ITEM 3. LEGAL PROCEEDINGS
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. The lawsuit has been stayed while we discuss with the State implementing an assessment and remediation plan for the Hartford refinery site. In the first quarter of 2004, an Administrative Order on Consent was signed by us, two other potentially responsible parties, and the U.S. Environmental Protection Agency. This order requires the investigation of groundwater contamination and the development of a remedial solution for a portion of the Village of Hartford.
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. was removed to the United States District Court for the Southern District of Illinois. In the second quarter of 2004, plaintiffs filed an amended complaint in the United States District Court Southern District of Illinois. The amended complaint added new, non-diverse defendants, eliminated a cause of action for strict liability and added a new cause of action based on a negligence theory. We filed an answer to the amended complaint setting forth its defenses. The United States District Court also remanded the case to state court. The case is currently in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 03-L-1053 captioned Sparks, et al. v. The Premcor Refining Group, Inc. et al.
In the second quarter of 2004, two new lawsuits were served by residents in the Village of Hartford. The original complaints have since been amended. The two lawsuits are Bedwell, et al. v. The Premcor Refining Group, Inc., et al. in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 04-L-342 and Abert, et al. v. Alberta Energy Company, Ltd., et al. in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 04-L-354. Bedwell contains allegations substantially similar to Sparks. Bedwell includes a request for class certification similar to Sparks. No class certification has been granted in either case. Abert also raises allegations substantially similar to Sparks but on behalf of approximately 114 individually named plaintiffs against approximately 24 different defendants. We have filed responsive pleadings in both cases including defenses to plaintiffs’ claims.
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 sought class certification, unspecified damages and the establishment of a trust fund for health concerns. The case is entitled Marion L Aaron, et al. v. Premcor Refining Group Inc. et al. and is filed in Judicial District Court of Jefferson County, Texas. The plaintiffs recently filed a Motion to Non-Suit all their claims in this case. The Motion was unopposed and dismisses the case in its entirety.
During the fourth quarter of 2004, we received service of 13 lawsuits also brought by residents in the area of Port Arthur, Texas alleging personal and pecuniary injuries caused by emissions from industrial facilities in the area. We were non-suited without prejudice in three of the lawsuits prior to filing an appearance. The cases have been consolidated into one lead case entitled Crystal Faulk, et al. v. Premcor Refining, et al. in the District Court of Jefferson County, Texas, Case No. B-173,357. Consolidated petitions have been filed in the case which assert the claims of 142 plaintiffs, 85 of whom are alleging claims against us and others. The cases generally involve allegations of negligence per se, negligence, fraud, permanent nuisance, trespass and gross negligence.
Methyl-Tertiary Butyl Ether Products Liability Litigation. During the fourth quarter of 2003 and continuing, we have been named in approximately 51 cases, along with dozens of other companies, filed in approximately 15 states concerning the use of MTBE. The cases contain allegations that MTBE is defective. The cases have been removed to federal court and consolidated 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. We have filed or joined in responsive pleadings including defenses to plaintiffs’ claims and has raised additional defenses including those based on the Company’s limited use of MTBE and its narrow geographical use.
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 alleged 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 alleged conditions that existed at the time have since changed. In May 2001, the TCEQ proposed an order covering some of the 1998 air and hazardous waste allegations and proposed 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.
The TCEQ conducted another inspection at our Port Arthur refinery on April 4, 2003. In August 2003, we received a notice of enforcement regarding that inspection alleging 46 air-related violations. We dispute the allegations 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 non-permanent personal injury resulting from that catalyst release. The complaint underlying this action was later amended to add allegations of subsequent events that allegedly interfered with the use and enjoyment of neighboring property. 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 sought damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. Mason was voluntarily dismissed in 2004. Rosolowski and Madrigal have been consolidated for the purpose of conducting discovery, which is currently proceeding. Other single plaintiff cases regarding the same incidents are also pending. The cases are pending in Circuit Court of Cook County, Illinois.
Blue Island Reformulated Gasoline Notice of Violation. In the second quarter of 2004, we received a Notice of Violation from the U.S. EPA under the Clean Air Act for allegedly not meeting the minimum annual average emissions performance for reformulated gasoline from the Blue Island Refinery in 2001. The Blue Island
Refinery only operated for approximately one month in 2001. We reached a settlement agreement with U.S. EPA on this matter in the fourth quarter of 2004 and the Notice of Violation has now been resolved.
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. We entered into a Consent Order with the State of Illinois to resolve this case. The Consent Order involves performing an assessment and remediation feasibility study of the Blue Island property.
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.
Former Retail Sites Violation Notices. In the first quarter of 2004, we received 39 Violation Notices from the Illinois EPA as a result of remediation activities at 35 former retail sites in the State of Illinois. The notices do not contain any proposed penalties but penalties may be sought under the applicable law. We have responded to the Violation Notices and are continuing the remediation work being performed at these sites.
Alleged Asbestos and Benzene Exposure. We, along with numerous other defendants, have been named in certain individual lawsuits alleging personal injury resulting from exposure to asbestos or benzene. A majority of the claims have been filed by employees of third party independent contractors who purportedly were exposed 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 previously commenced an industry-wide enforcement initiative regarding New Source Review and other laws. The 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 ten 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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of our fiscal year ended December 31, 2004.
Executive Officers of Registrant
The following is a list of our executive officers as of March 4, 2005:
Name
Age
Position
Jefferson F. Allen
Chief Executive Officer and Director
Dennis R. Eichholz
Senior Vice President and Controller
Michael D. Gayda
Senior Vice President-General Counsel and Secretary
Henry M. Kuchta
President and Chief Operating Officer
Donald F. Lucey
Senior Vice President-Commercial
Joseph D. Watson
Senior Vice President and Chief Financial Officer
James R. Voss
Senior Vice President and Chief Administrative Officer
Jefferson F. Allen has served as our chief executive officer since January 2005. Mr. Allen has served on the board of directors since February 2002 and was the chairman of the audit committee from February 2002 to December 2004. From June 1990 to September 2001, Mr. Allen served in various positions with Tosco Corporation, most recently as Tosco’s president and chief financial officer. From November 1988 to June 1990, Mr. Allen served in various positions at Comfed Bancorp Inc., including chairman and chief executive officer.
Dennis R. Eichholz has served as senior vice president and controller of our company since February 2001. Since joining the Company’s predecessor 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, following 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.
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, following 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. Mr. Kuchta is the brother of the vice president of domestic and international crude purchasing for PRG.
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.
Joseph D. Watson has served as senior vice president and chief financial officer since January 2005. Mr. Watson served as senior vice president-corporate development, treasurer and assistant secretary of our company from July 2003 to December 2004. 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 positions with Tosco from 1993 to 2000. From 1991 to 1993, he served as vice president of Argus Investments, Inc., a private investment company.
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. and from October 1996 to June 1999, he served as a human resource manager of Foodmaker, Inc. Prior to joining Foodmaker, Inc., he spent 10 years in human resources management, operations and labor relations with United Parcel Service.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common stock. Premcor Inc.’s common stock trades on the New York Stock Exchange under the symbol “PCO”. As of March 4, 2005, Premcor Inc.’s common stock was held by 31 stockholders of record and an estimated 39,000 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 2004 and 2003, 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.
During the fourth quarter of 2004, we announced a $0.02 dividend per share; we also announced a $0.02 dividend per share in the first quarter of 2005. 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. Premcor has no restrictions on its ability to pay dividends; however, PRG’s ability to pay dividends is effectively limited by the terms of its credit facility and debt instruments.
Purchases of Common Stock. We did not repurchase any of our common stock in 2004 and we have no plans to do so in the foreseeable future.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
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 operations and cash flows data for the years ended December 31, 2004, 2003 and 2002 and the selected balance sheet data as of December 31, 2004 and 2003 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 operations and cash flow data for the years ended December 31, 2001 and 2000 and the selected balance sheet data as of December 31, 2002, 2001, and 2000 have been derived from our audited consolidated financial statements, including the notes thereto, not included in this Annual Report on Form 10-K. The 2001 and 2000 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, the acquisition of our Memphis refinery in March 2003 and the acquisition of our Delaware City refinery in May 2004. 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 Annual Report on Form 10-K.
(1) Cost of sales includes the net effect of the buying and selling of crude oil to supply our refineries. Operating revenue and cost of sales for 2002, 2001 and 2000 have been reclassified to conform to the fourth quarter 2003 application of 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, effective as of January 1, 2003. The reclassification had no effect on previously reported operating income (loss) or net income (loss).
(2) Stock based compensation, which is included in general and administrative expenses, consisted of $19.6 million, $17.6 million, $14 million, nil and nil as of December 31, 2004, 2003, 2002, 2001 and 2000, respectively.
(3) Interest and finance expense, net, included amortization of debt issuance costs of $8.5 million, $9.1 million, $12.3 million, $14.9 million, and $12.4 million for the years ended December 31, 2004, 2003, 2002, 2001, and 2000, respectively. Interest and finance expense, net, also included interest on all indebtedness, net of capitalized interest and interest income.
(4) In 2002, we elected the early adoption of Statement of Financial Accounting Standard No. 145 and, accordingly, have included the gain (loss) on extinguishment of debt in “Income (loss) from continuing operations” as opposed to an extraordinary item, net of tax, in our statement of operations. We have accordingly restated our statement of operations and statement of cash flows for 2001.
(5) Discontinued operations is net of an income tax benefit of $3.6 million, $4.4 million and $11.5 million for the years ended December 31, 2004, 2003 and 2001, respectively.
(6) In 2004, the Company began to classify its investment in auction rate securities as short-term investments. These amounts were previously included in cash and cash equivalents, such amounts have been reclassified in the accompanying consolidated financial statements to conform to the current period classification. The reclassification was made because the certificates had stated maturities beyond three months. The reclassification resulted in changes in the consolidated statement of cash flows within the cash and cash equivalent balances and investing activities and impacted cash flows used in investing activities by $(211) million, $144 million, $(239) million and $0 million for the years ended December 31, 2003, 2002, 2001 and 2000, respectively.
(7) Cash, cash equivalents, and short-term investments includes $69.1 million, $66.6 million, $61.7 million, $30.8 million and nil of cash and cash equivalents restricted for debt service as of December 31, 2004, 2003, 2002, 2001 and 2000, respectively.
(8) Working capital is calculated by subtracting total current assets from total current liabilities.
(9) In order to assess our operating performance, we compare our actual gross margin per barrel (net sales and operating revenues less cost of sales divided by total throughput) and our operating expenses per barrel (operating expenses divided by total throughput).
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
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 four 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 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 four refineries, which are located in Port Arthur, Texas; Lima, Ohio; Memphis, Tennessee; and Delaware City, Delaware; with a combined crude oil volume processing capacity, known as throughput capacity, of approximately 800,000 barrels per day, or bpd. We sell petroleum products in the Midwest, the Gulf Coast, Northeastern 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.
Recent Developments in 2005
We announced on January 27, 2005 that our Board of Directors had declared a dividend of $.02 per share payable on March 15, 2005 to shareholders of record on March 1, 2005.
Factors Affecting Comparability
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.
Acquisition of the Delaware City refinery and related financings
Effective May 1, 2004, we completed an agreement with Motiva Enterprises LLC (“Motiva”) to purchase its Delaware City refining complex located in Delaware City, Delaware. The Delaware City refinery has a rated crude unit throughput capacity of approximately 190,000 bpd. Also included in the purchase was a 2,400 tons per day petroleum coke gasification unit, a 180 megawatt cogeneration facility, 8.5 million barrels of crude oil, intermediates, blendstock, and product tankage and a 50,000 bpd truck-loading rack. The purchase price was $800 million ($780 million cash and $20 million assumed liabilities), plus additional petroleum inventories valued at $90 million and approximately $2 million in transaction fees. In addition, Motiva will be entitled to receive contingent purchase payments of $25 million per year up to a total of $75 million over a three-year period depending on the amount of crude oil processed at the refinery and the level of refining margins during that period, and a $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. Any amount we pay to Motiva for the contingent consideration will be recorded as goodwill. Such goodwill will not be amortized but will be subject to an annual impairment test.
The Delaware City refinery is a high-conversion medium and heavy high-sulfur crude oil refinery. Major process units include a crude unit, a fluid coking unit, a fluid catalytic cracking unit, a high pressure
hydrocracking unit, a reformer unit and a coke gasification unit. Primary products include regular and premium conventional and reformulated gasoline, low-sulfur diesel, heating oil and jet fuel. 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.
The Company financed the acquisition from a portion of the proceeds from its April 2004 public common stock offering of 14.9 million shares which provided net proceeds of $490 million; from PRG’s $400 million senior notes offering completed April 2004 of which $200 million, due in 2011, bear interest at 6 1/8% per annum and $200 million, due in 2014, bear interest at 6 3/4% per annum; and from available cash.
The acquisition of the Delaware City 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 fourth quarter of 2004, we adjusted the purchase price allocation based on the revised value of the long-term liabilities (primarily post-retirement benefits) that we assumed. The adjusted preliminary purchase price allocation, subject to finalization, is as follows:
In conjunction with the acquisition of the Delaware City refinery, We entered into an agreement, effective May 1, 2004, with the Saudi Arabian Oil Company for the supply of 105,000 bpd of crude oil, however, due to certain quota restrictions the current supply is 85,000 bpd. The agreement has terms extending to April 30, 2005, with automatic one-year extensions thereafter unless terminated at the option of either party. The crude oil is priced by a market-based formula as defined in the agreement. We also entered into a product offtake agreement with Motiva that provides for the delivery by Premcor to Motiva of approximately 36,700 bpd of finished light petroleum products, such as gasoline and heating oil. The agreement was effective May 1, 2004, and the main portion of the offtake agreement has terms extending for six months with automatic renewals until canceled by either party.
For federal income tax purposes, we have incurred, as a result of the April 2004 equity offering, a stock ownership change of more than 50%, determined over the preceding three-year period. Under federal tax law, the more than 50% stock ownership change has resulted in an annual limitation being placed on the amount of regular and alternative minimum tax net operating losses, and certain other losses and tax credits (collectively “tax attributes”) that may be utilized in any given year. Accordingly, our ability to utilize tax attributes could be affected in both timing and amount. However, management believes such annual limitation will not restrict our ability to significantly utilize our tax attributes over the applicable carryforward periods. Therefore, at this time, we do not anticipate the need for an additional valuation allowance as a result of this more than 50% stock ownership change.
Acquisition of the Memphis refinery and related financings
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 155,000 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 13 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, or its assignee over the next seven years, depending on the level of refining margins during that period. Any amounts we pay for the contingent consideration will be recorded as goodwill. Such goodwill will not be amortized, but will be subject to an annual impairment evaluation. As of December 31, 2004, we had paid $27.6 million of contingent consideration.
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 previous credit agreement to allow for the acquisition. See “-Liquidity and Capital Resources-Cash Flows from Financing Activities” and “Credit Agreements” for additional details of the financings.
Refinery Restructuring and Other Charges
During the year ended December 31, 2004, we recorded refinery restructuring and other charges of $19.5 million. The charges included $7.3 million related to the relocation of our St. Louis general office to its Connecticut headquarters, $3.1 million related to litigation costs associated with non-operating assets and $9.1 million related to environmental charges primarily for additional estimated costs related to cleanup at the Village of Hartford and additional remediation activities at our other sites.
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 management, refinery operations, and administrative restructuring in 2002, 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.
Below are further discussions of the Hartford and Blue Island refinery closures and the management, refinery, and administrative function restructurings.
Refinery Closures and Asset Sales. 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 postretirement benefits that were extended to certain employees who were nearing the retirement requirements. We continue to utilize our storage and distribution facilities at both the Blue Island and Hartford 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. Equipment dismantling at our Blue Island site is expected to be completed by the end of 2005. In 2004, we signed a consent order with the State of Illinois for the Blue Island site investigation. Discussions continue on the Hartford site and we have begun voluntary remediation investigations on this site. 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 2004, we recorded a charge of $9.1 million related to our environmental remediation activity. This charge was primarily for additional estimated costs related to cleanup at the Village of Hartford and additional remediation activities at our other sites.
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.
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, which was completed in 2004, cost $14.8 million, which included $4.3 million of severance related benefits and $10.5 million of other costs such as training, relocation and the movement of physical assets. The severance related costs were amortized over the future service period of the affected employees and the other costs were expensed as incurred.
The following table summarizes the expenses associated with the administrative restructuring and provides a reconciliation of the administrative restructuring liability as of December 31, 2004 and 2003:
Extinguishment of Debt
In 2004, as a result of the early extinguishment of a $785 million credit facility, which was replaced by a $1 billion credit facility, we recorded a loss of $3.6 million representing the write-off of unamortized deferred financing costs for the year ended December 31, 2004.
In 2003, we redeemed the remaining principal balance of our 11½% subordinated debentures; repaid our $240 million floating rate loan; redeemed the outstanding balances of our 8 7/8% senior subordinated notes, 8 5/8% senior notes, and 8 3/8% senior notes; purchased in the open market a portion of PACC’s 12½% 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 11½% subordinated debentures, which were held by Premcor USA.
In 2002, we redeemed the outstanding balances of our 10 7/8% senior notes, 9½% senior notes, senior secured bank loan and purchased a portion of our 11½% subordinated debentures. We recorded a loss on extinguishment of long-term debt of $19.5 million related to these early repayments. The loss included premiums associated with the early repayment of long-term debt of $9.4 million, a write-off of unamortized deferred financing costs related to this debt of $9.5 million and the write-off of a prepaid premium for an insurance policy guaranteeing the interest and principal payments on Sabine’s long-term debt of $0.6 million. Related to the redemption of the 9½% senior notes and the repayment of the senior secured bank loan, PRG recorded a loss of $9.3 million, of which $0.9 million related to premiums, $7.8 million related to the write-off of deferred financing costs and $0.6 million related to the write-off of debt guarantee fees at Sabine.
Discontinued Operations
In connection with the 1999 sale of PRG’s retail assets to Clark Retail Enterprises, Inc. (“CRE”), PRG assigned certain 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 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 July 2004, the CRE bankruptcy estate was liquidated and the case dismissed. As of December 31, 2004, PRG was subleasing 34 operating stores, the leases on 29 stores had either been terminated or expired, the leases on 87 operating stores were held by third parties and PRG is in the process of buying out the leases on the two remaining stores. In 2004, PRG recorded an after-tax charge of $5.6 million. These charges represent the estimated net present value of its remaining liability under the current operating stores that were subleased, net of estimated sublease income, and other direct costs. In 2003, PRG recorded an after-tax charge of $7.2 million representing the estimated net present value of its remaining liability under the current operating stores that were subleased, net of estimated sublease income, and other direct costs. A portion of the $21.6 million liability 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.
Total payments on leases and subleases upon which we may remain jointly and severally liable, subject to certain defenses, are currently estimated as follows: (in millions) 2005-$7, 2006-$7, 2007-$7, 2008-$7, 2009-$7 and in the aggregate thereafter-$30.
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:
Factors Affecting Operating Results
Our earnings and cash flows 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 crude oil and other 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, pipeline capacity, and the extent of government regulation. Our net sales and operating revenues fluctuate significantly with movements in industry refined product prices, our cost of sales fluctuate significantly with movements in crude oil prices and our operating expenses fluctuate with movements in the price of natural gas. 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 and Midwest.
In order to assess our operating performance, we compare our refining margins (net sales and operating revenues less cost of sales) against a benchmark industry refining margin. The industry refining margin is based on a crack spread. For example, one such crack spread is calculated by assuming that two barrels of benchmark light low-sulfur 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 industry refining margin. We calculate the benchmark industry refining margin using the market value of U.S. Gulf Coast gasoline and diesel fuel against the market value of West Texas Intermediate, or WTI, crude oil and refer to that benchmark as the Gulf Coast 2/1/1 industry refining margin, or simply, the Gulf Coast industry refining margin. The Gulf Coast industry refining margin 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 processed WTI crude oil and produced and sold the benchmark production of conventional gasoline and high sulfur diesel fuel. We utilize the Gulf Coast 2/1/1 industry refining margin as a benchmark for our Port Arthur and Memphis refinery operations. We utilize the Chicago 3/2/1 industry refining margin as a benchmark for our Lima refinery operations. We utilize the New York Harbor Reformulated Gasoline 3/2/1 industry refining margin, or NYH RFG 3/2/1 as a benchmark for our Delaware City 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 costs and/or product value advantages and disadvantages as compared to the benchmark.
Our Port Arthur and Delaware City refineries are able to process significant quantities of heavy high-sulfur crude oil that has historically cost less than WTI crude oil. For the Port Arthur refinery we measure the cost advantage of heavy high-sulfur crude oil by calculating the spread between the value of Maya crude oil, a heavy crude oil produced in Mexico, to the value of WTI crude oil, a light low-sulfur crude oil. We use Maya crude oil for this measurement because a significant amount of our heavy high-sulfur crude oil throughput at Port Arthur is Maya. For the Delaware City refinery we measure the cost advantage of the medium to heavy high-sulfur crude oil by calculating the spread between the value of Arab Medium crude oil, produced in Saudi Arabia, to the value of WTI 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 crude oil from PMI Comercio Internacional, 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 186,000 bpd of Maya crude oil, designed to provide us with a stable and secure supply 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 at market prices. The agreement expires in 2011.
In conjunction with the acquisition of the Delaware City refinery, the Company entered into an agreement, effective May 1, 2004, with the Saudi Arabian Oil Company for the supply of 105,000 bpd of crude oil, however due to certain quota restrictions the current supply is approximately 85,000 bpd. The agreement has terms extending to April 30, 2005, with automatic one-year extensions thereafter unless terminated at the option of either party. The crude oil is priced by a market-based formula as defined in the agreement.
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 Lima and Memphis refineries. 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 May 2006, 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 industry refining margin. 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. A similar condition exists in the Northeast where consumption also exceeds production thereby allowing our Delaware City refinery to have an inherent geographic competitive advantage.
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 solid 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 industry refining margins. 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 12% and 6% of the respective product slates at Port Arthur and Delaware City are lower value petroleum coke, sulfur, and residual oils, which negatively impacts the refineries’ gross margin against the benchmark industry refining margin. 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 price 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. 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. As discussed below, to mitigate this market risk, we may purchase futures contracts to offset our fixed commitments. Our fixed price purchase and sale commitments and futures contracts are classified as derivative instruments and are recorded at fair market value.
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 and increased maintenance expense. 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.
Results of Operations
The following tables provide supplementary income statement and operating data.
* Represents the average over the period May 1, 2004 to December 31, 2004
** Not relevant
(1) We acquired our Memphis refinery effective March 3, 2003 and the total throughput for the year ended December 31, 2003 reflects 304 days of operations over that period. Total throughput averaged 157,000 bpd during the 304 days of operations in 2003.
(2) We acquired our Delaware City refinery effective May 1, 2004 and the total throughput for the year ended December 31, 2004 reflects 245 days of operations over that period. Total throughput averaged 174,100 bpd during the 245 days of operations in 2004.
2004 Compared to
Overview. Net income available to common stockholders was $477.9 million ($5.52 per diluted share) as compared to $116.6 million ($1.58 per diluted share) in 2003. Our operating income was $904.2 million in 2004 as compared to $330.4 million in 2003. The increase in the results of 2004 compared to the results in 2003 was principally due to the acquisition of Delaware City, continued strong refining margins and wider price differentials between light low-sulfur crude oil and heavy high-sulfur crude oil in our markets.
The results of operations for 2004 include the operations of our Delaware City refinery beginning May 1, 2004, the date of acquisition. The results of operations for 2003 include the operations of our Memphis refinery beginning March 3, 2003, the date of acquisition.
Net Sales and Operating Revenues. Net sales and operating revenues increased $6,530.9 million or 74%, from $8,803.9 million in 2003. The increase was principally due to the acquisition of the Delaware City refinery. Additionally, refined product prices increased significantly throughout 2004, remaining well above more historical levels.
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 net sales and 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 this prior period reclassification.
Gross Margin. Gross margin is defined as net sales and operating revenues less cost of sales. Gross margin increased $962.9 million, or 89% to $2,047.6 million in 2004 from $1,084.7 million in 2003. The increase in gross margin for 2004 was due to the acquisition of the Delaware City refinery and a full year of operations at the Memphis refinery. Additionally, the increase in gross margin was also driven by continued strong refining margins and widening crude oil price differentials. These market benefits were slightly offset by the effects of our price risk management activities.
Average industry refining margins and crude oil price differentials were stronger in 2004 as compared to 2003. The Gulf Coast 2/1/1 and Chicago 3/2/1 industry refining margins were approximately 43% and 18% higher, respectively, in 2004 than in 2003. The NYH RFG 3/2/1 industry refining margin averaged $7.97 for the period May 1, 2004 to December 31, 2004. While the light low-sulfur crude oil industry refining margins were good during the year the crude oil price differentials had a significant positive impact on our operating results. The Maya/WTI differential and WTS/WTI differential were approximately 67% and 45% higher, respectively, in 2004 than in 2003. The Arab Medium/WTI differential averaged $7.11 for the period May 1, 2004 to December 31, 2004. In 2004, we believe these industry refining margins and crude oil price 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, weather-related disruptions in the Gulf of Mexico, labor issues in South America, and political uncertainty in Nigeria. A strong heavy high-sulfur crude oil price differential has a significant positive impact on Port Arthur’s and Delaware City’s gross margin because their crude oil throughput is mainly heavy high-sulfur crude oil. Our Lima and Memphis refineries partially benefited from the stronger Dated Brent/WTI differential as a portion of their crude oil in 2004 was purchased in the foreign market.
During 2004, absolute hydrocarbon prices continued to be volatile and were at historically high levels, and the market structure for crude oil was significantly backwardated. 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 commitments. Due to the backwardated crude oil market structure, this price risk mitigation strategy carried a cost as discussed in “-Factors Affecting Our Operating Results”. Our operating results in 2004 were negatively affected by approximately $33 million related to our derivative activities. This amount includes a loss of $30 million for the forward sales of crack spread commitments. At December 31, 2004, there were no outstanding forward sales of crack spread commitments. Our operating results in 2003 were negatively affected by approximately $30 million related to our derivative activities. See “Quantitative and Qualitative Disclosures about Market Risk-Commodity Risk” for a description of our price risk management strategies and policies.
Refinery Operations
Port Arthur. In 2004, the total throughput rate at our Port Arthur refinery averaged approximately 237,200 bpd. The refinery experienced reduced throughputs related to both scheduled and unscheduled reformer and crude unit outages. During the fourth quarter, the refinery ran very well and achieved record throughput rates. The refinery has completed its Tier II and capital expenditures and is currently producing gasoline which meets with the final sulfur reduction EPA requirements.
In 2003, the average total throughput rate at our Port Arthur refinery was approximately 244,900 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 industry refining margins. Otherwise, the crude oil throughput rates were at or above capacity and the refinery ran well.
Lima. In 2004, the average total throughput rate at our Lima refinery was approximately 131,800 bpd. The 2004 rate was restricted due to a scheduled month-long maintenance turnaround affecting all operating units. This maintenance shutdown required a plant-wide shutdown as the refinery is a single train operation. Our Lima refinery also had slightly reduced crude oil throughput rates in late fall due to limited demand for high-sulfur diesel.
In 2003, the average total throughput rate at our Lima refinery was approximately 139,700 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.
Memphis. In 2004, the average total throughput rate at our Memphis refinery was approximately 153,200 bpd. Crude oil throughput was supplemented by more economical intermediate feedstocks in order to keep downstream units operating at full rates and to take advantage of strong refinery margins. The refinery ran well, with only limited restriction in throughput rates in the third quarter due to delays in crude oil deliveries and production in the Gulf of Mexico from Hurricane Ivan.
Our Memphis refinery was acquired effective March 3, 2003 and averaged approximately 157,000 bpd of total throughput for the period from March 3, 2003 through December 31, 2003. The total 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 refining margins.
Delaware City. Our Delaware City refinery was acquired effective May 1, 2004 and averaged approximately 174,100 bpd of total throughput for the period from May 1, 2004 through December 31, 2004. The total throughput rate averaged over the year ended December 31, 2004 was 116,500 bpd. The total throughput rate was restricted due to a fourth quarter turnaround of the FCC unit, alkylation unit, and polymerization unit. The turnaround of the FCC unit extended 14 days past the original plan for the completion of more extensive repairs.
Operating Expenses. Operating expenses increased $294.5 million, or 56%, to $819.4 million in 2004 from $524.9 million in 2003. High natural gas prices were a major contributor to this increase, resulting in an estimated $80 million increase in 2004 as compared to 2003. Natural gas prices averaged $5.73 for 2004 as compared to $5.36 for 2003. The effects of higher natural gas prices and other operating expenses included a full year of Memphis operations and the addition of Delaware City refinery operations.
General and Administrative Expenses. General and administrative expenses increased $65.9 million, or 78%, to $150.6 million in 2004 from $84.7 million in 2003. The increase is mainly attributable to an increase of $43 million in the incentive compensation accrual and increases in costs for certain employee benefit programs, insurance, legal fees, Sarbanes-Oxley Act compliance and the acquisition of the Delaware City refinery. Included in general and administrative expenses is stock-based compensation expense which increased $2.1 million, or 12%, to $19.7 million in 2004 from $17.6 million in 2003. The increase related to the additional option grants in 2004 and 2003.
Depreciation and Amortization. Depreciation and amortization increased $47.7 million, or 45%, to $153.9 in 2004 from $106.2 million in 2003. This increase was principally due to capital expenditure activity and the addition of the Delaware City refinery in 2004 and a full year of Memphis activity.
Interest and Finance Expense, net. Interest and finance expense, net increased by $13.2 million, or 11.5%, to $128.3 million, from $115.1 million in 2003. The increase was primarily due to additional interest expense related to an additional $400 million in new debt, partially offset by lower financing costs and higher capitalized interest in 2004.
Income Tax Provision. We recorded an income tax provision of $288.8 million in 2004 compared to $64.0 million in the corresponding period in 2003. Our effective tax rate was 37.4% in 2004 as compared to 34.1% in 2003. 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 increase in our 2004 consolidated effective tax rate as compared to 2003 resulted from a lower percentage of our 2004 consolidated income being recognized by Sabine, which has a lower effective tax rate than other subsidiaries.
As of December 31, 2004, we have a net deferred tax liability of $200.9 million (PRG-$208.0 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 2004 we decreased our valuation allowance by $0.6 million to $2.2 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 net operating loss carryforwards available at December 31, 2004 of approximately $165.7 million (PRG-$150.3 million). In addition, our actual cash payment of taxes is expected to benefit from alternative minimum tax credit carryforwards available as of December 31, 2004 of $51.3 million (PRG-$45.7 million). Our regular tax net operating loss carryforwards will expire during 2022, to the extent they have not been used to reduce taxable income prior to such time.
For federal income tax purposes, we have incurred, as a result of the April 2004 equity offering, a stock ownership change of more than 50%, determined over the preceding three-year period. Under federal tax law, the more than 50% stock ownership change has resulted in an annual limitation being placed on the amount of regular and alternative minimum tax net operating losses, and certain other losses and tax credits (collectively “tax attributes”) that may be utilized in any given year. Accordingly, our ability to utilize tax attributes could be affected in both timing and amount. However, management believes such annual limitation will not restrict our ability to significantly utilize its tax attributes over the applicable carryforward periods. Therefore, at this time, we do not anticipate the need for an additional valuation allowance as a result of this more than 50% stock ownership change.
2003 Compared to 2002
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 net sales and 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 had 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 is defined as net sales and operating revenues less cost of sales. 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 industry refining margins and crude oil price differentials. These market benefits were partially offset by the effects on our price risk management activities during an extremely volatile and backwardated hydrocarbon market in the first half of 2003.
Average industry refining margins and crude oil price differentials were stronger in 2003 as compared to 2002. The Gulf Coast 2/1/1 and Chicago 3/2/1 industry refining margins were approximately 49% and 28% higher, respectively, in 2003 than in 2002. The industry refining margins 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 price differentials were approximately 32% and 98% higher, respectively, in 2003 than in 2002. In 2003, we believe the crude oil price 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 high-sulfur and sour crude oil price differential has a significant positive impact on Port Arthur’s gross margin because its crude oil throughput is approximately 80% heavy high-sulfur 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 price 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”. Our operating results in 2003 were negatively affected by approximately $30 million related to our derivative activities. 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.
Refinery Operations
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 industry refining margins. 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 industry refining margins.
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 $18.9 million, or 29%, to $84.7 million in 2003 from $65.8 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. Included in general and administrative expenses is stock-based compensation expense which 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 and Finance Expense, net. Interest and finance expense, 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 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 the other subsidiaries. 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.
Outlook
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 2005 have been strong. The Gulf Coast 2/1/1 industry refining margin has averaged approximately $5.60 per barrel, the Chicago 3/2/1 industry refining margin has averaged approximately $6.10 per barrel, the NYH RFG 3/2/1 has averaged approximately $5.90 per barrel, the WTI/Maya differential has averaged approximately $17.10 per barrel and the WTI/Arab Medium differential has averaged approximately $9.80 per barrel. We believe the market outlook for 2005 as a whole will be favorable for the U.S. refining industry due to an increasingly tight worldwide supply and demand
balance for oil products. The combination of worldwide crude production becoming heavier and higher-sulfur; increasing demand for light low-sulfur crude oil; limited heavy high-sulfur crude oil refining capacity; and tightening environmental standards for products in many major global markets has led to a strong environment for high-conversion, pure-play refiners.
We believe that absent any unexpected changes, see “Forward-Looking Statements” for a list of factors that could impact our industry and us, the refining industry will do well next year, subject to seasonality changes and if supply and demand continue to stay in line with each other. While we expect margins to fluctuate we believe that we are well positioned in the industry, with over 50% heavy sour refining capacity. Our strategy is to grow both from internal investments and from the purchase of additional assets, if those assets are deemed to be accretive. We plan to fund all our internal investments from internally generated cash flows.
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, Chicago 3/2/1 and NYH RFG 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 industry refining margin appropriately reflects our product slate. However, approximately 12% 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 refining margins. Port Arthur’s crude oil slate is mostly heavy high-sulfur crude oil. Accordingly, the WTI/Maya crude oil price differential can be used as an adjustment to the benchmark industry refining margin. Ancillary crude costs, primarily transportation, at Port Arthur averaged $0.72 per barrel of total throughput in the year ended December 31, 2004. In 2005, we expect our full year total throughput rate to approximate 210,000 bpd to 220,000 bpd. This throughput rate reflects a maintenance turnaround in the first quarter which will involve all major process units except the reformer unit. Based on the scheduled maintenance turnaround of these units, we expect the throughput rate at our Port Arthur refinery to approximate 150,000 bpd to 160,000 bpd in the first quarter of 2005.
Our Lima refinery has a product slate of approximately 97% light products, of which 60% is gasoline and 30% is distillate. For this reason, we believe the Chicago 3/2/1 is an appropriate benchmark industry refining margin. This refinery consumes approximately 95% light low-sulfur crude oil with the balance being light high-sulfur crude oils. We opportunistically buy a mix of domestic and foreign sweet crude oils. The foreign crude oils consumed at Lima are priced relative to Brent and the WTI/Brent differential can be used to adjust the benchmark. Ancillary crude costs for Lima averaged $1.58 per barrel of crude throughput in the year ended December 31, 2004. In 2005, we expect our full year total throughput rate to approximate 140,000 bpd to 145,000 bpd. This throughput rate reflects the fact that Lima has no major turnaround activity scheduled in 2005. We expect the total throughput rate at our Lima refinery to approximate 140,000 bpd to 150,000 bpd in the first quarter of 2005.
In November 2004, we reached an agreement with EnCana Midstream & Marketing, a partnership of EnCana Corporation, to jointly conduct a preliminary design and engineering study of the modifications necessary to upgrade our Lima refinery to process Canadian heavy crude oil blends. The design and engineering study is expected to be completed in approximately six to nine months. Provided the study indicates an acceptable investment plan, we intend to form a 50-50 joint venture with EnCana. Our contribution to the joint venture would include the Lima refinery and related assets. EnCana would contribute the equivalent fair value of the refinery in cash to the joint venture for the upgrade project. If additional funding is necessary, each partner would contribute 50 percent. Final capital and financial arrangements will be negotiated as part of the project’s definitive agreement. Major capital expenditures are not expected to be required before 2006. The agreement also
provides for the sale of Canadian heavy crude oil blends to the joint venture by EnCana. The upgrade is subject to the execution of a definitive agreement. There can be no assurances that a definitive agreement will be reached upon the completion of the design and engineering study.
Our Memphis refinery has a product slate of approximately 97% light products, of which 50% is gasoline and 45% is distillate. We expect that the operating results will track a Gulf Coast 2/1/1 benchmark industry refining margin. Ancillary crude costs for Memphis averaged $0.72 per barrel of crude throughput in the year ended December 31, 2004. In 2005, we expect our full year total throughput rate to approximate 150,000 bpd to 160,000 bpd. Based on current market conditions, we expect the total throughput rate at our Memphis refinery to approximate 150,000 bpd to 160,000 bpd in the first quarter of 2005. 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 industry refining margins.
Our Delaware City refinery has a product slate of approximately 60% gasoline, 35% distillate and 5% petroleum coke. For this reason, we believe the NYH RFG 3/2/1 is an appropriate benchmark industry refining margin. This refinery typically consumes medium and heavy high-sulfur crude oil. Accordingly, the WTI/Arab Medium crude oil price differential can be used as an adjustment to the benchmark industry refining margin, as it generally reflects our crude oil mix. Ancillary crude costs, primarily transportation, averaged $1.24 per barrel of crude unit throughput for the year ended December 31, 2004. In 2005, we expect our full year total throughput rate to approximate 175,000 bpd to 185,000 bpd. Based on current market conditions, we expect the total throughput rate at our Delaware City refinery to approximate 175,000 bpd to 185,000 bpd in the first quarter of 2005.
Operating Expenses. Natural gas is the most variable component of our operating expenses. On an annual basis, our four refineries combined purchase a total of approximately 30 million to 35 million mmbtu of natural gas for energy related use, with most of these purchases relating to our Port Arthur and Delaware City refineries. In a $6.00 per mmbtu natural gas price environment and assuming average crude oil throughput levels, our annual operating expenses should range between $810 million and $830 million. We contract for the purchase of natural gas on a calendar month basis and set the price at the beginning of the month. Our current natural gas contracts are set to expire in the next two to three years. 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, including stock-based compensation expense and excluding incentive compensation expense, will approximate $25 million. Our incentive compensation expense for 2005 will be based solely on our achievement of earnings per share results in excess of a minimum of $2.40 per share. In administering the plan, our Board of Directors typically exclude refinery restructuring charges and other special items in determining the threshold earnings per share level.
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. We expect that stock-based compensation expense in 2005, for options granted in 2002 through 2005, will approximate $14 million to $15 million. Stock-based compensation is included in the general and administrative expenses line item and is included in the estimate given above.
Depreciation and Amortization. We expect depreciation and amortization to be about $43 million for the first quarter of 2005. This quarterly rate will vary 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, 2004, we expect that our 2005 annual gross interest expense will be approximately $150 million and amortization of deferred financing
costs will be approximately $10 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 $40 million to $45 million in 2005.
Income Taxes. We expect our effective income tax rate for 2005 will range from approximately 35% to 38%.
Capital Expenditures and Turnarounds. Capital expenditures and turnarounds for the year ended December 31, 2004 totaled $658.8 million. This amount excludes the purchase price of the Delaware City refinery. We plan to expend approximately $720 million to $740 million for turnarounds and capital expenditures, excluding capitalized interest, in 2005. Approximately $145 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.
Liquidity and Capital Resources
Cash Balances
As of December 31, 2004, we had cash and short-term investments of $753.3 million of which $609.2 million was held by PRG, $143.1 million was held by Premcor Inc., and $1.0 million was held by other Premor Inc. subsidiaries. As of December 31, 2003, we had cash and short-term investments 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.
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 $69.1 million and $66.6 million as of December 31, 2004 and 2003, 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 exists at any time, PACC shall forgive PRG for the payable amount, which would take the form of a non-cash dividend. Non-cash dividends of $516.1 million were made in 2004 and non-cash dividends of $174.7 million were made in 2003.
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 $5 million as of December 31, 2004, and has committed to funding $1 million annually until a balance of $10 million is established.
Cash Flows from Operating Activities
Net cash flows provided by operating activities were $1,016.8 million for the year ended December 31, 2004 as compared to net cash flows provided by operating activities of $182.4 million for the year ended December 31, 2003 and $15.9 million for the year ended December 31, 2002. Cash flows from operating activities were mainly impacted by strong earnings for the years ended December 31, 2004 and 2003. 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, 2004 was $1,224.3 million, a 1.93-to-1 current ratio, versus $860.1 million, a 1.87-to-1 current ratio, as of December 31, 2003. The change in restricted cash related to future interest payments is included in cash flows from operating activities.
Working capital experienced some significant fluctuations as of December 31, 2004 as compared to December 31, 2003, primarily due to strong operating results and the acquisition of and subsequent activity at our Delaware City refinery and the increase in crude oil and refined product prices. In addition, accrued expenses were further affected by higher accrued interest due to additional $400 million in debt, higher employee benefit costs, including incentive compensation 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, excluding acquisitions.
Cash Flows from Investing Activities
Cash flows used in investing activities were $1,751.5 million for the year ended December 31, 2004, as compared to $921.3 million for the year ended December 31, 2003 and $0.5 million for the year ended December 31, 2002. The cash flows used in investing activities in 2004 reflected the acquisition of the Delaware City refinery for $871 million and in 2003 reflected the acquisition of the Memphis refinery for $476 million. Aside from these items, activity in 2004, 2003 and 2002 primarily reflected capital expenditures, including turnarounds and the purchase and sales of our short-term investments.
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 $356.8 million, $100.7 million, and $63.5 million for the years ended December 31, 2004, 2003, and 2002, respectively. We estimate that total mandatory capital and turnaround expenditures, excluding expenditures for new product standards, for all four refineries will average $250 million per year over the next four years and the budget for these expenditures is approximately $395 million for 2005. 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 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 $780 million, including $368 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 $645 million reported in the 2003 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 Delaware City refinery. Further, the increase in worldwide prices and demand for steel and equipment has also put pressure on our project costs.
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, with the phasing beginning on January 1, 2004. We currently have the capability to produce gasoline under the new sulfur standards at all of our refineries, except Lima. We expect to have the capability to comply with the gasoline standards at the Lima refinery in the third quarter 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 $345 million, of which $314 million had been incurred as of December 31, 2004. Future revisions to this cost estimate, and the estimated time during which costs are incurred, may be necessary.
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. In May 2004, the EPA promulgated its non-road diesel regulations, which will require a reduction in the sulfur content of non-road diesel fuel. The final ruling limits the sulfur levels in non-road diesel to 500 ppm by 2007 and 15 ppm by 2010. Our Port Arthur, Memphis and Delaware City refinery’s produce diesel fuel which complies with the current diesel standards. We estimate that capital expenditures required to comply with the diesel standards at all four refineries in the aggregate through 2006 is approximately $435 million, of which $98 million had been incurred as of December 31, 2004. 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 through 2006 with the greatest concentration of spending occurring in 2005. The Lima refinery does not currently produce diesel fuel to low-sulfur specifications, we expect the refinery to have the capability to produce diesel with the low-sulfur standards by the second quarter of 2006.
As of December 31, 2004, we have outstanding contractual commitments of $183 million related to the design and construction activity at our refineries for the Tier 2 gasoline and low-sulfur diesel compliance.
In 2005, we expect to make expenditures of approximately $221 million for compliance with Tier 2 gasoline standards and diesel regulations, excluding capitalized interest. We spent $211.2 million, and $144.4 million and $56.7 million in 2004, 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 on hand and 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.
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 high-sulfur crude oil. This project is estimated to cost between $220 million and $230 million and is expected to be completed by mid-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 $90.8 million, $16.2 million and $28.4 million for the year ended December 31, 2004, 2003 and 2002 respectively. Our budget for discretionary capital expenditures is approximately $109 million for 2005, which includes approximately $100 million related to the Port Arthur expansion project. As discussed above, 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, including turnarounds described above for the following years (in millions):
Cash Flows from Financing Activities
Cash flows provided by financing activities were $847.3 million for the year ended December 31, 2004, as compared to $787.2 million for the year ended December 31, 2003 and cash flows used in financing activities of $214.1 million for the year ended December 31, 2002.
In 2004, our cash flows from financing activities reflected cash provided by the receipt of net proceeds of approximately $490 million from a public offering of 14.95 million shares of common stock by Premcor Inc. and the receipt of proceeds from the sale of $400 million in senior notes, of which $200 million, due in 2011, bear interest at 6 1/8% per annum and $200 million, due in 2014, bear interest at 6¾% per annum by PRG. The majority of these proceeds were used to finance the Delaware City refinery acquisition. PACC made $24.2 million of scheduled principal payments on its 12 ½% senior notes. Cash and cash equivalents restricted for debt repayment reflected changes to the portion of restricted cash that related to future principal payments. In 2004, we incurred deferred financing costs of $16.1 million related to the issuance of our new bonds and the $1 billion credit facility. Cash flows from our financing activities also reflected the receipt of proceeds from the exercise of stock options and the fourth quarter dividend of $0.02 per share paid on December 15, 2004.
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 9 1/2% per annum and $175 million, due in 2010, bear interest at 9 1/4% 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 11 1/2% 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 12 1/2% 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 7 1/2% 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 6 3/4% per annum and $175 million of senior subordinated notes due 2012, bearing interest at 7 3/4% per annum. PRG used the proceeds from these notes to redeem its 8 3/8% senior notes, 8 5/8% senior notes, and 8 7/8% 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 12 1/2% 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 9 1/2% senior notes at par value. Premcor USA redeemed the remaining $144.4 million of its 10 7/8% senior notes, including a $5.2 million premium, and repurchased, in the open market, $57.5 million in aggregate principal amount of its 11 1/2% 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 12 1/2% 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 2004, Premcor Inc. made capital contributions to Premcor USA of $403.5 million (2003-$297.5 million) and Premcor USA subsequently contributed $403.5 million (2003-$263.3 million) to PRG, all primarily for the acquisition of the Delaware City refinery in 2004 and for the repayment of long-term debt.
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, 2004, we had total long-term debt, including current maturities, of $1,827.5 million (PRG-$1,817.6 million). We had stockholders’ equity of $2,134.4 million, resulting in a total debt to total capitalization ratio of 46%. PRG had stockholder’s equity of $1,902.5 million, resulting in a total debt to total capitalization ratio of 49%. 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:
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a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
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covenants contained in our existing debt arrangements require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry;
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our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited;
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we may be at a competitive disadvantage to those of our competitors; and
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we may be more vulnerable to adverse economic and industry conditions.
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 business other than our current business, 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.
Credit Agreements
On April 13, 2004, PRG completed a new $1 billion senior secured revolving credit facility, maturing in April 2009, to replace its existing $785 million credit facility. The facility is used primarily to secure crude oil purchase obligations for our refinery operations and to provide for other working capital needs. The revolving credit facility allows for the issuance of letters of credit and direct borrowings, individually or collectively, up to the lesser of $1 billion or the amount available under a defined borrowing base. The borrowing base includes, among other items, eligible cash and cash equivalents, eligible investments, eligible receivables and eligible petroleum inventories. The revolving credit facility also allows for an overall increase in the principal amount of the facility of up to $250 million under certain circumstances. The revolving credit facility is secured by a lien on substantially all of PRG’s cash and cash equivalents, receivables, crude oil and refined product inventories and intellectual property and is guaranteed by Premcor Inc. The collateral also includes the capital stock of Sabine and certain other subsidiaries and certain PACC 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.
The covenants and conditions under this new credit agreement are generally less restrictive than the covenants contained in the agreement governing our terminated $785 million facility. The new credit agreement
contains covenants and conditions that, among other things, limit dividends, indebtedness, liens, investments, restricted payments as defined and the sale of assets. The covenants also provide that in the event PRG does not maintain certain availability within the facility, additional restrictions and a cumulative cash flow test will apply. PRG was in compliance with these covenants as of December 31, 2004.
As of December 31, 2004, the borrowing base was $1,853.1 million with $484.1 million of the facility utilized for letters of credit. As of December 31, 2004, there were no direct cash borrowings under the credit facility. The portion of the facility utilized for letters of credit was lower as of December 31, 2004 as compared to December 31, 2003 due to the increase of open trade credit and the addition of purchases of domestic crude for Lima through the MSCG supply contract, partially offset by the addition of purchases for the Delaware City refinery.
PRG’s previous credit agreement, which was amended and restated in February 2003, provided 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 was able to be increased to $800 million under certain circumstances. PRG utilized this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. The borrowing base included 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 was early terminated in April 2004. As of December 31, 2003, the borrowing base was $1,348.9 million.
The $785 million credit agreement provided 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 were subject to a defined repayment provision. Borrowings under the credit agreement were 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 $785 million credit agreement contained covenants and conditions that, among other things, limited PRG’s dividends, indebtedness, liens, investments and contingent obligations. PRG was 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 provided for a cumulative cash flow test that from January 1, 2003 to February 10, 2006 could not be less than zero.
PRG also has a $40 million cash-collateralized credit facility which was renewed effective June 1, 2004 for one year. 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, 2004, $39.7 million (December 31, 2003-$18.0 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 $1 billion credit facility. We also have the ability to fix the interest rate on the Ohio bonds in which case additional security might no longer be required.
Liquidity Requirements Related to Obligations
In the table below, we summarize the payment schedule for our future obligations as of December 31, 2004 (in millions):
(1) Our long-term debt and capital leases obligations assume our long-term debt and capital leases are held to maturity and it also assumes that we do not borrow against our current credit agreement. Our long-term debt obligations are further explained in Note 13 and our capital leases are further explained in Note 10 and Note 13 of this Form 10-K.
(2) We enter into operating leases in the normal course of business, some of these lease provide us with the option to renew the lease or purchase the leased item. Future operating lease obligations would change if we chose to exercise those renewal options and if we entered into additional operating lease agreements. For more information refer to Note 14 of this Form 10-K.
(3) Our environmental obligations are based on the current remediation plans and cleanup activities. As we began our remediation and clean up activities we may identify additional remediation needs or find that less work is needed to bring the sites to the environmental regulation status. As such this obligation is only based on current information and as our environmental remediation activities proceed, we expect this amount to change. For more information refer to Note 23 of this Form 10-K.
(4) Pension and post-retirement obligations includes only those amounts we expect to pay out in benefit payments. For more information refer to Note 16 of this Form 10-K.
(5) Purchase obligations include such obligations as crude oil purchases, electricity and pipeline usage requirements. These future obligation calculations were based on current year information, as such future minimum obligations may vary in the future periods. Variables such as the price of crude oil, future volume requirements and other prices that are adjusted based on various factors, including performance, can cause the minimum obligations to change. For more information refer to Note 23 of this Form 10-K.
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, tank cars, office space and office equipment from unrelated third parties with lease terms ranging from 1 to 12 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 28 years and 46 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 34 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 20 years. Certain of these properties are being subleased.
Capital Expenditure Commitments. As of December 31, 2004, we have entered into contracts totaling $278 million related to the design and construction activity at our refineries. We will make the majority of these expenditures in 2005.
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 contracts 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 186,000 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.
In conjunction with the acquisition of the Delaware City refinery, we entered into an agreement, effective May 1, 2004, with the Saudi Arabian Oil Company for the supply of 105,000 bpd of crude oil, however, due to certain quota restrictions the current supply is 85,000 bpd. The agreement has terms extending to April 30, 2005, with automatic one-year extensions thereafter unless terminated at the option of either party. The crude oil is priced by a market-based formula as defined in the agreement.
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 contract which expires June 2021 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 $83 million in 2004 in relation to this hydrogen supply contract and we would need to make minimum payments of approximately $36 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 June 2007. 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 $9 million in 2004, and we would need to make minimum payments of approximately $6 million on an annual basis if we did not meet any of our committed volumes. 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.
Sales Obligations. We enter into various contracts to provide certain refined products in the normal course of business. Typically these contracts are short term, one to several months. We expect to be able to fulfill all of these sales obligations.
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 2005, we expect to contribute $9 million to our pension plans and expect to make payments of $4 million related to our obligations under our other post retirement benefit plans.
Other Obligations
In addition to the enforceable and legally binding obligations quantified in the table above, we have other obligations for goods and services entered into in the normal course of business. These contracts, however, either are not enforceable or legally binding or are subject to change based on our business decisions.
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, $96 million as of December 31, 2004 (December 31, 2003-$98 million). We expect to spend approximately $14 million to $15 million in 2005 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, equipment dismantling at the site is expected to be completed by the third quarter 2005. In 2004, we signed a consent order with the State of Illinois for the environmental matters at Blue Island. In relation to the Hartford liability, discussions continue. We have begun voluntary remediation investigations on this site. As the remediation plans are finalized and as work is performed, adjustments to 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.
Related Party Transactions
The following related party transactions are not discussed elsewhere in the Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Premcor Inc. and PRG
As of December 31, 2004, PRG had a receivable from Premcor Inc., excluding amounts due related to income taxes and the tax sharing agreement, of $2.2 million. The $2.2 million relates to payments PRG made for Premcor Inc. to Opus and cash Premcor Inc. received on the income tax deductions for stock options. As of December 1, 2003, PRG had a payable to Premcor Inc. for management fees paid by Premcor Inc. on PRG’s behalf of $0.1 million. PRG’s loan receivable from Premcor Inc. for $8.9 million in 2003, which included both principal and interest, was paid in full during 2004. PRG’s subsidiary, Premcor Investments Inc., had loaned these proceeds to Premcor Inc. to allow Premcor Inc. to pay certain fees. The loan had bore interest at 12% per annum. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.
Premcor USA and PRG
In 2004, PRG received capital contributions from Premcor USA totaling $403.5 million, primarily for the acquisition of the Delaware City refinery. In 2003, PRG received capital contributions from Premcor USA totaling $263.3 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. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.
The Premcor Pipeline Co. and PRG
In 2004, PRG contributed $14.3 million to Premcor USA, the contribution represented 100% ownership in the capital stock of the Port Arthur Pipeline Company, which was previously a subsidiary of PRG.
As of December 31, 2004, PRG had a receivable from The Premcor Pipeline Co. of $20.2 million (2003-$5.9 million) related to amounts that PRG paid on behalf of The Premcor Pipeline Co. As of December 31, 2004, PRG had a payable to The Premcor Pipeline Co. of $16.0 million (December 31, 2003-$2.0 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.
Fuel Strategies International, Inc.
The Company entered into an agreement with Fuel Strategies International, Inc. (“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 the Company’s chairman of the board of directors and senior executive employee. For the years ended December 31, 2004 and 2003, the Company incurred fees of $0.2 million and $0.4 million, respectively, related to this agreement. In June 2004, the Company hired the principal as a full time employee and the contract with FSI expired in May 2004.
Blackstone
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. We recorded expenses related to the annual monitoring fee and the reimbursement of out-of-pocket costs of $0.3 million for the year ended December 31, 2002.
Critical Accounting Judgments and Estimates
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 2004.
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.
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, 2004 the replacement cost (market value) of our crude oil and refined product inventories exceeded its carrying value by approximately $379.8 million, or approximately $14 per barrel over cost. If the market value of these inventories had been lower by over $14 per barrel as of December 31, 2004, we would have had to write-down the value of our inventory. If prices significantly decline from year-end 2004 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 decommissioning 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, had 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, 2004, we had a valuation allowance of $2.2 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, 2004, we have a liability of $81.4 million for our postretirement plan obligations and a net liability of $11.3 million for our pension plan obligations, which reflects plan assets of $15.5 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:
We utilize a health care cost trend rate that currently reflects an 11% 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. 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. The expected rate of return on assets 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 1% change in the discount rate assumption and in the health care cost trend rate assumption would impact our post-retirement liability as of December 31, 2004 and our 2005 post-retirement service and interest cost (in millions):
Because our pension asset funds are newly funded, a 1% 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 $11.5 million to these plans in 2004. We expect to contribute approximately $20 million in 2005 for all pension-related plans. This amount may be revise based on available cash. 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 and 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.
In May 2004, the FASB issued FSP 106-2 “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). We have applied FSP 106-2 retroactively to the date of enactment. The impact of adopting FSP 106-2 resulted in a reduction in our accumulated projected benefit obligation (“APBO”) of $15.5 million for the full year of 2004 and a reduction of $2.2 million for net periodic post-retirement cost for the year ended December 31, 2004. Our actuaries have determined the plan is actuarially equivalent. We are currently evaluating the expected gross receipts to be received from the subsidy; no subsidies have been received as of December 31, 2004.
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.
Derivative Instruments. We account for derivative instruments in accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities as amended and interpreted. We periodically enter into fixed commitments, on a limited basis, as part of our programs to acquire refinery feedstocks at reasonable costs and to manage margins on certain refined product sales. We also enter into futures contracts to help
mitigate the price risk on these fixed commitments. The fixed commitments and future contracts are classified as derivatives according to SFAS No. 133 and we mark to market these derivatives and recognize the changes in their fair values in earnings. Derivatives are recorded on the balance sheet at their fair value as either other current assets or other current liabilities. As of December 31, 2004 and 2003, we 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 statements of cash flows.
Revenue Recognition. We sell various refined products, including gasoline, distillates, residual fuel, petrochemicals and petroleum coke. Revenues related to the sale of products are recognized when title passes. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
We also engage 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 us 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 our production, the effects from these activities on our 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.
New Accounting Standards
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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments are held for trading.
Commodity Risk
Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, crude oil, other feedstocks, gasoline, other refined products and natural gas. The demand for these commodities depend 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 can fluctuate significantly. Our net sales and operating revenues fluctuate significantly with movements in industry refined product prices, our cost of sales fluctuate significantly with movements in crude oil price and our operating expenses fluctuate with movements in the price of natural gas. 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.
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 industry refining margins 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 trading activities.
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. We also fix the price of a portion of our product sales in advance of producing and delivering that refined product. As a result, we are exposed to crude oil price movements and refined product price movements during this period. In 2004, with the acquisition of our Delaware City refinery, our average fixed price purchase commitments is approximately 10 million barrels. Our average fixed price sale commitments is approximately 2 million barrels, on a net basis, we have on average fixed price purchase commitments of approximately 8 million barrels. As of December 31, 2004, 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.
We prepared a sensitivity analysis to estimate our exposure to market risk associated with our futures contracts. This analysis may differ from actual results. The fair value of each contract was based on quoted futures prices. As of December 31, 2004, we had net short future contracts of approximately 6 million barrels, a $1 change in quoted futures prices would result in an approximate $6 million change to the fair market value of the futures contracts and correspondingly the same change in operating income. As of December 31, 2003, a $1 change in quoted futures prices would result in an approximately $10 million change to the fair market value of the futures contracts 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, 2004, the replacement cost (market value) of our crude oil and refined product inventories exceeded the carrying value by $379.8 million, or approximately $14 per barrel over cost. If the market value of these inventories had been lower by over $14 per barrel as of December 31, 2004, we would have had to write-down the value of our inventory. As of December 31, 2003, the replacement cost (market value) of our crude oil and refined product inventories exceeded the carrying value by $172 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. 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 2004 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 30 to 35 million mmbtus of
natural gas, a $1 change per million mmbtu in the price of natural gas would generally change our natural gas costs by $30 to $35 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.
Interest Rate Risk
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 $1,827.5 million (PRG-$1,817.6 million). The weighted average interest rate on our fixed rate long-term debt is 8.5% (PRG-8.5%). We are subject to interest rate risk on our Ohio bonds and any direct borrowings under our credit agreement. As of December 31, 2004 and 2003, 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, 2004 and 2003, there were no cash borrowings under our credit agreements.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is set forth beginning on page of this Annual Report on Form 10-K.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
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 Rules 13a-14, 13a-15(e) and 15d-15(e). 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 at the reasonable assurance level 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.
Management’s annual report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as the term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). In designing and evaluating our internal controls and procedures over financial reporting, 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 objective over the preparation and fair presentation of our consolidated financial statements 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 CEO and CFO. In assessing the effectiveness of the Company’s internal controls over financial reporting management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment, we believe that as of December 31, 2004, the Company’s internal controls over financial reporting are effective at the reasonable assurance level based on those criteria.
The independent registered public accounting firm that audited our consolidated financial statements included herein, and containing the disclosures required by this Item, has issued an attestation report on management’s assessment of our internal control over financial reporting
Attestation report of registered public accounting firm. The attestation reports of the registered public accounting firm are located on page 69 and page 70 of this Annual Report on Form 10-K.
Changes in internal control over financial reporting. There were no changes in our internal controls over financial reporting or in other factors that have materially affected, or are reasonably likely to materially affect these internal controls over financial reporting in the last fiscal quarter of 2004.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Premcor Inc:
Old Greenwich, Connecticut
We have audited management’s assessment, included in management’s annual report on internal control over financial reporting, included in Item 9A, that Premcor Inc. (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004 of the Company and our report dated March 1, 2005 expressed an unqualified opinion on those financial statements and financial statement schedules.
DELOITTE & TOUCHE LLP
Stamford, Connecticut
March 1, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of The Premcor Refining Group Inc:
Old Greenwich, Connecticut
We have audited management’s assessment, included in management’s annual report on internal control over financial reporting, included in Item 9A, that The Premcor Refining Group Inc. (“PRG”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our report dated March 1, 2005 expressed an unqualified opinion on those financial statements and financial statement schedule.
DELOITTE & TOUCHE LLP
Stamford, Connecticut
March 1, 2005
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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 2005 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 2005 Annual Meeting of Stockholders.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
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 2005 Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 12.
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 2005 Annual Meeting of Stockholders is incorporated herein 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. See our Proxy Statement for the 2005 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, 2004:
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information appearing under the heading “Related Party Transactions” in the Proxy Statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information appearing under the heading “Appointment of Independent Auditor” in the Proxy Statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1. and 2. Financial Statements and Financial Statement Schedules
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.
3. Exhibits
* Filed herewith.
** Confidential treatment permitted as to certain portions, which portions are omitted and filed separately with the Securities and Exchange Commission.
Pursuant to Regulation S-K 601(b)(4)(iii)(A), the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the Commission upon its request, copies of certain instruments, each relating to long-term debt exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.
PREMCOR INC. AND SUBSIDIARIES
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Premcor Inc:
Old Greenwich, Connecticut
We have audited the accompanying consolidated balance sheets of Premcor Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Stamford, Connecticut
March 1, 2005
PREMCOR INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share data)
The accompanying notes are an integral part of these statements.
PREMCOR INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
The accompanying notes are an integral part of these statements.
PREMCOR INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
The accompanying notes are an integral part of these statements.
PREMCOR INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in millions, except share data)
The accompanying notes are an integral part of these statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of The Premcor Refining Group Inc:
Old Greenwich, Connecticut
We have audited the accompanying consolidated balance sheets of The Premcor Refining Group Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Stamford, Connecticut
March 1, 2005
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share data)
The accompanying notes are an integral part of these statements.
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
The accompanying notes are an integral part of these statements.
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
The accompanying notes are an integral part of these statements.
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(in millions, except share data)
The accompanying notes are an integral part of these statements.
PREMCOR INC. AND SUBSIDIARIES
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2004, 2003 and 2002
(Tabular amounts in millions, except per share data)
1. NATURE OF BUSINESS
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 four refineries with an aggregate throughput capacity of 800,000 barrels per day (“bpd”). The refineries are located in Port Arthur, Texas; Lima, Ohio; Memphis, Tennessee; and Delaware City, Delaware. 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.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
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.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments, such as time deposits, money market instruments, commercial paper and United States and foreign government securities, purchased with an original maturity of
three months or less, to be cash equivalents. 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 are classified as a current or noncurrent asset based on its designated purpose. Cash and cash equivalents include compensating balances related to future credit availability such as unused lines of credit. Cash restricted under the requirements of long-term debt obligations totaled $69.1 million and $66.6 million as of December 31, 2004 and 2003, respectively.
Short-term Investments
The Company had short-term investments of $520.0 million and $311.9 million at December 31, 2004 and 2003, respectively. The short-term investments consisted primarily of auction rate securities representing cash available for current operations. In accordance with SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, the Company classified these short-term investments as available-for-sale. These securities are carried at estimated fair market value, the aggregate unrealized gains and losses net of taxes related to the investments, if material, are recorded as part of other comprehensive income within stockholders’ equity. See Note 8, Financial Instruments for further detail.
For all periods presented herein, investments in auction rate securities have been reclassed from cash and cash equivalents to short-term investments on the consolidated balance sheets. The reclassification was made because the certificates had stated maturities beyond three months. The amount of the investments in auction rate securities as of December 31, 2004 and 2003, was $513 million and $306 million, respectively. The reclassification resulted in changes in the consolidated statement of cash flows within the cash and cash equivalent balances and investing activities. This change had no impact on total assets, current assets or net income of the Company.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of trade receivables. Credit risk on trade receivables is minimized as a result of the credit quality of the Company’s customer base and industry collateralization practices. The Company conducts ongoing evaluations of its customers and requires letters of credit or other collateral as appropriate. Trade receivable credit losses were $0.1 million, $1.3 million and $0.1 million, for the years ended December 31, 2004, 2003, 2002, 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.
Fair Value Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature of these items. See Note 13, Long-term Debt for the disclosure of the fair value of long-term debt.
Inventories
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.
Risk Management Activity
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, refined product 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.
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. We account for these types of transactions as derivatives for accounting purposes.
Derivative Instruments
The Company accounts for derivative instruments in accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. The Company periodically enters into fixed commitments as part of its programs to acquire refinery feedstock and crude oil at reasonable costs and to manage margins on certain refined product sales. The Company also enters into futures contracts to help mitigate the price risk on these fixed commitments. The fixed commitments and future contracts are classified as derivatives according to SFAS No. 133 and the Company marks to market these derivatives and recognize the changes in their fair values in earnings. Derivatives are recorded on the balance sheet at their fair value as either other current assets or other current liabilities. As of December 31, 2004 and 2003, 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 statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment additions are recorded at cost. The Company capitalizes costs associated with the preliminary, pre-acquisition 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.
Asset Retirement Obligations
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.
Goodwill and Intangible Assets
Effective January 1, 2002, the Company adopted SFAS 142, Goodwill and Other Intangible Assets, whereby goodwill is no longer amortized but instead is tested for impairment annually or more frequently if an event or circumstance indicates that an impairment loss may have been incurred. Intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized. The intangible assets are amortized either over the useful life of the asset or in a manner over the useful life that reflects the pattern in which the economic benefit of the asset is consumed. The Company has determined as of 2004 and 2003 that there was no impairment of the above mentioned assets.
Deferred Turnaround Costs
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.
Deferred Financing Costs
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 statements of operations.
Environmental Costs
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.
Litigation Costs
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 Recognition
The Company sells various refined products, including gasoline, distillates, residual fuel, petrochemicals and petroleum coke. Revenues related to the sale of products are recognized when title passes. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
The Company 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 considered significant.
The Emerging Issues Task Force is currently considering this matter under Issue 4-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF 04-13 is considering whether or not these transactions should be recorded at historical cost and has raised the following questions related to these types of transactions; 1) when should these transactions be considered a non-monetary transactions under APB 29, Accounting for Nonmonetary Transactions, and 2) if these are considered non-monetary transactions, are there any circumstances where they should be recorded at fair value. For the years ended December 31, 2004, 2003 and 2002, the Company recorded $1.8 billion, $1.1 billion and $1.0 billion to net sales and operating revenues, respectively, for buy/sell arrangements with the same counterparty. For the years ended December 31, 2004, 2003 and 2002, the Company recorded $1.8 billion, $1.1 billion and $1.1 billion to cost of sales, respectively, for buy/sell arrangements with the same counterparty. Any buy/sell arrangements the Company enters into with the same counterparty are recorded at the contract price which is typically comparable to the current market value of the product and the arrangements are settled in cash on a gross basis. The Company has recorded these transactions on a gross basis according to the guidance provided in EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. The key factors which led to a conclusion that gross reporting was appropriate, were; 1) the Company was the primary obligor in the arrangement, 2) the Company has both general and physical loss of inventory risk , 3) the Company took title to the inventory it received and 4) the Company has credit risk for the amounts it billed to the counterparty.
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.
Supply and Marketing Activities
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. The current period presentation and prior period reclassifications have no effect on current or previously reported operating income (loss) or net income (loss).
Prior period reclassifications include:
Excise Taxes
The Company collects excise taxes on sales of gasoline and other petroleum products. Excise taxes of approximately $863.2 million, $710.9 million and $347.4 million were collected from customers and paid to various governmental entities related to activities in 2004, 2003 and 2002, respectively. The increase in the 2004 amount collected and paid is primarily related to the operations of the newly acquired Delaware City refinery. The increase in the 2003 activity is primarily related to the operations of the Memphis refinery. Excise taxes are not included in net sales and operating revenues.
Income Taxes
The Company provides for deferred taxes under the asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities. Deferred taxes are classified as current or noncurrent depending on the classification of the assets and liabilities to which the temporary differences relate. Deferred taxes arising from temporary differences that are not related to a specific asset or liability are classified as current or noncurrent depending on the periods in which the temporary differences are 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.
Stock-Based Compensation
As of December 31, 2004, 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. 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 one to five years and typically expire in ten 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, 2004, the Company expects to record future non-cash stock-based compensation expense and additional paid-in capital of $14.6 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.
Earnings Per Share
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 is calculated by dividing net income available to common stockholders by the sum of weighted average common shares outstanding during the period plus common stock equivalents, such as stock options and warrants.
New Accounting Standards
In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4, Inventory Pricing. SFAS No. 151 amends the guidance in ARB No. 43, Chapter 4, to clarify the accounting for abnormal amounts of idle facility expense, freight, handing costs, and spoilage. This statement requires that those items be recognized as current period charges regardless of whether they meet the criterion of “so abnormal” which was the criterion specified in ARB No. 43. In addition, this Statement requires that allocation of fixed production overheads to the cost of production be based on normal capacity of the production facilities. This pronouncement is effective for the Company beginning October 1, 2005. The Company does not believe the adoption of this new standard will have a material impact on its results of operations.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees and amends SFAS No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an
alternative. The new standard will be effective for the Company in the first interim or annual reporting period beginning after June 15, 2005. As the Company already records grants of employee stock options in the income statement based on their fair values, the Company does not believe the adoption of this new standard will have a material impact on its results of operations.
Reclassifications
Certain reclassifications have been made to prior years’ financial statements to conform to classifications used in the current year.
3. ACQUISITIONS
Acquisition of the Delaware City refinery and related financings
Effective May 1, 2004, the Company completed an agreement with Motiva Enterprises LLC (“Motiva”) to purchase its Delaware City refining complex located in Delaware City, Delaware. The Delaware City refinery has a rated crude unit throughput capacity of approximately 190,000 bpd. Also included in the purchase was a 2,400 tons per day petroleum coke gasification unit, a 180 megawatt cogeneration facility, 8.5 million barrels of crude oil, intermediates, blendstock, and product tankage and a 50,000 bpd truck-loading rack. The purchase price was $800 million ($780 million cash less $20 million assumed liabilities), plus additional petroleum inventories valued at $90 million and approximately $2 million in transaction fees. In addition, Motiva will be entitled to receive contingent purchase payments of $25 million per year up to a total of $75 million over a three-year period depending on the amount of crude oil processed at the refinery and the level of refining margins during that period, and a $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. Any amount the Company pays to Motiva for the contingent consideration will be recorded as goodwill and will be subject to an annual impairment measurement test.
The Delaware City refinery is a high-conversion medium and heavy high-sulfur 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.
The Company financed the acquisition from a portion of the proceeds from its April 2004 public common stock offering of 14.9 million shares which provided net proceeds of $490 million; from PRG’s $400 million senior notes offering completed April 2004 of which $200 million, due in 2011, bear interest at 6 1/8% per annum and $200 million, due in 2014, bear interest at 6 3/4% per annum; and from available cash.
The acquisition of the Delaware City 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 fourth quarter of 2004, we adjusted the purchase price allocation based on management’s evaluation of independent appraisals and other information. The adjusted preliminary purchase price allocation, which is subject to finalization, is as follows:
In conjunction with the acquisition of the Delaware City refinery, the Company entered into an agreement, effective May 1, 2004, with the Saudi Arabian Oil Company for the supply of 105,000 bpd of crude oil, however, due to certain quota restrictions the current supply is 85,000 bpd. The agreement has terms extending to April 30, 2005, with automatic one-year extensions thereafter unless terminated at the option of either party. The crude oil is priced by a market-based formula as defined in the agreement. The Company also entered into a product offtake agreement with Motiva that provides for the delivery by Premcor to Motiva of approximately 36,700 bpd of finished light petroleum products, such as gasoline and heating oil. The agreement was effective May 1, 2004, and the main portion of the offtake agreement has terms extending for six months with automatic renewals until canceled by either party.
Acquisition of the Memphis refinery and related financings
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 155,000 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, 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 we 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 13 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, or assignee over the next seven years, depending on the level of refining margins during that period. Any amounts the Company pays for the contingent consideration will be recorded as goodwill. Such goodwill will not be amortized, but will be subject to an annual impairment evaluation. As of December 31, 2004, the Company had paid $27.6 million of contingent consideration.
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 previous credit agreement to allow for the acquisition.
4. SABINE RESTRUCTURING
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 12½% Senior Notes. PACC owns all the outstanding common stock of PAFC.
5. REFINERY RESTRUCTURING AND OTHER CHARGES
In 2004, the Company recorded refinery restructuring and other charges of $19.5 million. The charges included $7.3 million related to the relocation of the Company’s St. Louis general office to its Connecticut headquarters, $3.1 million related to litigation costs associated with non-operating assets and $9.1 million related to environmental charges primarily for additional estimated costs related to cleanup at the Village of Hartford and costs for additional remediation activities at our other sites.
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.
Below are further discussions of the Hartford and Blue Island refinery closures and the management, refinery, and administrative function restructurings.
Refinery Closures and Asset Sales. 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 postretirement benefits that were extended to certain employees who were nearing the retirement requirements. The Company continues to utilize its storage and distribution facilities at both Blue Island and Hartford 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. Equipment dismantling at our Blue Island site is expected to be completed by the end of 2005. In 2004 the Company signed a consent order with the State of Illinois for Blue Island environmental investigation. Discussions continue on the Hartford site and the Company has begun voluntary remediation investigations on this site in 2005. 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 2004, we recorded a charge of $9.1 million related to our environmental remediation activity. This charge was primarily for additional estimated costs related to cleanup at the Village of Hartford and costs for additional remediation activities at our other sites.
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. 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, which was completed in 2004, cost $14.8 million, which included $4.3 million of severance related benefits and $10.5 million of other costs such as training, relocation and the movement of physical assets. The severance related costs were amortized over the future service period of the affected employees and the other costs were 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, 2004 and 2003:
6. DISCONTINUED OPERATIONS
In connection with the 1999 sale of PRG’s retail assets to Clark Retail Enterprises, Inc. (“CRE”), PRG assigned certain 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 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 July 2004, the CRE bankruptcy estate was liquidated and the case dismissed. As of December 31, 2004, PRG was subleasing 34 operating stores, the leases on 29 stores had either been terminated or expired, the leases on 87 operating stores were held by third parties and PRG is in the process of buying out the leases on the two remaining stores. In 2004, PRG recorded an after-tax charge of $5.6 million. These charges represent the estimated net present value of its remaining liability under the current operating stores that were subleased, net of estimated sublease income, and other direct costs. In 2003, PRG recorded an after-tax charge of $7.2 million representing the estimated net present value of its remaining liability under the current operating stores that were subleased, net of estimated sublease income, and other direct costs. Total payments on leases and subleases upon which the Company will likely remain jointly and severally liable are currently estimated as follows: (in millions) 2005-$7, 2006-$7, 2007-$7, 2008-$7, 2009-$7 and in the aggregate thereafter-$30.
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 may no longer be responsible for certain sites.
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:
7. EARNINGS PER SHARE
The common shares used to compute the Company’s basic and diluted earnings per share is as follows (in millions):
Stock options of 3.8 million, 4.2 million, and 4.4 million common shares for the years ended December 31, 2004, 2003, and 2002, respectively, were excluded from the diluted earnings per share calculation because they were anti-dilutive.
8. FINANCIAL INSTRUMENTS
Short-term Investments
Short-term investments include United States government security funds, maturing between three and twelve months from date of purchase and auction rate securities. 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, 2004, the Company maintained short-term investments totaling $520 million (2003-$312 million), of which $1.7 million was pledged as collateral for self-insured workers’ compensation programs at PRG. As of December 31, 2004, a wholly owned subsidiary of Premcor Inc. held $5.3 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 (2003-$4.2 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.
Derivative Financial Instruments
The Company enters into derivative financial instruments, such as fixed purchase/sale commitments and futures contracts, which are treated as derivative financial instruments and are marked-to-market. Fixed purchase commitments are typically entered into in order to supply our refineries with crude oil on a timely basis. These types of commitments generally are entered into at a fixed price one to several weeks in advance of receiving and processing the crude oil. Fixed sale commitments may be entered into several weeks in advance of producing and delivering the product. These commitments are also entered into a fixed price. Futures contracts are then entered into to mitigate the price risk the Company is exposed to on the fixed commitments. All gains and losses are recorded to cost of sales as all derivative activity is related to the purchase and sale of inventory.
During the year ended December 31, 2004, the Company recognized net losses of $33 million related to its price risk management activities. The net loss was comprised of $30 million related to the forward sales of crack spread commitments, unrealized and realized gains on crude fixed commitments of $93 million, unrealized and realized gains on product fixed commitments of $7 million, unrealized and realized losses on crude futures contracts of $100 million and unrealized and realized losses on product futures contracts of $3 million. During the year ended December 31, 2003 and 2002, the Company recognized net losses of $30 million and net gains of $34 million, respectfully, related to its price risk management activities.
At December 31, 2004, the Company had recorded its unrealized gains and losses on outstanding fixed commitments of $33.0 million recorded in other current assets and $51.0 million recorded in accrued expenses and other. All of the outstanding fixed commitments at year end are expected to mature within the next few months. At December 31, 2004, the Company had outstanding futures contracts of $0.9 million recorded in other current assets and $9.7 million recorded in accrued expenses and other. All of the outstanding futures contracts at year end are expected to mature within the next few months. At December 31, 2004, the Company also had $3.4 million and $4.5 million recorded to accounts receivable and accounts payable, respectively. These amounts primarily related to expired energy swap agreements which had expired but the Company had not yet received or made a payment on the agreements.
At December 31, 2003, the Company had recorded $22 million in current assets and $19 million in current liabilities, related to its price risk management activities. The majority of the balance in both current assets and current liabilities related to the unrealized gains and losses on the Company’s fixed commitments.
9. INVENTORIES
The carrying value of inventories consisted of the following:
As of December 31, 2004, the market value of crude oil, refined product and blendstock inventories was approximately $379.8 million above carrying value (2003-$171.6 million).
Inventories recorded under LIFO include crude oil, refined products and blendstocks of $735.4 million and $600.2 million for the years ended December 31, 2004 and 2003, respectively. There was no LIFO liquidation in 2004. In 2003, a LIFO liquidation increased the Company’s pretax earnings by $2.2 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. 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 a decrease of approximately $11 million to 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.
10. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
The useful lives on depreciable assets used to determine depreciation were as follows:
Process units, buildings, and oil storage and movement
15 to 40 years; average 32 years
Office equipment, furniture and autos
3 to 12 years; average 6 years
As of December 31, 2004 and 2003, process units, buildings and oil storage and movement included capitalized leases of $20.0 million (PRG-$9.4 million). As of December 31, 2004 and 2003, accumulated depreciation included capitalized leases of $4.9 million and $3.8 million, respectively (PRG: 2004-$3.5 million and 2003-$3.1 million). As of December 31, 2004, construction in progress included approximately $208.7 million (2003-$100 million) related to expenditures to conform to new federally mandated fuel specifications as discussed more fully in Note 23, Commitments and Contingencies.
11. OTHER ASSETS
Other assets consisted of the following:
In 2004, the Company incurred deferred financing costs of $16.1 million, related to the new $1 billion credit facility and the issuance of $400 million of senior notes. As a result of the early extinguishment of the $785 million credit facility, the Company and PRG recorded a loss for the write-off of unamortized deferred financing costs of $3.6 million.
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 12 1/2% Senior Notes due January 15, 2009, the early repayment of certain debt, and the amendment of its credit agreement.
For the year ended December 31, 2004, amortization of deferred financing costs was $8.5 million (2003-$9.1 million, 2002-$10.3 million) for the Company. For PRG, amortization of deferred financing costs for the year ended December 31, 2004 was $8.5 million (2003-$9.1 million 2002-$10.2 million). Amortization of deferred financing costs is included in “Interest and finance expense.”
Intangible assets were comprised of the following as of December 31, 2004:
Amortization expense related to intangible assets was $0.4 million, $0.1 million and nil for the years ended December 31, 2004, 2003 and 2002, respectively. The Company expects amortization expense for intangible to approximate $0.5 million annually through 2009.
12. CREDIT AGREEMENTS
On April 13, 2004, PRG completed a new $1 billion senior secured revolving credit facility, maturing in April 2009, to replace its previous $785 million credit facility. The facility is used primarily to secure crude oil purchase obligations for our refinery operations and to provide for other working capital needs. The revolving credit facility allows for the issuance of letters of credit and direct borrowings, individually or collectively, up to the lesser of $1 billion or the amount available under a defined borrowing base. The borrowing base includes, among other items, eligible cash and cash equivalents, eligible investments, eligible receivables and eligible petroleum inventories. The revolving credit facility also allows for an overall increase in the principal amount of the facility of up to $250 million under certain circumstances. The revolving credit facility is secured by a lien on substantially all of PRG’s cash and cash equivalents, receivables, crude oil and refined product inventories and intellectual property and is guaranteed by Premcor Inc. The collateral also includes the capital stock of Sabine and certain other subsidiaries and certain PACC 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.
The covenants and conditions under this new credit agreement are generally less restrictive than the covenants contained in the agreement governing our terminated $785 million facility. The new credit agreement contains covenants and conditions that, among other things, limit dividends, indebtedness, liens, investments, restricted payments as defined and the sale of assets. The covenants also provide that in the event PRG does not maintain certain availability within the facility, additional restrictions and a cumulative cash flow test will apply. PRG was in compliance with these covenants as of December 31, 2004.
As of December 31, 2004, the borrowing base was $1,853.1 million with $484.1 million of the facility utilized for letters of credit. As of December 31, 2004, there were no direct cash borrowings under the credit facility. The portion of the facility utilized for letters of credit was lower as of December 31, 2004 as compared to December 31, 2003 due to the increase of open trade credit and the addition of purchases of domestic crude for Lima through the MSCG supply contract, partially offset by the addition of purchases for the Delaware City refinery.
PRG’s previous credit agreement, which was amended and restated in February 2003, provided 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 utilized this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. The borrowing base included 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 was early terminated in April 2004. As of December 31, 2003, the borrowing base was $1,348.9 million, with $602.1 million of the facility utilized for letters of credit. As of December 31, 2003, $208.5 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 related to deliveries in which the Company had taken title and accordingly recorded purchases and accounts payable.
The previous credit agreement provided 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 were 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 there were no direct cash borrowings under the previous credit agreement.
The $785 million credit agreement contained covenants and conditions that, among other things, limited PRG’s dividends, indebtedness, liens, investments and contingent obligations. PRG was 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 provided for a cumulative cash flow test that from January 1, 2003 to February 10, 2006 could not be less than zero.
PRG also has a $40 million cash-collateralized credit facility which was renewed effective June 1, 2004 for one year. 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, 2004, $39.7 million (December 31, 2003-$18.0 million) of the line of credit was utilized for letters of credit.
13. LONG-TERM DEBT
Long-term debt consisted of the following:
(1) Issued or borrowed by Port Arthur Finance Corp., a subsidiary of PACC
(2) Issued or borrowed by stand-alone PRG
(3) Assumed by The Premcor Pipeline Co., a subsidiary of Premcor USA Inc.
(4) Guaranteed by Premcor Inc.
On April 23, 2004, PRG completed an offering of $400 million in senior notes, of which $200 million, due in 2011, bear interest at 6 1/8% per annum and $200 million, due in 2014, bear interest at 6 3/4% per annum. A portion of the proceeds was used to purchase the Delaware City refining complex. The senior notes are unsecured. Premcor Inc. has fully and unconditionally guaranteed the principal payments on these senior notes and any applicable premiums and interest.
PRG’s long-term debt, including current maturities, as of December 31, 2004 was $1,817.6 million and is the same as the Premcor Inc. long-term debt as noted in the table above except that it excludes the $9.9 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, 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.
The estimated fair value of the Company’s long-term debt, excluding capital leases, at December 31, 2004 was $1,984 million (2003-$1,578 million). The estimated fair value of PRG’s long-term debt, excluding capital leases, at December 31, 2004 was $1,984 million (2003-$1,567 million). Estimated fair value was determined using quoted market prices for each debt issue.
The 12 1/2% 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 12 1/2% 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 12 1/2% Senior Notes. The current portion of the 12 1/2% Senior Notes was $38.5 million as of December 31, 2004.
The 9 1/4% Senior Notes and 9 1/2% Senior Notes were issued at par by PRG in February 2003 and are unsecured. The 9 1/4% Senior Notes and 9 1/2% 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 9 1/4% Senior Notes and 9 1/2% Senior Notes at any time prior to February 2006 at redemption prices of 109.25% of principal and 109.5% of principal, respectively.
The 7 1/2% Senior Notes were issued at par by PRG in June 2003 and are unsecured. The 7 1/2% 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 7½% Senior Notes at any time prior to June 2006 at a redemption price equal to 107.5% of principal.
The 6 3/4% Senior Notes and 7 3/4% Senior Subordinated Notes were issued at par by PRG in November 2003. These notes are unsecured, with the 7 3/4% Senior Subordinated Notes subordinated in right of payment to all unsubordinated indebtedness of PRG. The 6 3/4% Senior Notes may not be redeemed prior to their maturity. The 7 3/4% 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 7 3/4% Senior Subordinated Notes at any time prior to February 2006 at a redemption price equal to 107.75% of principal.
The 6 1/8 % Senior Notes and 6 3/4% Senior Notes were issued at par by PRG in April 2004. These notes are fully and unconditionally guaranteed by Premcor Inc. The 6 3/4% Senior Notes may be redeemed in full or in part at the option of PRG on or after May 2009. PRG may utilize proceeds from one or more equity offerings to redeem up to 35% of the aggregate principal amount of the 6 3/4% Senior Notes at any time prior to May 2007, at a redemption price of 106.75%. The 6 1/8% Senior Notes are not redeemable prior to maturity.
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 interest rate on these bonds is determined in a remarketing process that takes place just prior to the end of the interest rate period. For 2004 and 2003, the interest rate was approximately 2%. PRG has the option to redeem the bonds prior to maturity during a window from April 1 to November 30 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 was renewed effective June 1, 2004 for one year 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 $1 billion credit facility. PRG also has the ability to fix the interest rate on the Ohio Bonds in which case additional security might no longer be required.
In February 2003, the Company redeemed the $40.1 million principal balance of Premcor USA Inc.’s 11 1/2% 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 12 1/2% Senior Notes at a $2.7 million premium. In 2003, PACC made $14.2 million of scheduled principal payments on its 12 1/2% Senior Notes. In December 2003, PRG redeemed the aggregate principal balance of the 8 3/8% Senior Notes, 8 5/8% Senior Notes, and 8 7/8% 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): 2005-$36.6; 2006-$44.1; 2007-$41.3; 2008-$48.5; 2009-$29.6; 2010 and thereafter-$1,627.4.
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 be permitted to incur at least $1 of additional debt as defined in the indenture, possess a positive balance of cumulative earnings plus capital issued less any dividends and not be in default of any covenants. In the event of a change of control of PRG, as defined in the indenture, 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 12 1/2% Senior Notes, prorated based on the number of months remaining until that payment is due. As of December 31, 2004, cash of $69.1 million (2003-$66.6 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, if an aggregate intercompany payable from PRG to PACC exists at any time, PACC shall forgive PRG for such amount, which would take the form of a non-cash dividend. Non-cash dividends of $516.1 million were made in 2004 (2003-$174.7).
Interest and finance expense
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 2004 for the Company was $138.9 million (2003-$110.4 million, 2002-$114.3 million). Cash paid for interest expense in 2004 for PRG was $137.5 million (2003-$107.4 million, 2002-$103.9 million).
Gain (loss) on extinguishment of long-term debt
In 2004, as a result of the early extinguishment of the $785 million credit facility, the Company and PRG recorded a loss for the write-off of unamortized deferred financing costs of $3.6 million for the year ended December 31, 2004.
As a result of the early extinguishment of debt in 2003 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 11 1/2% subordinated debentures, which were held by Premcor USA.
As a result of the early extinguishment of debt in 2002, 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.
14. LEASE COMMITMENTS
The Company leases refinery equipment, crude oil tankers, tank cars, office space, and office equipment from unrelated third parties with lease terms ranging from 1 to 12 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 28 years and 46 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 34 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 20 years. Certain of these properties are being subleased. As of December 31, 2004, net future minimum lease payments under non-cancelable operating leases were as follows (in millions): 2005-$53.6; 2006-$50.0; 2007-$42.8; 2008-$41.2; 2009-$37.9; 2010 and thereafter-$46.6. Total future rental receipts are $29.1 million as of December 31, 2004. Rental expense during 2004 was $58.1 million (2003-$49.0 million, 2002-$31.5 million).
15. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following:
Legal and environmental liabilities reflected the long-term portion of these liabilities and are more fully discussed in Note 23, Commitments and Contingencies. The postretirement and pension benefit obligations are discussed in Note 16, Employee Benefit Plans.
16. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement 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 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. The Company uses a September 30 measurement date for its other post retirement benefits.
Information concerning the SERP was not included in 2002 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 2004 and 2003 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 periodic 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 11% in 2005, 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 contribute a total of $20 million to its pension plans in 2005; this amount may be revised based on available cash. The Company expects to make payments of $4 million for its obligations under its other post retirement benefit plans in 2005.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Act”) was signed into law. The Act will provide prescription drug coverage to retirees beginning in 2006 and will provide subsidies to sponsors of post-retirement medical plans that provide prescription drug coverage. 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. The Company is evaluating potential changes to the postretirement plans in order to take advantage of this new coverage and is evaluating the various options provided by the act and any changes that may be necessary to make to the plans.
In May 2004, the FASB issued FSP 106-2 Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP 106-2”). The Company has applied FSP 106-2 retroactively to the date of enactment. The impact of adopting FSP 106-2 resulted in a reduction of the Company’s accumulated projected benefit obligation (“APBO”) of $15.5 million for the full year 2004 and a reduction in net periodic post-retirement cost of $2.2 million for the year ended December 31, 2004. The Company’s actuaries have determined the plan is actuarially equivalent. The Company is currently evaluating the expected gross receipts to be received from the subsidy; no subsidies have been received as of December 31, 2004.
Pension Plan Assets
The guiding principles in implementing the Company’s investment policy with respect to its qualified employee pension plans are to 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 was derived using an asset allocation model with an expected return on the plan assets that takes into account 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.
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 reviews performance of its investment funds quarterly and reviews 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 in 2002 and 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. In 2004, the funding was invested in accordance with the Company’s long-term investment strategy.
Employee Savings Plan
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 2004 were $10.3 million (2003-$8.1 million; 2002-$8.3 million).
17. INCOME TAXES
Premcor Inc. and Subsidiaries:
The income tax (provision) benefit is summarized as follows:
A reconciliation between the income tax (provision) benefit computed on pretax income (loss) 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:
PRG and Subsidiaries:
The income tax (provision) benefit is summarized as follows:
A reconciliation between the income tax (provision) benefit computed on pretax income (loss) 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:
PRG:
As of December 31, 2004, the Company has made net cumulative payments of $51.3 million (PRG-$45.7 million) under the federal alternative minimum tax system which are available to reduce future regular income tax payments. As of December 31, 2004, the Company had regular federal tax net operating loss carryforwards of $165.7 million (PRG-$150.3 million). As of December 31, 2004, neither the Company nor PRG had an alternative minimum tax net operating loss carryforward. As of December 31, 2004, the Company had federal business tax credit carryforwards in the amount of $15.3 million (PRG-$15.3 million). Such operating losses and tax credit carryforwards have carryover periods of 15 years (20 years for losses and credits originating in 1998 and years thereafter) and are available to reduce future tax liabilities through the year ending December 31, 2023. The tax credit carryover periods begin to terminate with the year ending December 31, 2005 and the net operating loss carryover periods will begin to terminate during 2022. The regular federal tax net operating carryforwards will expire during 2022 to the extent they have not been used to reduce regular taxable income prior to such time.
For federal income tax purposes, the Company has incurred, as a result of the April 2004 equity offering, a stock ownership change of more than 50%, determined over the preceding three-year period. Under federal tax law, the more than 50% stock ownership change has resulted in an annual limitation being placed on the amount of regular tax net operating losses, and certain other losses and tax credits (collectively “tax attributes”) that may be utilized in any given year. Accordingly, the Company’s ability to utilize tax attributes could be affected in both timing and amount. However, management believes such annual limitation will not restrict the Company’s ability to significantly utilize its tax attributes over the applicable carryforward periods. Therefore, at this time, the Company does not anticipate the need for an additional valuation allowance as a result of this more than 50% stock ownership change.
The valuation allowance of the Company and PRG as of December 31, 2004 was $2.2 million (2003-$2.8 million). The decrease of the deferred tax valuation allowance in 2004 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 2004, the Company made net federal cash payments of $104.2 million (2003-$3.7 million net federal cash payments; 2002-$12.6 million net federal cash refunds). During 2004, PRG neither made nor received any net federal cash payments or refunds (2003-no net cash payments or refunds; 2002-$12.6 million net federal cash refunds). PRG provides for its portion of consolidated refunds and liability under its tax sharing agreement with Premcor Inc. As of December 31, 2004, PRG had an amount due to affiliates of $116.2 million (2003-$41.2 million) related to income taxes and its tax sharing agreement with Premcor Inc. and its predecessor. During 2004, PRG made net state cash payments of $0.3 million (2003-no net state cash payments or refunds; 2002-$0.3 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).
18. STOCKHOLDERS’ EQUITY
As of December 31, 2004, Premcor Inc. had one class of outstanding common stock. On April 23, 2004, Premcor Inc. completed a public offering of 14.95 million shares of common stock, which included 1.95 million shares related to the over allotment option, which was exercised by the underwriter. The shares were issued at a price of $34.00 per share and the Company received proceeds, net of underwriter’s discount and commissions, of $490 million. A portion of the proceeds was used to purchase the Delaware City refinery complex, which is discussed in Note 3. Stockholders’ equity also reflects the receipt of proceeds from the exercise of stock options.
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 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.
19. STOCK OPTION PLANS
As of December 31, 2004, 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 4,500,000 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, 2004, all of the outstanding performance vesting options were vested and had been excercised.
Information regarding stock option plans as of December 31, 2004, 2003 and 2002 is as follows:
Information regarding stock options granted during 2004, 2003 and 2002 is as follows:
Information regarding stock options outstanding as of December 31, 2004 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:
20. RELATED PARTY TRANSACTIONS
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.
Premcor Inc. and PRG
As of December 31, 2004, PRG had a receivable from Premcor Inc., excluding amounts due related to income taxes and the tax sharing agreement, which is discussed in Note 17, of $2.2 million. The $2.2 million relates to payments PRG made for Premcor Inc to Opus and cash Premcor Inc. received on the income tax deductions for stock options. As of December 1, 2003, PRG had a payable to Premcor Inc. for management fees paid by Premcor Inc. on PRG’s behalf of $0.1 million. PRG’s loan receivable from Premcor Inc. for $8.9 million in 2003, which included both principal and interest, was paid in full during 2004. PRG’s subsidiary, Premcor Investments Inc., had loaned these proceeds to Premcor Inc. to allow Premcor Inc. to pay certain fees. The loan had bore interest at 12% per annum. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.
Premcor USA and PRG
In 2004, PRG received capital contributions from Premcor USA totaling $403.5 million, primarily for the acquisition of the Delaware City refinery. In 2003, PRG received capital contributions from Premcor USA totaling $263.3 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. These intercompany balances are eliminated in Premcor Inc.’s consolidated financial statements.
The Premcor Pipeline Co. and PRG
In 2004, PRG contributed $14.3 million to Premcor USA, the contribution represented 100% ownership in the capital stock of the Port Arthur Pipeline Company, which was previously a subsidiary of PRG.
As of December 31, 2004, PRG had a receivable from The Premcor Pipeline Co. of $20.2 million (2003-$5.9 million) related to amounts that PRG paid on behalf of The Premcor Pipeline Co. As of December 31, 2004, PRG had a payable to The Premcor Pipeline Co. of $16.0 million (December 31, 2003-$2.0 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.
Fuel Strategies International, Inc.
The Company entered into an agreement with Fuel Strategies International, Inc. (“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 of the board of directors and senior executive employee. For the years ended December 31, 2004 and 2003, the Company incurred fees of $0.2 million and $0.4 million, respectively, related to this agreement. In June 2004, the Company hired the principal as a full time employee and the contract with FSI expired in May 2004.
Blackstone
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 for the year ended December 31, 2002.
21. CONSOLIDATING FINANCIAL STATEMENTS OF PRG AS CO-GUARANTOR OF PAFC’S 12 1/2% 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 12 1/2% 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, 2004, the maximum potential amounts of future payments under the guarantee were $197.6 million in principal payments and $70 million in future interest payments. See Note 13, Long-term Debt, for additional information on the collateralization of the 12½% 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 12 1/2% 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 or processes them further. The net receivables and payables related to these transactions are shown by each company and eliminated in the consolidation of PRG.
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2004
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2004
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2004
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2003
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2003
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2003
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2002
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2002
22. CONSOLIDATING FINANCIAL STATEMENTS OF PREMCOR INC. AS GUARANTOR OF PRG’S SENIOR NOTES
Presented below are the Premcor Inc. condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3-10 of the Securities Exchange Act of 1934, as amended. Premcor Inc. is a full and unconditional guarantor of PRG’s 6 1/8% 2011 Senior Notes and 6 3/4% 2014 Senior Notes. Premcor Inc. indirectly owns PRG through its 100% ownership of Premcor USA. PRG is a wholly owned subsidiary of Premcor USA. Under Rule 3-10, the condensed consolidating balance sheets, statements of operations, and statements of cash flows presented below meet the requirements for financial statements of the issuer and the guarantor of the notes, and all guarantees are full and unconditional on a joint and several basis.
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2004
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2004
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2004
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2003
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2003
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2003
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2002
PREMCOR INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2002
23. COMMITMENTS AND CONTINGENCIES
Legal and Environmental
The following is a summary of potentially material pending legal proceedings to which the Company or any of the Company’s subsidiaries are a party or to which any of the Company or their subsidiaries 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, the Company also has been named in various other suits and claims. The Company believes that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on the Company’s consolidated financial condition, results of operations or cash flows. However, an adverse outcome of any one or more of these matters could have a material adverse 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 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 lawsuit has been stayed while the Company discusses with the State implementing an assessment and remediation plan for the Hartford refinery site. Also, in the first quarter of 2004, an Administrative Order on Consent was signed by Premcor, two other potentially responsible parties, and the U.S. Environmental Protection Agency. This order requires the investigation of groundwater contamination and the development of a remedial solution for a portion of the Village of Hartford.
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. was removed to the United States District Court for the Southern District of Illinois. In the second quarter of 2004, plaintiffs filed an amended complaint in the United States District Court Southern District of Illinois. The amended complaint added new, non-diverse defendants, eliminated a cause of action for strict liability and added a new cause of action based on a negligence theory. The Company filed an answer to the amended complaint setting forth its defenses. The United States District Court also remanded the case to state court. The case is currently in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 03-L-1053 captioned Sparks, et al. v. The Premcor Refining Group, Inc. et al.
Also in the second quarter of 2004, two new lawsuits were served by residents in the Village of Hartford. The original complaints have since been amended. The two lawsuits are Bedwell, et al. v. The Premcor Refining Group, Inc., et al. in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 04-L-342 and Abert, et al. v. Alberta Energy Company, Ltd., et al. in the Circuit Court Third Judicial Circuit Madison County, Illinois, Case No. 04-L-354. Bedwell contains allegations substantially similar to Sparks. Bedwell includes a request for class certification similar to Sparks. No class certification has been granted in either case. Abert also raises allegations substantially similar to Sparks but on behalf of approximately 114 individually named plaintiffs against approximately 24 different defendants. The Company has filed responsive pleadings in both cases including defenses to plaintiffs’ claims.
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 sought class certification, unspecified
damages and the establishment of a trust fund for health concerns. The case is entitled Marion L. Aaron, et al. v. Premcor Refining Group Inc. et al. and is filed in Judicial District Court of Jefferson County, Texas. The plaintiffs recently filed a Motion to Non-Suit all their claims in this case. The Motion was unopposed and dismisses the case in its entirety.
During the fourth quarter of 2004, the Company received service of 13 lawsuits also brought by residents in the area of Port Arthur, Texas alleging personal and pecuniary injuries caused by emissions from industrial facilities in the area. The Company was non-suited without prejudice in three of the lawsuits prior to filing an appearance. The cases have been consolidated into one lead case entitled Crystal Faulk, et al. v. Premcor Refining, et al. in the District Court of Jefferson County, Texas, Case No. B-173,357. Consolidated petitions have been filed in the case which assert the claims of 142 plaintiffs, 85 of whom are alleging claims against the Company and others. The cases generally involve allegations of negligence per se, negligence, fraud, permanent nuisance, trespass and gross negligence.
Methyl-Tertiary Butyl Ether Products Liability Litigation. During the fourth quarter of 2003 and continuing, the Company has been named in approximately 51 cases, along with dozens of other companies, filed in approximately 15 states concerning the use of methyl-tertiary butyl ether, or MTBE. The cases contain allegations that MTBE is defective. The cases have been removed to federal court and consolidated 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. The Company has filed or joined in responsive pleadings and has raised additional defenses to plaintiffs’ claims including those defenses based on the Company’s limited use of MTBE and its narrow geographical use.
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, 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 alleged 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 alleged conditions that existed at the time have since changed. In May 2001, the TCEQ proposed an order covering some of the 1998 air and hazardous waste allegations and proposed 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.
The TCEQ conducted another inspection at our Port Arthur refinery on April 4, 2003. In August 2003, the Company received a notice of enforcement regarding that inspection alleging 46 air-related violations. The Company disputes the allegations 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 the Company seeking to recover damages in an unspecified amount for alleged property damage and non-permanent personal injury resulting from that catalyst release. The complaint underlying this action was later amended to add allegations of subsequent events that allegedly interfered with the use and enjoyment of neighboring property. 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 sought damages in an unspecified amount for alleged property damage and personal injury resulting from that catalyst release. Mason was voluntarily dismissed in 2004. Rosolowski and Madrigal have been consolidated for the purpose of conducting discovery, which is currently proceeding. Other single plaintiff cases regarding the same incidents are also pending. The cases are pending in Circuit Court of Cook County, Illinois.
Blue Island Reformulated Gasoline Notice of Violation. In the second quarter of 2004, the Company received a Notice of Violation from the U.S. EPA under the Clean Air Act for allegedly not meeting the minimum annual average emissions performance for reformulated gasoline from the Blue Island Refinery in 2001. The Blue Island Refinery only operated for approximately one month in 2001. The Company reached a settlement agreement with U.S. EPA on this matter in the fourth quarter of 2004 and the Notice of Violation has now been resolved.
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 Company entered into a Consent Order with the State of Illinois to resolve this case. The Consent Order involves performing an assessment and remediation feasibility study of the Blue Island property.
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.
Former Retail Sites Violation Notices. In the first quarter of 2004, the Company received 39 Violation Notices from the Illinois EPA as a result of remediation activities at 35 former retail sites in the State of Illinois. The notices do not contain any proposed penalties but penalties may be sought under the applicable law. The Company has responded to the Violation Notices and the Company is continuing the remediation work being performed at these sites.
Alleged Asbestos and Benzene Exposure. The Company, along with numerous other defendants, have been named in certain individual lawsuits alleging personal injury resulting from exposure to asbestos or benzene. A majority of the claims have been filed by employees of third party independent contractors who purportedly were exposed 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. Therefore it is not possible at this time for us to quantify our 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 our financial condition, results of operations and cash flows.
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 previously commenced an industry-wide enforcement initiative regarding New Source Review and other laws. The EPA initiative, which includes sending numerous refineries information requests pursuant to Section 114 of the Clean Air Act, appears to target many items that the industry has historically considered routine repair, replacement, maintenance or other activity exempted from the New Source Review requirements.
The Company has responded to 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 ten years. The Company believes that any costs to respond to New Source Review issues at those refineries prior to our purchase are the responsibility of the prior owners and operators of those facilities.
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.
Environmental matters are as follows:
Port Arthur, Lima, Memphis and Delaware City 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 in 1941 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.
The Delaware City purchase agreement provides that, subject to certain limitations, the seller shall indemnify the Company against certain environmental liabilities and costs to the extent related to, arising out of,
resulting from, or occurring during the ownership, operation or use of the refinery assets prior to the closing. Conversely, the Company has agreed to indemnify the seller against environmental liabilities and costs to the extent related to, arising out of, resulting from, or occurring during the period of time after the closing. These indemnities are generally subject to a cap of $50 million, with the exception of certain matters, including outstanding consent orders involving, and ongoing cleanup projects at, the refinery, which are subject to an aggregate cap of $800 million. In addition, the Company has agreed to assume responsibility under an existing consent order which requires the installation of air pollution control technology to the refinery’s coker and fluid catalytic cracker by 2006. Our current estimate for the scrubbers and modifications to the refinery associated with the installations will be $263 million. There can be no assurances that the seller will satisfy its obligations under this agreement, or that significant liabilities will not arise with respect to the matters the Company has assumed or for which the Company is indemnifying the seller.
There can be no assurances that these environmental liabilities and/or costs or expenditures to comply with environmental laws will not have a material adverse effect on our current or future financial condition, results of operations, and cash flow.
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 entered into a consent order setting forth the agreement for investigation of the site. 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. The project is currently underway and is expected to be completed in 2005.
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 over a number of years at 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 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 Company and the purchaser of the retail division assumed certain preclosure environmental obligations. The bankruptcy discussed below may have an affect on these obligations.
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, subject to certain defenses, 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, subject to certain defenses, will likely remain jointly and severally liable on the assigned leases.
Of the remaining 478 former retail sites not sold in the 1999 transaction described above, the Company has sold all but 4 stores. The Company is actively seeking to sell these remaining properties. The Company generally retained the remediation obligations for sites that were sold with presale contamination. Typically, the Company agreed to retain liability for all of these sites until an appropriate state regulatory agency issued 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 108 of the former retail sites that were not sold in the 1999 transaction.
During the period from the beginning of 1999 through December 31, 2004, the Company expended approximately $25 million to satisfy all the environmental cleanup obligations of the former retail marketing business and, as of December 31, 2004, had $21.6 million accrued to satisfy those obligations in the future.
A portion of the $21.6 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.
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 until December 2005 up to a maximum of $1.5 million. In 2004 these terminals were sold to another third party except for the Hammond, Indiana terminal which we repurchased and continue to retain responsibility for environmental matters.
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 to foreclose the land farm in accordance with the permit’s closure procedures is not material.
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, 2004, the Company had accrued a total of approximately $96 million (December 31, 2003-$98 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 adverse effect on the Company’s operating results and cash flows when resolved in a future period.
Environmental Product Standards
The Company expects to incur costs in the aggregate of approximately $780 million, of which $412 million has been incurred as of December 31, 2004, 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, with the phasing beginning on January 1, 2004. The Company currently has the capability to produce gasoline under the new sulfur standards at all of our refineries, except Lima. We expect to have the capability to produce gasoline under the new sulfur standards at the Lima refinery in the third quarter 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 $345 million, of which $314 million had been incurred as of December 31, 2004. Future revisions to this cost estimate, and the estimated time during which costs are incurred, may be necessary.
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. In May 2004, the EPA promulgated its non-road diesel regulations, which will require a reduction in the sulfur content of non-road diesel fuel. The final ruling limits the sulfur levels in non-road diesel to 500 ppm by 2007 and 15 ppm by 2010. Our Port Arthur, Memphis and Delaware City refinery’s produce diesel fuel which complies with the current low-sulfur specifications of 500 ppm. The Lima refinery does not currently produce diesel fuel to low-sulfur specifications, the Company expects the refinery to produce diesel with low-sulfur standards in the second quarter of 2006. The Company estimates that capital expenditures required to comply with the diesel standards at all four refineries in the aggregate through 2006 is approximately $435 million, of which $98 million had been incurred as of December 31, 2004. Future revisions to the cost estimate, and the estimated time during which costs are incurred, may be necessary. The projected investment will be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005.
As of December 31, 2004, the Company had outstanding contract commitments of $183 million related to the design and construction activity at the refineries for the Tier 2 gasoline and low-sulfur diesel compliance.
Other Commitments
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.
The Company currently has a crude oil supply agreement with MSCG through which the Company 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, the Company 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. The Company relies 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 standard industry terms. This supply agreement with MSCG expires in May 2006.
Long-Term Crude Oil Contract. The Company is party to a long-term crude oil supply agreement with an affiliate of PEMEX, which currently supplies approximately 186,000 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.
In conjunction with the acquisition of the Delaware City refinery, the Company entered into an agreement, effective May 1, 2004, with the Saudi Arabian Oil Company for the supply of 105,000 bpd of crude oil, however, due to certain quota restrictions the current supply is 85,000 bpd. The agreement has terms extending to April 30, 2005, with automatic one-year extensions thereafter unless terminated at the option of either party. The crude oil is priced by a market-based formula as defined in the agreement.
Other Purchase Obligations. The Company enters 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. The Company also enters 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.
The Company also has certain contracts related to the fuel supply for our refineries. These 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. The Company purchases 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 the Company is required to purchase minimum volumes on a quarterly basis or make payments equal to what would be due for these minimum volumes. The Company made payments totaling $83 million in 2004 in relation to this hydrogen supply contract and the Company would need to make minimum payments of approximately $36 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.
The Company also contracts for certain services under long-term contracts, some of which have minimum contract volumes or dollar amounts. The Company has 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 June 2007. The Company is 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 the Company made payments totaling $9 million in 2004, and would need to make minimum payments of approximately $6 million on an annual basis if they did not meet any of our committed volumes. The Company also has a ten-year contract expiring in 2011 for the operation and maintenance of a petroleum coke handling system at our Port Arthur refinery. The Company is obligated to meet certain minimum dollar amounts related to petroleum coke handling fees on an annual basis. Under this contract minimum payments would equate to approximately $7 million on an annual basis.
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 June 2021.
Sales Obligations. The Company enters into various contracts to provide certain refined products in the normal course of business. Typically these contracts are short term, one to several months. The Company expects to be able to fulfill all of these sales obligations.
24. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The Company’s results of operations by quarter for the years ended December 31, 2004 and 2003 were as follows (in millions, except per share amounts):
a) Operating income included refinery restructuring and other charges of $4.6 million, $4.7 million, $1.1 million and $9.1 million in the quarters ended March 31, June 30, September 30 and December 31, respectively. Net income also included a loss on extinguishment of debt of $3.6 million in the quarter ended June 30.
a) Net sales and operating revenue for all quarters except the quarter ended December 31, 2003 have been restated to reflect the fourth quarter 2003 application of 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. The reclassification had no effect on previously reported operating income or net income (loss). Net sales and operating revenues were originally reported as $2,376.3 million, $2,619.9 million and $2,878.2 million in the quarters ended March 31, June 30 and September 30, respectively.
b) Operating income included refinery restructuring and other charges of $15.0 million, $0.7 million, $2.9 million and $19.9 million in the quarters ended March 31, June 30, September 30 and December 31, respectively. Net income (loss) also included a loss on extinguishment of debt of $7.0 million, $3.4 million and $17.1 million in the quarters ended March 31, June 30 and December 31, respectively.
25. SUBSEQUENT EVENTS
The Company announced on January 27, 2005 that its Board of Directors has declared a dividend of $.02 per share payable on March 15, 2005 to shareholders of record on March 1, 2005.
PREMCOR INC.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY BALANCE SHEETS
(in millions)
See accompanying note to non-consolidated financial statements.
PREMCOR INC.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY STATEMENTS OF OPERATIONS
(in millions)
See accompanying note to non-consolidated financial statements.
PREMCOR INC.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
PARENT COMPANY ONLY STATEMENTS OF CASH FLOWS
(in millions)
See accompanying note to non-consolidated financial statements.
PREMCOR INC.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
NOTE TO NON-CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2004, 2003 and 2002
1. BASIS OF PRESENTATION
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, 2004, 2003 and 2002, Premcor Inc.’s non-consolidated operations include 100% equity interest in Premcor USA Inc. and a 100% equity interest in Opus Energy Risk Limited.
In 2004, Premcor Inc. paid a $0.02 per share dividend to all stockholders of record on December 1, 2004. Premcor Inc. did not pay any dividends to stockholders in 2003 and 2002.
For further information, refer to the consolidated financial statements, including the notes thereto, included in this Annual Report on Form 10-K.
PREMCOR INC. AND SUBSIDIARIES
THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
(in millions)
(a) This transferred balance in 2003 is related to the on-going environmental remediation of the closed refinery sites.
SIGNATURES
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 and Controller
(principal accounting officer)
Date: March 4, 2005
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.
SIGNATURES
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.
THE PREMCOR REFINING GROUP INC.
(Registrant)
By:
/S/ DENNIS R. EICHHOLZ
Dennis R. Eichholz
Senior Vice President and Controller
(principal accounting officer)
Date: March 4, 2005
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.
Signature
Title
Date
/S/ JEFFERSON F. ALLEN
Jefferson F. Allen
Chief Executive Officer and Director (principal executive officer)
March 4, 2005
/S/ HENRY M. KUCHTA
Henry M. Kuchta
President, Chief Operating Officer and Director
March 4, 2005
/S/ JOSEPH D. WATSON
Joseph D. Watson
Senior Vice President, Chief Financial Officer and Director (principal financial officer)
March 4, 2005
/S/ DENNIS R. EICHHOLZ
Dennis R. Eichholz
Senior Vice President and Controller (principal accounting officer)
March 4, 2005
/S/ MICHAEL D. GAYDA
Michael D. Gayda
Senior Vice President, General Counsel, Secretary and Director
March 4, 2005
/S/ JAMES R. VOSS
James R. Voss
Senior Vice President, Chief Administrative Officer and Director
March 4, 2005