10-Q 1 d10q.txt FORM 10-Q (FOR THE PERIOD 09-30-2001) -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission file number 333-92871-02 SABINE RIVER HOLDING CORP. (Exact name of registrant as specified in its charter) Delaware 43-1857408 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1801 S. Gulfway Drive Office No. 36 77640 Port Arthur, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code (409) 982-7491 Indicate by check mark whether the registrant:(1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ --- Number of shares of registrant's common stock, $.01 par value, outstanding as of October 31, 2001: 6,818,182 -------------------------------------------------------------------------------- Sabine River Holding Corp. Form 10-Q September 30, 2001 Table of Contents PART I. FINANCIAL INFORMATION Item 1. Financial Statements Independent Accountants' Report ................................. 1 Consolidated Balance Sheets as of December 31, 2000 and September 30, 2001 ............................................. 2 Consolidated Statements of Operations for the Three- and Nine-Month Periods Ended September 30, 2000 and 2001 ........... 3 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2000 and 2001 .................................... 4 Notes to Consolidated Financial Statements ...................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................... 11 PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K ................................ 21 Signature ....................................................... 22 FORM 10-Q - PART I ITEM 1. FINANCIAL STATEMENTS INDEPENDENT ACCOUNTANTS' REPORT ------------------------------- To the Board of Directors of Sabine River Holding Corp.: We have reviewed the accompanying consolidated balance sheet of Sabine River Holding Corp. and subsidiaries (the "Company") as of September 30, 2001, the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2000 and 2001, and consolidated statements of cash flows for the nine-month periods then ended. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2000, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 13, 2001, we expressed an unqualified opinion on those consolidated financial statements. Deloitte & Touche LLP St. Louis, Missouri November 7, 2001 1 SABINE RIVER HOLDING CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (dollars in millions, except share data)

The accompanying notes are an integral part of these financial statements. 2 SABINE RIVER HOLDING CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited, dollars in millions)

The accompanying notes are an integral part of these financial statements. 3 SABINE RIVER HOLDING CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited, dollars in millions)

The accompanying notes are an integral part of these financial statements. 4 FORM 10-Q - PART I ITEM 1. FINANCIAL STATEMENTS (continued) Sabine River Holding Corp. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) September 30, 2001 (tabular dollar amounts in millions of U.S. dollars) 1. Basis of Preparation Sabine River Holding Corp. is owned 90% by Premcor Inc. and 10% by Occidental Petroleum Corporation ("Occidental"). Premcor Inc. is owned principally by Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates ("Blackstone") and Occidental. Sabine River Holding Corp. is the 1% general partner of Port Arthur Coker Company L.P., a limited partnership ("Port Arthur Coker Company"), and the 100% owner of Neches River Holding Corp. ("Neches River Holding"), which is the 99% limited partner of Port Arthur Coker Company. Port Arthur Coker Company is the 100% owner of Port Arthur Finance Corp. ("Port Arthur Finance"). The accompanying unaudited consolidated financial statements of Sabine River Holding Corp. and subsidiaries (the "Company") are presented pursuant to the rules and regulations of the Securities and Exchange Commission in accordance with the disclosure requirements for Form 10-Q. In the opinion of the management of the Company, the unaudited consolidated financial statements reflected all adjustments (consisting only of normal recurring adjustments) necessary to fairly state the results for the interim periods presented. Operating results for the three- and nine-month periods ended September 30, 2001 were not necessarily indicative of the results that may be expected for the year ended December 31, 2001. These unaudited financial statements should be read in conjunction with the audited financial statements and notes included in the Company's 2000 Annual Report on Form 10-K. 2. New Accounting Standards In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133" which delayed the effective date of SFAS No. 133 for one year to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138 "Accounting for Certain Derivative Instruments and Hedging Activities" which amended various provisions of SFAS No. 133. The Company adopted SFAS No. 133, 5 as amended, effective January 1, 2001. The adoption of SFAS No. 133 did not have a material impact on the financial position or results of operations of the Company. On July 20, 2001, the FASB issued SFAS No. 141 "Business Combinations" and SFAS No. 142 "Goodwill and Other Intangible Assets." SFAS No. 141, which became effective on issuance, requires business combinations initiated after June 30, 2001 be accounted for using the purchase method of accounting and addresses the initial recording of intangible assets separate from goodwill. SFAS No. 142 requires that goodwill and intangible assets with indefinite lives will not be amortized, but will be tested at least annually for impairment. Intangible assets with finite lives will continue to be amortized. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The Company does not expect the implementation of these standards to have a material effect on its financial position and results of operations. In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset Retirement Obligations". SFAS No. 143 addresses when a liability should be recorded for asset retirement obligations and how to measure this liability. The initial recording of a liability for an asset retirement obligation will require the recording of a corresponding asset, which will be required to be amortized. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company is in the process of evaluating the impact of the adoption of this standard on its financial position and results of operations. 3. Inventories The carrying value of inventories consisted of the following: December 31, September 30, 2000 2001 ----------- ----------- Crude oil ........................... $ 44.6 $ 67.8 Blendstocks ......................... 0.7 1.0 Warehouse stock ..................... - 0.2 Inventory write-down to market ...... - (8.7) --------- -------- $ 45.3 $ 60.3 ========= ======== As of September 30, 2001, the Company recorded an $8.7 million inventory valuation adjustment to write the carrying value of crude oil and blendstock inventories down to market. This write-down to market was included in "Cost of sales". The carrying value of crude oil, refined product, and blendstock inventories approximated market as of December 31, 2000. 4. Property, Plant and Equipment, Net The Company began depreciating its fixed assets in accordance with Company policy in January 2001. 5. Other Assets Other assets consisted of the following: December 31, September 30, 2000 2001 ----------- ---------- Deferred financing costs ........... $ 18.0 $ 15.0 6 Environmental permits ...................... 1.4 1.4 PMI long term crude oil supply agreement ... 0.8 0.8 ---------- --------- $ 20.2 $ 17.2 ========== ========= Amortization of deferred financing costs for the three- and nine-month periods ended September 30, 2001 was $0.8 million (2000 - $0.8 million) and $2.3 million (2000 - $1.9 million), respectively, and was included in "Interest and finance expense." During 2001, related to the adoption of SFAS No. 133, the Company wrote-off deferred financing costs associated with an interest rate cap on its bank senior loan agreement of $0.7 million. 6. Capital Contributions Receivable In August 1999, Blackstone and Occidental signed capital contribution agreements totaling $135.0 million for the purpose of funding the construction of the heavy oil processing facility. Blackstone agreed to contribute $121.5 million and Occidental agreed to contribute $13.5 million. As of September 30, 2001, Blackstone had contributed $109.6 million and Occidental had contributed $12.2 million. The obligation to fund the capital contributions was contingent upon the Company borrowing funds under the bank senior loan agreement. In the third quarter, the Company decided not to borrow the remaining loan commitment under the bank senior loan agreement, and consequently, forfeited the remaining capital contributions. Accordingly, as of September 30, 2001, the remaining unfunded capital contributions of $13.2 million were no longer recorded as a capital contribution receivable. The ability to draw any remaining funds under the bank senior loan agreement and receive the remaining capital contributions expired in September of 2001 upon the achievement of substantial reliability of the heavy oil upgrade facility, as defined for purposes of the financing documents. 7. Interest and Finance Expense Interest and finance expense consisted of the following: For the Three Months For the Nine Months Ended September 30, Ended September 30, --------------------- --------------------- 2000 2001 2000 2001 ------- ------- -------- ------- Interest expense ...... $ 14.7 $ 14.8 $ 39.9 $ 46.5 Financing costs ....... 1.2 1.9 2.9 5.2 Capitalized interest .. (14.7) (0.1) (39.9) (0.9) ------- ------- -------- ------- $ 1.2 $ 16.6 $ 2.9 $ 50.8 ======= ======= ======== ======= Cash paid for interest for the three-and nine-month periods ended September 30, 2001 was $23.1 million (2000 - $ 21.4 million) and $55.3 million (2000 - $ 42.1 million), respectively. 8. Income Taxes The Company made net cash income tax payments during the three-month and nine-month periods ended September 30, 2001 of $13.0 million (2000 - none) and $13.0 million (2000 - none), respectively. 9. Port Arthur Coker Company Condensed Consolidated Financial Information 7 Sabine River Holding Corp directly owns a 1% general partnership interest in Port Arthur Coker Company and through its wholly-owned subsidiary, Neches River Holding, owns the remaining 99% limited partnership interest. Port Arthur Finance, which is wholly owned by Port Arthur Coker Company, issued debt on Port Arthur Coker Company's behalf. Both the Company and Neches River Holding fully and unconditionally guarantee the debt issued by Port Arthur Finance. Port Arthur Coker Company is the only company with operations in the consolidated financial statements of the Company. Neither Neches River Holding nor Port Arthur Finance have independent operations. Port Arthur Coker Company's condensed consolidated financial information consisted of the following: Consolidated statement of operations:

Consolidated balance sheet information:

In the third quarter, Port Arthur Coker Company distributed cash of $12.9 million to Sabine River Holding Corp. and $0.1 million to Neches River Holding. 10. Related Party Transactions Port Arthur Coker Company and The Premcor Refining Group Inc. Port Arthur Coker Company and The Premcor Refining Group Inc. (the "Premcor Refining Group") have entered into certain agreements associated with the ongoing operations of the coker, hydrocracking, and sulfur removal facilities of the Port Arthur Coker Company and the Premcor Refining Group's Port 8 Arthur refinery. Port Arthur Coker Company's general partner Sabine River Holding Corp. and the parent company of the Premcor Refining Group, Premcor USA Inc., are subsidiaries of Premcor Inc. Related party receivables, payables, revenues, cost of sales, and operating expenses from these agreements were as follows: As of September 30, 2001, Port Arthur Coker Company had an outstanding receivable from the Premcor Refining Group of $85.7 million (December 31, 2000 - $50.4 million) and a payable to the Premcor Refining Group of $36.3 million (December 31, 2000 - $28.0 million) related to ongoing operations. As of September 30, 2001, Port Arthur Coker Company had a note payable to the Premcor Refining Group of $7.5 million (December 31, 2000 - $7.0 million) related to construction management services of which $4.9 million (December 31, 2000 - $4.9 million) was accounted for as a long-term liability and the remainder as a current liability. Port Arthur Coker Company generated $466.2 million and $1,500.9 million in revenues for the three-and nine-month periods ended September 30, 2001, respectively, primarily from the sales of finished and intermediate refined products and crude oil to the Premcor Refining Group. Port Arthur Coker Company incurred $23.9 million and $80.7 million in costs of sales for the three-month and nine-month periods ended September 30, 2001, respectively. These costs were associated with the purchases of feedstocks and hydrogen and the incurrence of pipeline tariffs from the Premcor Refining Group for the three-and nine-month periods ended September 30, 2001. Port Arthur Coker Company recorded operating expenses of $10.4 million and $43.8 million respectively, for the three-and nine-month periods ended September 30, 2001. These operating expenses related to services provided by the Premcor Refining Group and lease operating expenses under the various agreements between the Premcor Refining Group and Port Arthur Coker Company. 11. Commitments and Contingencies In July 1999, Port Arthur Coker Company entered into a contract with Foster Wheeler USA for the engineering, procurement and construction of the heavy oil processing facility. Under this construction contract, Foster Wheeler USA engineered, designed, procured equipment for, constructed, tested, and oversaw start-up of the heavy oil processing facility and its integration with the Port Arthur refinery of the Premcor Refining Group. Under the construction contract, Port Arthur Coker Company paid Foster Wheeler USA a fixed price of approximately $544 million. The contract has provisions whereby Foster Wheeler USA will pay Port Arthur Coker Company up to $145 million in damages for delays in achieving mechanical completion or guaranteed reliability, based on a defined formula. As of September 30, 2001 the heavy oil processing facility had reached mechanical completion and guaranteed reliability. Tier 2 Motor Vehicle Emission Standards. In February 2000, the Environmental Protection Agency ("EPA") promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the sulfur content of gasoline at any refinery not exceed 30 ppm during any calendar year by January 1, 2006. These requirements will be phased in beginning on January 1, 2004. Modifications will be required to the Company's facility as a result of the Tier 2 standards. Based on preliminary estimates, the Company believes that compliance with the new Tier 2 gasoline specifications will require capital expenditures in the aggregate through 2005 in a range of $20 million to $25 million. More than 90% of the projected investment is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003. Low Sulfur Diesel Standards. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Refining industry groups have filed two lawsuits, which may delay implementation of the on-road diesel rule beyond 2006. In its release, the EPA 9 estimated that the overall cost to fuel producers of the reduction in sulfur content would be approximately $0.04 per gallon. The EPA has also announced its intention to review the sulfur content in diesel fuel sold to off-road consumers. If regulations are promulgated to regulate the sulfur content of off-road diesel, the Company expects the sulfur requirement to be either 500 ppm, which is the current on-road limit, or 15 ppm, which will be the future on-road limit. If the new off-road standard is 500 ppm, the Company will not need to incur any capital expenditures to comply with the diesel standards because the Port Arthur refinery currently meets the 500 ppm specification. The Company would thus continue to have a market for its current diesel production at Port Arthur, albeit a smaller and lower priced market, and therefore could elect not to make any capital expenditures necessary to comply with the new on-road standard. Depending upon the standard promulgated for off-road diesel, if any, and the compliance strategy the Company adopts, the Company estimates that its capital expenditure cost in the aggregate through 2006 of complying with the diesel standards utilizing existing technologies may range from zero to $175 million. Approximately 90% of the projected investment, if necessary, is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. The decision of which strategy to pursue will be made in conjunction with the Premcor Refining Group. 10 ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward-Looking Statements Certain statements in this document are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to the safe harbor provisions of this legislation. Words such as "expects," "intends," "plans," "projects," "believes," "estimates," "will" and similar expressions typically identify such forward-looking statements. Even though we believe our expectations regarding future events are based on reasonable assumptions, forward-looking statements are not guarantees of future performance. Important factors that could cause actual results to differ materially from those contained in our forward-looking statements include, among others, changes in: . Industry-wide refining margins; . Crude oil and other raw material costs, embargoes, industry expenditures for the discovery and production of crude oil, and military conflicts between, or internal instability in, one or more oil-producing countries, and governmental actions; . Market volatility due to world and regional events; . Availability and cost of debt and equity financing; . Labor relations; . U.S. and world economic conditions; . Supply and demand for refined petroleum products; . Reliability and efficiency of our operating facilities which are effected by such potential hazards as equipment malfunctions, plant construction/repair delays, explosions, fires, oil spills and the impact of severe weather; . Actions taken by competitors which may include both pricing and expansion or retirement of refinery capacity; . The enforceability of contracts; . Civil, criminal, regulatory or administrative actions, claims or proceedings and regulations dealing with protection of the environment; . Other unpredictable or unknown factors not discussed. Because of all of these uncertainties, and others, you should not place undue reliance on our forward-looking statements. 11 Overview We were formed to develop, construct, own, operate, and finance a heavy oil processing facility that includes a new 80,000 barrel per stream day delayed coking unit, a 35,000 barrel per stream day hydrocracker unit, and a 417 long tons per day sulfur complex that are operated in conjunction with the refining assets at the Port Arthur, Texas refinery of an affiliate, The Premcor Refining Group Inc. This heavy oil processing facility along with modifications made by Premcor Refining Group at their Port Arthur refinery allows the refinery to process primarily lower-cost, heavy sour crude oil. We were incorporated in May of 1999 and were capitalized in August of 1999. We are the 1% general partner of Port Arthur Coker Company L.P. and the 100% owner of Neches River Holding Corp., which is the 99% limited partner of Port Arthur Coker Company. We are owned 90% by Premcor Inc. and 10% by Occidental Petroleum Corporation. In January 2001, we began full operation of our newly constructed coking, hydrocracking, and sulfur removal units. Premcor Refining Group began construction of these new units in 1998. In the third quarter of 1999, we purchased a portion of the work in progress and certain other related assets from Premcor Refining Group. We financed and completed the construction of the heavy oil processing facility. Start-up of our units occurred in stages, with the sulfur removal units and the coker unit beginning operations in December 2000 and the hydrocracker unit beginning operations in January 2001. Substantial reliability, as defined in our financing documents, of the heavy oil processing facility was achieved as of September 30, 2001. Additional information regarding the construction of the heavy oil processing facility is included in our Annual Report on Form 10-K for the year ended December 31, 2000. We entered into agreements with Premcor Refining Group associated with the operations of our heavy oil processing facility and Premcor Refining Group's Port Arthur refinery, including supply and services, product purchase, and ancillary unit lease agreements as described below: . We lease 100% of Premcor Refining Group's crude, vacuum and other ancillary units for a quarterly lease fee, which is reported as an operating expense. Premcor Refining Group utilizes through the processing arrangement discussed below approximately 20%, or 50,000 barrels per day ("bpd") of crude distillation capacity and this is recorded as revenue. As a result of this arrangement, we are utilizing approximately 80%, or 200,000 bpd, of the Port Arthur refinery's crude distillation capacity. . Our production consists of intermediate refined products and lesser volumes of finished light products, petroleum coke and sulfur, all of which are sold at fair market value to Premcor Refining Group for either further processing into higher value finished refined products or immediate sale to third parties. . Premcor Refining Group utilizes a portion of the capacity of our heavy oil processing facility for a monthly processing fee. This fee is recorded as an offset to operating expenses. . We pay Premcor Refining Group a fee for providing certain services and supplies, including employee, maintenance and energy costs. These fees are included in operating expenses. We also pay Premcor Refining Group for pipeline access and the use of their Port Arthur refinery dock. These fees are included in cost of sales. Factors Affecting Operating Results 12 Our earnings and cash flow from operations are primarily affected by the relationship between intermediate and refined product prices and the prices for crude oil. The cost to acquire feedstocks and the price for which intermediate and refined products are ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. While our net sales and operating revenues fluctuate significantly with movements in industry crude oil prices, such prices do not generally have a direct long-term relationship to net earnings. Crude oil price movements may impact net earnings in the short term because of fixed price crude oil purchase commitments. The effect of changes in crude oil prices on our operating results is influenced by the rate at which the prices of refined products adjust to reflect such changes. Feedstock, intermediate and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the price of intermediate and refined products have historically been subject to wide fluctuations. 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 an increased demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In order to assess our operating performance, we compare our gross margin against an industry gross margin benchmark. The industry gross margin is calculated by assuming that three barrels of benchmark light sweet crude oil is converted, or cracked, into two barrels of conventional gasoline and one barrel of high sulfur diesel fuel. This is referred to as the 3/2/1 crack spread. Since we calculate the benchmark margin using the market value of U.S. Gulf Coast gasoline and diesel fuel against the market value of West Texas Intermediate crude oil, we refer to the benchmark as the Gulf Coast 3/2/1 crack spread, or simply, the Gulf Coast crack spread. The Gulf Coast crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery situated on the Gulf Coast would earn assuming it produced and sold the benchmark production of conventional gasoline and high sulfur diesel fuel. The Port Arthur refinery configuration is unique and has logistical advantages to a benchmark refinery, and as a result, our gross margin per barrel of throughput will differ from the benchmark crack spread. Of our total feedstocks, we are able to process up to 80% heavy sour crude oil that has historically cost less than West Texas Intermediate crude oil. We measure the cost advantage of heavy crude oil by calculating the spread between the value of Maya crude oil produced in Mexico to the value of West Texas Intermediate crude oil because Maya is our predominant heavy sour crude oil. The cost advantage of sour crude oil is measured by calculating the spread between the value of West Texas Sour crude oil to the value of West Texas Intermediate crude oil. The sales value of our production is also an important consideration in understanding our results. Our product slate is substantially comprised of intermediate refined products that are sold to Premcor Refining Group for further processing. Since intermediate refined products carry a value less than finished refined products, our typical product slate carries a sales value lower than that for the products used to calculate the Gulf Coast crack spread. 13 Our operating cost structure is also important to our profitability. Major operating costs include energy, employee labor, lease fees, maintenance, including contract labor, and environmental compliance. By far, the predominant variable cost is energy and the most important benchmark for energy costs is the value of natural gas. Consistent, safe and reliable operations at our heavy oil processing facility and at the Port Arthur refinery in general is a key to our financial performance. Unplanned downtime of refinery assets generally results in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that considers such things as margin environment, availability of resources to perform the needed maintenance and feedstock logistics. The nature of our business leads us to maintain a substantial investment in petroleum inventories. As petroleum feedstocks and intermediate products are essentially commodities, we have no control over the changing market value of our investment. Because most of our titled inventory is valued under the first-in, first-out costing method, price fluctuations on our titled inventory can have material effects on our financial results. Our petroleum inventories consist principally of crude oil since we sell all of our production to Premcor Refining Group under the product purchase agreement. We have a long-term crude oil supply agreement with PMI Comercio International S.A. de C.V. that provides us with a stable and secure supply of Maya crude oil. An important feature of this agreement is a mechanism intended to provide us with a minimum average coker gross margin and moderate fluctuations in our coker gross margins during the eight-year period from April 1, 2001. This mechanism uses a formula to approximate quarterly coker gross margins and provides for discounts or premiums on our crude oil purchases from PMI in subsequent quarters based on the following methodology. Quarterly formula coker gross margins that exceed the minimum average coker gross margin of $15 per barrel result in a quarterly surplus, while quarterly formula coker gross margins that fall short of the minimum average coker gross margin of $15 per barrel result in a quarterly shortfall. The contract provides: . In the case of a quarterly shortfall amount, the amount of such shortfall, less the amount, if any, by which cumulative surpluses exceed cumulative shortfalls for prior quarters, will be taken as a discount on our crude oil purchases from PMI in the succeeding quarter; provided, however, that in any given quarter the discount we receive may not exceed $30 million regardless of the magnitude of the net shortfalls accumulated. Any such "excess discount" will be carried forward and applied in subsequent quarters; and . In the case of a quarterly surplus amount, the lesser of the amounts of such surplus and the amount, if any, by which cumulative shortfalls exceed cumulative surpluses for prior quarters, will be paid as a premium on our crude oil purchases from PMI in the succeeding quarter; provided, however, that in any given quarter the premium we pay may not exceed $20 million. Any such "excess premium" will be carried forward and applied in subsequent quarters. As of September 30, 2001, as a result of the favorable market conditions related to the value of Maya crude oil versus the refined products derived from it, the amount of cumulative quarterly surpluses exceeded cumulative quarterly shortfalls by $112.5 million. As a result, to the extent we experience quarterly shortfalls in formula coker gross margins going forward, the price we pay for Maya crude oil in succeeding quarters will not be discounted unless cumulative surpluses are offset by cumulative shortfalls. Also, because the amount of any premium we pay on the price of Maya crude oil is limited to the amount of net cumulative shortfalls in prior quarters, we will not be required to pay a premium in succeeding quarters in excess of the net cumulative shortfall. In other words, we retain the benefit of net cumulative surpluses in our formula coker gross margins in excess of the support amount of $15 per barrel. Industry Outlook Our earnings depend largely on refining industry margins, which have been and continue to be volatile. The cost of crude oil and intermediate feedstocks we purchase and the prices of refined products we sell have fluctuated widely in the past. Crude oil, intermediate feedstocks and refined product prices depend on numerous factors beyond our control. While it is impossible to predict refining margins due to the uncertainties associated with global crude oil supply and domestic demand for refined products, we believe that refining margins for United States refineries will generally remain above those experienced in the period 1995 through 2000 as growth in demand for refining products in the United States, particularly transportation fuels, continues to exceed the ability of domestic refiners to increase capacity. The review of 2001 year-to-date refining industry margins summarized below gives some indication of the volatility that exists in the industry. Over the first five months of 2001, the market price of distillate relative to crude oil was above average due to low industry inventories and strong consumer demand brought about by the relatively cold winter weather in the northeast United States and eastern Canada and high natural gas prices which led to an increase in industrial users switching from natural gas to fuel oil. In addition, gasoline margins were above average, primarily because substantial scheduled and unscheduled refinery maintenance turnaround activity in the United States in late 2000 and early 2001 resulted in inventories that did not 14 increase in a manner typically experienced during the winter. The increased demand for refined products due to the relatively cold winter and the decreased supply due to high turnaround activity, led to increasing refining margins during the first five months of 2001. As a result, the average margin achieved over the first half of 2001 was approximately twice the average for the first six month period over the last four years. During the ensuing four months of 2001 the refining markets were extremely volatile. During June and July 2001, refining margins declined from the highs experienced earlier in the year. This decline was largely the result of increasing product inventories due to high refinery production rates, excessive product import levels and slowing consumer demand. The healthy refining margins realized in early 2001 led refiners to postpone scheduled turnarounds in order to maximize utilization rates. Import levels increased because of high domestic product prices relative to foreign product prices. Growth in consumer demand slowed as a result of high prices and a weakening economy. However, refining margins strengthened in August due to other refiners' unplanned downtime and decisions to undertake delayed maintenance turnarounds and due to lower product imports. The terrorist attacks on September 11th created a downward spiral of refining margins, lowering demand for distillates, in particular jet fuel, and gasoline. The lower demand has led to higher gasoline and distillate inventories. Average discounts for sour and heavy sour crude oil increased in the first nine months of 2001 from already favorable 2000 levels due to increasing worldwide production of sour and heavy sour crude oil relative to production of light sweet crude oil, coupled with continuing demand for light sweet crude oil. In April 2001, the discount for heavy sour crude oil versus West Texas Intermediate widened to more than double historical averages. Although the heavy sour crude oil discount to West Texas Intermediate crude oil has narrowed from these record highs, the discount continues to exceed historic levels. Sweet crude oil continues to trade at a premium to West Texas Sour due to continued high demand for sweet crude oil resulting from the more stringent fuel specifications implemented in the United States and Europe and the higher margins for light products. In the near term, we anticipate that refining margins will remain at slightly depressed levels as the country and the world wait to see what will happen in the war against terrorism both here in the United States and in the Middle East. The attacks and the subsequent retaliation have raised questions about gasoline and distillate demand and crude oil supply, particularly the supply from the Middle East. Additionally, the depth of economic recession in the United States, and the decline in consumer spending confidence and the weak industrial sector will curtail demand for petroleum products. In the long-term, we expect refined product supply and demand balances to tighten worldwide as growth in demand for refined products is expected to exceed net capacity growth, particularly for transportation fuels. A portion of the supply growth due to new capacity built by foreign refiners and the continued de-bottlenecking and expansion of existing refineries will likely be offset by more stringent environmental specifications and refinery closures resulting from capital requirements to meet worldwide low-sulfur gasoline and diesel specifications. We expect that the worldwide growth in production of sour and heavy sour crude oil will continue to exceed increases in the production of light sweet crude oil and that this, when coupled with the continuing demand for light sweet crude oil, will support a wide spread between the prices of light sweet and heavy sour crude oil. In summary, we believe refining margins in the United States will benefit from continuing favorable supply and demand fundamentals. 15 Results of Operations The following table reflects our financial and operating highlights for the three- and nine-month periods ended September 30, 2000 and 2001.

(1) Earnings before interest, income taxes, depreciation, and amortization

17 Overview. Net income increased $17.6 million to $14.8 million in the third quarter of 2001 from a net loss of $2.8 million in the corresponding period in 2000. Operating income increased $39.0 million to $37.4 million in the third quarter of 2001 from a loss of $1.6 million in the corresponding period in 2000. Net income increased $129.6 million to $123.5 million in the first nine months of 2001 from a net loss of $6.1 million in the corresponding period in 2000. Operating income increased $239.8 million to $236.0 million in the first nine months of 2001 from a loss of $3.8 million in the corresponding period in 2000. The operating results for 2001 compared to 2000 were affected by the completion and operation of the heavy oil upgrade project. See "Factors Affecting Operating Results" for a detailed discussion of how the completion of the heavy oil upgrade project has affected our results. Net Sales and Operating Revenue. Net sales and operating revenues were $461.3 million and $1,506.0 million in the third quarter and first nine months of 2001, respectively. Gross Margin. Gross margin was $71.0 million and $368.4 million in the third quarter and first nine months of 2001, respectively. The gross margin for the third quarter reflected lower Gulf Coast crack spreads, narrowing heavy sour crude oil differentials, and operational issues related to a lightning strike to the crude unit in May of 2001. The first nine months of 2001 reflected strong market conditions in the first half of the year partially offset by operational issues and slowing market conditions in the third quarter. For the first nine months of 2001, our gross margin benefited from the strong crude oil discounts reflected in the significant differentials between WTI and sour and heavy sour crude oil and improvements to refining margins as reflected in the Gulf Coast crack spread. Crude oil throughput rates averaged 177,100 bpd and 180,200 bpd, of the available 200,000 bpd, in the third quarter and first nine months of 2001, respectively. Crude oil throughput rates in the third quarter of 2001 were restricted due to a lightning strike in early May and a ten day shutdown of the crude unit in July to repair the damage caused by the lightning strike. Both the crude unit rate restriction and subsequent downtime for repairs lowered feedstock throughput rates by approximately 22,000 bpd during the third quarter. Crude oil throughput rates in the first nine months of 2001 were restricted due to the lightning strike plus restrictions on the crude unit as units downstream were in start-up operations during the first quarter. The crude unit throughput rates were close to capacity during the months of August and September of 2001. The 80,000 bpd coker unit averaged approximately 70,300 bpd and 73,900 bpd of throughput during the third quarter and first nine months of 2001, respectively. Overall throughput rates were lower than capacity due to the restrictions from the lightning strike, a planned maintenance turnaround of the Premcor Refining Group's alkylation unit and the fine tuning of operations associated with the start-up of our coker and hydrocracker units. Operating Expenses. Operating expenses increased $26.0 million to $27.3 million in the third quarter of 2001 from $1.3 million in the corresponding period in 2000. Operating expenses increased $111.0 million to $114.2 million in the first nine months of 2001 from $3.2 million in the corresponding period in 2000. Operating expenses included employee, catalyst/chemical, repair and maintenance, insurance, taxes, and energy costs as well as costs, net of lease fees, related to the service and supply agreements with Premcor Refining Group. In the first nine months of 2001 our operating expenses were negatively impacted by the significant rise in energy costs, particularly in the first six months of the year, as reflected in the natural gas prices. 18 General and Administrative Expenses. General and administrative expenses increased $0.7 million to $1.0 million in the third quarter of 2001 from $0.3 million in the corresponding period in 2000. General and administrative expenses increased $2.4 million to $3.0 million in the first nine months of 2001 from $0.6 million in the corresponding period in 2000. The 2001 general and administrative expenses primarily included costs associated with the services and supply agreement with Premcor Refining Group. This agreement did not take affect until the fourth quarter of 2000. The 2000 general and administrative expenses primarily included employee and professional fee expenses related to the pre-operation period. Depreciation and Amortization. Depreciation and amortization was $5.3 million and $15.2 million in the third quarter and first nine months of 2001, respectively. We began depreciating our assets in accordance with our property, plant and equipment policy during the first quarter of 2001, following the substantial completion of the heavy oil upgrade project in stages, beginning December 2000 and commencement of operations. Interest Expense and Finance Income, net. Interest expense and finance income, net increased $13.3 million to $14.5 million in the third quarter of 2001 from $1.2 million in the corresponding period in 2000. Interest expense and finance income, net increased $43.5 million to $45.8 million in the first nine months of 2001 from $2.3 million in the corresponding period in 2000. In 2000, the majority of the interest costs were capitalized as part of the heavy oil upgrade project. These costs are being expensed in 2001 upon the completion of the project. Income Tax Provision. An income tax provision of $8.1 million in the third quarter of 2001 and an income tax provision of $66.7 million in the first nine months of 2001 represented an approximate 35% effective tax rate on pretax income or loss. In September 2001, under the terms of our tax sharing agreement with the common parent of our consolidated group, Premcor Inc., and the common security agreement related to our senior debt, we made a federal estimated income tax payment of $13.0 million. Liquidity and Capital Resources Cash flows from Operating Activities Cash flows provided by operating activities for the nine-month period ended September 30, 2001 was $200.5 million compared to cash used in operating activities of $18.1 million for the same period last year. These cash flows mainly resulted from the earnings from operations in 2001 and the loss during the development stage in 2000. Working capital changes were principally due to the shift from accounts payables related solely to capital expenditure accruals to accounts receivable, accounts payable and inventory related to full operations. As of September 30, 2001, we had a cash balance of $228.2 million. Under a common security agreement related to our senior debt, this cash is reserved for specific operational uses and mandatory debt repayment. The operational uses include various levels of spending, such as current and operational working capital needs, interest and principal payments, taxes, and maintenance and repairs. Cash is applied to each level until that level has been fully funded, upon which the remaining cash flows to the next level. Once these spending levels are funded, any cash surplus satisfies obligations of a debt service reserve and mandatory debt repayment with funding occurring semiannually on January and July 15th. The cash balance of $228.2 million included $30.6 million restricted for debt service payments on our long-term debt. In order to provide security to PMI Comercio Internacional, S.A. de C.V. for our obligation to pay for shipments of Maya crude oil under a long term crude oil supply agreement, we obtained from Winterthur International Insurance Company Limited an oil payment guaranty insurance policy for the 19 benefit of PMI. This oil payment guaranty insurance policy is in the amount of $150 million and will be a source of payment to PMI if we fail to pay PMI for one or more shipments of Maya crude oil. Under certain senior debt documents, we are required to reimburse Winterthur for any payments they make on this policy. This reimbursement obligation to Winterthur has a priority claim on all of the collateral held for the senior debt equal to the note holders and holders of Port Arthur Coker Company's other senior debt, except in specified circumstances in which it has a senior claim to these parties. As of September 30, 2001, $123.9 million of crude oil purchase commitments were outstanding related to this policy. We also have in place a $35 million working capital facility which is primarily for the issuance of letters of credit for the purchases of non-Maya crude oil. As of September 30, 2001, $18.3 million of the facility was utilized for letters of credit. Cash Flows from Investing Activities Cash flows used in investing activities were $8.7 million for the nine-month period ended September 30, 2001 as compared to $165.9 million in the same period last year. Expenditures for property, plant and equipment in 2000 and 2001 were associated with the construction of the heavy oil upgrade facility. All proceeds from our 1999 debt financings were restricted for use on the construction, financing, and start-up operations of the heavy oil upgrade facility. As a result, cash and cash equivalents associated with the construction of the heavy oil upgrade facility were classified as a non-current asset and the restricted cash and cash equivalent activity was reflected as investing activity in 2000. We classify our capital expenditures into two categories, mandatory and discretionary. Mandatory capital expenditures, such as for turnarounds and maintenance, are required to maintain safe and reliable operations or to comply with regulations pertaining to soil, water and air contamination or pollution and occupational, safety and health issues. We estimate that total mandatory capital and turnaround expenditures will average approximately $10 million per year over the next four years. This estimate includes the capital costs necessary to comply with environmental regulations, except for Tier 2 gasoline standards and on-road diesel regulations described below. Because our assets have been in operation for such a short period of time, we have not incurred any mandatory capital and refinery maintenance turnaround expenditures in 2001. Discretionary capital expenditures are undertaken by us on a voluntary basis after thorough analytical review and screening of projects based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields and/or a reduction in operating costs. We plan to fund both mandatory and discretionary capital expenditures with cash flow from operations. Accordingly, total discretionary capital expenditures may be less than budget if cash flow is lower than expected and higher than budget if cash flow is better than expected. Our discretionary capital expenditure budget related to the completion of the heavy oil processing facility is approximately $15.3 million in 2001, of which $8.7 million has been spent as of September 30, 2001. We currently plan to spend approximately $10 million on discretionary capital projects in 2002. In addition to mandatory capital expenditures, we expect to incur significant costs in order to comply with environmental regulations discussed below. For example, the Environmental Protection Agency has promulgated new regulations under the Clean Air Act that establish stringent sulfur content specifications for gasoline and on-road diesel fuel designed to reduce air emissions from the use of these products. The gasoline specifications, referred to as the Tier 2 standards, have been enacted and will be phased in beginning in 2004, with full compliance required by January 1, 2006. Based on our preliminary estimates, we believe that compliance with the Tier 2 gasoline standards will require us to spend between $20 million and $25 million in the aggregate through 2005. More than 90% of the projected investment is expected to be incurred during 2002 through 2004 with the greatest concentration of spending occurring in 2003. The low sulfur highway on-road diesel regulations 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. The Environmental Protection Agency has also announced its intention to review the sulfur content in diesel fuel sold to off-road consumers. If regulations are promulgated to regulate the sulfur content of off-road diesel, we expect the sulfur requirement to be either 500 ppm, which is the current on-road limit, or 15 ppm, which will be the future on-road limit. If the new off-road standard is 500 ppm, the capital expenditures necessary for us to comply with the new diesel standards may be significantly reduced because the Port Arthur refinery currently meets the 500 ppm specifications. We would thus continue to have a market for our current diesel production at Port Arthur, albeit a smaller and lower-priced market, and therefore we could elect not to make any capital expenditures necessary to comply with the new on-road standard. Depending upon the standard promulgated for off-road diesel, if any, and the compliance strategy we adopt in conjunction with the Premcor Refining Group, the estimate or our capital expenditures in the aggregate through 2006 required to comply with the diesel standards utilizing existing technologies may range from zero to $175 million. More than 90% of the projected investment, if necessary, is expected to be incurred during 2004 through 2006 with the greatest concentration of spending occurring in 2005. Cash Flows from Financing Activities Cash flows provided by financing activities were zero for the nine-month period ended September 30, 2001 compared to $184.0 million last year. The 2000 proceeds were comprised principally of borrowings under the bank senior loan agreement and required pro-rata shareholder contributions received pursuant to capital contribution agreements that were used to fund the heavy oil upgrade project. The deferred financing costs in 2000 were associated with the filing of documents with the Securities and Exchange Commission for the registration of the 12 1/2 % senior secured notes. As of June 30, 2001, $37.4 million and $13.2 million was available to us through our bank senior loan agreement and capital contribution agreements, respectively. During the third quarter, we decided not to borrow the remaining portion of the bank senior loan agreement. Since the obligation to fund the capital contributions was contingent upon the funding of the bank senior loan agreement, we will not receive the unfunded capital contribution commitments. The ability to draw any remaining funds under the senior bank loan agreement and receive the remaining capital contribution commitments expired upon the achievement of substantial reliability of the heavy oil upgrade facility in September of 2001. Funds generated from operating activities together with existing cash and cash equivalents are expected to be adequate to fund existing requirements for working capital and capital expenditure programs for the next year. Our operating results are subject to rapid and wide fluctuations due to the commodity nature of our feedstocks and products. However, there can be no assurance that market conditions or actual operations will not be worse than anticipated. Future working capital and discretionary and mandatory capital expenditures may require additional debt or equity capital. 20 PART II - OTHER INFORMATION ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit Number Description ------ ----------- 3.01 Amended and Restated Certificate of Incorporation of Sabine River Holding Corp. ("Sabine River") and the Certificate of Amendment thereto dated August 11, 1999 (Incorporated by reference to Exhibit 3.01(b) filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 3.02 Amended and Restated By Laws of Sabine River (Incorporated by reference to Exhibit 3.02(b) filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 4.01 Indenture, dated as of August 19, 1999, among Sabine River, Neches River Holding Corp. ("Neches River"), Port Arthur Finance Corp. ("PAFC"), Port Arthur Coker Company L.P. ("PACC"), HSBC Bank USA, the capital markets trustee, and Bankers Trust Company, as Collateral Trustee (Incorporated by reference to Exhibit 4.01 filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 4.02 Form of 12.50% Senior Secured Notes due 2009 (the "Exchange Note") (Incorporated by reference to Exhibit 4.02 filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 4.03 Common Security Agreement, dated as of August 19, 1999, among PAFC, PACC, Sabine River, Neches River, Bankers Trust Company, as Collateral Trustee and Depositary Bank, Deutsche Bank AG, New York Branch ("Deutsche Bank"), as Administrative Agent, Winterthur International Insurance Company Limited, an English company ("Winterthur"), as Oil Payment Insurers Administrative Agent and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.04 filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 4.04 Transfer Restrictions Agreement, dated as of August 19, 1999, among PAFC, PACC, Premcor Inc. (f/k/a Clark Refining Holdings Inc.), Sabine River, Neches River, Blackstone Capital Partners III Merchant Banking Fund L.P. ("BCP III"), Blackstone Offshore Capital Partners III L.P. ("BOCP III"), Blackstone Family Investment Partnership III ("BFIP III"), Winterthur, as the Oil Payment Insurers Administrative agent, Bankers Trust Company, as Collateral Trustee, Deutsche Bank, as Administrative Agent and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.05 filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) 4.05 Intercreditor Agreement, dated as of August 19, 1999, among Bankers Trust Company, as Collateral Trustee, Deutsche Bank, as Administrative Agent, Winterthur, as Oil Payment Insurers Administrative Agent and Debt Service Reserve Insurer and HSBC Bank, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.06 filed with the Company's Registration Statement on Form S-4 (Registration No. 333-92871)) (b) Reports on Form 8-K Except as previously disclosed, the Company has not filed any reports on Form 8-K during the period covered by this report and up to and including the date of filing of this report. 21 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Sabine River Holding Corp. (Registrant) /s/ Dennis R. Eichholz --------------------------------------- Dennis R. Eichholz Controller (Principal Accounting Officer and Duly Authorized Officer) November 13, 2001 22

SABINE RIVER HOLDING CORP 10-Q