filed a lawsuit against the Company and a former owner of the Hartford refinery for injunctive relief, cost recovery and penalties related to subsurface contamination in the area of the refinery and facilities owned by other companies. The case, entitled People of the State of Illinois, ex rel. v. The Premcor Refining Group, Inc. et al., is filed in the Circuit Court for the Third Judicial Circuit, Madison County, Illinois. The Attorney General’s office also sent notices to other companies with current or former operations in the area of the state’s intent to sue those companies as well. The Company, along with other companies, have met with the state and U. S. EPA regarding the issues in the Village of Hartford and those discussions are ongoing.

In July 2003, approximately 12 residents of the Village of Hartford, Illinois filed a lawsuit against the Company and a prior owner of the Hartford refinery alleging personal injury and property damage due to releases from the refinery and related pipelines. The plaintiffs are seeking class certification and unspecified damages. The case, entitled Sparks, et al. v. The Premcor Refining Group, Inc., et al. has been removed to the United States District Court for the Southern District of Illinois.

Lawsuits by Residents of Port Arthur, Texas. In June 2003, approximately 700 residents of Port Arthur, Texas filed a lawsuit against the Company and five other companies alleging personal injuries and property damage from emissions from refining and chemical facilities in the area. The plaintiffs are seeking class certification, unspecified damages and the establishment of a trust fund for health concerns. The case is entitled Marion L Aaron, et al. Premcor Refining Group Inc. et al. and is filed in Judicial District Court of Jefferson County, Texas.

Methyl-Tertiary Butyl Ether Products Liability Litigation. During the fourth quarter of 2003 and continuing, the Company has been named in approximately 35 cases, along with dozens of other companies, filed in approximately 12 states concerning the use of methyl-tertiary butyl ether, or MTBE. The cases contain allegations that MTBE is defective. The cases are in various procedural stages with defendants attempting to remove the cases to federal court and consolidate them in the Southern District of New York under the rules for Multi-District Litigation, or MDL. The cases are before the Judicial Panel on MDL Docket No. 1358, In Re: Methyl-Tertiary Butyl Ether Products Liability Litigation.

Port Arthur: Enforcement. The Texas Commission on Environmental Quality (“TCEQ”) conducted a site inspection of the Port Arthur refinery in the spring of 1998. In August 1998, the Company received a notice of enforcement alleging 47 air-related violations and 13 hazardous waste-related violations. The number of allegations was significantly reduced in an enforcement determination response from 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 its 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 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 (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. The Company disputes the allegations and the proposed penalty, and negotiations with the TCEQ are ongoing.

Blue Island: Class Action Matters. In October 1994, the 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 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. All three cases are pending in Circuit Court of Cook County, Illinois.

People of the State of Illinois v. The Premcor Refining Group Inc.; Circuit Court of Cook County, Illinois. In this case the Illinois Attorney General’s office filed suit alleging violations of environmental standards and other causes of actions arising from operations at the former Blue Island refinery. The case was only recently served on the Company and the time for a responsive pleading has not occurred. The Company has been in discussions with the Attorney General’s office to resolve these issues.

People of the State of Illinois v. Clark Retail Enterprises, Inc. et al.; Circuit Court of Tazewell, Illinois. In this case the Illinois Attorney General’s office filed suit alleging violations of environmental standards and other common law actions arising from operations of a retail site in Morton, Illinois. The Company has filed a motion to dismiss the lawsuit and is in discussions with the Attorney General’s office and the Illinois EPA on disposition of the site.

Alleged Asbestos Exposure. The Company, along with numerous other defendants, have been named in certain 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 the Hartford and Port Arthur refineries. Some of the cases are in the early stages of litigation. Substantive discovery has not yet been concluded. It is impossible at this time for the Company to quantify its exposure from these claims, but, based on currently available information, the Company does not believe that any liability resulting from the resolution of these matters will have a material adverse effect on its financial condition, results of operations and cash flow.

Port Arthur, Lima and Memphis 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 1995 purchase of the Port Arthur refinery, Chevron Products Company, the former owner, generally 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 active processing units, which are the Company’s responsibility. Less than 200 acres of the 3,600-acre refinery site are occupied by active processing units. Extensive due diligence efforts prior to the Company’s 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 Texas Commission on Environmental Quality, or TCEQ, that incorporates the contractual division of the remediation responsibilities for certain assets into an agreed order. The Company has recorded a liability for its portion of the Port Arthur remediation.

Under the terms of the purchase of the Lima refinery, BP, the former owner, indemnified the Company, 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 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 an 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.

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 the Company against all environmental liabilities incurred 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 the Company and (2) not known by them prior to the closing. The Company is responsible for all other environmental liabilities, including various pending clean-up and compliance matters. The Company recorded a liability for various on-going remediation matters as part of the acquisition accounting. Any claims made by the Company against Williams for environmental liabilities must be made within seven years. Williams obtained, 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 and a self-insured retention of $250,000 per incident. The maximum amount the Company 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 the Company 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 the Company for any fines and penalties that result from William’s operations or ownership prior to the closing.

Blue Island Refinery Decommissioning and Closure. In January 2001, the Company ceased refining operations at its Blue Island refinery. The decommissioning of the facility is complete. The Company has been in discussions with state and local governmental agencies concerning remediation of the site and expects a consent order setting forth the agreement for remediation of the site to have been filed with the court in the first half of 2004. The Company has recorded a liability for the environmental remediation of the refinery site based on costs that are reasonably foreseeable at this time, taking into consideration studies performed in conjunction with the insurance policies discussed below. In 2002, the Company obtained environmental risk insurance policies covering the Blue Island refinery site. This insurance program allows the Company to quantify and, within the limits of the policies, cap its cost to remediate the site, and provide insurance coverage from future third party claims arising from past or future environmental releases. The remediation cost overrun policy has a term of ten years and, subject to certain exceptions and exclusions, provides $25 million in coverage in excess of a self-insured retention amount of $26 million. The pollution legal liability policy provides for $25 million in aggregate coverage and per incident coverage in excess of a $100,000 deductible per incident. The responsibility for the dismantling and environmental remediation of the refinery’s above ground assets had been assumed by a third party in connection with its purchase of the assets for resale. The third party has defaulted on its obligation and the Company recorded a liability of $4.1 million in the fourth quarter of 2003 to provide for its estimated cost to dismantle and remediate the remaining above ground refinery equipment.

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 has recorded a liability for the environmental remediation of the refinery site based on costs that are reasonably foreseeable at this time, and the Company is also currently in discussions with state governmental agencies concerning environmental remediation of the site.

Former Retail Sites. In 1999, the Company sold its former retail marketing business, which it 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 approximately 670 sites, 225 of which had no known preclosure contamination, 365 of which had known preclosure contamination of varying extent, and 80 of which had been previously remediated. The purchaser of the retail division assumed preclosure 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 preclosure liabilities, subject to certain time limitations. With respect to the sites on which there was known preclosing 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 preclosing liability for sites that had been previously remediated. The bankruptcy discussed below may have an affect on these allocations.

Of the remaining 478 former retail sites not sold in the 1999 transaction described above, the Company has sold all but 5 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 for which a letter was received and subsequently revoked. The Company is currently involved in the active remediation of approximately 140 of the retail sites sold in open market and auction sales. The Company is actively seeking to sell the remaining properties. During the period from the beginning of 1999 through December 31, 2003, the Company expended approximately $22 million to satisfy all the environmental cleanup obligations of the former retail marketing business and, as of December 31, 2003, had $21.2 million accrued to satisfy those obligations in the future.

In connection with the 1999 sale, the Company assigned approximately 170 leases and subleases of retail stores to the purchaser of its retail division, Clark Retail Enterprises, Inc., or CRE. The Company remained jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. The Company may also be contingently liable for environmental obligations at these sites. In October 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. In bankruptcy hearings throughout 2003, CRE rejected, and subject to certain defenses, the Company became primarily obligated for, approximately 36 of these leases. During the third quarter of 2003, CRE conducted an orderly sale of its remaining retail assets, including most of the leases and subleases previously assigned by the Company to CRE except those that were rejected by CRE. The primary obligation under the non-rejected leases and subleases was transferred in the CRE sale process to various unrelated third parties; however, the Company will likely remain jointly and severally liable on the assigned leases and the remaining unassigned leases could be rejected.

A portion of the $21.2 million liability discussed above was established pursuant to an environmental indemnity agreement with CRE in connection with the 1999 sale of retail assets. The environmental indemnity obligation as it relates to the CRE retail properties was not extended to the buyers of CRE’s retail assets in the recent bankruptcy proceedings and, as a result, the Company intends to review its environmental liability accordingly upon the final disposition of the bankruptcy proceedings.

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.

Other Memphis Related Assets. 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. The Company has been working with TDEC to continue remediation of the groundwater. 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 cost for closing the land farm in accordance with the permit’s closure procedures is not expected to exceed $1 million.

Legal and Environmental Liabilities. As a result of its normal course of business, the Company is a party to certain legal and environmental proceedings. As of December 31, 2003, the Company had accrued a total of approximately $98 million (December 31, 2002—$93 million), including both the long-term and current portion of this liability, on primarily an undiscounted basis, for legal and environmental-related obligations that may result from the matters noted above and other legal and environmental matters. An adverse outcome of any one or more of these matters could have a material effect on the Company’s operating results and cash flows when resolved in a future period.

The Company expects to incur costs in the aggregate of approximately $645 million, of which $201 million has been incurred as of December 31, 2003, in order to comply with environmental regulations related to the new stringent sulfur content specifications 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 produces gasoline under the new sulfur standards at the Port Arthur refinery, and it expects to comply with the gasoline standards at the Memphis refinery in the second quarter of 2004. As a result of the corporate pool averaging provisions of the regulations and the possession of what the Company believes, based on current information, to be sufficient sulfur credits, the Company intends to defer a significant portion of the investment required for compliance at the Lima refinery until the end of 2005. The Company believes, based on current estimates, that compliance with the new Tier 2 gasoline specifications will require it to make capital expenditures in the aggregate through 2005 of approximately $315 million, of which $194 million had been incurred as of December 31, 2003. Future revisions to this cost estimate, and the estimated time during which costs are incurred, may be necessary. As of December 31, 2003, the Company had outstanding contract commitments of $89 million related to the design and construction activity at the refineries for the Tier 2 gasoline compliance.

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 fourth quarter of 2005.

Crude Oil Purchase Commitment. On October 1, 2002, the Company entered into a crude oil linefill agreement with Morgan Stanley Capital Group Inc., or MSCG, which obligated it to purchase 2.7 million barrels of crude oil in the pipeline system supplying the Lima refinery from MSCG. The agreement with MSCG was terminated in June 2003, and the Company purchased the 2.7 million barrels of crude oil from MSCG at a net cost of approximately $80 million.

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, 2003, a cumulative quarterly surplus of $203.2 million (2002—$79.6 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.

Service and Product Contracts. The Company has certain long-term contracts for services and products that have minimum contract volumes or dollar amounts, based on quarterly or annual activity. These contracts are based on market prices, and the minimum requirements are waived in certain instances defined in the contracts. The service contracts have terms extending into 2011 and a hydrogen supply contract expires in 2020.

The Company’s results of operations by quarter for the years ended December 31, 2003 and 2002 were as follows (in millions, except per share amounts):

In January 2004, the Company announced its intention to purchase the assets of Motiva Enterprises LLC’s Delaware City Refining Complex located in Delaware City, Delaware, subject to the satisfaction of certain conditions, including execution of a definitive agreement and obtaining regulatory approvals. There is no assurance the Company will enter into a definitive agreement or consummate the transaction. Assets to be purchased include a heavy crude oil refinery capable of processing in excess of 180,000 bpd, a 2,400 tpd petroleum coke gasification unit, a 160 MW cogeneration facility, and related assets. The asset purchase price is expected to be $800 million, plus the value of petroleum inventories at closing. We expect the inventories will be approximately $100 million. The Company expects to finance the purchase with equal parts equity and debt. As part of the financing the Company is considering the assumption or refinancing of Motiva’s obligations associated with $365 million of tax-exempt bonds issued by the Delaware Economic Development Authority (DEDA) in connection with the gasification and cogeneration facilities. The Company’s assumption of the tax-exempt bonds would be subject to the consent of the DEDA and other parties involved in the financing. There is also a contingent purchase price provision that may result in an additional $25 million payment per year up to a total of $75 million over a three-year period depending on the level of industry refining margins during that period, and a gasifier performance provision that may result in an additional $25 million payment per year up to a total of $50 million over a two-year period depending on the achievement of certain performance criteria at the gasification facility

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, 2003 and 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.


PREMCOR INC.
(Registrant)

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 8, 2004.


THE PREMCOR REFINING GROUP INC.
(Registrant)

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


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


		Page
PART I
Items 1 and 2.	Business and Properties	2
Item 3.	Legal Proceedings	23
Item 4.	Submission of Matters to a Vote of Security Holders	25
	Executive Officers of the Registrant	25

PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	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	60
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A.	Controls and Procedures	62

PART III
Item 10.	Directors and Executive Officers of the Registrant	63
Item 11.	Executive Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
Item 13.	Certain Relationships and Related Transactions	63
Item 14.	Principal Accountant Fees and Services	63

PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	64
	Index to Financial Statements	F-1


	For the Year Ended December 31,
	2003			2002			2001
	bpd (thousands)	Percent of Total		bpd (thousands)	Percent of Total		Bpd (thousands)	Percent of Total
Feedstocks
Crude oil throughput:
Medium and light sour crude oil	31.4	12.5	%	34.3	14.7	%	48.3	20.0	%
Heavy sour crude oil	203.3	80.9		190.4	81.6		181.5	75.2

Total crude oil	234.7	93.4		224.7	96.3		229.8	95.2
Unfinished and blendstocks	16.4	6.6		8.7	3.7		11.4	4.8

Total feedstocks	251.1	100.0	%	233.4	100.0	%	241.2	100.0	%

Production
Light products:
Conventional gasoline	86.0	32.7	%	82.4	32.9	%	82.9	32.7	%
Premium and reformulated gasoline	30.4	11.6		23.0	9.2		24.4	9.6
Diesel fuel	77.6	29.4		65.4	26.1		77.2	30.4
Jet fuel	19.3	7.3		26.5	10.5		19.7	7.8
Petrochemical feedstocks	18.2	6.9		17.8	7.1		18.3	7.2

Total light products	231.5	87.9		215.1	85.8		222.5	87.7
Petroleum coke and sulfur	27.0	10.2		28.7	11.5		26.5	10.4
Residual oil	5.1	1.9		6.8	2.7		4.8	1.9

Total production	263.6	100	%	250.6	100.0	%	253.8	100.0	%


	For the Year Ended December 31,
	2003				2002				2001
	bpd (thousands)		Percent of Total		bpd (thousands)		Percent of Total		bpd (thousands)		Percent of Total
Feedstocks
Crude oil throughput:
Sweet crude oil	136.1		100.7	%	138.0		101.0	%	136.5		99.7	%
Light sour crude oil	3.4		2.5		3.5		2.6		4.0		2.9

Total crude oil	139.5		103.2		141.5		103.6		140.5		102.6
Unfinished and blendstocks	(4.4	)	(3.2	)	(4.9	)	(3.6	)	(3.6	)	(2.6	)

Total feedstocks	135.1		100.0	%	136.6		100.0	%	136.9		100.0	%

Production
Light products:
Conventional gasoline	68.9		50.6	%	73.3		53.0	%	71.2		51.4	%
Premium and reformulated gasoline	12.1		8.9		11.5		8.3		11.5		8.3
Diesel fuel	21.8		16.0		19.3		13.9		21.3		15.4
Jet fuel	21.8		16.0		22.2		16.0		22.7		16.4
Petrochemical feedstocks	7.2		5.2		7.5		5.4		7.0		5.1

Total light products	131.8		96.7		133.8		96.6		133.7		96.6
Petroleum coke and sulfur	2.4		1.8		2.8		2.0		2.8		2.0
Residual oil	2.1		1.5		1.9		1.4		2.0		1.4

Total production	136.3		100.0	%	138.5		100.0	%	138.5		100.0	%


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


	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, 2003

Light products:
Conventional gasoline	32.7	%	50.6	%	40.5	%	39.2	%
Premium and reformulated gasoline	11.6		8.9		8.7		10.1
Diesel fuel	29.4		16.0		29.0		25.9
Jet fuel	7.3		16.0		15.0		11.5
Petrochemical feedstocks	6.9		5.2		4.6		5.9

Subtotal light products	87.9		96.7		97.8		92.6
Petroleum coke and sulfur	10.2		1.8		0.2		5.5
Residual oil	1.9		1.5		2.0		1.9

Total production	100.0	%	100.0	%	100.0	%	100.0	%


	For the Year Ended December 31, 2003
	bpd (thousands)(1)	Percent of Total
Feedstocks
Crude oil throughput:
Sweet crude oil	126.9	95.2	%
Light sour crude oil	0.2	0.1

Total crude oil	127.1	95.3
Unfinished and blendstocks	6.2	4.7

Total feedstocks	133.3	100.0	%

Production
Light products:
Conventional gasoline	53.7	40.5	%
Premium and reformulated gasoline	11.5	8.7
Diesel fuel	38.5	29.0
Jet fuel	19.9	15.0
Petrochemical feedstocks	6.1	4.6

Total light products	129.7	97.8
Petroleum coke and sulfur	0.2	0.2
Residual oil	2.8	2.0

Total production	132.7	100.0	%


Sources of Crude Oil Supply
	bpd (thousands)	Percent of Total
Latin America
Mexico	190.6	38.0	%
Rest of Latin America	57.7	11.5
United States	163.3	32.6
Africa	44.2	8.8
North Sea	26.1	5.2
Middle East	16.3	3.3
Other	3.1	0.6

Total	501.3	100.0	%


Name	Age	Position
Thomas D. O’Malley	62	Chairman of the Board and Chief Executive Officer
Henry M. Kuchta	47	President and Chief Operating Officer
William E. Hantke	56	Executive Vice President and Chief Financial Officer
Dennis R. Eichholz	50	Senior Vice President—Finance and Controller
Michael D. Gayda	49	Senior Vice President—General Counsel and Secretary
Donald F. Lucey	51	Senior Vice President—Commercial for PRG
James R. Voss	37	Senior Vice President and Chief Administrative Officer
Joseph D. Watson	39	Senior Vice President—Corporate Development, Treasurer and Assistant Secretary


	Sales Price per Share
Quarter ended	High		Low
2003:
March 31	$	26.00	$	19.28
June 30	$	25.70	$	20.84
September 30	$	24.50	$	21.30
December 31	$	26.00	$	22.06

2002:
June 30	$	28.25	$	24.52
September 30	$	24.95	$	15.65
December 31	$	22.93	$	13.40


	Year Ended December 31,
	2003			2002			2001			2000			1999
	(in millions, except as noted)
Statement of earnings data:
Net sales and operating revenues (1)	$	8,803.9		$	5,906.0		$	5,985.0		$	7,162.3		$	4,245.7
Cost of sales (1)		7,719.2			5,235.0			4,818.9			6,423.1			3,825.0
Operating expenses		524.9			432.2			467.7			467.7			402.8
General and administrative expenses		67.1			51.8			63.3			53.0			51.5
Stock-based compensation		17.6			14.0			—			—			—
Depreciation and amortization (2)		106.2			88.9			91.9			71.8			63.1
Refinery restructuring and other charges		38.5			172.9			176.2			—			—
Inventory write-down (recovery) to market value		—			—			—			—			(105.8	)

Operating income (loss)		330.4			(88.8	)		367.0			146.7			9.1
Interest expense and finance income, net (3)		(115.1	)		(101.8	)		(139.5	)		(82.2	)		(91.5	)
Gain (loss) on extinguishment of long-term debt (4)		(27.5	)		(19.5	)		8.7			—			—
Income tax (provision) benefit		(64.0	)		81.3			(52.4	)		25.8			12.0
Minority interest in subsidiary		—			1.7			(12.8	)		(0.6	)		1.4

Income (loss) from continuing operations		123.8			(127.1	)		171.0			89.7			(69.0	)
Discontinued operations, net of taxes (5)		(7.2	)		—			(18.0	)		—			32.6

Net income (loss)		116.6			(127.1	)		153.0			89.7			(36.4	)
Preferred stock dividends		—			(2.5	)		(10.4	)		(9.6	)		(8.6	)

Net income (loss) available to common stockholders	$	116.6		$	(129.6	)	$	142.6		$	80.1		$	(45.0	)

Net income (loss) from continuing operations per share:
—basic	$	1.70		$	(2.65	)	$	5.05		$	2.79		$	(3.59	)
—diluted		1.68			(2.65	)		4.65			2.55			(3.59	)
Weighted average number of common shares outstanding:
—basic		72.8			49.0			31.8			28.8			21.6
—diluted		73.6			49.0			34.5			31.5			21.6
PRG:
Net sales and operating revenues (1)	$	8,802.2		$	5,905.8		$	5,985.0		$	7,162.3		$	4,245.5
Income (loss) from continuing operations		124.7			(114.4	)		158.9			83.8			(47.0	)
Cash flow data:
Cash flows from operating activities	$	182.4		$	15.9		$	439.2		$	124.4		$	85.5
Cash flows from investing activities		(710.3	)		(144.5	)		(152.9	)		(375.3	)		(321.3	)
Cash flows from financing activities		787.2			(214.1	)		(66.3	)		234.8			393.9
Capital expenditures for property, plant and equipment		229.8			114.3			94.5			390.7			438.2
Capital expenditures for turnarounds		31.5			34.3			49.2			31.5			77.9
Refinery acquisition expenditures		476.0			—			—			—			—
Earn-out payment on refinery acquisition		14.2			—			—			—			—
Key operating statistics:
Production (barrels per day in thousands)		532.6			438.2			463.4			477.3			460.5
Crude oil throughput (barrels per day in thousands)		501.3			412.8			439.7			468.0			451.7
Total crude oil throughput (millions of barrels)		183.0			150.7			160.5			171.3			164.9
Per barrel of crude oil throughput:
Gross margin	$	5.93		$	4.45		$	7.27		$	4.32		$	2.55
Operating expenses		2.87			2.87			2.91			2.73			2.44


	As of December 31,
	2003		2002		2001		2000		1999
	(in millions)
Balance sheet data:
Premcor Inc.:
Cash, cash equivalents and short-term investments (6)	$	499.2	$	234.0	$	542.6	$	291.8	$	307.6
Working capital		860.1		320.9		482.6		325.0		305.8
Total assets		3,715.3		2,323.0		2,509.8		2,469.1		1,984.1
Long-term debt		1,452.1		924.9		1,472.8		1,516.0		1,340.4
Exchangeable preferred stock		—		—		94.8		90.6		81.1
Stockholders’ equity		1,145.2		704.0		294.7		152.1		14.7
PRG:
Cash, cash equivalents and short-term investments (6)	$	445.2	$	183.1	$	515.0	$	252.9	$	286.4
Working capital		778.1		243.2		429.2		261.1		267.0
Total assets		3,659.8		2,246.3		2,477.9		2,414.0		1,960.4
Long-term debt		1,441.8		884.8		1,328.4		1,341.0		1,165.4
Stockholder’s equity		1,026.6		627.8		443.8		328.7		222.3


	Premcor Inc.			PRG
Current assets	$	174.0		$	174.0
Property, plant, & equipment		315.6			291.6
Accrued liabilities		(2.7	)		(2.7	)
Current portion of long-term debt		(0.3	)		—
Long-term debt (capital leases)		(10.2	)		—
Other long-term liabilities		(2.3	)		(2.3	)

Total purchase price allocation		474.1			460.6
Integration costs		1.9			1.9

Expenditures for refinery acquisition	$	476.0		$	462.5


	Severance			Other Costs			Total Costs
Summary of Restructuring Expenses:
Expected total restructuring expenses	$	6.4		$	8.7		$	15.1
Expenses recorded this year		5.0			4.1			9.1
Cumulative expenses recorded to date		5.0			4.1			9.1
Liability Activity:
Beginning balance, December 31, 2002	$	4.9		$	—		$	4.9
Expenses recorded this year		5.0			4.1			9.1
Adjustments		(1.6	)		—			(1.6	)
Cash outflows		(3.1	)		(4.1	)		(7.2	)

Ending balance, December 31, 2003	$	5.2		$	—		$	5.2


	Lease Obligations			Environmental Obligations of Previously Owned and Leased Sites			Total Discontinued Operations
Beginning balance, December 31, 2002	$	—		$	23.0		$	23.0
Net present value of lease obligations		8.6			—			8.6
Accretion and other expenses		3.2			—			3.2
Net cash outlays		(4.4	)		(1.8	)		(6.2	)

Ending balance, December 31, 2003	$	7.4		$	21.2		$	28.6


	Year Ended December 31,
Financial Results	2003			2002			2001
	(in millions, except per share data)
Net sales and operating revenues	$	8,803.9		$	5,906.0		$	5,985.0
Cost of sales		7,719.2			5,235.0			4,818.9

Gross margin		1,084.7			671.0			1,166.1
Operating expenses		524.9			432.2			467.7
General and administrative expenses		67.1			51.8			63.3
Stock-based compensation		17.6			14.0			—
Depreciation & amortization		106.2			88.9			91.9
Refinery restructuring and other charges		38.5			172.9			176.2

Operating income (loss)		330.4			(88.8	)		367.0
Interest expense and finance income, net		(115.1	)		(101.8	)		(139.5	)
Gain (loss) on extinguishment of long-term debt		(27.5	)		(19.5	)		8.7
Income tax (provision) benefit		(64.0	)		81.3			(52.4	)
Minority interest		—			1.7			(12.8	)

Income (loss) from continuing operations		123.8			(127.1	)		171.0
Discontinued operations		(7.2	)		—			(18.0	)

Net income (loss)		116.6			(127.1	)		153.0
Preferred stock dividends		—			(2.5	)		(10.4	)

Net income (loss) available to common stockholders	$	116.6		$	(129.6	)	$	142.6

Diluted net income (loss) available to common stockholders per share	$	1.58		$	(2.65	)	$	4.13
Diluted weighted average common shares outstanding		73.6			49.0			34.5

	Year Ended December 31,
Market Indicators	2003			2002			2001
	(dollars per barrel, except as noted)
West Texas Intermediate (WTI) crude oil	$	31.15		$	26.13		$	25.96
Crack Spreads
Gulf Coast 2/1/1		4.06			2.72			3.92
Chicago 3/2/1		6.39			5.00			7.90
Crude Oil Differentials:
WTI less Maya (heavy sour)		6.87			5.21			8.76
WTI less WTS (sour)		2.73			1.38			2.81
WTI less Dated Brent (foreign)		2.31			1.12			1.48
Natural gas (dollars per million btu)		5.36			3.17			4.22

	Year Ended December 31,
Selected Operational Data	2003			2002			2001
	(in thousands of barrels per day, except as noted)
Crude oil throughput by refinery:
Port Arthur		234.7			224.7			229.8
Lima		139.5			141.5			140.5
Memphis		127.1			—			—
Hartford		—			46.6			65.5
Blue Island		—			—			3.9

Total crude oil throughput		501.3			412.8			439.7
Total crude oil throughput (millions of barrels)		183.0			150.7			160.5
Per barrel of crude oil throughput (in dollars):
Gross margin	$	5.93		$	4.45		$	7.27
Operating expenses		2.87			2.87			2.91


	Projected 2004		2003		2002		2001
Mandatory, excluding low-sulfur standards	$	235	$	100.7	$	63.5	$	86.6
Gasoline low-sulfur standards		100		140.4		53.2		—
Diesel low-sulfur standards		75		4.0		3.5		—
Discretionary		100		16.2		28.4		57.1

Total	$	510	$	261.3	$	148.6	$	143.7


	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt obligations	$	1,441.8	$	24.2	$	79.8	$	88.8	$	1,249.0
Capital lease obligations		10.3		0.3		0.9		1.0		8.1
Operating lease obligations		216.3		34.8		65.2		56.6		59.7
Capital expenditure commitments		89.0		89.0		—		—		—

	$	1,757.4	$	148.2	$	145.8	$	146.5	$	1,316.8


	Pension Plans				Postretirement Plans
	2003		2002		2002		2002
Discount rate	6.00	%	6.75	%	6.00	%	6.75	%
Expected return on asset	8.50	%	8.50	%	—		—
Average rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%


	Pension Benefits		Other Postretirement Benefits
Increase to benefit liability:
Discount rate	$	0.6	$	9.8
Health care cost trend rate		—		8.8
Increase in expense:
Discount rate		0.3		1.1
Health care cost trend rate		—		0.7


	(a) Number of securities to be issued upon exercise of outstanding options	(b) Weighted average exercise price of outstanding options		(c) Number of securities remaining available for future issuance under the equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	5,114,171	$	14.49 per share	1,351,225
Equity compensation plans not approved by security holders	—		—	—

Total	5,114,171	$	14.49 per share	1,351,225


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		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)).

4.02		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 12¹/2% 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)).

4.03		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)).


Exhibit Number		Description
4.04		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)).

4.05		Indenture dated as of February 11, 2003, between PRG and Deutsche Bank Trust Company Americas, as Trustee (Incorporated by reference to Exhibit 4.13 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392))

4.06		Form of 9¹/4% Senior Notes due 2010 and 9¹/2% Senior Notes due 2013 (Incorporated by reference to Exhibit 4.11 and 4.12, respectively, filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-104682))

4.07		Form of 7¹/2% Senior Note due 2015 (Incorporated by reference to Exhibit 4.11 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-106916)).

4.08		Form of 6³/4% Senior Notes due 2011 (Incorporated by reference to Exhibit 4.12 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-111265))

4.09		Supplemental Indenture, dated as of November 12, 2003, between PRG and Deutsche Bank Trust Company Americas, as Trustee (Incorporated by reference to Exhibit 4.10 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-111265)).

4.10		Form of 7³/4% Senior Subordinated Notes due 2012 (Incorporated by reference to Exhibit 4.13 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-111265))

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)).

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)).


Exhibit Number		Description
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		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)).

10.09		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. (Incorporated by reference to Exhibit 10.13 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392)).

10.10		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 (Incorporated by reference to Exhibit 10.14 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392)).

10.11		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)).

10.12		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 (Incorporated by reference to Exhibit 10.16 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392))

10.13	*	Crude Oil Supply Agreement, dated March 3, 2003, between Morgan Stanley Capital Group Inc. and PRG (Incorporated by reference to Exhibit 10.1 filed with Premcor’s Quarterly Report on Form 10Q for the quarter ended March 31, 2003 (File No. 1-11392)).

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

10.15		Amendment to the Premcor Inc. Senior Executive Retirement Plan dated as of February 28, 2003 (Incorporated by reference to Exhibit 10.19 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392))

10.16		Amendment to the Premcor Inc. Senior Executive Retirement Plan dated May 30, 2003 (Incorporated by reference to Exhibit 10.1 filed with PRG’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-11392)).

10.17		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)).

10.18		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, 2002 (File No. 1-11392)).


Exhibit Number		Description
10.19		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)).

10.20		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)).

10.21		Amendment to Employment Agreement, dated May 20, 2003, of Thomas D. O’Malley (Incorporated by reference to Exhibit 10.26 filed with PRG’s Registration Statement on Amendment No. 1 to Form S-4 (Registration No. 333-106916)

10.22		Letter Agreement, dated December 15, 2003, amending the employment agreement of Thomas D. O’Malley (filed herewith).

10.23		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)).

10.24		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)).

10.25		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)).

10.26		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)).

10.27		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)).

10.28		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)).

10.29		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)).

10.30		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)).

10.31		Form of Letter Agreement, dated as of January 22, 2003, 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 10.2 filed with PRG’s Quarterly Report on Form 10Q for the quarter ended March 31, 2003 (File No. 1-11392)).

10.32		Form of Amendment to Employment Agreement, dated May 20, 2003, of William E. Hantke, Henry M. Kuchta, Joseph D. Watson, James R. Voss, Michael D. Gayda and Donald Lucey (Incorporated by reference to Exhibit 10.5 filed with PRG’s Quarterly Report on Form 10Q for the quarter ended June 30, 2003 (File No. 1-11392)).


Exhibit Number		Description
10.33		Amended and Restated Letter Agreement, dated as of November 6, 2002, between Premcor Inc. and Wilkes McClave III (Incorporated by reference to Exhibit 10.40 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392))

10.34		Amended and Restated Letter Agreement, dated as of November 6, 2002, between Premcor Inc. and Jefferson F. Allen (Incorporated by reference to Exhibit 10.41 filed with PRG’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-11392))

10.35		Amended and Restated Employment Agreement, dated June 1, 2002 and Letter of Agreements, dated November 13, 2002 and January 22, 2003 of Donald F. Lucey (filed herewith).

10.36		Form of Letter Agreement, dated as of December 15, 2003, amending Employment Agreements of Henry Kuchta, William Hantke, Michael Gayda, James Voss, Joseph Watson and Donald Lucey (filed herewith).

14.1		Code of Business Conduct and Ethics of Premcor Inc. (filed herewith).

21.1		Subsidiaries of the Registrant (filed herewith).

23.1		Consent of Deloitte & Touche (filed herewith).

31.1		Section 302 Chief Executive Officer certificate for Premcor Inc. (filed herewith).

31.2		Section 302 Chief Financial Officer certificate for Premcor Inc. (filed herewith).

31.3		Section 302 Chief Executive Officer certificate for PRG. (filed herewith).

31.4		Section 302 Chief Financial Officer certificate for PRG. (filed herewith).

32.1		Section 906 Chief Executive Officer certificate for Premcor Inc. (filed herewith).

32.2		Section 906 Chief Financial Officer certificate for Premcor Inc. (filed herewith).

32.3		Section 906 Chief Executive Officer certificate for PRG. (filed herewith).

32.4		Section 906 Chief Financial Officer certificate for PRG. (filed herewith).


		Page
Financial Statements:

Premcor Inc.:
Independent Auditors’ Report		F-2
Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001		F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001		F-5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001		F-6

The Premcor Refining Group Inc.:
Independent Auditors’ Report		F-7
Consolidated Balance Sheets as of December 31, 2003 and 2002		F-8
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001		F-9
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001		F-10
Consolidated Statements of Stockholder’s Equity for the Years Ended December 31, 2003, 2002, and 2001		F-11

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

Financial Statement Schedules:

Schedule I—Condensed Financial Information of Premcor Inc.		F-57
Schedule II—Valuation and Qualifying Accounts		F-61


	December 31,
	2003			2002
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	426.7		$	167.4
Short-term investments		5.9			4.9
Cash and cash equivalents restricted for debt service		66.6			61.7
Accounts receivable, net of allowance of $1.9 and $3.2		623.5			269.1
Inventories		630.3			287.3
Prepaid expenses and other		92.7			45.9
Assets held for sale		—			49.3

Total current assets		1,845.7			885.6
PROPERTY, PLANT AND EQUIPMENT, NET		1,739.8			1,262.6
DEFERRED INCOME TAXES		—			57.5
OTHER ASSETS		129.8			117.3

	$	3,715.3		$	2,323.0

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	779.9		$	466.2
Accrued expenses and other		125.8			57.2
Accrued taxes other than income		53.8			26.3
Current portion of long-term debt		26.1			15.0

Total current liabilities		985.6			564.7
LONG-TERM DEBT		1,426.0			909.9
DEFERRED INCOME TAXES		0.6			—
OTHER LONG-TERM LIABILITIES		157.9			144.4
COMMITMENTS AND CONTINGENCIES

COMMON STOCKHOLDERS’ EQUITY:
Common, $0.01 par value per share; 150,000,000 authorized, 74,119,694 issued and outstanding as of December 31, 2003; 150,000,000 authorized, 58,043,935 issued and outstanding as of December 31, 2002		0.7			0.6
Paid-in capital		1,186.8			862.3
Accumulated deficit		(42.3	)		(158.9	)

Total common stockholders’ equity		1,145.2			704.0

	$	3,715.3		$	2,323.0


	For the Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	116.6		$	(127.1	)	$	153.0
Discontinued operations		7.2			—			18.0
Adjustments:
Depreciation		64.4			48.8			53.2
Amortization		51.3			50.6			50.3
Deferred income taxes		62.5			(79.2	)		52.0
Stock-based compensation		17.6			14.0			—
Minority interest		—			(1.7	)		12.8
Refinery restructuring and other charges		14.8			110.3			118.5
Write-off of deferred financing costs		10.3			9.5			0.6
Write-off of equity investment		—			4.2			—
Other, net		14.0			6.8			0.9
Cash provided by (reinvested in) working capital:
Accounts receivable		(354.4	)		(120.8	)		102.2
Prepaid expenses and other		(37.8	)		6.4			(13.1	)
Inventories		(178.0	)		31.0			60.0
Accounts payable		313.7			99.8			(138.8	)
Accrued expenses and other		58.5			(38.2	)		5.0
Accrued taxes other than income		27.5			(9.4	)		(2.7	)
Cash and cash equivalents restricted for debt service		0.2			14.3			(24.3	)

Net cash provided by operating activities of continuing operations		188.4			19.3			447.6
Net cash used in operating activities of discontinued operations		(6.0	)		(3.4	)		(8.4	)

Net cash provided by operating activities		182.4			15.9			439.2

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(229.8	)		(114.3	)		(94.5	)
Expenditures for turnaround		(31.5	)		(34.3	)		(49.2	)
Expenditures for refinery acquisition		(476.0	)		—			—
Earn-out payment associated with refinery acquisition		(14.2	)		—			—
Cash and cash equivalents restricted for investment in capital additions		2.2			7.3			(9.9	)
Proceeds from sale of assets		40.0			—			0.7
Other		(1.0	)		(3.2	)		—

Net cash used in investing activities		(710.3	)		(144.5	)		(152.9	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,210.0			—			10.0
Long-term debt and capital lease payments		(694.3	)		(645.8	)		(59.3	)
Cash and cash equivalents restricted for debt repayment		(5.1	)		(45.2	)		(6.5	)
Proceeds from issuance of common stock, net		306.5			488.3			—
Deferred financing costs		(29.9	)		(11.4	)		(10.2	)
Other		—			—			(0.3	)

Net cash provided by (used in) financing activities		787.2			(214.1	)		(66.3	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		259.3			(342.7	)		220.0
CASH AND CASH EQUIVALENTS, beginning of period		167.4			510.1			290.1

CASH AND CASH EQUIVALENTS, end of period	$	426.7		$	167.4		$	510.1


	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, 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
Stock issuance	15,984,100		0.1	—			—			306.0		—			306.1
Exercise of stock options, including tax benefits	91,659		—	—			—			0.9		—			0.9
Stock-based compensation	—		—	—			—			17.6		—			17.6
Net income	—		—	—			—			—		116.6			116.6

BALANCE, December 31, 2003	74,119,694	$	0.7	—		$	—		$	1,186.8	$	(42.3	)	$	1,145.2


	Number of Common Shares	Common Stock		Paid-in Capital			Retained Earnings			Total
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
Capital contributions, net	—		—		263.3			—			263.3
Stock-based compensation	—		—		17.6			—			17.6
Tax benefit on stock options exercised	—		—		0.4			—			0.4
Net income	—		—		—			117.5			117.5

BALANCE, December 31, 2003	100	$	—	$	822.7		$	203.9		$	1,026.6


	Severance			Other Costs			Total Costs
Summary of Restructuring Expenses:
Expected total restructuring expenses	$	6.4		$	8.7		$	15.1
Expenses recorded this year		5.0			4.1			9.1
Cumulative expenses recorded to date		5.0			4.1			9.1
Liability Activity:
Beginning balance, December 31, 2002	$	4.9		$	—		$	4.9
Expenses recorded this year		5.0			4.1			9.1
Adjustments		(1.6	)		—			(1.6	)
Cash outflows		(3.1	)		(4.1	)		(7.2	)

Ending balance, December 31, 2003	$	5.2		$	—		$	5.2


	Lease Obligations			Environmental Obligations of Previously Owned and Leased Sites			Total Discontinued Operations
Beginning balance, December 31, 2002	$	—		$	23.0		$	23.0
Net present value of lease obligations		8.6			—			8.6
Accretion and other expenses		3.2			—			3.2
Net cash outlays		(4.4	)		(1.8	)		(6.2	)

Ending balance, December 31, 2003	$	7.4		$	21.2		$	28.6


	For The Year Ended December 31,
	2003	2002	2001
Weighted average common shares outstanding	72.8	49.0	31.8
Dilutive effect of:
Stock options	0.8	—	—
Common stock warrants	—	—	2.7

Weighted average common shares outstanding, assuming dilution	73.6	49.0	34.5