================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 1-14569 PLAINS ALL AMERICAN PIPELINE, L.P. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 76-0582150 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 500 DALLAS STREET HOUSTON, TEXAS 77002 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) (713) 654-1414 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- COMMON UNITS NEW YORK STOCK EXCHANGE 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 The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $521,861,243 on March 22, 2001, based on $22.80 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on such date. At March 22, 2001, there were outstanding 23,049,239 Common Units, 1,307,190 Class B Common Units and 10,029,619 Subordinated Units. DOCUMENTS INCORPORATED BY REFERENCE: NONE Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] ================================================================================
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 2000 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS PAGE ---- Part I Items 1. and 2. Business and Properties............................... 3 Item 3. Legal Proceedings..................................... 22 Item 4. Submission of Matters to a Vote of Security Holders... 23 PART II Item 5. Market for Registrant's Common Units and Related Unitholder Matters.................................... 23 Item 6. Selected Financial and Operating Data................. 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 27 Item 7a. Quantitative and Qualitative Disclosures About Market Risks.......................................... 37 Item 8. Financial Statements and Supplementary Data........... 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................... 38 PART III Item 10. Directors and Executive Officers of Our General Partner............................................... 39 Item 11. Executive Compensation................................ 41 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................ 44 Item 13. Certain Relationships and Related Transactions........ 44 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................... 47 FORWARD-LOOKING STATEMENTS All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views and those of our general partner with respect to future events, based on what we believe are reasonable assumptions. These statements, however, are subject to certain risks, uncertainties and assumptions, including, but not limited to: . the availability of adequate supplies of and demand for crude oil in the areas in which we operate; . the impact of crude oil price fluctuations; . the effects of competition; . the success of our risk management activities; . the availability (or lack thereof) of acquisition or combination opportunities; . the impact of current and future laws and governmental regulations; . environmental liabilities that are not covered by an indemnity or insurance; . fluctuations in the debt and equity markets; and . general economic, market or business conditions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from the results anticipated in the forward-looking statements. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. 2
PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL We are a publicly traded Delaware limited partnership engaged in interstate and intrastate marketing, transportation and terminalling of crude oil. We were formed in September 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. ("Plains Resources"), whose wholly owned subsidiary, Plains All American, Inc., is our general partner. Our operations are concentrated in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of Mexico and can be categorized into two primary business activities: . CRUDE OIL PIPELINE TRANSPORTATION. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff, as well as merchant activities designed to capture location and quality price differentials. We own and operate several pipeline systems including: . a segment of the All American Pipeline that extends approximately 140 miles from Las Flores, California to Emidio, California; . the San Joaquin Valley Gathering System in California; . the West Texas Gathering System, the Spraberry Pipeline System, and the East Texas Pipeline System, which are all located in Texas; . the Sabine Pass Pipeline System in southwest Louisiana and southeast Texas; . the Ferriday Pipeline System in eastern Louisiana and western Mississippi; and . the Illinois Basin Pipeline System in southern Illinois. . TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We own and operate a state-of-the-art, 3.1 million barrel, above-ground crude oil terminalling and storage facility at Cushing, Oklahoma, the largest crude oil trading hub in the United States and the designated delivery point for New York Mercantile Exchange ("NYMEX") crude oil futures contracts. We also have an additional 6.7 million barrels of terminalling and storage capacity in our other facilities, including tankage associated with our pipeline and gathering systems. Our terminalling and storage operations generate revenue through a combination of storage and throughput charges to third parties. Our gathering and marketing operations include: . the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities; . the transportation of crude oil on trucks, barges or pipelines; and . the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain. Consistent with our publicly announced intention to expand operations into Canada, we are pursuing the acquisition of certain Canadian assets in two separate transactions for aggregate consideration of approximately $200.0 million. See "Acquisitions and Dispositions". PARTNERSHIP STRUCTURE AND MANAGEMENT Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our interests in our subsidiaries through two operating partnerships, Plains Marketing, L.P. and All American Pipeline, L.P. Our Canadian operations will be conducted through Plains Marketing Canada, L.P. Our general partner has sole responsibility for conducting our business and managing our operations and owns all of the incentive distribution rights. See Item 13. - "Certain Relationships and Related Transactions". Some of the senior executives who currently manage our business also manage and operate the business of Plains Resources. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf. 3
The chart below depicts the current organization and ownership of Plains All American Pipeline, the operating partnerships and the subsidiaries. As is reflected in the chart, a subsidiary of our general partner owns 6,791,816 common units and 10,029,619 subordinated units, representing a 19.4% and 28.6% interest in the partnership and our subsidiaries. In addition, our general partner owns 1,307,190 Class B common units representing a 3.7% interest in the partnership and our subsidiaries. Except for the table inset, the percentages reflected in the organization chart represent the approximate ownership interest in Plains All American Pipeline, the operating partnerships and their subsidiaries individually and not on a combined basis. [CHART APPEARS HERE] 4
UNAUTHORIZED TRADING LOSSES Background In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $174.0 million, which includes estimated associated costs and legal expenses. A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred from March through November 1999, and the impact warranted a restatement of previously reported financial information for 1999 and 1998. Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and the remainder in 1999. In 2000, we recognized an additional $7.0 million charge for litigation related to the unauthorized trading losses. Normally, as we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third parties, or by entering into future delivery obligations with respect to futures contracts. The employee in question violated our policy of maintaining a substantially balanced position between purchases and sales (or future delivery obligations) by negotiating one side of a transaction without negotiating the other, leaving the position "open." The trader concealed his activities by hiding open trading positions, by rolling open positions forward using off-market, inter-month transactions, and by providing to counter-parties forged documents that purported to authorize such transactions. An "inter-month" transaction is one in which the receipt and delivery of crude oil are scheduled in different months. An "off-market" transaction is one in which the price is higher or lower than the prices available in the market on the day of the transaction. By matching one side of an inter-month transaction with an open position, and using off-market pricing to match the pricing of the open position, the trader could present documentation showing both a purchase and a sale, creating the impression of compliance with our policy. The offsetting side of the inter-month transaction became a new, hidden open position. Investigation; Enhancement of Procedures Upon discovery of the violation and related losses, we engaged an outside law firm to lead the investigation of the unauthorized trading activities. The law firm retained specialists from an independent accounting firm to assist in the investigation. In parallel effort with the investigation mentioned above, the role of the accounting-firm specialists was expanded to include reviewing and making recommendations for enhancement of our systems, policies and procedures. As a result, we have developed a new written policy document and manual of procedures designed to enhance our processes and procedures and improve our ability to detect any activity that might occur at an early stage. The new policy was adopted by the Board of Directors of Plains All American Inc. in May 2000; however, implementation of many of the procedures commenced in January 2000, based on information developed throughout the investigation and the review of the policies, processes and procedures. In March 2000, management hired another independent accounting firm to provide additional objective input regarding the processes and procedures, and to supplement management's efforts to expedite the implementation of the enhanced policies and automation of the processes and procedures. The procedures have now been implemented, although not all reports are fully automated. The procedures have been, and will continue to be, refined. To specifically address the methods used by the trader to conceal the unauthorized trading, in January 2000 we sent a notice to each of our material counter-parties that no person at Plains All American Pipeline, L.P. was authorized to enter into off-market transactions. In addition, we have taken the following actions: . We have communicated our trading strategies and risk tolerance to our traders by more clearly and specifically defining those strategies and risk limits in our written procedures. . The new procedures require (i) more comprehensive and frequent reporting that will allow our officials to evaluate risk positions in greater detail, and (ii) enhanced procedures to check compliance with these reporting requirements and to confirm that trading activity was conducted within guidelines. . The procedures provide a system to educate each employee who is involved, directly or indirectly, in our crude oil transaction activities with respect to policies and procedures, and impose an obligation to notify the Risk Manager, (an independent function that reports directly to the Chief Financial Officer) directly of any questionable transactions or failure of others to adhere to the policies, practices and procedures. . Finally, following notification to each of our material counter-parties that off-market trading is against our policy and that any written evidence to the contrary is unauthorized and false, the Risk Manager and our other representatives have also communicated our policies and enhanced procedures to our counter-parties to advise them of the information we will routinely require from them to assure timely recording and confirmation of trades. 5
We can give no assurance that the above steps will serve to detect and prevent all violations of our trading policy; we believe, however, that such steps substantially reduce the possibility of a recurrence of unauthorized trading activities, and that any unauthorized trading that does occur would be detected before any material loss could develop. Effects of the Loss The unauthorized trading and associated losses resulted in a default of certain covenants under our then-existing credit facilities and significant short-term cash and letter of credit requirements. In December 1999, we executed amended credit facilities and obtained default waivers from all of our lenders. We paid approximately $13.7 million to our lenders in connection with the amended credit facilities. In connection with the amendments, our general partner loaned us approximately $114.0 million. On May 8, 2000, we entered into new bank credit agreements to refinance our existing bank debt and repay the $114.0 million owed to our general partner. The new bank credit agreements also provided us with additional flexibility for working capital, capital expenditures and other general corporate purposes. At closing, we had $256.0 million outstanding under a $400.0 million senior secured revolving credit facility. We also had at closing letters of credit of approximately $173.8 million and borrowings of approximately $20.3 million outstanding under a separate $300.0 million senior secured letter of credit and borrowing facility. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." In the period immediately following the disclosure of the unauthorized trading losses, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost of letters of credit increased under our credit facility. Some of our purchase contracts were terminated. As a result of these changes, aggregate volumes purchased have declined from an average of 528,000 barrels per day for the fiscal quarter preceding the trading loss to an average of 302,000 barrels per day in the fourth quarter of 2000. Approximately 72,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 154,000 barrels per day is attributable to bulk purchases. As a result of the increase in letter of credit costs and reduced volumes, annual Adjusted EBITDA and net income for 2000 was adversely affected by approximately $6.0 million, excluding the positive impact of current favorable market conditions. Adjusted EBITDA means earnings before interest expense, income taxes, depreciation and amortization, unauthorized trading losses, noncash compensation expense, restructuring expense, gains on the sale of linefill and pipeline, allowance for accounts receivable and extraordinary loss from extinguishment of debt. After the public announcement of the trading losses, class action lawsuits were filed against us and Plains Resources. Derivative lawsuits have also been filed in the United States District Court of the Southern District of Texas and the Delaware Chancery Court, Newcastle County. We and Plains Resources reached an agreement to settle all of the class actions and the Delaware derivative action. See Item 3. - "Legal Proceedings". RESULTS OF OPERATIONS For the year ended December 31, 2000, our Adjusted EBITDA, cash flow from operations and net income totaled $103.0 million, $73.9 million and $77.5 million, respectively. Cash flow from operations represents net income before noncash items. Cash flow from operations also excludes the unauthorized trading losses, noncash compensation expense, gains on the sale of linefill and pipeline, allowance for accounts receivable and extraordinary loss from extinguishment of debt. Excluding the unauthorized trading losses, our gross margin in 2000 was $134.7 million with our terminalling and storage activities and gathering and marketing activities accounting for approximately 62% of our gross margin and our pipeline operations accounting for approximately 38%. ACQUISITIONS AND DISPOSITIONS Consistent with our publicly announced intention to expand operations into Canada, we are pursuing the acquisition of certain Canadian assets in two separate transactions for aggregate consideration of approximately $200.0 million. Set forth below is a brief description of the acquisitions. 6
Murphy Oil Company Ltd. Midstream Operations On March 1, 2001, we signed an agreement to purchase substantially all of the crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. ("Murphy") for approximately $155.0 million in cash, plus an additional cash payment, to be determined prior to closing in accordance with the agreement, for excess inventory in the systems (estimated to be approximately $5.0 million). The principal assets to be acquired include approximately 450 miles of crude oil and condensate transmission mainlines and associated gathering and lateral lines, and approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently inactive 108-mile mainline system and 121 trailers used primarily for crude oil transportation. Murphy has agreed to continue to transport production from fields currently delivering crude oil to these pipeline systems, under a new long-term contract. The current volume is approximately 11,000 barrels per day. The pipeline systems transport approximately 200,000 barrels per day of light, medium and heavy crudes, as well as condensate. Certain of the principal assets include: . Manito Pipeline - A 100% ownership interest in a 101-mile crude oil line and a parallel 101-mile condensate line that connects the North- Saskatchewan Pipeline and multiple gathering lines to the Enbridge system at Kerrobert, Saskatchewan. The Enbridge system is a 1.9 million barrel per day pipeline that transports liquid hydrocarbons from the oilfields of Western Canada to refineries and markets in Eastern Canada and the Midwestern U.S. The Manito line is located in the Canadian province of Saskatchewan near the Alberta border and has current throughput of approximately 80,000 barrels per day. . Cactus Lake/Bodo Pipeline - Varying interests from 13.125% to 76.25% in a 55-mile crude oil line and a parallel 55-mile condensate line, which connect to the terminal at Kerrobert. Current throughput approximates 39,000 barrels per day. . Milk River Pipeline - A 100% ownership in three parallel 11-mile lines connecting the Bow River Pipeline in Alberta to the Cenex Pipeline at the U.S. border. Current throughput approximates 90,000 barrels per day. Canadian Marketing Assets We have entered into a letter of intent to purchase the assets of a Canadian marketing company. The expected purchase price is approximately $43.0 million, of which approximately $18.0 million will be subject to certain performance targets. The marketing company currently generates annual EBITDA of approximately $10.0 million, gathering approximately 75,000 barrels per day of crude oil and marketing approximately 26,000 barrels per day of natural gas liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel tank facility and working capital of approximately $8.5 million. Initial financing for the acquisitions will be provided via an expansion of our existing revolving credit, letter of credit and inventory facility. The expanded facility will initially be underwritten by Fleet Boston and will consist of a $100.0 million five-year term loan and a $30.0 million revolving credit facility that will expire in April 2005. Consistent with our stated policy of maintaining a strong capital structure by funding acquisitions with a balance of debt and equity, we intend to refinance a portion of our bank facility with proceeds from future bond and equity financings. We intend to create and establish a midstream crude oil presence in Canada that is similar to our existing operations in the U.S. By using the knowledge and skills developed in our U.S. operations, we hope to generate attractive financial returns in the Canadian market through exploiting existing inefficiencies, while attempting to improve revenues and margins on our acquired pipeline, terminalling and gathering assets. These assets complement our current activities and enhance our ability to service the needs of refiners in the U.S. Midwest. The completion of both transactions, while independent of one another, will provide us with direct access to substantial Canadian wellhead volumes via gathering and pipeline systems and strategically located terminal and storage assets. Scurlock Acquisition On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Financing for the acquisition was provided through $117.0 million of borrowings and the sale of 1.3 million Class B Units to our general partner for total cash consideration of $25.0 million. 7
Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, was engaged in crude oil transportation, gathering and marketing. The assets acquired included approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of trucks. The largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas than extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil linefill. West Texas Gathering System Acquisition On July 15, 1999, we completed the acquisition of the West Texas Gathering System from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Financing for the amounts paid at closing was provided by a draw under a previous credit facility. The assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines, and approximately 2.9 million barrels of tankage located along the system. All American Pipeline Linefill Sale and Asset Disposition In March 2000, we sold to a unit of El Paso Corporation ("El Paso") for $129.0 million the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. Except for minor third-party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce outstanding debt. We recognized a gain of approximately $20.1 million in connection with the sale. We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized gains of approximately $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with the sale of the linefill. CRUDE OIL PIPELINE OPERATIONS We present below a description of our principal pipeline assets. All of our pipeline systems are operated from one of two central control rooms with computer systems designed to continuously monitor real time operational data including measurement of crude oil quantities injected in and delivered through the pipelines, product flow rates and pressure and temperature variations. This monitoring and measurement technology provides us the ability to efficiently batch differing crude oil types with varying characteristics through the pipeline systems. The systems are designed to enhance leak detection capabilities, sound automatic alarms in the event of operational conditions outside of pre-established parameters and provide for remote-controlled shut- down of pump stations on the pipeline systems. Pump stations, storage facilities and meter measurement points along the pipeline systems are linked by telephone, microwave, satellite or radio communication systems for remote monitoring and control, which reduces our requirement for full time site personnel at most of these locations. We perform scheduled maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We attempt to control corrosion of the mainlines through the use of corrosion inhibiting chemicals injected into the crude stream, external coatings and anode bed based or impressed current cathodic protection systems. Maintenance facilities containing equipment for pipe repairs, spare parts and trained response personnel are strategically located along the pipelines and in concentrated operating areas. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute and accepted industry practice. All American Pipeline The segment of the All American Pipeline that we retained following the sale of the line to El Paso is a common carrier crude oil pipeline system that transports crude oil produced from Outer Continental Shelf ("OCS") fields offshore California to locations in California. See " - All American Pipeline Linefill Sale and Asset Disposition." This segment is subject to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") (see " - Regulation - Transportation Regulation"). As a common carrier, the All American Pipeline offers transportation services to any shipper of crude oil, provided that the crude oil tendered for transportation satisfies the conditions and specifications contained in the applicable tariff. As a result, we transport both our own crude oil and crude oil owned by third parties on the All American Pipeline. 8
We currently operate the segment of the system that extends approximately 10 miles from ExxonMobil's onshore facilities at Las Flores on the California coast to Plains Resources' onshore facilities at Gaviota, California (24-inch diameter pipe) and continues from Gaviota approximately 130 miles to our station in Emidio, California (30-inch pipe). Between Gaviota and our Emidio Station, the All American Pipeline interconnects with our SJV Gathering System as well as various third party intrastate pipelines, including the Unocap Pipeline System, Pacific Pipeline, and a pipeline owned by EOTT Energy Partners, L.P. System Supply. The All American Pipeline currently transports OCS crude oil received at the onshore facilities of the Santa Ynez field at Las Flores, California and the onshore facilities of the Point Arguello field located at Gaviota, California. ExxonMobil, which owns all of the Santa Ynez production, and Plains Resources, Texaco and Sun Operating L.P., which together own approximately one-half of the Point Arguello production, have entered into transportation agreements committing to transport all of their production from these fields on our retained segment of the All American Pipeline. These agreements, which expire in August 2007, provide for a minimum tariff with annual escalations. At December 31, 2000, the tariffs averaged $1.41 per barrel for deliveries to connecting pipelines in California. The tariff was increased by 10% effective January 1, 2001. The agreements do not require these owners to transport a minimum volume. The producers from the Point Arguello field who do not have contracts with us have no other means of transporting their production and, therefore, ship their volumes on the All American Pipeline at the posted tariffs. For the year ended December 31, 2000, approximately $24.6 million, or 18% of our gross margin was attributable to the Santa Ynez field and approximately $7.8 million, or 6%, was attributable to the Point Arguello field. Transportation of volumes commenced from the Point Arguello field on the All American Pipeline in 1991 and from the Santa Ynez field in 1994. The table below sets forth the historical volumes received from both of these fields. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------- 2000 1999 1998 1997 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- ---- ---- ---- ----- (BARRELS IN THOUSANDS) <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Average daily volumes received from: Point Arguello (at Gaviota) 18 20 26 30 41 60 73 63 47 Santa Ynez (at Las Flores) 56 59 68 85 95 92 34 - - -- -- -- --- --- --- ---- --- -- Total 74 79 94 115 136 152 107 63 47 == == == === === === === == == </TABLE> A wholly owned subsidiary of Plains Resources is the operator of record for the Point Arguello Unit. All of the volumes attributable to Plains Resources' interests are committed for transportation on the All American Pipeline and are subject to our Marketing Agreement with Plains Resources. Plains Resources expects that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. As operator of Point Arguello, Plains Resources is conducting additional drilling and other activities on this field, but we cannot assure you that these activities will affect the production decline. San Joaquin Valley Supply. The San Joaquin Valley is one of the most prolific oil producing regions in the continental United States, producing approximately 568,000 barrels per day of crude oil during the first nine months of 2000 which accounted for approximately 68% of total California production and 12% of the total production in the lower 48 states. The following table reflects the historical production for the San Joaquin Valley as well as total California production (excluding OCS volumes) as reported by the California Division of Oil and Gas. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------------- 2000 (1) 1999 1998 1997 1996 1995 1994 1993 1992 1991 -------- ---- ---- ---- ---- ---- ---- ---- ----- ---- (BARRELS IN THOUSANDS) <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> Average daily volumes: San Joaquin Valley production (2) 568 562 592 584 579 569 578 588 609 634 Total California production (excluding OCS volumes) 739 734 781 781 772 764 784 803 835 875 </TABLE> - ----------------------------- (1) Reflects information through September 2000. (2) Consists of production from California Division of Oil and Gas District IV. 9
System Demand. Deliveries from the All American Pipeline are made to California refineries through connections with third-party pipelines at Sisquoc, Pentland and Emidio. Deliveries at Mojave were discontinued in the second quarter of 1999, and volumes previously delivered to Mojave are delivered to Emidio. The following table sets forth All American Pipeline average deliveries per day within California. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 1997 1996 ------- ------ ------ ------ ------- (BARRELS IN THOUSANDS) <S> <C> <C> <C> <C> <C> Average daily volumes delivered to: Sisquoc 25 27 24 21 17 Pentland 49 52 69 74 71 Mojave - 7 22 32 6 Emidio 41 15 - - - --- --- --- --- -- Total 115 101 115 127 94 === === === === == </TABLE> SJV Gathering System The SJV Gathering System is a proprietary pipeline system. As a proprietary pipeline, the SJV Gathering System is not subject to common carrier regulations. The SJV Gathering System was constructed in 1987 with a design capacity of approximately 140,000 barrels per day. The system consists of a 16-inch pipeline that originates at the Belridge station and extends 45 miles south to a connection with the All American Pipeline at the Pentland station. The SJV Gathering System is connected to several fields, including the South Belridge, Elk Hills and Midway Sunset fields, three of the seven largest producing fields in the lower 48 states. In 1999, we leased a pipeline that provides us access to the Lost Hills field. The SJV Gathering System also includes approximately 586,000 barrels of tank capacity, which can be used to facilitate movements along the system as well as to support our other activities. The SJV Gathering System is supplied with crude oil production primarily from major oil companies' equity production from the South Belridge, Cymeric, Midway Sunset, Elk Hills and Lost Hills fields. The table below sets forth the historical volumes received into the SJV Gathering System. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 2000 1999 1998 1997 1996 ---- ---- ----- ---- ----- (BARRELS IN THOUSANDS) <S> <C> <C> <C> <C> <C> Total average daily volumes 60 84 85 91 67 </TABLE> West Texas Gathering System We purchased the West Texas Gathering System from Chevron Pipe Line Company in July 1999 for approximately $36.0 million, including transaction costs. The West Texas Gathering System is a common carrier crude oil pipeline system located in the heart of the Permian Basin producing area. The West Texas Gathering System has lease gathering facilities in Crane, Ector, Upton, Ward and Winkler counties. In the aggregate, these counties have produced on average in excess of 150,000 barrels per day of crude oil over the last four years. The West Texas Gathering System was originally built by Gulf Oil Corporation in the late 1920's, expanded during the late 1950's and updated during the mid 1990's. The West Texas Gathering System provides us with considerable flexibility, as major segments are bi-directional and allow us to move crude oil between three of the major trading locations in West Texas. Total system volumes were approximately 75,000 barrels per day in 2000. Lease volumes gathered into the system average approximately 50,000 barrels per day. Chevron USA has agreed to transport its equity crude oil production from fields connected to the West Texas Gathering System on the system through July 2011 (currently representing approximately 20,000 barrels per day, or 40% of total system gathering volumes and 27% of the total system volumes). Other large producers connected to the gathering system include Burlington Resources, Devon Energy, Anadarko, Altura, Bass, and TotalFinaElf. Volumes from connecting carriers, including ExxonMobil, Phillips and Unocal, average approximately 47,000 barrels per day. Our West Texas Gathering System has the capability to transport approximately 190,000 barrels per day. At the time of the acquistion, truck injection stations were limited and provided less than 1,000 barrels per day. We have installed 16 truck injection stations on the West Texas Gathering System since the acquisition. Our trucks are used to pick up crude oil produced in the areas adjacent to the West Texas Gathering System and 10
deliver these volumes into the pipeline. These additional injection stations have allowed us to reduce the distance of our truck hauls in this area, increase the utilization of our pipeline assets and reduce our operating costs. Volumes received from truck injection stations were increased to 16,000 barrels per day by the fourth quarter of 2000. The West Texas Gathering System also includes approximately 2.9 million barrels of tank capacity located along the pipeline system. Spraberry Pipeline System The Spraberry Pipeline System, acquired in the Scurlock acquisition, is a proprietary pipeline system that gathers crude oil from the Spraberry Trend of West Texas and transports it to Midland, Texas, where it interconnects with the West Texas Gathering System and other pipelines. The Spraberry Pipeline System consists of approximately 800 miles of pipe of varying diameter, and has a throughput capacity of approximately 50,000 barrels of crude oil per day. The Spraberry Trend is one of the largest producing areas in West Texas, and we are one of the largest gatherers in the Spraberry Trend. The Spraberry Pipeline System gathers approximately 39,000 barrels per day of crude oil. Large suppliers to the Spraberry Pipeline System include Coast Energy and Pioneer Natural Resources. The Spraberry Pipeline System also includes approximately 173,000 barrels of tank capacity located along the pipeline. Sabine Pass Pipeline System The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system. The primary purpose of the Sabine Pass Pipeline System is to gather crude oil from onshore facilities of offshore production near Johnson's Bayou, Louisiana, and deliver it to tankage and barge loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System consists of approximately 34 miles of pipe ranging from 4 to 6 inches in diameter and has a throughput capacity of approximately 26,000 barrels of Louisiana light sweet crude oil per day. For the year ended December 31, 2000, the system transported approximately 16,000 barrels of crude oil per day. The Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity located along the pipeline. Ferriday Pipeline System The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system which is located in East Louisiana and West Mississippi. The Ferriday Pipeline System consists of approximately 600 miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday Pipeline System delivers 9,000 barrels per day of crude oil to third-party pipelines that supply refiners in the Midwest. The Ferriday Pipeline System also includes approximately 348,000 barrels of tank capacity located along the pipeline. In November 1999, we completed the construction of an 8-inch pipeline underneath the Mississippi River that connects our Ferriday Pipeline System in West Mississippi with the portion of the system located in East Louisiana. This connection provides us with bi-directional capability to access additional markets and enhances our ability to service our pipeline customers and take advantage of additional high margin merchant activities. East Texas Pipeline System The East Texas Pipeline System, acquired in the Scurlock acquisition, is a proprietary crude oil pipeline system that is used to gather approximately 15,000 barrels per day of crude oil in East Texas and to transport approximately 24,000 barrels per day of crude oil to Crown Central's refinery in Longview, Texas. The deliveries to Crown Central are subject to a throughput and deficiency agreement, which extends through 2004. The East Texas Pipeline System also includes approximately 221,000 barrels of tank capacity located along the pipeline. Illinois Basin Pipeline System The Illinois Basin Pipeline System, acquired with the Scurlock acquisition, consists of common carrier pipeline and gathering systems and truck injection facilities in southern Illinois. The Illinois Basin Pipeline System consists of approximately 170 miles of pipe of varying diameter and delivers approximately 10,000 barrels per day of crude oil to third-party pipelines that supply refiners in the Midwest. Approximately 3,300 barrels per day of the supply on this system are from fields operated by Plains Resources. 11
TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES Terminalling and Storage Activities We own approximately 9.8 million barrels of terminalling and storage assets, including tankage associated with our pipeline and gathering systems. Our storage and terminalling operations increase the margins in our business of purchasing and selling crude oil and also generate revenue through a combination of storage and throughput charges to third parties. Storage fees are generated when we lease tank capacity to third parties. Terminalling fees, also referred to as throughput fees, are generated when we receive crude oil from one connecting pipeline and redeliver crude oil to another connecting carrier in volumes that allow the refinery to receive its crude oil on a ratable basis throughout a delivery period. Both terminalling and storage fees are generally earned from: . refiners and gatherers that segregate or custom blend crudes for refining feedstocks; . pipeline operators, refiners or traders that need segregated tankage for foreign cargoes; . traders who make or take delivery under NYMEX contracts; and . producers and resellers that seek to increase their marketing alternatives. The tankage that is used to support our arbitrage activities positions us to capture margins in a contango market (when the oil prices for future deliveries are higher than current prices) or when the market switches from contango to backwardation (when the oil prices for future deliveries are lower than current prices). Our most significant terminalling and storage asset is our Cushing Terminal. The terminal was constructed in 1993, and expanded by approximately 50% in 1999, to capitalize on the crude oil supply and demand imbalance in the Midwest. The imbalance was caused by the continued decline of regional production supplies, increasing imports and an inadequate pipeline and terminal infrastructure. The Cushing Terminal is also used to support and enhance the margins associated with our merchant activities relating to our lease gathering and bulk trading activities. The Cushing Terminal has total storage capacity of approximately 3.1 million barrels. The Cushing Terminal is comprised of fourteen 100,000 barrel tanks, four 150,000 barrel tanks and four 270,000 barrel tanks, which are used to store and terminal crude oil. The Cushing Terminal also includes a pipeline manifold and pumping system that has an estimated daily throughput capacity of approximately 800,000 barrels per day. The pipeline manifold and pumping system is designed to support more than ten million barrels of tank capacity. The Cushing Terminal is connected to the major pipelines and terminals in the Cushing Interchange through pipelines that range in size from 10 inches to 24 inches in diameter. The Cushing Terminal is a state-of-the-art facility designed to serve the needs of refiners in the Midwest. In order to service an expected increase in the volumes as well as the varieties of foreign and domestic crude oil projected to be transported through the Cushing Interchange, we incorporated certain attributes into the design of the Cushing Terminal including: . multiple, smaller tanks to facilitate simultaneous handling of multiple crude varieties in accordance with normal pipeline batch sizes; . dual header systems connecting most tanks to the main manifold system to facilitate efficient switching between crude grades with minimal contamination; . bottom drawn sumps that enable each tank to be efficiently drained down to minimal remaining volumes to minimize crude contamination and maintain crude integrity during changes of service; . mixer(s) on each tank to facilitate blending crude grades to refinery specifications; and . a manifold and pump system that allows for receipts and deliveries with connecting carriers at their maximum operating capacity. As a result of incorporating these attributes into the design of the Cushing Terminal, we believe we are favorably positioned to serve the needs of Midwest refiners, to handle an increase in varieties of crude transported through the Cushing Interchange. The Cushing Terminal also incorporates numerous environmental and operational safeguards. We believe that our terminal is the only one at the Cushing Interchange in which each tank has a secondary liner (the equivalent of double bottoms), leak detection devices and secondary seals. The Cushing Terminal is the only terminal at the Cushing Interchange equipped with aboveground pipelines. Like the pipeline systems we operate, the Cushing Terminal is operated by a computer system designed to monitor real time operational data and each tank is cathodically protected. In addition, each tank is 12
equipped with an audible and visual high level alarm system to prevent overflows; a double seal floating roof that minimizes air emissions and prevents the possible accumulation of potentially flammable gases between fluid levels and the roof of the tank; and a foam dispersal system that, in the event of a fire, is fed by a fully-automated fire water distribution network. The Cushing Interchange is the largest wet barrel trading hub in the U.S. and the delivery point for crude oil futures contracts traded on the NYMEX. The Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a primary source of refinery feedstock for the Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The following table sets forth throughput volumes for our terminalling and storage operations, and quantity of tankage leased to third parties from 1996 through 2000. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (BARRELS IN THOUSANDS) <S> <C> <C> <C> <C> <C> Throughput volumes (average daily volumes): Cushing Terminal 59 72 69 69 56 Ingleside Terminal 8 11 11 8 3 ----- ----- ------ --- --- Total 67 83 80 77 59 ===== ===== ====== === === Storage leased to third parties (average monthly volumes): Cushing Terminal 1,437 1,743 890 414 203 Ingleside Terminal 220 232 260 254 211 ----- ----- ------ --- --- Total 1,657 1,975 1,150 668 414 ===== ===== ====== === === </TABLE> Gathering and Marketing Activities Our gathering and marketing activities are conducted in 23 states; however, the vast majority of those activities are in Texas, Louisiana, California, Illinois and the Gulf of Mexico. These activities include: . purchasing crude oil from producers at the wellhead and in bulk from aggregators at major pipeline interconnects and trading locations; . transporting this crude oil on our own proprietary gathering assets or, when necessary or cost effective, assets owned and operated by third parties; . exchanging this crude oil for another grade of crude oil or at a different geographic location, as appropriate, in order to maximize margins or meet contract delivery requirements; and . marketing crude oil to refiners or other resellers. We purchase crude oil from many independent producers and believe that we have established broad-based relationships with crude oil producers in our areas of operations. For the year ended December 31, 2000, we purchased approximately 262,000 barrels per day of crude oil directly at the wellhead from more than 3,100 producers from approximately 19,400 leases. We purchase crude oil from producers under contracts that range in term from a thirty-day evergreen to three years. Gathering and marketing activities are characterized by large volumes of transactions with lower margins relative to pipeline and terminalling and storage operations. In the period immediately following the disclosure of the unauthorized trading losses in 1999, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost of letters of credit increased under our credit facility. Some of our purchase contracts were terminated. As a result of these changes, aggregate volumes purchased have declined from an average of 528,000 barrels per day for the fiscal quarter preceding the trading loss to an average of 302,000 barrels per day in the fourth quarter of 2000. Approximately 72,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 154,000 barrels per day is attributable to bulk purchases. See "Unauthorized Trading Losses" and Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources". 13
The following table shows the average daily volume of our lease gathering and bulk purchases from 1996 through 2000. YEAR ENDED DECEMBER 31, -------------------------------- 2000 1999 (1) 1998 1997 1996 ---- ------- ---- ---- ---- (BARRELS IN THOUSANDS) Lease gathering 262 265 88 71 59 Bulk purchases 28 138 98 49 32 --- --- --- --- -- Total volumes 290 403 186 120 91 === === === === == - ---------------- (1) Includes volumes from Scurlock Permian since May 1, 1999. Crude Oil Purchases. In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the crude oil is treated to remove water, sand and other contaminants and is then moved into the producer's on-site storage tanks. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. We utilize our truck fleet and gathering pipelines and third-party pipelines, trucks and barges to transport the crude oil to market. We have a Marketing Agreement with Plains Resources Inc., under which we are the exclusive marketer/purchaser for all of Plains Resources' equity crude oil production. The Marketing Agreement provides that we will purchase for resale at market prices all of Plains Resources' equity crude oil production for which we charge a fee of $0.20 per barrel. This fee will be adjusted every three years based upon then-existing market conditions. The Marketing Agreement will terminate upon a "change of control" of Plains Resources or our general partner. Bulk Purchases. In addition to purchasing crude oil at the wellhead from producers, we purchase crude oil in bulk at major pipeline terminal points. This production is transported from the wellhead to the pipeline by major oil companies, large independent producers or other gathering and marketing companies. We purchase crude oil in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period. Our bulk purchasing activities are concentrated in California, Texas, Louisiana and at the Cushing Interchange. Crude Oil Sales. The marketing of crude oil is complex and requires detailed current knowledge of crude oil sources and end markets and a familiarity with a number of factors including grades of crude oil, individual refinery demand for specific grades of crude oil, area market price structures for the different grades of crude oil, location of customers, availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil to the appropriate customer. We sell our crude oil to major integrated oil companies, independent refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one month to three years. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. From time to time, we enter into fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Our policy is generally to purchase only crude oil for which we have a market, and to structure our sales contracts so that crude oil price fluctuations do not materially affect the gross margin we receive. We do not acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses. In November 1999, we discovered that this policy was violated, and we incurred $174.0 million in unauthorized trading losses, including estimated associated costs and legal expenses. In 2000, we recognized an additional $7.0 million charge for litigation related to the unauthorized trading losses. See "Unauthorized Trading Losses". Risk management strategies, including those involving price hedges using NYMEX futures contracts, have become increasingly important in creating and maintaining margins. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook". Such hedging techniques require significant resources dedicated to managing futures positions. We are able to monitor crude oil volumes, grades, locations and delivery schedules and to coordinate marketing and exchange opportunities, as well as NYMEX hedging positions. This coordination ensures that our NYMEX hedging activities are successfully implemented. We have a Risk Manager that has direct responsibility and authority for our risk policies and our trading controls and procedures and other aspects of corporate risk management. 14
Crude Oil Exchanges. We pursue exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more nearly matches our physical delivery requirement or the preferences of our refinery customers, we exchange physical crude oil with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy crude oil that differs in terms of geographic location, grade of crude oil or physical delivery schedule from crude oil we have available for sale. Generally, we enter into exchanges to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs and increasing our margin. We also exchange our crude oil to be physically delivered at an earlier or later date, if the exchange is expected to result in a higher margin net of storage costs, and enter into exchanges based on the grade of crude oil, which includes such factors as sulfur content and specific gravity, in order to meet the quality specifications of our physical delivery contracts. Producer Services. Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through our team of crude oil purchasing representatives, we maintain ongoing relationships with more than 3,100 producers. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. High-quality field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by us), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners and calculation and payment of ad valorem and production taxes on behalf of interest owners. In order to compete effectively, we must maintain records of title and division order interests in an accurate and timely manner for purposes of making prompt and correct payment of crude oil production proceeds, together with the correct payment of all severance and production taxes associated with such proceeds. Credit. Our merchant activities involve the purchase of crude oil for resale and require significant extensions of credit by our suppliers of crude oil. In order to assure our ability to perform our obligations under crude oil purchase agreements, various credit arrangements are negotiated with our crude oil suppliers. Such arrangements include open lines of credit directly with us and standby letters of credit issued under our letter of credit facility. In the period immediately following the disclosure of the 1999 unauthorized trading losses, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. Currently, our letter of credit requirement levels are lower than those levels existing prior to the unauthorized trading losses. See "Unauthorized Trading Losses". When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. If we determine that a customer should receive a credit line, we must then decide on the amount of credit that should be extended. Since our typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. Credit review and analysis are also integral to our leasehold purchases. Payment for all or substantially all of the monthly leasehold production is sometimes made to the operator of the lease. The operator, in turn, is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, we must determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend us in the event any third party should bring a protest, action or complaint in connection with the ultimate distribution of production proceeds by the operator. OPERATING ACTIVITIES See Note 17 in the Notes to the Consolidated and Combined Financial Statements appearing elsewhere in this report for information with respect to our pipeline activities and terminalling and storage and gathering and marketing activities and also those of our predecessor. 15
CUSTOMERS Customers accounting for more than 10% of sales for the periods indicated are as follows: <TABLE> <CAPTION> PERCENTAGE ---------------------------------------------------------------------------- NOVEMBER 23, JANUARY 1, YEAR ENDED DECEMBER 31, 1998 TO 1998 TO -------------------------------- DECEMBER 31, NOVEMBER 22, CUSTOMER 2000 1999 1998 1998 - ---------------------------------- ------------ --------- ------------ ------------ <S> <C> <C> <C> <C> Marathon Ashland Petroleum 12% - - - Sempra Energy Trading Corporation - 22% 20% 31% Koch Oil Company - 19% - 19% ExxonMobil - - 11% - </TABLE> All of the customers above pertain to our marketing, gathering, terminalling and storage segment. COMPETITION Competition among pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. We believe that high capital requirements, environmental considerations and the difficulty in acquiring rights of way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. We face intense competition in our terminalling and storage activities and gathering and marketing activities. Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil. REGULATION Our operations are subject to extensive regulations. Many federal, state and local departments and agencies are authorized by statute to issue and have issued laws and regulations binding on the oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil industry increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state and local regulations that may affect us, directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations. Pipeline Regulation Our petroleum pipelines are subject to regulation by the U.S. Department of Transportation with respect to the design, installation, testing, construction, operation, replacement, and management of pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations. We believe that our pipeline operations are in substantial compliance with applicable requirements. Pipeline safety issues are currently receiving significant attention in various political and administrative arenas at both the state and federal levels. For example, a pipeline safety bill passed the Senate late last year but was defeated in the House. In the current Congress, the Senate has approved a similar bill unanimously. These developments renew the prospect of incurring significant expenses if additional safety requirements are imposed that exceed our current pipeline control system capabilities. States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. 16
Transportation Regulation General Interstate Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes crude oil, as well as refined product and petrochemical pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to proposed new or changed rates by protest, and challenges to rates that are already final and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain reparations for overcharges sustained for a period of up to two years prior to the filing of a complaint. The FERC is authorized to suspend the effectiveness of a new or changed tariff rate for a period of up to seven months and to investigate the rate. If upon the completion of an investigation the FERC finds that the rate is unlawful, it will order the pipeline to change its rates prospectively to the lawful level and may require the pipeline to refund to shippers, with interest, any difference between the rates the FERC determines to be lawful and the rates under investigation. In general, petroleum pipeline rates must be cost-based, although settlement rates, which are rates that have been agreed to by all shippers, are permitted, and market-based rates may be permitted in certain circumstances. Cost-based rates are just and reasonable if they generate operating revenues, on the basis of projected volumes, not greater than the total of operating expenses, depreciation and amortization, federal and state income taxes and an allowed rate of return on the pipeline's "rate base." Energy Policy Act of 1992 and Subsequent Developments. In October 1992, Congress passed the Energy Policy Act of 1992, which among other things, required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing several orders, including Order No. 561. Beginning January 1, 1995, Order No. 561 enables petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made pursuant to the indexing methodology are subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. The Act deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show that a substantial change has occurred since enactment in either the economic circumstances or the nature of the services which were a basis for the rate or that a provision of the tariff is unduly discriminatory or preferential. In a proceeding involving Lakehead Pipe Line Company, Limited Partnership (Opinion No. 397), FERC concluded that there should not be a corporate income tax allowance built into a petroleum pipeline's rates to reflect income attributable to noncorporate partners since noncorporate partners, unlike corporate partners, do not pay a corporate income tax. On January 13, 1999, the FERC issued Opinion No. 435 in a Santa Fe Proceeding, which, among other things, affirmed Opinion No. 397's determination that there should not be a corporate income tax allowance built into a petroleum pipeline's rates to reflect income attributable to noncorporate partners. On rehearing, the FERC affirmed its position; however, additional rehearing requests on other matters remain pending. Petitions for review of Opinion No. 435 are before the D.C. Circuit Court of Appeals, but are being held in abeyance pending FERC action on the remaining rehearing requests. Once the rehearing process is completed, the FERC's position on the income tax allowance and on other rate issues could be subject to judicial review. Our Pipelines. The FERC generally has not investigated rates, such as those currently charged by us, which have been mutually agreed to by the pipeline and the shippers or which are significantly below cost of service rates that might otherwise be justified by the pipeline under the FERC's cost-based ratemaking methods. Substantially all of our gross margins on transportation are produced by rates that are either grandfathered or set by agreement of the parties. The indexing method has not required a reduction in these rates. Rates for OCS crude are set by transportation agreements with shippers that do not expire until 2007 and provide for a minimum tariff with annual escalation. The FERC has twice approved the agreed OCS rates, although application of the indexing method would have required their reduction. When these OCS agreements expire in 2007, they will be subject to renegotiation or to any of the other methods for establishing rates under Order No. 561. As a 17
result, we believe that the rates now in effect can be sustained, although no assurance can be given that the rates currently charged would ultimately be upheld if challenged. In addition, we do not believe that an adverse determination on the tax allowance issue in the Santa Fe Proceeding would have a detrimental impact upon our current rates. Trucking Regulation We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Department of Transportation. The trucking regulations cover, among other things, driver operations, keeping of log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to the Occupational Safety and Health Act, as amended ("OSHA"), with respect to our trucking operations. ENVIRONMENTAL REGULATION General Numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment affect our operations and costs. In particular, our activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and wastes are subject to stringent environmental laws and regulations. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Although these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position because our competitors that comply with such laws and regulations are similarly affected. Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of such laws and regulations on our operations. Violation of these environmental laws and regulations and any associated permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage. Water The Oil Pollution Act, as amended ("OPA"), was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), and other statutes as they pertain to prevention and response to oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages, and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. The OPA establishes a liability for onshore facilities of $350.0 million; however, a party cannot take advantage of this liability limit if the spill is caused by gross negligence or willful misconduct or resulted from a violation of a federal safety, construction, or operating regulation. If a party fails to report a spill or cooperate in the cleanup, the liability limits likewise do not apply. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations have been or are currently being developed under OPA and state laws that may also impose additional regulatory burdens on our operations. The FWPCA imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA imposes substantial potential liability for the costs of removal, remediation and damages. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations. Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with these state requirements. 18
Air Emissions Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local statutes. We believe that our operations are in substantial compliance with these statutes in all states in which we operate. Amendments to the federal Clean Air Act enacted in late 1990 (the "1990 Federal Clean Air Act Amendments") require or will require most industrial operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the U.S. Environmental Protection Agency (the "EPA") and state environmental agencies. In addition, the 1990 Federal Clean Air Act Amendments include a new operating permit for major sources ("Title V permits"), which applies to some of our facilities. Although we can give no assurances, we believe implementation of the 1990 Federal Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations. Solid Waste We generate wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes. The EPA is considering the adoption of stricter disposal standards for non-hazardous wastes, including oil and gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated as non-hazardous wastes during operations, will in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations could result in additional capital expenditures or operating expenses for us as well as the industry in general. Hazardous Substances The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been disposed of or released into the environment. We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. OSHA We are subject to the requirements of OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. 19
Endangered Species Act The Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered species or their habitats. While certain of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the ESA. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or operation restrictions or bans in the affected area. Hazardous Materials Transportation Requirements The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of oil discharge from onshore oil pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in substantial compliance with such regulations. ENVIRONMENTAL REMEDIATION In connection with our acquisition of Scurlock Permian, we identified a number of areas of potential environmental exposure. Under the terms of our acquisition agreement, Marathon Ashland is fully indemnifying us for areas of environmental exposure which were identified at the time of the acquisition, including any and all liabilities associated with two superfund sites at which it is alleged Scurlock Permian deposited waste oils as well as any potential liability for hydrocarbon soil and water contamination at a number of Scurlock Permian facilities. For environmental liabilities which were not identified at the time of the acquisition but which occurred prior to the closing, we have agreed to pay the costs relating to matters that are under $25,000. Our liabilities relating to matters discovered prior to May 2003 and that exceed $25,000, is limited to an aggregate of $1.0 million, with Marathon Ashland indemnifying us for any excess amounts. Marathon Ashland's indemnification obligations for identified sites extend indefinitely while its obligations for non-identified sites extend to matters discovered within four years of the date of acquisition (May 12, 1999) of Scurlock Permian. While we do not believe that our liability, if any, for environmental contamination associated with our Scurlock Permian assets will be material, there can be no assurance in that regard. In any event, should we be found liable, we believe that our indemnification from Marathon Ashland should prevent such liability from having a material adverse effect on our financial condition, results of operations or cash flows. In connection with our acquisition of the West Texas Gathering System, we agreed to be responsible for pre-acquisition environmental liabilities up to an aggregate amount of $1.0 million, while Chevron Pipe Line Company agreed to remain solely responsible for liabilities which are discovered prior to July 2002 which exceed this $1.0 million threshold. During our pre-acquisition investigation, we identified a number of sites along our West Texas Gathering System on which there are hydrocarbon contaminated soils. While the total cost of remediation of these sites has not yet been determined, we believe our indemnification arrangement with Chevron Pipe Line Company should prevent such costs from having a material adverse effect on our financial condition, results of operations or cash flows. From 1994 to 1997, our Venice, Louisiana terminal experienced several releases of crude oil and jet fuel into the soil. The Louisiana Department of Environmental Quality has been notified of the releases. Marathon Ashland has performed some soil remediation related to the releases. The extent of the contamination at the sites is uncertain and there is a potential for groundwater contamination. We do not expect expenditures related to this terminal to be material, although we can provide no assurances in that regard. During 1997, the All American Pipeline experienced a leak in a segment of its pipeline in California which resulted in an estimated 12,000 barrels of crude oil being released into the soil. Immediate action was taken to repair the pipeline leak, contain the spill and to recover the released crude oil. We have expended approximately $400,000 to date in connection with this spill and do not expect any additional expenditures to be material, although we can provide no assurances in that regard. Prior to being acquired by our predecessor in 1996, the Ingleside Terminal experienced releases of refined petroleum products into the soil and groundwater underlying the site due to activities on the property. We are undertaking a voluntary state-administered remediation of the contamination on the property to determine the extent of the contamination. We have spent approximately $140,000 to date in investigating the contamination at this site. We do not anticipate the total additional costs related to this site to exceed $250,000, although no assurance can be given that the actual cost could not exceed such estimate. In addition, a portion of any such costs may be reimbursed to us from Plains Resources. 20
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. While we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. OPERATIONAL HAZARDS AND INSURANCE A pipeline may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damages and suspension of operations. We maintain insurance of various types that we consider to be adequate to cover our operations and properties. The insurance covers all of our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. TITLE TO PROPERTIES Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property and in some instances such rights- of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. All of the pump stations are located on property owned in fee or property under long-term leases. In certain states and under certain circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines. Some of the leases, easements, rights-of-way, permits and licenses transferred to us, upon our formation in 1998 and in connection with acquisitions we have made since that time, required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. Our general partner believes that it has obtained such third-party consents, permits and authorizations as are sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects as described in this report. With respect to any consents, permits or authorizations that have not yet been obtained, our general partner believes that such consents, permits or authorizations will be obtained within a reasonable period, or that the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business. Our general partner believes that we have satisfactory title to all of our assets. Although title to such properties are subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, our general partner believes that none of such burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business. EMPLOYEES To carry out our operations, our general partner or its affiliates employed approximately 915 employees at December 31, 2000. None of the employees of our general partner were represented by labor unions, and our general partner considers its employee relations to be good. 21
ITEM 3. LEGAL PROCEEDINGS Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of our general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name our general partner and Plains Resources as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of our general partner and the board of directors of Plains Resources. All such amounts were reflected in our financial statements at December 31, 2000. The settlement is subject to a number of conditions, including final approval by the court. A hearing is set for March 30, 2001. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named our general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Susser v. Plains All American Inc. as the complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. The plaintiffs in the Delaware derivative litigation seek that the defendants . account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses; . establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices detrimental to Plains All American; . pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees; and . provide the plaintiffs any additional relief as may be just and proper under the circumstances. We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court of the Southern District of Texas entitled Fernandes v. Plains All American Inc., et al, naming our general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation, described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. We intend to vigorously defend the claims made in the Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial position or results of operation. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS The common units, excluding the Class B common units, are listed and traded on the New York Stock Exchange under the symbol "PAA". On March 22, 2001, the market price for the common units was $22 4/5 per unit and there were approximately 14,378 recordholders and beneficial owners (held in street name). The following table sets forth high and low sales prices for the common units as reported on the New York Stock Exchange Composite Tape, and the cash distributions paid per common unit for the periods indicated: <TABLE> <CAPTION> COMMON UNIT PRICE RANGE ----------------------------------------------- CASH HIGH LOW DISTRIBUTIONS --------------------- -------------------- ------------------- <S> <C> <C> <C> 2000: 1st Quarter $16 9/16 $13 $0.450 2nd Quarter 18 5/8 15 1/4 0.463 3rd Quarter 19 3/4 18 0.463 4th Quarter 20 1/16 18 0.463 1999: 1st Quarter $19 $15 7/8 $0.450 2nd Quarter 19 15/16 16 5/16 0.463 3rd Quarter 20 17 3/8 0.481 4th Quarter 20 1/4 9 5/8 0.450 (1) </TABLE> - -------------------- (1) A distribution was not made on the subordinated units for the fourth quarter of 1999. The Class B common units are pari passu with common units with respect to quarterly distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, the Class B units have the same voting rights as the common units. We have also issued subordinated units, all of which are held by an affiliate of our general partner, for which there is no established public trading market. We will distribute to our partners (including holders of subordinated units), on a quarterly basis, all of our available cash in the manner described herein. Available cash generally means, for any of our fiscal quarters, all cash on hand at the end of the quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to: . provide for the proper conduct of our business; . comply with applicable law, any of our debt instruments or other agreements; or . provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters. Minimum quarterly distributions are $0.45 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. The expiration of the subordination period will generally not occur prior to December 31, 2003. Under the terms of our bank credit agreement and letter of credit and borrowing facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources". 23
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (in thousands, except unit and operating data) On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of our predecessor. The historical financial information below for Plains All American Pipeline was derived from our audited consolidated financial statements as of December 31, 2000, 1999 and 1998, and for the years ended December 31, 2000 and 1999 and for the period from November 23, 1998 through December 31, 1998. The financial information below for our predecessor was derived from the audited combined financial statements of our predecessor, as of December 31, 1997 and 1996 and for the period from January 1, 1998 through November 22, 1998 and for the years ended December 31, 1997 and 1996, including the notes thereto. The operating data for all periods is derived from our records as well as those of our predecessor. Commencing May 1, 1999, the results of operations of the Scurlock Permian businesses are included in our results of operations. Commencing July 30, 1998, the results of operations of the All American Pipeline and the SJV Gathering System are included in the results of operations of our predecessor and Plains All American Pipeline. The selected financial data should be read in conjunction with the consolidated and combined financial statements, including the notes thereto, included elsewhere in this report, and Item 7, -"Management's Discussion and Analysis of Financial Condition and Results of Operations". <TABLE> <CAPTION> PREDECESSOR ----------------------------------- NOVEMBER 23, JANUARY 1, YEAR ENDED YEAR ENDED DECEMBER 31, 1998 TO 1998 TO DECEMBER 31, ------------------------ DECEMBER 31, NOVEMBER 22, ------------------- 2000 1999 1998 1998 1997 1996 ---------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> Statement of Operations Data: Revenues (1) $6,641,187 $10,910,423 $398,918 $3,118,353 $2,815,278 $1,996,715 Cost of sales and operations (1) 6,506,504 10,800,109 391,419 3,087,372 2,802,798 1,987,184 Unauthorized trading losses and related expenses (2) 6,963 166,440 2,400 4,700 - - ---------- ----------- -------- ---------- ---------- ---------- Gross margin 127,720 (56,126) 5,099 26,281 12,480 9,531 ---------- ----------- -------- ---------- ---------- ---------- General and administrative expenses (3) 40,821 23,211 771 4,526 3,529 2,974 Depreciation and amortization 24,523 17,344 1,192 4,179 1,165 1,140 Restructuring expense - 1,410 - - - - ---------- ----------- -------- ---------- ---------- ---------- Total expenses 65,344 41,965 1,963 8,705 4,694 4,114 ---------- ----------- -------- ---------- ---------- ---------- Operating income (loss) 62,376 (98,091) 3,136 17,576 7,786 5,417 Interest expense (28,691) (21,139) (1,371) (11,260) (4,516) (3,559) Gain on sale of assets (4) 48,188 16,457 - - - - Interest and other income (5) 10,776 958 12 572 138 90 ---------- ----------- -------- ---------- ---------- ---------- Net income (loss) before provision (benefit) in lieu of income taxes and extraordinary item 92,649 (101,815) 1,777 6,888 3,408 1,948 Provision (benefit) in lieu of income taxes - - - 2,631 1,268 726 ---------- ----------- -------- ---------- ---------- ---------- Net income (loss) before extraordinary item $ 92,649 $ (101,815) $ 1,777 $ 4,257 $ 2,140 $ 1,222 ========== =========== ======== ========== ========== ========== Basic and diluted net income (loss) per limited partner unit before extraordinary item (6) $ 2.64 $ (3.16) $ 0.06 $ 0.25 $ 0.12 $ 0.07 ========== =========== ======== ========== ========== ========== Weighted average number of limited partner units outstanding 34,386 31,633 30,089 17,004 17,004 17,004 ========== =========== ======== ========== ========== ========== Table and footnotes continued on following page </TABLE> 24
<TABLE> <CAPTION> PREDECESSOR ----------------------------------- NOVEMBER 23, JANUARY 1, YEAR ENDED YEAR ENDED DECEMBER 31, 1998 TO 1998 TO DECEMBER 31, ------------------------ DECEMBER 31, NOVEMBER 22, ------------------- 2000 1999 1998 (1) 1998 (1) 1997 1996 ---------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> BALANCE SHEET DATA: (at end of period): Working capital (9) $ 47,111 $ 101,539 $ 2,231 N/A $ 2,017 $ 2,586 Total assets 885,801 1,223,037 607,186 N/A 149,619 122,557 Related party debt - Long-term - 114,000 - N/A 28,531 31,811 Total debt (10) 321,300 368,819 184,750 N/A 18,000 - Partners' capital 213,999 192,973 270,543 N/A - - Combined equity - - - N/A 5,975 3,835 OTHER DATA: EBITDA (7) $ 103,048 $ 89,074 $ 6,740 $ 27,027 $ 9,089 $ 6,647 Maintenance capital expenditures (8) 1,785 1,741 200 1,508 678 1,063 Net cash provided by (used in) operating activities (33,511) (71,245) 7,218 21,384 (12,869) 733 Net cash provided by (used in) investing activities 211,001 (186,093) (3,089) (399,611) (1,854) (3,285) Net cash provided by (used in) financing activities (227,832) 305,603 1,374 386,154 14,321 2,759 OPERATING DATA: Volumes (barrels per day): All American Tariff (11) 73,800 102,700 110,200 113,700 - - Margin (12) 60,000 54,100 50,900 49,100 - - Other 106,500 61,400 - - - - -------- ---------- -------- -------- -------- -------- Total pipeline 240,300 218,200 161,100 162,800 - - ======== ========== ======== ======== ======== ======== Lease gathering (13) 262,600 264,700 126,200 87,100 71,400 58,500 Bulk purchases (14) 27,700 138,200 133,600 94,700 48,500 31,700 ======== ========== ======== ======== ======== ======== Total 290,300 402,900 259,800 181,800 119,900 90,200 ======== ========== ======== ======== ======== ======== Terminal throughput (15) 67,000 83,300 61,900 81,400 76,700 59,800 ======== ========== ======== ======== ======== ======== </TABLE> - ----------------------- (1) We have reclassified Revenues and Costs of Sales and Operations for periods prior to 2000 in accordance with Emerging Issues Task Force ("EITF") Issue No. 99-19 - "Recording Revenue Gross as a Principal versus Net as an Agent". See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Accounting Pronouncements". Reclassifications to Revenues and Cost of sales and operations for the years ended December 31, 2000 and 1999, for the periods November 23, 1988 to December 31, 1998 and January 1, 1998 to November 22, 1998 and for the years ended December 31, 1997 and 1996 were $2.5 billion, $6.2 billion, $0.2 billion, $2.1 billion, $2.0 billion and $1.4 billion, respectively. This reclassification had no effect on earnings. (2) In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses of which $166.4 million and $7.1 million was recognized in 1999 and 1998, respectively). In 2000, we recognized an additional $7.0 million charge for litigation related to the unauthorized trading losses. See Item 1. - "Business - Unauthorized Trading Losses". (3) General and administrative expense for 2000 includes a $5.0 million charge to reserve potentially uncollectible accounts receivable. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations". (4) In March 2000, we completed the sale of 5.2 million barrels of crude oil linefill from the All American Pipeline. We recognized gains of $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with that sale. We also sold a segment of the All American Pipeline to El Paso and recognized a gain of $20.1 million in the first quarter of 2000. See Item 1. - "Acquisitions and Dispositions - All American Pipeline Linefill and Asset Disposition". (5) For the year ended December 31, 2000, this amount includes $9.7 million of previously deferred gains from terminated interest rate swaps recognized as a result of debt extinguishment. (6) Basic and diluted net income (loss) per unit is computed by dividing the limited partners' interest in net income by the number of outstanding common and subordinated units. For periods prior to November 23, 1998, the number of units are equal to the common and subordinated units received by our general partner in exchange for the assets contributed to the partnership. (7) EBITDA means earnings before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA also excludes unauthorized trading losses, noncash compensation, restructuring expense, gains on the sale of linefill and pipeline, allowance for accounts receivable and extraordinary loss from extinguishment of debt. Adjusted EBITDA is not a measurement presented in accordance with GAAP and is not intended to be used in lieu of GAAP presentations of results of operations and cash provided by operating activities. EBITDA is commonly used by debt holders and financial statement users as a measurement to determine the ability of an entity to meet its interest obligations. Footnotes continued on following page 25
(8) Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of existing assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand operating capacity are charged to expense as incurred. (9) At December 31, 1999, working capital includes $37.9 million of pipeline linefill and $103.6 million for the segment of the All American Pipeline that were both sold in the first quarter of 2000. See Item 1. - "Acquisitions and Dispositions - All American Pipeline Linefill and Asset Disposition". (10) Excludes related party debt. (11) Represents crude oil deliveries on the All American Pipeline for the account of third parties. (12) Represents crude oil deliveries on the All American Pipeline and the SJV Gathering System for the account of affiliated entities. (13) Represents barrels of crude oil purchased at the wellhead, including volumes which were purchased under the Marketing Agreement. (14) Represents barrels of crude oil purchased at collection points, terminals and pipelines. (15) Represents total crude oil barrels delivered from the Cushing Terminal and the Ingleside Terminal. 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion of our financial condition and results of our operations and those of the midstream subsidiaries of Plains Resources (our "predecessor") should be read in conjunction with our historical consolidated and combined financial statements and accompanying notes and those of our predecessor included elsewhere in this report. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical consolidated and combined financial statements. OVERVIEW We were formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of our predecessor. Our operations are conducted through Plains Marketing, L.P. and All American Pipeline, L.P. Plains All American Inc., a wholly owned subsidiary of Plains Resources, is our general partner. We are engaged in interstate and intrastate marketing, transportation and terminalling of crude oil. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling." Pipeline Operations. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff and merchant activities designed to capture price differentials between the cost to purchase and transport crude oil to a sales point and the price received for such crude oil at the sales point. Tariffs on our pipeline systems vary by receipt point and delivery point. The gross margin generated by our tariff activities depends on the volumes transported on the pipeline and the level of the tariff charged, as well as the fixed and variable costs of operating the pipeline. Our ability to generate a profit on margin activities is not tied to the absolute level of crude oil prices but is generated by the difference between an index related price paid and other costs incurred in the purchase of crude oil and an index related price at which we sell crude oil. We are well positioned to take advantage of these price differentials due to our ability to move purchased volumes on our pipeline systems. We combine reporting of gross margin for tariff activities and margin activities due to the sharing of fixed costs between the two activities. Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage activities is dependent on the throughput volume of crude oil stored and the level of fees generated at our terminalling and storage facilities. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. These operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and fluctuations in market related indices. During periods when the demand for crude oil is weak (as was the case in late 1997, 1998 and the first quarter of 1999), the market for crude oil is often in contango, meaning that the price of crude oil for future deliveries is higher than current prices. A contango market has a generally negative impact on marketing margins, but is favorable to the storage business, because storage owners at major trading locations (such as the Cushing Interchange) can simultaneously purchase production at low current prices for storage and sell at higher prices for future delivery. When there is a higher demand than supply of crude oil in the near term, the market is backward, meaning that the price of crude oil for future deliveries is lower than current prices. A backward market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. We purchase crude oil on both a fixed and floating price basis. As fixed price barrels are purchased, we enter into sales arrangements with refiners, trade partners or on the NYMEX, which establishes a margin and protects it against future price fluctuations. When floating price barrels are purchased, we match those contracts with similar type sales agreements with our customers, or likewise establish a hedge position using the NYMEX futures market. From time to time, we enter into arrangements that will expose us to basis risk. Basis risk occurs when crude oil is purchased based on a crude oil specification and location that differs from the countervailing sales arrangement. Our policy is only to purchase crude oil for which we have a market, and to structure our sales contracts so that crude oil price fluctuations do not materially affect the gross margin which we receive. In November 1999, we discovered that this policy was violated. See Item 1. "Business - Unauthorized Trading Losses" and "Unauthorized Trading Losses" 27
below. We do not acquire and hold crude oil futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses. RECENT DEVELOPMENTS Consistent with our publicly announced intention to expand operations into Canada, we are pursuing the acquisition of certain Canadian assets in two separate transactions for aggregate consideration of approximately $200.0 million. See "Liquidity and Capital Resources - Recent Developments". UNAUTHORIZED TRADING LOSSES In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $174.0 million which includes estimated associated costs and legal expenses. Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and the remainder in 1999. In 2000, we recognized an additional $7.0 million charge for litigation related to the unauthorized trading losses. See Item 1. "Business - Unauthorized Trading Losses" for a discussion of the unauthorized trading loss, its financial effects and the steps taken to prevent future violations of our trading policies. See Item 3. - "Legal Proceedings". RESULTS OF OPERATIONS In the fourth quarter of 2000, we adopted EITF 99-19. Prior to this adoption, we reported the results of certain of our crude oil buy/sell and exchange activities on a net margin basis. Under EITF 99-19, we report these activities as gross revenues and costs of sales and operations. Revenues and costs of sales and operations for all periods presented have been reclassified to reflect this adoption, with no effect on earnings. Analysis of Three Years Ended December 31, 2000. The results of operations for the year ended December 31, 1999 include the results of the Scurlock acquisition effective May 1, 1999 and the West Texas Gathering System acquisition effective July 1, 1999. The combined results of operations for the year ended December 31, 1998 are derived from our financial statements for the period from November 23, 1998 through December 31, 1998, and the combined financial statements of our predecessor for the period from January 1, 1998 through November 22, 1998, which in the following discussion are combined and referred to as the year ended December 31, 1998. Commencing July 30, 1998 (the date of acquisition of the All American Pipeline and the SJV Gathering System from Goodyear), the results of operations of the All American Pipeline and the SJV Gathering System are included in the results of operations of the predecessor. For 2000, we reported net income of $77.5 million on total revenue of $6.6 billion compared to a net loss for 1999 of $103.4 million on total revenue of $10.9 billion and net income for 1998 of $6.0 million on total revenue of $3.5 billion. The results for the years ended December 31, 2000, 1999 and 1998 include the following items: 2000 . a $28.1 million gain on the sale of crude oil linefill; . a $20.1 million gain on the sale of the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas; . $9.7 million of previously deferred gains on interest rate swap terminations recognized due to the early extinguishment of debt; . an extraordinary loss of $15.1 million related to the early extinguishment of debt; . a $7.0 million charge for litigation related to the unauthorized trading losses; . a $5.0 million reserve for potentially uncollectible accounts receivable; . amortization of $4.6 million of debt issue costs associated with facilities put in place during the fourth quarter of 1999; and . $3.1 million of noncash compensation expense. 28
1999 . $166.4 million of unauthorized trading losses; . a $16.5 million gain on the sale of crude oil linefill that was sold in 1999; . restructuring expense of $1.4 million; . an extraordinary loss of $1.5 million related to the early extinguishment of debt; and . $1.0 million of noncash compensation expense. 1998 . $7.1 million of unauthorized trading losses. Excluding the items listed above, we would have reported net income of $54.4 million, $50.6 million and $11.2 million for the years ended December 31, 2000, 1999 and 1998, respectively. Excluding the unauthorized trading losses, we reported gross margin (revenues less direct expenses of purchases, transportation, terminalling and storage and other operating and maintenance expenses) of $134.7 million for the year ended December 31, 2000 compared to $110.3 million and $38.5 million reported for 1999 and 1998, respectively. Gross profit (gross margin less general and administrative expense), also excluding the unauthorized trading losses, was $93.9 million, $87.1 million and $33.2 million for the years ended December 31, 2000, 1999 and 1998, respectively. The following table sets forth combined financial and operating information for the periods presented and includes the impact of the items discussed above (in thousands): <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Operating Results: Revenues $6,641,187 $10,910,423 $3,517,271 ========== =========== ========== Gross margin Pipeline $ 51,787 $ 58,001 $ 16,768 Terminalling and storage and gathering and marketing 82,896 52,313 21,712 Unauthorized trading losses (6,963) (166,440) (7,100) ---------- ----------- ---------- Total 127,720 (56,126) 31,380 General and administrative expense (40,821) (23,211) (5,297) ---------- ----------- ---------- Gross profit $ 86,899 $ (79,337) $ 26,083 ========== =========== ========== Extraordinary item $ (15,147) $ (1,545) $ - ========== =========== ========== Net income (loss) $ 77,502 $ (103,360) $ 6,034 ========== =========== ========== AVERAGE DAILY VOLUMES (BARRELS): Pipeline Activities: All American Tariff activities 74 103 113 Margin activities 60 54 50 Other 107 61 - ---------- ----------- ---------- Total 241 218 163 ========== =========== ========== Lease gathering 262 265 88 Bulk purchases 28 138 98 ---------- ----------- ---------- Total 290 403 186 ========== =========== ========== Terminal throughput 67 83 80 ========== =========== ========== Storage leased to third parties, monthly average volumes 1,657 1,975 1,150 ========== =========== ========== </TABLE> Revenues. Total revenues were $6.6 billion, $10.9 billion and $3.5 billion for 2000, 1999 and 1998, respectively. The decrease in 2000 as compared to 1999 was primarily attributable to lower buy/sell and exchange volumes associated with our gathering and marketing activities, partially offset by higher crude oil prices. The increase in 1999 as compared to 1998 was primarily due to increased volumes from our gathering and marketing activities, partially attributable to the May 1999 Scurlock acquisition, as well as higher crude oil prices. 29
Cost of Sales and Operations. Cost of sales and operations increased to $6.5 billion from $10.8 billion and $3.5 billion in 1999 and 1998, respectively, primarily due to the reasons discussed above for revenues. Unauthorized trading losses. As previously discussed, we recognized losses of approximately $7.0 million, $166.4 million and $7.1 million in 2000, 1999 and 1998, respectively, as a result of unauthorized trading by a former employee. See "Unauthorized Trading Losses." General and Administrative. General and administrative expenses were $40.8 million for the year ended December 31, 2000, compared to $23.2 million and $5.3 million for 1999 and 1998, respectively. The increase from 1999 to 2000 is primarily due to (1) a $5.0 million reserve for potentially uncollectible accounts receivable, (2) the Scurlock acquisition in mid-1999 ($5.7 million), (3) consulting fees related to the unauthorized trading loss investigation, (4) consulting and accounting charges related to system modifications and enhancements and implementation of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") and (5) noncash compensation expense. The increase from 1998 to 1999 was primarily attributable to the Scurlock and West Texas Gathering System acquisitions in 1999 ($13.1 million), the All American Pipeline acquisition in 1998 ($0.7 million), expenses related to our operations as a public entity ($0.7 million) and continued expansion of our business activities. During 2000, a review of our accounts receivable indicated that certain amounts would not be collectible within one year. Accordingly, we reclassified approximately $10.0 million of accounts receivable from current assets to other assets. In addition, we recorded a $5.0 million charge to reserve for potentially uncollectible accounts receivable. During 2000 and 1999, we incurred charges of $3.1 million and $1.0 million, respectively, related to noncash incentive compensation paid to certain officers and key employees of Plains All American Inc. and its affiliates. In 1998 and 2000, Plains All American Inc. granted its employees the right to earn ownership in our common units owned by Plains All American Inc. The units vest over a three-year period subject to paying distributions on the common and subordinated units. See Item 11.- "Executive Compensation - Transaction Grant Agreements," and Item 12. - "Security Ownership of Certain Beneficial Owners and Management." These amounts are included in general and administrative expense on the Consolidated Statements of Operations. We expect general and administrative expenses to run approximately $8.5 million to $9.0 million per quarter during the first six months of 2001, as we complete modifications to our existing systems and processes and we pursue collection of the accounts receivable that were reserved. This expectation is approximately $1.0 million to $1.5 million higher than what we estimate our normal expenses will be, exclusive of the recently announced acquisitions. Depreciation and Amortization. Depreciation and amortization expense was $24.5 million in 2000, $17.3 million in 1999 and $5.4 million in 1998. Approximately $5.1 million of the increase in 2000 as compared to 1999 is due to increased amortization expense, primarily related to amortization of debt issue costs associated with facilities put in place during the fourth quarter of 1999, subsequent to the unauthorized trading losses. The remaining increase is attributable to the Scurlock and West Texas Gathering System acquisitions which were effective May 1, 1999 and July 1, 1999, respectively, as well as our 1999 and 2000 expansion capital additions. The increase in 1999 is due primarily to the aforementioned acquisitions. Restructuring expense. We incurred a $1.4 million restructuring charge in 1999, primarily associated with severance-related expenses of 24 employees who were terminated. As of December 31, 1999, all severance costs were paid and the terminated employees were not employed by us. Interest expense. Interest expense was $28.7 million in 2000, $21.1 million in 1999 and $12.6 million in 1998. The increase in 2000 is primarily due to higher interest rates as well as slightly higher debt balances. The increase in 1999 is due to (1) interest associated with the debt incurred for the Scurlock and West Texas Gathering System acquisitions, (2) a full year of interest for the All American Pipeline acquisition, (3) an increase in interest related to hedged inventory transactions and (4) an increase in interest rates as a result of the unauthorized trading losses. Gain on sale of assets. In March 2000, we sold to a unit of El Paso for $129.0 million the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. Except for minor third-party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce outstanding debt. We recognized a gain of approximately $20.1 million in connection with the sale. We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We 30
recognized gains of approximately $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with the sale of the linefill. Early extinguishment of debt. During 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $15.1 million related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of our credit facilities. In addition, interest and other income for the year ended December 31, 2000, includes $9.7 million of previously deferred gains from terminated interest rate swaps as a result of debt extinguishment. The extraordinary item of $1.5 million in 1999 relates to the write-off of certain debt issue costs and penalties associated with the prepayment of debt. Segment Results Pipeline Operations. Gross margin from pipeline operations was $51.8 million for the year ended December 31, 2000, compared to $58.0 million for 1999 and $16.8 million for 1998. Gross margin from pipeline activities was negatively impacted on a comparative basis in 2000 due to the sale of the California to West Texas portion of the All American Pipeline, decreased tariff volumes from California OCS production and slightly higher fuel and power charges in 2000. These decreases in 2000 were partially offset by increased margins from the Scurlock and West Texas gathering system acquisitions in mid-1999. The increase in 1999 resulted primarily from twelve months of results from the All American Pipeline in 1999 versus five months in 1998, increased margins from our pipeline merchant activities, and to the two 1999 acquisitions. The margin between revenue and direct cost of crude purchased from our pipeline margin activities was $21.1 million for the year ended December 31, 2000, compared to $35.6 million and $3.9 million for 1999 and 1998, respectively. Pipeline tariff revenues were approximately $47.0 million for the year ended December 31, 2000 compared to approximately $46.4 million for 1999 and approximately $19.0 million for 1998. Pipeline operations and maintenance expenses were approximately $16.3 million, $24.0 million and $6.1 million for the years ended December 31, 2000, 1999 and 1998, respectively. Average daily pipeline volumes totaled 241,000 barrels per day, 218,000 barrels per day and 163,000 barrels per day in 2000, 1999 and 1998, respectively. Volumes on the All American Pipeline decreased from an average of 157,000 barrels per day in 1999 to 134,000 barrels per day in 2000 due to the reasons discussed above. All American's tariffs volumes attributable to California OCS production were approximately 74,000 barrels per day in 2000 compared to 79,000 barrels per day in 1999. Volumes from the Santa Ynez and Point Arguello fields, both offshore California, have steadily declined from 1995 through 2000. A 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline tariff revenues of approximately $2.6 million. Tariff volumes shipped on the Scurlock and West Texas gathering systems averaged 107,000 barrels per day and 61,000 barrels per day in 2000 and 1999, respectively. The 1999 period includes volumes for Scurlock effective May 1, 1999 and West Texas gathering system volumes effective July 1, 1999. Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from gathering and marketing and terminalling and storage activities was approximately $82.9 million for the year ended December 31, 2000, reflecting a 59% increase over the $52.3 million reported for 1999 and a 282% increase over the $21.7 million reported for 1998. The increase in gross margin is primarily due to a full year of results from the Scurlock acquisition and increased per barrel margins due to the strong crude oil market in 2000. Gross revenues from gathering, marketing, terminalling and storage activities were approximately $6.1 billion, $10.1 billion and $3.3 billion for the years ended December 31, 2000, 1999 and 1998, respectively. The decrease in 2000 as compared to 1999 was primarily attributable to lower buy/sell, exchange and bulk volumes, partially offset by higher crude oil prices. The increase in 1999 as compared to 1998 was primarily due to increased buy/sell, exchange, bulk and lease volumes, partially attributable to the May 1999 Scurlock acquisition, as well as higher crude oil prices. Lease gathering volumes averaged 262,000 barrels per day in 2000, 265,000 barrels per day in 1999 and 88,000 barrels per day in 1998. Bulk purchase volumes averaged 28,000 barrels per day, 138,000 barrels per day and 98,000 barrels per day in 2000, 1999 and 1998, respectively. The decreases in 2000 compared to 1999 are due primarily to a significant amount of low margin barrels that were phased out subsequent to the discovery of the trading losses, partially offset by increased volumes attributable to the Scurlock acquisition, which was effective May 1, 1999. The increase in 1999 compared to 1998 is due to the Scurlock acquisition. In the period immediately following the disclosure of the unauthorized trading losses, a significant number of our suppliers and trading partners reduced or eliminated the open credit previously extended to us. Consequently, the amount of letters of credit we needed to support the level of our crude oil purchases then in effect increased significantly. In addition, the cost to us of obtaining letters of credit increased under our credit facility. In many instances we arranged for letters of 31
credit to secure our obligations to purchase crude oil from our customers, which increased our letter of credit costs and decreased our unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, our purchase contracts were terminated. We estimate that adjusted EBITDA and net income was adversely affected by approximately $6.0 million in 2000 as a result of the increase in letter of credit costs and reduced volumes. Currently, our letter of credit requirement levels are lower than those levels existing prior to the unauthorized trading losses. Terminal throughput, which includes both our Cushing and Ingleside terminals, was 67,000, 83,000 and 80,000 barrels per day for the years ended December 31, 2000, 1999 and 1998, respectively. Storage leased to third parties averaged 1.8 million, 2.0 million and 1.2 million barrels per month for the same periods. LIQUIDITY AND CAPITAL RESOURCES Recent Developments Consistent with our publicly announced intention to expand operations into Canada, we are pursuing the acquisition of certain Canadian assets in two separate transactions for aggregate consideration of approximately $200.0 million. Set forth below is a brief description of the acquisitions. Murphy Oil Company Ltd. Midstream Operations On March 1, 2001, we signed an agreement to purchase substantially all of the crude oil pipeline, gathering, storage and terminalling assets of Murphy for approximately $155.0 million in cash, plus an additional cash payment, to be determined prior to closing in accordance with the agreement, for excess inventory in the systems (estimated to be approximately $5.0 million). The principal assets to be acquired include approximately 450 miles of crude oil and condensate transmission mainlines and associated gathering and lateral lines, and approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently inactive 108-mile mainline system and 121 trailers used primarily for crude oil transportation. Murphy has agreed to continue to transport production from fields currently delivering crude oil to these pipeline systems, under a new long-term contract. The current volume is approximately 11,000 barrels per day. The pipeline systems transport approximately 200,000 barrels per day of light, medium and heavy crudes, as well as condensate. Canadian Marketing Assets We have entered into a letter of intent to purchase the assets of a Canadian marketing company. The expected purchase price is approximately $43.0 million, of which approximately $18.0 million will be subject to certain performance targets. The marketing company currently generates annual EBITDA of approximately $10.0 million, gathering approximately 75,000 barrels per day of crude oil and marketing approximately 26,000 barrels per day of natural gas liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel tank facility and working capital of approximately $8.5 million. Initial financing for the acquisitions will be provided via an expansion of our existing revolving credit, letter of credit and inventory facility. The expanded facility will initially be underwritten by Fleet Boston and will consist of a $100.0 million five-year term loan and a $30.0 million revolving credit facility that will expire in April 2005. Consistent with our stated policy of maintaining a strong capital structure by funding acquisitions with a balance of debt and equity, we intend to refinance a portion of our bank facility with proceeds from future bond and equity financings. We intend to create and establish a midstream crude oil presence in Canada that is similar to our existing operations in the U.S. By using the knowledge and skills developed in our U.S. operations, we hope to generate attractive financial returns in the Canadian market through exploiting existing inefficiencies, while attempting to improve revenues and margins on our acquired pipeline, terminalling and gathering assets. These assets complement our current activities and enhance our ability to service the needs of refiners in the U.S. Midwest. The completion of both transactions, while independent of one another, will provide us with direct access to substantial Canadian wellhead volumes via gathering and pipeline systems and strategically located terminal and storage assets. General Cash generated from operations and our credit facilities are our primary sources of liquidity. At December 31, 2000, we had working capital of approximately $47.1 million and approximately $80.0 million of availability under our revolving credit facility. In connection with the previously discussed Canadian acquisitions, our existing credit facilities will be 32
expanded to $830.0 million. See "Credit Agreements." Consistent with our stated policy of maintaining a strong capital structure by funding acquisitions with a balance of debt and equity, we intend to refinance a portion of our credit facilities with proceeds from future bond and equity financings. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. Cash Flows YEAR ENDED DECEMBER 31, -------------------------------------- (in millions) 2000 1999 1998 ------------------------------------------------------------------- (COMBINED) Cash provided by (used in): Operating activities $ (33.5) $ (71.2) $ 28.6 Investing activities 211.0 (186.1) (402.7) Financing activities (227.8) 305.6 387.5 ------------------------------------------------------------------- Operating Activities. Net cash used in operating activities in 2000 and 1999 resulted primarily from the unauthorized trading losses. The losses were partially offset by increased margins due to the Scurlock and West Texas Gathering System acquisitions. Investing Activities. Net cash provided by investing activities for 2000 included approximately $224.0 million of proceeds from the sale of the All American Pipeline and pipeline linefill offset by approximately $12.6 million of capital expenditures. Capital expenditures for 2000 included approximately $10.8 million for expansion capital and $1.8 million for maintenance capital. Net cash used in investing activities for 1999 included approximately $176.9 million for acquisitions, primarily for the Scurlock and West Texas gathering system acquisitions, $11.1 million for expansion capital and $1.7 million for maintenance capital. Net cash used in investing activities for 1998 consisted primarily of approximately $394.0 million for the purchase of the All American Pipeline and SJV Gathering System. Financing activities. Cash used in financing activities in 2000 consisted primarily of (1) net payments of $47.5 million of short-term and long-term debt, (2) the repayment of subordinated debt of $114.0 million to our general partner and (3) distributions to unitholders of $59.6 million. Proceeds used to reduce the bank debt primarily came from the asset sales discussed above. Proceeds to repay the $114.0 million of subordinated debt to our general partner came from our revolving credit facility. Cash provided by financing activities in 1999 was generated from net issuances of (1) $76.5 million in common and Class B units, (2) $184.1 million of short-term and long-term debt and (3) $114.0 million of two subordinated notes to our general partner. Financing activities for 1999 includes $51.7 million in distributions to unitholders. Cash inflows from financing activities during 1998 included (1) $283.8 million from the net issuance of short-term and long-term debt and (2) a capital contribution of approximately $113.7 million from our general partner primarily in connection with the acquisition of the All American Pipeline and SJV Gathering System. In October 1999, we completed a public offering of an additional 2,990,000 common units, representing limited partner interests, at $18.00 per unit. Net proceeds, including our general partners' contribution, were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. The proceeds, together with our general partner's capital contribution of approximately $0.5 million to maintain its 2% general partner interest, were used to reduce outstanding debt. Capital Expenditures We have made and will continue to make capital expenditures for acquisitions and expansion and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, bank borrowings and the sale of additional common units. We intend to make aggregate capital expenditures of approximately $7.0 million in 2001 and believe that we will have sufficient cash from working capital, cash flow and availability under our revolving credit facility under our bank credit agreement. We estimate that capital expenditures necessary to maintain our existing asset base at current operating levels will be approximately $4.0 million to $5.0 million each year. 33
Commitments The aggregate amounts of maturities of all long-term indebtedness for the next five years at December 31, 2000 are: 2005 - $320.0 million. This amount is due under our revolving credit facility and reflects the February 2001 amendments to our revolving credit facility. We will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record, and to our general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter less reserves established for future requirements. Minimum quarterly distributions are $0.45 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. The expiration of the subordination period will generally not occur prior to December 31, 2003. There were no arrearages on common units at December 31, 2000. On February 14, 2001, we paid a cash distribution of $0.4625 per unit on our outstanding common units, Class B units and subordinated units. The distribution was paid to unitholders of record on February 2, 2001 for the period October 1, 2000 through December 31, 2000. The total distribution paid was approximately $16.3 million, with approximately $7.5 million paid to our public unitholders and the remainder paid to us for our limited and general partner interests. In connection with our crude oil marketing, we provide certain purchasers and transporters with irrevocable standby letters of credit to secure their obligation for the purchase of crude oil. Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 2000, we had outstanding letters of credit of approximately $59.7 million. Such letters of credit are secured by our crude oil inventory and accounts receivable. As is common within the industry, we have entered into various commitments and agreements related to the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows. Credit Agreements In May 2000, we entered into new bank credit agreements consisting of a $400.0 million senior secured revolving credit facility maturing in 2004 and a $300.0 million senior secured letter of credit and borrowing facility expiring in April 2003. At December 31, 2000, $320.0 million was outstanding on the revolving credit facility and $1.3 million in borrowings and $59.7 million in letters of credit were outstanding under the letter of credit and borrowing facility. In February 2001, our bank credit agreements were amended. The amount available under the senior secured revolving credit facility was increased to $500.0 million and the maturity date was extended to April 2005. The amount available under the senior secured letter of credit and borrowing facility was reduced to $200.0 million and the expiration date was extended to April 2004. In addition, the banks agreed to an amendment which will allow us to borrow an additional $130.0 million under the terms of the senior secured revolving credit facility to consummate the Canadian acquisitions. We have an underwritten commitment, subject to certain conditions, for the $130.0 million. Our bank credit agreements currently consist of: . a $500.0 million senior secured revolving credit, of which $492.0 million is currently available, facility which is secured by substantially all of our assets and matures in April 2005. No principal is scheduled for payment prior to maturity. The revolving credit facility bears interest at our option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin. We incur a commitment fee on the unused portion of the revolving credit facility. . A $200.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. The letter of credit facility is secured by substantially all of our assets and has a sublimit for cash borrowings of $100.0 million to purchase crude oil that has been hedged against future price risk. The letter of credit facility expires in April 2004. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base that is determined monthly based on certain of our current assets and current liabilities, primarily accounts receivable and accounts payable related to the purchase and sale of crude oil. 34
Our bank credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things: . incur indebtedness; . grant liens; . sell assets; . make investments; . engage in transactions with affiliates; . enter into prohibited contracts; and . enter into a merger or consolidation. Our bank credit agreements treat a change of control as an event of default and also require us to maintain: . a current ratio (as defined) of 1.0 to 1.0; . a debt coverage ratio which is not greater than 4.0 to 1.0 for the period from March 31, 2000, to March 31, 2002, and subsequently 3.75 to 1.0; . an interest coverage ratio which is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.65 to 1.0. The consummation of the Canadian marketing company acquisition will result in a change in the required debt coverage and debt to capital ratios to: . a debt coverage ratio which is not greater than 4.25 to 1.0 through December 30, 2002 and 4.0 to 1.0 thereafter; and . a debt to capital ratio of not greater than 0.67 to 1.0 through December 30, 2002 and 0.65 to 1.0 thereafter. The consummation of the Murphy Acquisition, whether or not the Canadian marketing company acquisition occurs, will result in a change in the required debt coverage and debt to capital ratios to: . a debt coverage ratio which is not greater than 4.75 to 1.0 through September 29, 2001, 4.50 to 1 from September 30, 2001 through June 29, 2002, 4.25 to 1.0 from June 30, 2002 through December 30, 2002 and 4.0 to 1.0 thereafter; and . a debt to capital ratio of not greater than 0.73 to 1.0 prior to December 30, 2002 and 0.65 to 1.0 thereafter. A default under our bank credit agreements would permit the lenders to accelerate the maturity of the outstanding debt and to foreclose on the assets securing the credit facilities. As long as we are in compliance with our bank credit agreements, they do not restrict our ability to make distributions of "available cash" as defined in our partnership agreement. We are currently in compliance with the covenants contained in our credit agreements. Under the most restrictive of these covenants, at December 31, 2000, we could have borrowed up to $386.4 million under our secured revolving credit facility. Contingencies Following our announcement in November 1999 of our losses resulting from unauthorized trading by a former employee, numerous class action lawsuits were filed against us, certain of our general partner's officers and directors and in some of these cases, our general partner and Plains Resources Inc. alleging violations of the federal securities laws. In addition, derivative lawsuits were filed in the Delaware Chancery Court against our general partner, its directors and certain of its officers alleging the defendants breached the fiduciary duties owed to us and our unitholders by failing to monitor properly the activities of our traders. These suits have, for the most part, been settled. See Item 3. - "Legal Proceedings". We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. 35
OUTLOOK As is common with most merchant activities, our ability to generate a profit on our margin activities is not tied to the absolute level of crude oil prices but is generated by the difference between the price paid and other costs incurred in the purchase of crude oil and the price at which we sell crude oil. The gross margin generated by tariff activities depends on the volumes transported on the pipeline and the level of the tariff charged, as well as the fixed and variable costs of operating the pipeline. These operations are affected by overall levels of supply and demand for crude oil. Our operations will be impacted by higher fuel and power costs relating to our pipeline and trucking operations. The increased costs will be offset by a 10% increase in the tariff rate on the All American Pipeline effective January 1, 2001. Also, the crude oil market moved into contango in March 2001, which generally means lower gross margin from our gathering and marketing activities during this transition. However, this type of market creates other arbitrage opportunities and an increase in the utilizations of our tankage at Cushing and in the field. We believe, although there can be no assurance, that increased profits from these opportunities will reduce the impact of the weaker gathering and marketing markets. A significant portion of our gross margin is derived from the Santa Ynez and Point Arguello fields located offshore California. Volumes received from the Santa Ynez and Point Arguello fields have declined from 92,000 and 60,000 average daily barrels, respectively, in 1995 to 56,000 and 18,000 average daily barrels, respectively, for the year ended December 31, 2000. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. As operator of Point Arguello, Plains Resources is conducting additional drilling and other activities on this field, but we cannot assure you that these activities will affect the production decline. A 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline tariff revenues of approximately $2.6 million. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS 133. SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" ("SFAS 137"), which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge Activities," which amended certain provisions, inclusive of the definition of the normal purchase and sale exclusion. We have determined that our physical purchase and sale agreements, which under SFAS 133 could be considered derivatives, qualify for the normal purchase and sale exclusion. SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the fair value of the hedged item. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income, a component of partners' capital. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in earnings in the current period. We have adopted SFAS 133, as amended, effective January 1, 2001. Our implementation procedures identified all instruments in place at the adoption date that are subject to the requirements of SFAS 133. Upon adoption, we recorded a cumulative effect charge of $8.3 million in accumulated other comprehensive income to recognize at fair value all derivative instruments that were designated as cash flow hedging instruments and a cumulative effect gain of $0.5 million to earnings. Correspondingly, an asset of $2.8 million and a liability of $10.6 million have been established. Implementation issues continue to be addressed by the FASB and any change to existing guidance might impact our implementation. Adoption of this standard could increase volatility in earnings and partners' capital through comprehensive income. 36
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage such exposure, we monitor our inventory levels, current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote. Commodity Price Risk. The fair value of outstanding derivative instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below (in millions): DECEMBER 31, --------------------------------------- 2000 1999 -------------------- ----------------- EFFECT OF EFFECT OF 10% 10% FAIR Price FAIR Price VALUE Decrease VALUE Decrease -------------------- ----------------- Crude oil: Futures contracts $(9.4) $6.0 - $(2.8) Swaps and options contracts - - (0.6) (0.1) The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the swap which approximate the gain or loss that would have been realized if the contracts had been closed out at year end. All hedge positions offset physical positions exposed to the cash market; none of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. At December 31, 2000, our hedging activities included crude oil futures contracts maturing through 2001, covering approximately 3.2 million barrels of crude oil. Because such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $15.1 million and $17.8 million in 2000 and 1999. The offsetting gains from the physical positions are not included in such amounts. The unrealized loss with respect to such instruments at December 31, 2000 was $7.8 million. Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for debt outstanding at December 31, 2000. Our variable rate debt bears interest at LIBOR or prime plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 2000. The carrying value of variable rate bank debt approximates fair value because interest rates are variable, based on prevailing market rates (dollars in millions). <TABLE> <CAPTION> EXPECTED YEAR OF MATURITY ------------------------------------------------------------- FAIR 2001 2002 2003 2004 2005 THEREAFTER TOTAL VALUE ------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> <C> <C> Liabilities: Short-term debt - variable rate $ 1.3 $ - $ - $ - $ - $ - $ 1.3 $ 1.3 Average interest rate 8.37% - - - - - 8.37% Long-term debt - variable rate - - - 320.0 (1) - - 320.0 320.0 Average interest rate - - - 9.15% - - 9.15% (1) After the February 2001 amendments to our bank credit agreements, the expected year of maturity is 2005. </TABLE> At December31,, 1999, the carrying value of short-term debt of $58.7 million and $424.1 million, respectively fair value. 37
Interest rate swaps and collars are used to hedge underlying debt obligtions. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interestexpense over the life of the instruments. At December 31, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $215.0 million, for which we would pay approximately $0.6 million if such arrangements were terminated as of such date. The adjustment to interest expense resulting from interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.1 million gain and a $0.1 million loss, respectively. These instruments are based on LIBOR margins and provide for a floor of 5% and a ceiling of 6.5% with an expiration date of February 2001 for $90.0 million notional principal amount and a floor of 6% and a ceiling of 8% with an expiration date of August 2002 for $125.0 million notional principal amount. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required here is included in the report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 38
PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER PARTNERSHIP MANAGEMENT Our general partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis. Two members of the board of directors of our general partner serve on a conflicts committee that reviews specific matters that the board believes may involve conflicts of interest between our general partner and Plains All American Pipeline. The conflicts committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us. The members of the conflicts committee also serve with another director on an audit committee, which reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers and are subject to the oversight of the directors of our general partner. Our operational personnel are employees of our general partner. Some officers of our general partner may spend a substantial amount of time managing the business and affairs of Plains Resources and its affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Plains Resources. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. Directors and Executive Officers of our General Partner The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner. Executive officers and directors are elected for one year terms. <TABLE> <CAPTION> NAME AGE POSITION WITH OUR GENERAL PARTNER - ------------------------ --- ----------------------------------------------------------------- <S> <C> <C> Greg L. Armstrong 42 Chairman of the Board, Chief Executive Officer and Director Harry N. Pefanis 43 President, Chief Operating Officer and Director Phillip D. Kramer 45 Executive Vice President and Chief Financial Officer George R. Coiner 50 Senior Vice President Alfred A. Lindseth 31 Vice President - Administration Tim Moore 43 Vice President, General Counsel and Secretary Mark F. Shires 43 Vice President - Operations Cynthia A. Feeback 43 Vice President - Accounting and Treasurer Everardo Goyanes 56 Director and Member of Audit and Conflicts Committees Robert V. Sinnott 51 Director and Member of Audit and Compensation Committees Arthur L. Smith 48 Director and Member of Audit, Conflicts and Compensation Committees </TABLE> Greg L. Armstrong has served as Chairman of the Board, Chief Executive Officer and Director of our general partner since its formation. In addition, he has been President, Chief Executive Officer and Director of Plains Resources since 1992. He previously served Plains Resources as: President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987. 39
Harry N. Pefanis has served as President, Chief Operating Officer and Director of our general partner since its formation. In addition, he has been Executive Vice President - Midstream of Plains Resources since May 1998. He previously served Plains Resources as: Senior Vice President from February 1996 until May 1998; Vice President - Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of several former midstream subsidiaries of Plains Resources until our formation in 1998. Phillip D. Kramer has served as Executive Vice President and Chief Financial Officer of our general partner since its formation. In addition, he has been Executive Vice President and Chief Financial Officer of Plains Resources since May 1998. He previously served Plains Resources as: Senior Vice President and Chief Financial Officer from May 1997 until May 1998; Vice President and Chief Financial Officer from 1992 to 1997; Vice President from 1988 to 1992; Treasurer from 1987 to March 2001; and Controller from 1983 to 1987. George R. Coiner has served as Senior Vice President of our general partner since its formation. In addition, he was Vice President of Plains Marketing & Transportation Inc., a former midstream subsidiary of Plains Resources, from November 1995 until our formation in 1998. Prior to joining Plains Marketing & Transportation Inc., he was Senior Vice President, Marketing with Scurlock Permian Corp. Alfred A. Lindseth has served as Vice President - Administration of our general partner since March 2001. He served as Risk Manager of our general partner from March 2000 until he was elected to his current position. He previously served PricewaterhouseCoopers LLP in its Financial Risk Management Practice section as a Consultant from 1997 to 1999 and as Principal Consultant from 1999 to March 2000. He also served GSC Energy, an energy risk management brokerage and consulting firm, as Manager of its Oil & Gas Hedging Program from 1995 to 1996 and as Director of Research and Trading from 1996 to 1997. Tim Moore has served as Vice President, General Counsel and Secretary of our general partner since May 2000. In addition, he has been Vice President, General Counsel and Secretary of Plains Resources since May 2000. Prior to joining Plains Resources, he served as General Counsel - Corporate of TransTexas Gas Corporation. He previously was a corporate attorney with the Houston office of Weil Gotshal & Manges. Mr. Moore also has seven years of industry experience as a petroleum geologist. Mark F. Shires has served as Vice President - Operations of our general partner since August 1999. He served as Manager of Operations for our general partner from April 1999 until he was elected to his current position. In addition, he was a business consultant from 1996 until April 1999. He served as a consultant to Plains Marketing & Transportation Inc. and Plains All American Pipeline from May 1998 until April 1999. He previously served as President of Plains Terminal & Transfer Corporation, a former midstream subsidiary of Plains Resources, from 1993 to 1996. Cynthia A. Feeback has served as Vice President - Accounting and Treasurer since May 2000 and Treasurer of our general partner since its formation. In addition, she has been Vice President - Accounting and Assistant Treasurer of Plains Resources since May 1999. She previously served Plains Resources as Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999; Controller and Principal Accounting Officer from 1993 to 1998; Controller from 1990 to 1993; and Accounting Manager from 1988 to 1990. Everardo Goyanes has served as a Director and a member of Audit and Conflicts Committees since May 1999. Mr. Goyanes has been President and Chief Executive Officer of Liberty Energy Holdings (an energy investment firm) since May 2000. From 1998 to May 2000 he was a financial consultant specializing in natural resources. From 1989 to 1998, he was Managing Director of the Natural Resources Group of ING Baring Furman Selz (a commercial banking firm). He was a financial consultant from 1987 to 1989 and was Vice President - Finance of Forest Oil Corporation from 1983 to 1987. Robert V. Sinnott has served as a Director and a member of Audit and Compensation Committees since September 1998. Mr. Sinnott has been Vice President of Kayne Anderson Investment Management, Inc. (an investment management firm) since 1992. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. He is also a director of Plains Resources and Glacier Water Services, Inc. (a vended water company). Arthur L. Smith has served as a Director and a member of Audit, Conflicts and Compensation Committees since February 1999. Mr. Smith is Chairman of John S. Herold, Inc. (a petroleum research and consulting firm), a position he has held since 1984. For the period from May 1998 to October 1998, he served as Chairman and Chief Executive Officer of Torch Energy Advisors Incorporated. He is also a director of Cabot Oil & Gas Corporation and Evergreen Resources, Inc. 40
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that during 2000 our officers and directors complied with all filing requirements with respect to our equity securities. REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER AND ITS AFFILIATES Our general partner does not receive any management fee or other compensation in connection with its management of Plains All American Pipeline. However, our general partner and its affiliates, including Plains Resources, perform services for us and are reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits properly allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business and properly allocable to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE We were formed in September 1998 but conducted no business until late November 1998. Accordingly, prior to 1999, no officer of our general partner received salary and bonus compensation for services to the partnership in excess of $100,000. Messrs. Armstrong, Pefanis, Kramer and Moore and Ms. Feeback are compensated by Plains Resources and do not receive compensation from our general partner with the exceptions of awards under the Long-Term Incentive Plan and the Transaction Grant Agreements described below. However, we reimburse our general partner and its affiliates, including Plains Resources for expenses incurred on our behalf, including the costs of officer compensation properly allocable to us. See Item 13. - "Certain Relationships and Related Transactions - Relationship with Plains Resources". The following table sets forth certain compensation information for all executive officers of our general partner who received salary and bonus compensation from our general partner in excess of $100,000 in 2000 (the "Named Executive Officers"). <TABLE> <CAPTION> ANNUAL COMPENSATION LONG-TERM ------------------- COMPENSATION OTHER NAME AND PRINCIPAL POSITION YEAR SALARY BONUS LTIP PAYOUTS COMPENSATION - ------------------------------ ---- ------------------- ------------- ------------- <S> <C> <C> <C> <C> <C> George Coiner 2000 $175,000 $500,700 $398,912 (1) $10,500 (3) Senior Vice President 1999 180,956 295,000 167,073 (2) 10,000 (3) Al Lindseth (4) 2000 109,308 55,000 - - Vice President - Administration Mark F. Shires 2000 155,000 220,000 - 10,500 (3) Vice President - Operations 1999 160,792 (5) 77,500 - - </TABLE> - ------------------------- (1) Represents the value of 16,667 common units plus distribution equivalent rights with respect to such units, which vested for 2000 under a Transaction Grant Agreement. See - "Transaction Grant Agreements" below. (2) Represents the value of 11,111 common units plus distribution equivalent rights with respect to such units, which vested for 1999 under a Transaction Grant Agreement. (3) Plains Resources matches 100% of our employees' contribution to its 401(k) Plan (subject to certain limitations in the plan), with such matching contribution being made 50% in cash and 50% in Plains Resources Common Stock (the number of shares for the stock match being based on the market value of the Common Stock at the time the shares are granted). (4) Mr. Lindseth was elected Vice President - Administration of our general partner in March 2001. He served as Risk Manager of our general partner from March 2000 until he was elected to his current position. (5) Includes $51,000 for consulting fees we paid to Mr. Shires prior to his becoming an employee of our general partner in April 1999. 41
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS Plains Resources has an employment agreement with Mr. Armstrong which expires on March 1, 2002, and provides for a current base salary of $330,000 per year, subject to annual review. If Mr. Armstrong's employment is terminated without cause, he will be entitled to receive an amount equal to two times his annual base salary. If his employment is terminated as a result of a change in control of Plains Resources, he will be entitled to receive an amount equal to three times the aggregate of his annual base salary and bonus. In either event, Mr. Armstrong will be entitled to receive medical benefits for two years following the date of his termination. Under Mr. Armstrong's agreement, a change in control of Plains Resources is defined to include (i) the acquisition by an entity or group of more than 25% of the voting stock of Plains Resources or (ii) the directors in office on the date of the agreement ceasing to constitute a majority of the Board of Directors of Plains Resources. Plains Resources also has an employment agreement with Mr. Pefanis, under which Mr. Pefanis serves as Executive Vice President of Plains Resources as well as President and Chief Operating Officer of our general partner and is responsible for our overall operations. The employment agreement provides that Plains Resources will not require Mr. Pefanis to engage in activities that materially detract from his duties and responsibilities as an officer of our general partner. The initial term of the employment agreement runs through November 23, 2001, subject to annual extensions and includes confidentiality, nonsolicitation and noncompete provisions, which, in general, will continue for two years following termination of Mr. Pefanis' employment. The employment agreement provides for an annual base salary of $235,000, subject to annual review. If Mr. Pefanis' employment is terminated without cause, he will be entitled to receive an amount equal to two times his base salary. Upon a Change in Control of Plains Resources or a Marketing Operations Disposition (as such terms are defined in the employment agreement), the term of the employment agreement will be automatically extended for three years, and if Mr. Pefanis' employment is terminated during the one-year period following either event by him for a Good Reason or by Plains Resources other than for death, disability or Cause (as such terms are defined in the employment agreement), he will be entitled to a lump sum severance amount equal to three times the sum of (1) his highest rate of annual base salary and (2) the largest annual bonus paid during the three preceding years. LONG-TERM INCENTIVE PLAN Our general partner has adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of our general partner's board of directors. Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2001, an aggregate of approximately 610,100 restricted units have been granted to employees of our general partner. Grants made include 60,000, 30,000, 15,000 and 30,000 units to Messrs. Pefanis, Coiner, Lindseth and Shires, respectively. In addition, 15,000 restricted units have been granted to non- employee directors of our general partner. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of the subordinated units to common units. Grants made to non-employee directors of our general partner are eligible to vest prior to termination of the subordination period. See "- Compensation of Directors" below for the vesting provisions of grants made to non-employee directors. If a grantee terminates employment or membership on the board for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. Following the subordination period, the Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units. The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration will be paid to us by the plan participants upon receipt of the common units. 42
Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided. Upon exercise of a unit option, our general partner will deliver common units acquired by it in the open market, purchased directly from us or any other person, or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of the common unitholders. Our general partner's board of directors in its discretion may terminate the Long-Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the Long-Term Incentive Plan or any part of the plan from time to time, including increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant. TRANSACTION GRANT AGREEMENTS In addition to the grants made under the Restricted Unit Plan described above, our general partner, at no cost to us, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of our general partner and its affiliates. Generally, under these grants, the common units vest based on attaining a targeted operating surplus for a given year. Approximately 75,000 and 6,000 of the common units vest for 2001 and 2002, respectively, if the operating surplus generated in each year equals or exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and the related distribution on our general partner interest. If a tranche of common units does not vest for a particular year due to a common unit arrearage, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 58,000 and 11,000 of the common units vest for 2001and 2002, respectively, if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and subordinated units and the related distributions on our general partner interest. Approximately 69,000 and 113,000 (excluding approximately 20,000 units withheld for payment of federal income taxes) of the units vested for 1999 and 2000, respectively and approximately 47,000 common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as our general partner prior to January 1, 2002. The compensation expense incurred in connection with these grants will be funded by our general partner, without reimbursement by us. Under these grants, 75,000 common units were allocated to each of Messrs. Armstrong and Pefanis, and 50,000 common units were allocated to Mr. Coiner. COMPENSATION OF DIRECTORS Each director of our general partner who is not an employee of our general partner or Plains Resources is paid an annual retainer fee of $20,000, an attendance fee of $2,000 for each board meeting he attends (excluding telephonic meetings), an attendance fee of $500 for each committee meeting or telephonic board meeting he attends plus reimbursement for related out-of-pocket expenses. In 2000, each director (other than Messrs. Armstrong and Pefanis) received a grant of 5,000 restricted units under our Long-Term Incentive Plan. The restricted units under these grants generally vest in equal installments in 2001, 2002, 2003 and 2004 if the operating surplus generated in the prior year exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and subordinated units and the related distributions on our general partner interest. Also in 2000, Messrs. Goyanes and Smith each received $25,000 for their service on a special committee of the Board of Directors of our general partner. Messrs. Armstrong and Pefanis, as officers of our general partner, are otherwise 43
compensated for their services to our general partner and therefore receive no separate compensation for their services as directors of our general partner. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth the beneficial ownership of units held by beneficial owners of 5% or more of the units, by directors and officers of our general partner and by all directors and executive officers of our general partner as a group as of March 15, 2001. <TABLE> <CAPTION> PERCENTAGE PERCENTAGE PERCENTAGE OF OF OF PERCENTAGE COMMON COMMON COMMON CLASS B SUBORDINATED SUBORDINATED OF NAME OF BENEFICIAL OWNER UNITS UNITS UNITS UNITS UNITS UNITS TOTAL UNITS - ---------------------------- -------------- ---------- ---------- ---------- ------------- ------------ ------------ <S> <C> <C> <C> <C> <C> <C> <C> <C> Plains Resources Inc. (1) 6,791,816 (3) 29.5% 1,307,190 100.0% 10,029,619 100% 52.7% Plains All American Inc. (2) 6,791,816 (3) 29.5% 1,307,190 100.0% 10,029,619 100% 52.7% Goldman, Sachs & Co. 1,412,575 (4) 6.1% - - - - 4.1% Greg L. Armstrong 95,000 (3) (7) - - - - (7) Harry N. Pefanis 142,900 (3)(5) (7) - - - - (7) George R. Coiner 79,976 (3)(5) (7) - - - - (7) Al Lindseth 15,000 (5) (7) - - - - (7) Mark F. Shires 30,000 (5) (7) - - - - (7) Everardo Goyanes 5,000 (6) (7) - - - - (7) Robert V. Sinnot 10,000 (6) (7) - - - - (7) Arthur L. Smith 12,500 (6) (7) - - - - (7) All directors and executive officers as a group (11 persons) 434,476 1.9% (8) - - - - 1.3% (8) </TABLE> - ------------------------- (1) Plains Resources Inc. is the sole stockholder of Plains All American Inc., our general partner. The address of Plains Resources Inc. is 500 Dallas, Suite 700, Houston, Texas 77002. (2) The address of Plains All American Inc. is 500 Dallas, Suite 700, Houston, Texas 77002. The record holder of such common units and subordinated units is PAAI LLC, a wholly owned subsidiary of Plains All American Inc., whose address is 500 Dallas, Suite 700, Houston, Texas 77002. (3) Includes 197,220 common units owned by affiliates of our general partner to be transferred to employees pursuant to transaction grant agreements, subject to certain vesting conditions. The recipients and their initial grants included: Mr. Armstrong - 75,000 (33,333 units currently vested); Mr. Pefanis - 75,000 (37,567 units currently vested); Mr. Coiner - 50,000 (23,754 units currently vested); Mr. Kramer - 30,000 (7,600 units currently vested) and Ms. Feeback - 10,000 (3,334 units currently vested). See Item 11. - "Executive Compensation - Transaction Grant Agreements". (4) The address for Goldman, Sachs & Co. and its parent, the Goldman Sachs Group, Inc., is 85 Broad Street, New York, New York 10004. Goldman, Sachs & Co., a broker/dealer, and its parent, the Goldman Sachs Group, Inc., are deemed to have shared voting power and shared disposition power over 1,412,575 common units owned by their customers. (5) Includes the following unvested common units issuable under the Long-Term Incentive Plan to: Mr. Pefanis - 60,000, Mr. Coiner - 30,000, Mr. Lindseth - 15,000 and Mr. Shires - 30,000. See Item 11. - "Executive Compensation - Long-Term Incentive Plan." (6) Includes 5,000 unvested restricted units issuable to each of Messrs. Goyanes, Sinnott and Smith under the Long-Term Incentive Plan. See Item 11. -"Executive Compensation - Compensation of Directors." (7) Less than one percent. (8) Assumes the vesting of the units granted pursuant to the transaction grant agreements and under the long-term incentive plan as described in footnotes (3), (5) and (6) above to the named officers and directors. See Item 11. "Executive Compensation - Long-Term Incentive Plan" for vesting conditions of these grants. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS RIGHTS OF OUR GENERAL PARTNER Our general partner and its affiliates own 8,099,006 common units, including 1,307,190 Class B common units, and 10,029,619 subordinated units, representing an aggregate 52.7% of the total limited partner interests in Plains All American Pipeline. In addition, our general partner owns an aggregate 2% general partner interest in Plains All American Pipeline and the operating partnerships on a combined basis. Through our general partner's ability, as general partner, to manage and operate Plains All American Pipeline and the ownership of 8,099,006 common units, including 1,307,190 Class B common units, and all of the outstanding subordinated units by our general partner and its affiliates (effectively giving our general partner the ability to veto certain actions of Plains All American Pipeline), our general partner has the ability to control the management of Plains All American Pipeline. 44
RELATIONSHIP WITH PLAINS RESOURCES General Plains Resources controls our general partner, which is its wholly owned subsidiary. We have extensive ongoing relationships with Plains Resources. These relationships include but are not limited to: . an Omnibus Agreement that provides for (1) the resolution of certain conflicts arising from the fact that we and Plains Resources conduct related businesses and (2) our general partner's indemnification of us for certain matters; and . a Marketing Agreement with Plains Resources that provides for the marketing of Plains Resources' equity crude oil production. In November 2000, Plains Resources announced that it is evaluating strategic restructuring alternatives intended to optimize the value and value-creating ability of each of its upstream and midstream business segments. The alternatives include, but are not limited to, a spin off or split off of the upstream segment or midstream segment, a spin off or special dividend of certain of our units and potential asset sales. Any modifications to the existing structure will depend on a number of factors including tax efficiency, critical mass and other considerations. Accordingly, there can be no assurance that any modifications will be made. Transactions with Affiliates For the year ended December 31, 2000, Plains Resources produced approximately 26,000 barrels per day that were subject to the Marketing Agreement. We paid approximately $244.9 million for such production and recognized profits of approximately $1.7 million under the terms of that agreement. Our general partner has sole responsibility for conducting our business and managing our operations and owns all of the incentive distribution rights. Some of the senior executives who currently manage our business also manage and operate the business of Plains Resources. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf. For the year ended December 31, 2000, our general partner and its affiliates incurred $63.8 million of direct and indirect expenses on our behalf. Of this amount, $165,000 and $212,000 represented reimbursement for the services of Messrs. Armstrong and Pefanis, respectively, as officers of our general partner. In December 1999, following the losses we incurred as a result of the unauthorized trading activity by a former employee, our general partner loaned us approximately $114.0 million. This subordinated debt was repaid in May 2000. We paid $3.3 million in 2000 for interest on this loan. Funding to our general partner for these loans was provided by Plains Resources. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources". Indemnity from Our General Partner In connection with the acquisition of the All American Pipeline and the SJV Gathering System in July 1998, Wingfoot agreed to indemnify our general partner for certain environmental and other liabilities. The indemnity is subject to limits of: . $10.0 million with respect to matters of corporate authorization and title to shares; . $21.5 million with respect to condition of rights-of-way, lease rights and undisclosed liabilities and litigation; and . $30.0 million with respect to environmental liabilities resulting from certain undisclosed and pre-existing conditions. Wingfoot has no liability, however, until the aggregate amount of losses with respect to each such category exceeds $1.0 million. These indemnities were in effect until July 2000, with the exception of the environmental indemnity, which will remain in effect until July 2001. However, upon the transfer to an unaffiliated third party of a major portion of the assets acquired from Wingfoot, the indemnities automatically terminate. The environmental indemnity is also subject to certain sharing ratios, which change, based on whether the claim is made in the first, second or third year of the indemnity as well as the amount of such claim. We have also agreed to be solely responsible for the cumulative aggregate amount of losses resulting from the oil leak from the All American Pipeline to the extent such losses do not exceed $350,000. Any costs in excess of $350,000 will be applied to the $1.0 million deductible for the Wingfoot environmental indemnity. Our general partner has agreed to indemnify us for environmental and other liabilities to the extent it is indemnified by Wingfoot. However, if the sale of the linefill from the All American Pipeline and the subsequent sale of such pipeline to EPNG Pipeline 45
Company are construed to constitute a sale of a major portion of the assets acquired from Wingfoot, the indemnities by Wingfoot will terminate. See Items 1. and 2. - "Business and Properties - Acquisitions and Dispositions - All American Pipeline Linefill Sale and Asset Disposition". Plains Resources has agreed to indemnify us for environmental liabilities related to the assets of the our predecessor transferred to us that arose prior to closing and are discovered within three years after closing (excluding liabilities resulting from a change in law after closing). Plains Resources' indemnification obligation is capped at $3.0 million. 46
PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES See "Index to Consolidated Financial Statements" set forth on Page F-1. (a) (3) EXHIBITS 3.1 -- Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.1 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 3.2 -- Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.2 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 3.3 -- Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 3.3 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 3.4 -- Certificate of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.4 to Registration Statement, file No. 333-64107). 3.5 -- Certificate of Limited Partnership of Plains Marketing, L.P. dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 3.6 -- Articles of Conversion of All American Pipeline Company dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 3.7 -- Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline L.P. dated as of May 12, 1999 (incorporated by reference to Exhibit 3.8 to Quarterly Report on Form 10-Q for the Quarter Ended June 30, 1999). 3.8 -- Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline L.P. dated as of May 12, 1999 (incorporated by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2000). 10.01 -- Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on Form 10-K for the Year Ended December 31, 1998). **10.02 -- Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.04 to Annual Report on Form 10-K for the Year Ended December 31, 1998). **10.03 -- Plains All American Inc., 1998 Management Incentive Plan Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.05 to Annual Report on Form 10-K for the Year Ended December 31, 1998). **10.04 -- Employment Agreement between Plains Resources Inc. and Harry N. Pefanis dated as of November 23, 1998 (incorporated by reference to Exhibit 10.06 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 10.05 -- Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 10.06 -- Omnibus Agreement among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and Plains All American Inc. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 47
10.07 -- Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, file No. 333- 64107). 10.08 -- Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, file No. 333-64107). **10.09 -- Form of Transaction Grant Agreement (Payment on Vesting) (incorporated by reference to Exhibit 10.12 to Registration Statement, file No. 333-64107). 10.10 -- First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 10.11 -- Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K for the Year Ended December 31, 1998). 10.12 -- Asset Sales Agreement between Chevron Pipe Line Company and Plains Marketing, L.P. dated as of April 16, 1999 (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999). **10.13 -- Transaction Grant Agreement with Greg L. Armstrong (incorporated by reference to Exhibit 10.20 to Registration Statement on Form S-1, file no. 333-86907) 10.14 -- Pipeline Sale and Purchase Agreement dated January 31, 2000, among Plains All American Pipeline, L.P., All American Pipeline, L.P., El Paso Natural Gas Company and El Paso Pipeline Company (incorporated by reference to Exhibit 10.27 to Annual Report on Form 10-K for the Year Ended December 31, 1999). 10.15 -- Credit Agreement [Letter of Credit and Hedged Inventory Facility] dated May 8, 2000, among Plains Marketing, L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet National Bank and certain other lenders (incorporated by reference to Exhibit 10.01 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2000). 10.16 -- Credit Agreement [Revolving Credit Facility] dated May 8, 2000, among Plains Marketing, L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet national Bank and certain other lenders (incorporated by reference to Exhibit 10.02 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2000). * 10.17 -- First Amendment to Credit Agreement [Letter of Credit and Hedged Inventory Facility] dated as of February 26, 2001. * 10.18 -- First Amendment to Credit Agreement [Revolving Credit Facility] dated as of February 26, 2001. * 21.1 -- Subsidiaries of the Registrant. * 23.1 -- Consent of PricewaterhouseCoopers LLP. - ---------------------- * Filed herewith ** Management contract or compensatory plan or arrangement (b) REPORTS ON FORM 8-K A Current Report on Form 8-K was filed on December 7, 2000, in connection with the announcement that Plains Resources Inc. would be evaluating strategic restructuring alternatives intended to optimize the value and value-creating ability of each of its upstream and midstream business segments. 48
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. PLAINS ALL AMERICAN PIPELINE, L.P.. By: PLAINS ALL AMERICAN INC., Our General Partner Date: April 2, 2001 By: /s/ Phillip D. Kramer ---------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Date: April 2, 2001 By: /s/ Greg L. Armstrong ---------------------------------------- Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of our General Partner (Principal Executive Officer) Date: April 2, 2001 By: /s/ Harry N. Pefanis ---------------------------------------- Harry N. Pefanis, President, Chief Operating Officer and Director of our General Partner Date: April 2, 2001 by: /s/ Phillip D. Kramer ---------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) of our General Partner Date: April 2, 2001 By: /s/ Cynthia A. Feeback ---------------------------------------- Cynthia A. Feeback, Vice President - Accounting (Principal Accounting Officer) of our General Partner Date: April 2, 2001 By: /s/ Everardo Goyanes ---------------------------------------- Everardo Goyanes, Director of our General Partner Date: April 2, 2001 By: /s/ Robert V. Sinnott ---------------------------------------- Robert V. Sinnott, Director of our General Partner Date: April 2, 2001 By: /s/ Arthur L. Smith ---------------------------------------- Arthur L. Smith, Director of our General Partner 49
PLAINS ALL AMERICAN PIPELINE, L.P. INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS <TABLE> <CAPTION> Page ---- <S> <C> Financial Statements Report of Independent Accountants..................................................................... F-2 Report of Independent Accountants..................................................................... F-3 Consolidated Balance Sheets as of December 31, 2000 and 1999.......................................... F-4 Consolidated and Combined Statements of Operations: For the years ended December 31, 2000 and 1999 For the period from inception (November 23,1998) to December 31, 1998 and For the period from January 1, 1998 to November 22, 1998 (Predecessor).............................. F-5 Consolidated and Combined Statements of Cash Flows: For the years ended December 31, 2000 and 1999 For the period from inception (November 23,1998) to December 31, 1998 and For the period from January 1, 1998 to November 22, 1998 (Predecessor).............................. F-6 Consolidated Statements of Changes in Partners' Capital for the period from inception (November 23, 1998) to December 31, 1998 and for the years ended December 31, 1999 and 2000....................... F-7 Notes to Consolidated and Combined Financial Statements............................................... F-8 </TABLE> All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. F-1
REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of the General Partner and the Unitholders of Plains All American Pipeline, L.P. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in partners' capital and of cash flows present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2000 and the period from inception (November 23, 1998) to December 31, 1998 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Houston, Texas March 22, 2001 F-2
REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of the General Partner and the Unitholders of Plains All American Pipeline, L.P. In our opinion, the accompanying combined statements of operations and cash flows of the Plains Midstream Subsidiaries, the predecessor entity of Plains All American Pipeline L.P., present fairly, in all material respects, the combined results of their operations and their cash flows for the period from January 1, 1998 to November 22, 1998 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Plains Midstream Subsidiaries' management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. PricewaterhouseCoopers LLP Houston, Texas March 22, 2001 F-3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) <TABLE> <CAPTION> DECEMBER 31, ------------------------- 2000 1999 -------- ------- <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents $ 3,426 $ 53,768 Accounts receivable and other 347,698 508,920 Inventory 46,780 34,826 Assets held for sale (Note 5) - 141,486 -------- ---------- Total current assets 397,904 739,000 -------- ---------- PROPERTY AND EQUIPMENT 467,619 454,878 Less allowance for depreciation and amortization (26,974) (11,581) -------- ---------- 440,645 443,297 -------- ---------- OTHER ASSETS Pipeline linefill 34,312 17,633 Other, net 12,940 23,107 -------- ---------- $885,801 $1,223,037 ======== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable and other current liabilities $328,542 $ 485,400 Due to affiliates 20,951 42,692 Short-term debt and current portion of long-term debt 1,300 109,369 -------- ---------- Total current liabilities 350,793 637,461 LONG-TERM LIABILITIES Bank debt 320,000 259,450 Subordinated note payable - general partner - 114,000 Other long-term liabilities and deferred credits 1,009 19,153 -------- ---------- Total liabilities 671,802 1,030,064 -------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 15) PARTNERS' CAPITAL Common unitholders (23,049,239 units outstanding) 217,073 208,359 Class B Common unitholders (1,307,190 units outstanding) 21,042 20,548 Subordinated unitholders (10,029,619 units outstanding) (27,316) (35,621) General partner 3,200 (313) -------- ---------- 213,999 192,973 -------- ---------- $885,801 $1,223,037 ======== ========== </TABLE> See notes to consolidated and combined financial statements. F-4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (in thousands, except per unit data) <TABLE> <CAPTION> PREDECESSOR ------------- NOVEMBER 23, JANUARY 1, YEAR ENDED DECEMBER 31, 1998 TO 1998 TO --------------------------- DECEMBER 31, NOVEMBER 22, 2000 1999 1998 1998 ---------- ----------- -------- ---------- <S> <C> <C> <C> <C> REVENUES $6,641,187 $10,910,423 $398,918 $3,118,353 COST OF SALES AND OPERATIONS 6,506,504 10,800,109 391,419 3,087,372 UNAUTHORIZED TRADING LOSSES AND RELATED EXPENSES (NOTE 3) 6,963 166,440 2,400 4,700 ---------- ----------- -------- ---------- Gross Margin 127,720 (56,126) 5,099 26,281 ---------- ----------- -------- ---------- EXPENSES General and administrative 40,821 23,211 771 4,526 Depreciation and amortization 24,523 17,344 1,192 4,179 Restructuring expense - 1,410 - - ---------- ----------- -------- ---------- Total expenses 65,344 41,965 1,963 8,705 ---------- ----------- -------- ---------- Operating income (loss) 62,376 (98,091) 3,136 17,576 Interest expense (28,691) (21,139) (1,371) (11,260) Gain on sale of assets (Note 5) 48,188 16,457 - - Interest and other income 10,776 958 12 572 ---------- ----------- -------- ---------- Net income (loss) before provision in lieu of income taxes and extraordinary item 92,649 (101,815) 1,777 6,888 Provision in lieu of income taxes - - - 2,631 ---------- ----------- -------- ---------- Net income (loss) before extraordinary item 92,649 (101,815) 1,777 4,257 Extraordinary item (Note 9) (15,147) (1,545) - - ---------- ----------- -------- ---------- NET INCOME (LOSS) $ 77,502 $ (103,360) $ 1,777 $ 4,257 ========== =========== ======== ========== NET INCOME (LOSS) - LIMITED PARTNERS $ 75,754 $ (101,517) $ 1,741 $ 4,172 ========== =========== ======== ========== NET INCOME (LOSS) - GENERAL PARTNER $ 1,748 $ (1,843) $ 36 $ 85 ========== =========== ======== ========== BASIC AND DILUTED INCOME (LOSS) PER LIMITED PARTNER UNIT Net income (loss) before extraordinary item $2.64 $(3.16) $0.06 $0.25 Extraordinary item (0.44) (0.05) - - ---------- ----------- -------- ---------- Net income (loss) $2.20 $(3.21) $0.06 $0.25 ========== =========== ======== ========== WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING 34,386 31,633 30,089 17,004 ========== =========== ======== ========== </TABLE> See notes to consolidated and combined financial statements. F-5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (in thousands) <TABLE> <CAPTION> PREDECESSOR ------------ NOVEMBER 23, JANUARY 1, YEAR ENDED DECEMBER 31, 1998 TO 1998 TO ---------------------------- DECEMBER 31, NOVEMBER 22, 2000 1999 1998 1998 ---------------------------- ----------- ---------- <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 77,502 $(103,360) $ 1,777 $ 4,202 Items not affecting cash flows from operating activities: Depreciation and amortization 24,523 17,344 1,192 4,179 (Gain) loss on sale of assets (Note 5) (48,188) (16,457) - 117 Change in payable in lieu of deferred taxes - - - 2,231 Noncash compensation expense 3,089 1,013 - - Allowance for doubtful accounts 5,000 - - - Other non cash items 4,574 1,047 45 - Change in assets and liabilities, net of acquisition: Accounts receivable and other 120,497 (224,181) (10,245) 37,498 Inventory (11,954) 34,772 (14,805) (3,336) Accounts payable and other current liabilities (161,543) 164,783 36,675 (25,850) Pipeline linefill (16,679) (3) (6,247) 2,343 Other long-term liabilities and deferred credits (8,591) 18,873 - - Advances from (payments to) affiliates (21,741) 34,924 (1,174) - ----------- --------- --------- --------- Net cash provided by (used in) operating activities (33,511) (71,245) 7,218 21,384 ----------- --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Costs incurred in connection with acquisitions (Note 4) - (176,918) - (394,026) Additions to property and equipment (12,603) (12,801) (2,887) (5,528) Disposals of property and equipment 402 294 - 8 Additions to other assets (657) (68) (202) (65) Proceeds from asset sales (Note 5) 223,859 3,400 - - ----------- --------- --------- --------- Net cash provided by (used in) investing activities 211,001 (186,093) (3,089) (399,611) ----------- --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Advances from (payments to) affiliates - - - 3,349 Proceeds from issuance of units - 76,450 241,690 - Distributions upon formation - - (241,690) - Costs incurred in connection with financing arrangements (6,748) (17,243) - (9,938) Cash balance at formation - - 224 - Subordinated notes - general partner (114,000) 114,000 - - Proceeds from long-term debt 1,433,750 403,721 - 331,300 Proceeds from short-term debt 51,300 131,119 1,150 30,600 Principal payments of long-term debt (1,423,850) (268,621) - (39,300) Principal payments of short-term debt (108,719) (82,150) - (40,000) Capital contribution from Parent - - - 113,700 Dividend to Parent - - - (3,557) Distributions to unitholders (59,565) (51,673) - - ----------- --------- --------- ---------- Net cash provided by (used in) financing activities (227,832) 305,603 1,374 386,154 ----------- --------- --------- --------- Net increase (decrease) in cash and cash equivalents (50,342) 48,265 5,503 7,927 Cash and cash equivalents, beginning of period 53,768 5,503 - 2 ----------- --------- --------- --------- Cash and cash equivalents, end of period $ 3,426 $ 53,768 $ 5,503 $ 7,929 =========== ========= ========= ========= </TABLE> See notes to consolidated and combined financial statements. F-6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998 AND THE YEARS ENDED DECEMBER 31, 1999 AND 2000 (in thousands) <TABLE> <CAPTION> Total CLASS B GENERAL PARTNERS' COMMON UNITS COMMON UNITS SUBORDINATED UNITS PARTNER CAPITAL -------------------- ----------------- --------------------- ----------- ----------- UNITS AMOUNT UNITS AMOUNT UNITS AMOUNT AMOUNT AMOUNT -------- --------- -------- -------- -------- --------- ---------- ----------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Issuance of units to public 13,085 $241,690 - $ - - $ - $ - $ 241,690 Contribution of assets and debt assumed 6,974 106,392 - - 10,030 153,005 9,369 268,766 Distribution at time of formation - (95,675) - - - (137,590) (8,425) (241,690) Net income for the period from November 23, 1998 to December 31, 1998 - 1,161 - - - 580 36 1,777 ------ -------- ------ ------- ------ --------- ------- --------- Balance at December 31, 1998 20,059 253,568 - - 10,030 15,995 980 270,543 Issuance of Class B Common Units - - 1,307 25,000 - - 252 25,252 Noncash compensation expense - - - - - - 1,013 1,013 Issuance of units to public 2,990 50,654 - - - - 544 51,198 Distributions - (33,265) - (1,234) - (15,915) (1,259) (51,673) Net loss - (62,598) - (3,218) - (35,701) (1,843) (103,360) ------ -------- ------ ------- ------ --------- ------- --------- Balance at December 31, 1999 23,049 208,359 1,307 20,548 10,030 (35,621) (313) 192,973 Noncash compensation expense - - - - - - 3,089 3,089 Distributions - (42,066) - (2,384) - (13,791) (1,324) (59,565) Net income - 50,780 - 2,878 - 22,096 1,748 77,502 ------ -------- ------ ------- ------ --------- ------- --------- Balance at December 31, 2000 23,049 $217,073 1,307 $21,042 10,030 $ (27,316) $ 3,200 $ 213,999 ====== ======== ====== ======= ====== ========= ======= ========= </TABLE> See notes to consolidated and combined financial statements. F-7
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS Note 1 -- Organization and Basis of Presentation Organization We are a Delaware limited partnership (the "Partnership") that was formed in September of 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. ("Plains Resources") and its wholly owned subsidiaries. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the business of the midstream subsidiaries of Plains Resources, also referred to as our predecessor or the Plains Midstream Subsidiaries. Our operations are conducted through Plains Marketing, L.P. and All American Pipeline, L.P. Our general partner, Plains All American Inc., is a wholly owned subsidiary of Plains Resources. We are engaged in interstate and intrastate marketing, transportation and terminalling of crude oil. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". Our operations are conducted primarily in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of Mexico. Formation and Offering On November 23, 1998, we completed an initial public offering of 13,085,000 common units at $20.00 per unit, representing limited partner interests and received net proceeds of approximately $244.7 million. Concurrently with the closing of the initial public offering, certain of the Plains Midstream subsidiaries were merged into Plains Resources, which sold the assets of these subsidiaries to us in exchange for $64.1 million and the assumption of $11.0 million of related indebtedness. At the same time, our general partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System to us in exchange for: . 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2% general partner interest; . the right to receive incentive distributions as defined in the partnership agreement; and . our assumption of $175.0 million of indebtedness incurred by our general partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System. In addition to the $64.1 million discussed above, we distributed approximately $177.6 million of the offering proceeds to our general partner and used approximately $3.0 million of the remaining proceeds to pay expenses incurred in connection with the initial public offering. Basis of Consolidation and Presentation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2000 and 1999, and the results of our operations, cash flows and changes in partners' capital for the years ended December 31, 2000 and 1999 and the period from inception (November 23, 1998) to December 31, 1998, and the results of operations and cash flows of our predecessor for the period from January 1, 1998 to November 22, 1998. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform with current period presentation. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management incude (1) depreciation and amortization, (2) allowance for doubtful accounts receivable and (3) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates. Revenue Recognition. Gathering and marketing revenues are accrued at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to us, which occurs upon our receipt of the product. Terminalling and storage revenues are recognized at the time service is performed. Revenues for the transportation of crude oil are recognized based upon regulated and non-regulated tariff rates and the related transported volumes. F-8
Cost of Sales and Operations. Cost of sales and operations consists of the cost of crude oil, transportation fees, field and pipeline operating expenses and letter of credit expenses. Field and pipeline operating expenses consist primarily of fuel and power costs, telecommunications, labor costs for pipeline field personnel, maintenance, utilities, insurance and property taxes. Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2000 and 1999, the majority of cash and cash equivalents is concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit risk is minimal. Accounts Receivable, Net. At December 31, 2000, our allowance for doubtful accounts receivable totaled $5.0 million and is reflected in the consolidated balance sheet as a reduction of certain accounts receivable which are included in Other Assets. The allowance was established in 2000 by a $5.0 million charge to general and administrative expense. Inventory. Inventory consists of crude oil in pipelines and in storage tanks which is valued at the lower of cost or market, with cost determined using the average cost method. Property and Equipment and Pipeline Linefill. Property and equipment is stated at cost and consists of: December 31, ---------------------------- 2000 1999 ------------- ------------- (in thousands) Crude oil pipelines $ 359,826 $ 351,460 Crude oil pipeline facilities 39,358 39,358 Crude oil storage and terminal facilities 45,989 43,583 Trucking equipment, injection stations and other 19,435 18,249 Office property and equipment 3,011 2,228 ------------- ------------- 467,619 454,878 Less accumulated depreciation and amortization (26,974) (11,581) ------------- ------------- $ 440,645 $ 443,297 ============= ============= Depreciation is computed using the straight-line method over estimated useful lives as follows: . crude oil pipelines - 40 years; . crude oil pipeline facilities - 25 years; . crude oil terminal and storage facilities - 30 to 40 years; . trucking equipment, injection stations and other - 5 to 10 years; and . other property and equipment - 5 to 7 years. Acquisitions and improvements are capitalized; maintenance and repairs are expensed as incurred. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs. Pipeline linefill is recorded at cost and consists of crude oil linefill used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location. At December 31, 2000, we had approximately 1.6 million barrels of crude oil used to maintain our minimum operating linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated and combined statements of cash flows. Proceeds from the sale of 5.2 million barrels of crude oil linefill in connection with the segment of the All American Pipeline that was sold are included in investing activities in the accompanying consolidated and combined statements of cash flows (see Note 5). Impairment of Long-Lived Assets. Long-lived assets, including any related goodwill, with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. Fair value is generally determined from estimated discounted future net cash flows. F-9
Other Assets. Other assets consist of the following (in thousands): DECEMBER 31, -------------------- 2000 1999 ------- ------- Debt issue costs $ 8,918 $24,776 Long-term receivable, net 5,000 - Goodwill and other 770 1,994 ------- ------- 14,688 26,770 Accumulated amortization (1,748) (3,663) ------- ------- $12,940 $23,107 ======= ======= Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method of amortization. Goodwill was recorded as the amount of the purchase price in excess of the fair value of certain transportation and crude oil gathering assets purchased by our predecessor and is amortized using the straight-line method over a period of twenty years. Federal Income Taxes. No provision for income taxes related to our operations is included in the accompanying consolidated financial statements, because as a partnership we are not subject to federal or state income tax and the tax effect of our activities accrues to the unitholders. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders will have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon his/her tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual unitholder's tax bases and his/her share of the net assets reported in the consolidated financial statements. We do not have access to information about each individual unitholder's tax attributes, and the aggregate tax bases cannot be readily determined. Accordingly, management does not believe that in our circumstances, the aggregate difference would be meaningful information. Our predecessor is included in the consolidated federal income tax return of Plains Resources. Income taxes are calculated as if our predecessor had filed a return on a separate company basis utilizing a federal statutory rate of 35%. Hedging. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and crude oil swap contracts entered into with financial institutions. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt. These derivative instruments qualify for hedge accounting as they reduce the price risk of the underlying hedged item and are designated as a hedge at inception. Additionally, the derivatives result in financial impacts that are inversely correlated to those of the items being hedged. This correlation, generally in excess of 80%, (a measure of hedge effectiveness) is measured both at the inception of the hedge and on an ongoing basis. If correlation ceases to exist, we would discontinue hedge accounting and apply mark to market accounting. Gains and losses on the termination of hedging instruments are deferred and recognized in income as the impact of the hedged item is recorded. Unrealized changes in the market value of crude oil hedge contracts are not generally recognized in our statement of operations or our predecessor's statements of operations until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in our and our predecessor's statements of operations as a component of revenues. Such financial impacts are offset by gains or losses realized in the physical market. Cash flows from crude oil hedging activities are included in operating activities in the accompanying statements of cash flows. Net deferred gains and losses on futures contracts, including closed futures contracts, entered into to hedge anticipated crude oil purchases and sales, are included in current assets or current liabilities in the accompanying consolidated balance sheets. Deferred gains or losses from inventory hedges are included as part of the inventory costs and recognized when the related inventory is sold. Amounts paid or received from interest rate swaps and collars are charged or credited to interest expense and matched with the cash flows and interest expense of the debt being hedged, resulting in an adjustment to the effective interest rate. F-10
Net income per unit. Basic and diluted net income (loss) per unit is determined by dividing net income (loss) after deducting the amount allocated to the general partner interest, by the weighted average number of outstanding common units and subordinated units. Partnership income (loss) is allocated first according to cash distributions, and the remainder according to percentage ownership in the partnership. For periods prior to November 23, 1998, outstanding units are assumed to equal the common and subordinated units received by our general partner in exchange for assets contributed to us. Unit Options. We have elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and related interpretations in accounting for our employee unit options and awards. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying units on the date of grant (see Note 14). Recent Accounting Pronouncements. We implemented Emerging Issues Task Force ("EITF") Issue No. 99-19, "Recording Revenue Gross as a Principal versus Net as an Agent" in the fourth quarter of 2000. Crude oil buy/sell contracts and exchanges whereby like volumes are purchased and sold were previously reported net in cost of sales and operations. These transactions have been reclassified to be reflected as gross revenues and cost of sales and operations in our statements of operations for all periods presented with no effect on earnings. The amounts by which revenues and cost of sales and operations have been reclassified for the years ended December 31, 2000 and 1999 and the periods November 23, 1998 to December 31, 1998 and January 1, 1998 to November 22, 1998 are $2.5 billion, $6.2 billion, $0.2 billion, and $2.1 billion, respectively. 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" ("SFAS 133"). SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" ("SFAS 137"), which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge Activities," which amended certain provisions, inclusive of the definition of the normal purchase and sale exclusion. We have determined that our physical purchase and sale agreements, which under SFAS 133 could be considered derivatives, qualify for the normal purchase and sale exclusion. SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the fair value of the hedged item. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income, a component of partners' capital. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in earnings in the current period. We adopted SFAS 133, as amended, effective January 1, 2001. Our implementation procedures identified all instruments in place at the adoption date that are subject to the requirements of SFAS 133. Upon adoption, we recorded a cumulative effect charge of $8.3 million in accumulated other comprehensive income to recognize at fair value all derivative instruments that are designated as cash flow hedging instruments and a cumulative effect gain of $0.5 million to earnings. Correspondingly, an asset of $2.8 million and a liability of $10.6 million have been established. Implementation issues continue to be addressed by the FASB and any change to existing guidance might impact our implementation. Adoption of this standard could increase volatility in earnings and partners' capital through comprehensive income. NOTE 3 -- UNAUTHORIZED TRADING LOSSES In November 1999, we discovered that a former employee had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred from March through November 1999. Approximately $7.1 million of the unauthorized trading losses was recognized in 1998 and the remainder in 1999. In 2000, we recognized an additional $7.0 million charge for litigation related to the unauthorized trading losses (see Note 15). F-11
NOTE 4 -- ACQUISITIONS Scurlock Acquisition On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Financing for the Scurlock acquisition was provided through: . borrowings of approximately $92.0 million under a previous bank facility; . the sale to our general partner of 1.3 million of our Class B common units for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of our common units on May 12, 1999; and . a $25.0 million draw under our existing revolving credit agreement. The assets, liabilities and results of operations of Scurlock are included in our consolidated financial statements effective May 1, 1999. The Scurlock acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations, ("APB 16") as follows (in thousands): Crude oil pipeline, gathering and terminal assets $125,120 Other property and equipment 1,546 Pipeline linefill 16,057 Other assets (debt issue costs) 3,100 Other long-term liabilities (environmental accrual) (1,000) Net working capital items (3,090) -------- Cash paid $141,733 ======== The purchase accounting entries include a $1.0 million accrual for estimated environmental remediation costs. Under the agreement for the sale of Scurlock by Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock for claims, liabilities and losses resulting from any act or omission attributable to Scurlock's business or properties occurring prior to the date of the closing of such sale to the extent the aggregate amount of such losses exceed $1.0 million; provided, however, that claims for such losses must individually exceed $25,000 and must be asserted by Scurlock against Marathon Ashland Petroleum on or before May 15, 2003. West Texas Gathering System Acquisition On July 15, 1999, we completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under a previous credit facility. F-12
Pro Forma Results for the Scurlock and West Texas Gathering System Acquisitions The following unaudited pro forma data is presented to show pro forma revenues, net income (loss) and basic and diluted net income (loss) per limited partner unit as if the Scurlock and West Texas Gathering System acquisitions had occurred on January 1, 1998 (in thousands): <TABLE> <CAPTION> YEAR NOVEMBER 23, JANUARY 1, ENDED 1998 TO 1998 TO DECEMBER 31, DECEMBER 31, NOVEMBER 22, 1999 1998 1998 ------------ ------------ ----------- <S> <C> <C> <C> Revenues $11,301,492 $501,578 $4,272,060 =========== ======== ========== Net income (loss) $ (97,501) $ (8,080) $ 936 =========== ======== ========== Basic and diluted net income (loss) per limited partner unit $ (3.02) $ (0.25) $ 0.05 =========== ======== ========== </TABLE> All American Pipeline Acquisition On July 30, 1998, our predecessor acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot, a wholly owned subsidiary of the Goodyear Tire and Rubber Company ("Goodyear"), for approximately $400.0 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline and the SJV Gathering System, as well as other assets related to such operations. The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with APB 16 as follows (in thousands): Crude oil pipeline, gathering and terminal assets $392,528 Other assets (debt issue costs) 6,138 Net working capital items (excluding cash received of $7,481) 1,498 -------- Cash paid $400,164 ======== Financing for the acquisition was provided through a $325.0 million, limited recourse bank facility and an approximate $114.0 million capital contribution by Plains All American Inc. We incurred a $1.4 million restructuring charge in 1999, primarily associated with severance-related expenses of 24 employees who were terminated. As of December 31, 1999, all severance costs were paid and the terminated employees were not employed by us. Pro Forma Results for the All American Pipeline Acquisition The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income per limited partner unit as if the All American Pipeline acquisition had occurred on January 1, 1998 (in thousands): JANUARY 1, 1998 TO NOVEMBER 22, 1998 ------------ Revenues $3,556,002 ========== Net income $ 14,448 ========== Basic and diluted net income per limited partner unit $ 0.83 ========== NOTE 5 -- ASSET DISPOSITIONS In March 2000, we sold to a unit of El Paso Corporation ("El Paso") for $129.0 million the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. Except for minor third-party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from Goodyear in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction F-13
costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce outstanding debt. We recognized a gain of approximately $20.1 million in connection with the sale. The cost of the pipeline segment is included in assets held for sale on the consolidated balance sheet at December 31, 1999. We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized gains of approximately $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with the sale of the linefill. The amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and is included in assets held for sale on the consolidated balance sheet. NOTE 6 --DEBT Short-term debt and current portion of long-term debt consists of the following (in thousands): <TABLE> <CAPTION> DECEMBER 31, ----------------- 2000 1999 ------ ------ <S> <C> <C> Plains Marketing, L.P. letter of credit facility and hedged inventory facility, bearing interest at a weighted average interest rate of 8.4% at December 31, 2000 $1,300 $ - Letter of credit and borrowing facility, bearing interest at weighted average interest rate of 8.7% at December 31, 1999 - 13,719 Secured term credit facility, bearing interest at a weighted average interest rate of 8.8% at December 31, 1999 - 45,000 ------ -------- 1,300 58,719 Current portion of long-term debt - 50,650 ------ -------- $1,300 $109,369 ====== ======== </TABLE> Long-term debt consists of the following (in thousands): <TABLE> <CAPTION> DECEMBER 31, -------------------- 2000 1999 -------- -------- <S> <C> <C> Plains Marketing, L.P. revolving credit facility, bearing interest at a weighted average interest rate of 9.2% at December 31, 2000 $320,000 $ - All American Pipeline, L.P. bank credit agreement, bearing interest at a weighted average interest rate of 8.3% at December 31, 1999 - 225,000 Plains Scurlock bank credit agreement, bearing interest at a weighted average interest rate of 9.1% at December 31, 1999 - 85,100 Subordinated note payable - general partner, bearing interest at a weighted average interest rate of 8.7% at December 31, 1999 - 114,000 -------- -------- 320,000 424,100 Less current maturities - (50,650) -------- -------- $320,000 $373,450 ======== ======== </TABLE> On May 8, 2000, we entered into new bank credit agreements. The borrower under the new facilities is Plains Marketing, L.P. We are a guarantor of the obligations under the credit facilities. The obligations are also guaranteed by the subsidiaries of Plains Marketing, L.P. We entered into the credit agreements in order to: . refinance the existing bank debt of Plains Marketing, L.P. and Plains Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock Permian, L.P. into All American Pipeline, L.P.; . refinance existing bank debt of All American Pipeline, L.P.; . repay up to $114.0 million plus accrued interest of subordinated debt to our general partner, and . provide additional flexibility for working capital, capital expenditures, and for other general corporate purposes. F-14
At December 31, 2000, our bank credit agreements consist of: . a $400.0 million senior secured revolving credit facility. The revolving credit facility is secured by substantially all of our assets and matures in April 2004. No principal is scheduled for payment prior to maturity. The revolving credit facility bears interest at our option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin. We incur a commitment fee of 0.25% to 0.5% on the unused portion of the revolving credit facility. . a $300.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. The letter of credit facility is secured by substantially all of our assets and has a sublimit for cash borrowings of $100.0 million to purchase crude oil that has been hedged against future price risk. The letter of credit facility expires in April 2003. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base that is determined monthly based on certain of our current assets and current liabilities (primarily inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil). At December 31, 2000, approximately $59.7 million in letters of credit were outstanding under the letter of credit and borrowing facility. Our bank credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things: . incur indebtedness; . grant liens; . sell assets; . make investments; . engage in transactions with affiliates; . enter into prohibited contracts; and . enter into a merger or consolidation. Our bank credit agreements treat a change of control as an event of default and also requires us to maintain: . a current ratio (as defined) of 1.0 to 1.0; . a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0; . an interest coverage ratio that is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.65 to 1.0. A default under our bank credit agreements would permit the lenders to accelerate the maturity of the outstanding debt and to foreclose on the assets securing the credit facilities. As long as we are in compliance with our bank credit agreements, they do not restrict our ability to make distributions of "available cash" as defined in our partnership agreement. We are currently in compliance with the covenants contained in our credit agreements. At December 31, 2000, we could have borrowed up to $386.4 million available under our secured revolving credit facility. In February 2001, our bank credit agreements were amended. The amount available under the senior secured revolving credit facility was increased to $500.0 million and the maturity date was extended to April 2005. The amount available under the senior secured letter of credit and borrowing facility was reduced to $200.0 million and the expiration date was extended to April 2004. In addition, the banks agreed to an amendment which will allow us to borrow an additional $130.0 million under the terms of the senior secured revolving credit facility. We have an underwritten commitment, subject to conditions, for the $130.0 million. In December 1999, our general partner loaned us $114.0 million that we used for working capital requirements created by the 1999 unauthorized trading losses (see Note 3). This loan was repaid in May 2000 with proceeds from our senior secured revolving credit facility. On December 30, 1999, we entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility. F-15
At December 31, 1999 we had a $225.0 million bank credit agreement that included a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December 1999. At December 31, 1999, we had $225.0 million outstanding under the terms of this bank credit facility. In addition, at December 31, 1999, Plains Scurlock had a bank credit agreement which consisted of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The revolving credit facility could be used for borrowings or letters of credit to support crude oil purchases. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. Amounts outstanding under these credit agreements were repaid in May 2000 with proceeds from our senior secured revolving credit facility. Maturities The aggregate amount of maturities of all long-term indebtedness at December 31, 2000 for the next five years is: 2004 - $320.0. After the February 2001 amendments to the revolving credit facility, the maturities were: 2005 - $320.0. NOTE 7 -- PARTNERSHIP CAPITAL AND DISTRIBUTIONS Partner's capital consists of 24,356,429 common units, including 1,307,190 Class B common units, representing a 69.4% effective aggregate ownership interest in the partnership and its subsidiaries, (a subsidiary of our general partner owns 6,791,816 of such common units), 10,029,619 Subordinated units owned by a subsidiary of our general partner representing a 28.6% effective aggregate ownership interest in the partnership and its subsidiaries limited partner interest and a 2% general partner interest. In the aggregate, our general partner's interests represent an effective 54.0% ownership of our equity at December 31, 2000. All of the subordinated units and 20,059,239 of the common units were issued in connection with our November 1998 initial public offering. In October 1999, we completed a public offering of an additional 2,990,000 common units representing limited partner interests at $18.00 per unit. Net proceeds, including our general partners' contribution, from the offering were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. These proceeds were used to reduce outstanding debt. The Class B common units were issued in May 1999 to our general partner at $19.125 per unit for total proceeds of $25.0 million in connection with the Scurlock acquisition. We will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Distributions of available cash to holders of subordinated units are subject to the prior rights of holders of common units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2003) and to receive any arrearages in the distribution of the MQD on the common units for the prior quarters during the subordination period. There were no arrearages on common units at December 31, 2000. The MQD is $0.45 per unit ($1.80 per unit on an annual basis). Upon expiration of the subordination period, all subordinated units will be converted on a one-for-one basis into common units and will participate pro rata with all other common units in future distributions of available cash. Under certain circumstances, up to 50% of the subordinated units may convert into common units prior to the expiration of the subordination period. Common units will not accrue arrearages with respect to distributions for any quarter after the subordination period and subordinated units will not accrue any arrearages with respect to distributions for any quarter. If quarterly distributions of available cash exceed the MQD or the Target Distribution Levels (as defined), our general partner will receive distributions which are generally equal to 15%, then 25% and then 50% of the distributions of available cash that exceed the MQD or Target Distribution Level. The Target Distribution Levels are based on the amounts of available cash from our Operating Surplus (as defined) distributed with respect to a given quarter that exceed distributions made with respect to the MQD and common unit arrearages, if any. Cash distributions for the second, third and fourth quarters of 2000 were $0.4625 per unit on our outstanding common units, Class B units and subordinated units, representing an increase of $0.0125 per unit over the MQD. Cash distributions for the second and third quarters of 1999 were $0.4625 per unit and $0.48125 per unit, respectively, on our outstanding common units, Class B units and subordinated units, representing an increase of $0.0125 per unit and $0.03125 per unit, respectively, over the MQD. The Class B common units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval F-16
of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units. NOTE 8 -- FINANCIAL INSTRUMENTS Derivatives We utilize derivative financial instruments to hedge our exposure to price volatility on crude oil and do not use such instruments for speculative trading purposes. These arrangements expose us to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where our purchases are less than expected. In the event of non-performance of a counterparty, we might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In order to minimize credit risk relating to the non-performance of a counterparty, we enter into such contracts with counterparties that are considered investment grade, periodically review the financial condition of such counterparties and continually monitor the effectiveness of derivative financial instruments in achieving our objectives. In view of our criteria for selecting counterparties, our process for monitoring the financial strength of these counterparties and our experience to date in successfully completing these transactions, we believe that the risk of incurring significant financial statement loss due to the non-performance of counterparties to these transactions is minimal. At December 31, 2000, our hedging activities included crude oil futures contracts maturing in 2000 through 2002, covering approximately 3.2 million barrels of crude oil. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $15.1 million and $17.8 million for the years ended December 31, 2000 and 1999, respectively. The unrealized loss with respect to such instruments at December 31, 2000 and 1999 was $7.8 million and $9.8 million, respectively. Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At December 31, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $215.0 million. The adjustment to interest expense resulting from interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.1 million gain and a $0.1 million loss. These instruments are based on LIBOR margins and provide for a floor of 5% and a ceiling of 6.5% with an expiration date of February 2001 for $90.0 million notional principal amount and a floor of 6% and a ceiling of 8% with an expiration date of August 2002 for $125.0 million notional principal amount. Fair Value of Financial Instruments The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying value of bank debt approximates fair value as interest rates are variable, based on prevailing market rates. Crude oil futures contracts permit settlement by delivery of the crude oil and, therefore, are not financial instruments, as defined. The fair value of crude oil swaps and option contracts and interest rate swap and collar agreements are based on current termination values or quoted market prices of comparable contracts. The carrying amounts and fair values of our financial instruments are as follows (in thousands): <TABLE> <CAPTION> DECEMBER 31, ----------------------------------------------------- 2000 1999 ---------------------------- ----------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE --------------- ---------- ----------- --------- <S> <C> <C> <C> <C> Unrealized loss on crude oil swaps and option contracts $ - $ - - $(569) Unrealized gain (loss) on interest rate swaps and collars - (561) - 388 </TABLE> NOTE 9 -- EARLY EXTINGUISHMENT OF DEBT During 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $15.1 million related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of our F-17
credit facilities. In addition, interest and other income for the year ended December 31, 2000, includes $9.7 million of previously deferred gains from terminated interest rate swaps as a result of debt extinguishment (see Notes 3 and 6). The extraordinary loss of $1.5 million in 1999 relates to the write-off of certain debt issue costs and penalties associated with the prepayment of debt. NOTE 10 -- INCOME TAXES As discussed in Note 2, our predecessor's results are included in Plains Resources' combined federal income tax return. The amounts presented below were calculated as if our predecessor filed a separate tax return. Provision in lieu of income taxes of our predecessor consists of the following components (in thousands): JANUARY 1, 1998 TO NOVEMBER 22, 1998 ------------ Federal Current $ 455 Deferred 1,900 State Current - Deferred 276 ------ Total $2,631 ====== A reconciliation of the provision in lieu of income taxes to the federal statutory tax rate of 35% is as follows (in thousands): JANUARY 1, 1998 TO NOVEMBER 22, 1998 ------------- Provision at the statutory rate $2,410 State income tax, net of benefit for federal deduction 181 Permanent differences 40 ------ Total $2,631 ====== NOTE 11 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION In connection with our formation, certain investing and financial activities occurred. Effective November 23, 1998, substantially all of the assets and liabilities of our predecessor were conveyed to us at historical cost. Net assets assumed by the operating partnership are as follows (in thousands): Cash and cash equivalents $ 224 Accounts receivable 109,311 Inventory 22,906 Prepaid expenses and other current assets 1,059 Property and equipment, net 375,948 Pipeline linefill 48,264 Intangible assets, net 11,001 -------- Total assets conveyed 568,713 -------- Accounts payable and other current liabilities 107,405 Due to affiliates 8,942 Bank debt 183,600 -------- Total liabilities assumed 299,947 -------- Net assets assumed by the Partnership $268,766 ======== F-18
Interest paid totaled $25.9 million, $22.3 million, $0.1 million and $8.5 million for the years ended December 31, 2000 and 1999, the period from November 23, 1998 to December 31, 1998 and the period from January 1, 1998 through November 23, 1998, respectively. NOTE 12 -- MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK Customers accounting for 10% or more of revenues were as follows for the periods indicated: <TABLE> <CAPTION> PERCENTAGE ------------------------------------------------------- NOVEMBER 23, JANUARY 1, YEAR ENDED DECEMBER 31, 1998 TO 1998 TO ----------------------- DECEMBER 31, NOVEMBER 22, CUSTOMER 2000 1999 1998 1998 - ------------------------------------- ------ ------ ----------- ------------ <S> <C> <C> <C> <C> Marathon Ashland Petroleum 12% - - - Sempra Energy Trading Corporation - 22% 20% 31% Koch Oil Company - 19% - 19% ExxonMobil - - 11% - </TABLE> All of the customers above pertain to our marketing, gathering, terminalling and storage segment. Financial instruments which potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers that are not considered investment grade, unless the credit risk can otherwise be reduced. We believe that the loss of an individual customer would not have a material adverse effect. NOTE 13 -- RELATED PARTY TRANSACTIONS Reimbursement of Expenses of Our General Partner and Its Affiliates We do not directly employ any persons to manage or operate our business. These functions are provided by employees of our general partner and Plains Resources. Our general partner does not receive a management fee or other compensation in connection with its management of us. We reimburse our general partner and Plains Resources for all direct and indirect costs of services provided, including the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business, and allocable to us. Our agreement provides that our general partner will determine the expenses allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed to our general partner and Plains Resources by us were approximately $63.8 million, $44.7 million and $0.5 million for the years ended December 31, 2000 and 1999 and for period from November 23, 1998 to December 31, 1998, respectively. Such costs include, (1) allocated personnel costs (such as salaries and employee benefits) of the personnel providing such services, (2) rent on office space allocated to our general partner in Plains Resources' offices in Houston, Texas (3) property and casualty insurance premiums and (4) out-of-pocket expenses related to the provision of such services. Plains Resources allocated certain general and administrative expenses to the Plains Midstream Subsidiaries during 1998. The types of indirect expenses allocated to the Plains Midstream Subsidiaries during this period were office rent, utilities, telephone services, data processing services, office supplies and equipment maintenance. Direct expenses allocated by Plains Resources were primarily salaries and benefits of employees engaged in the business activities of the Plains Midstream Subsidiaries. Crude Oil Marketing Agreement We are the exclusive marketer/purchaser for all of Plains Resources' equity crude oil production. The marketing agreement with Plains Resources provides that we will purchase for resale at market prices all of Plains Resources' crude oil production for which we charge a fee of $0.20 per barrel. For the years ended December 31, 2000 and 1999 and the period from November 23, 1998 to December 31, 1998, we paid Plains Resources approximately $244.9 million, $131.5 million and $4.1 million, respectively, for the purchase of crude oil under the agreement, including the royalty share of production, and recognized profits of approximately $1.7 million, $1.5 million and $0.1 million from the marketing fee for the same periods, respectively. Prior to the marketing agreement, our predecessor marketed crude oil production of Plains Resources, its subsidiaries and its royalty owners. Our predecessor paid approximately $83.4 million for the purchase of these products for F-19
the period from January 1, 1998 to November 22, 1998. In management's opinion, these purchases were made at prevailing market prices. Our predecessor did not recognize a profit on the sale of the crude oil purchased from Plains Resources. Financing In May 2000, we repaid to our general partner $114.0 million of subordinated debt (see Note 6). Interest expense related to the notes was $3.3 million and $0.6 million for the years ended December 31, 2000 and 1999, respectively. To finance a portion of the purchase price of the Scurlock acquisition, we sold to our general partner 1.3 million Class B common units at $19.125 per unit, the market value of our common units on May 12, 1999 (see Note4). The balance of amounts due to affiliates at December 31, 2000 and 1999 was $21.0 million and $42.7 million, respectively, and was related to the transactions discussed above. Benefit Plan Plains Resources maintains a 401(k) defined contribution plan whereby they match 100% of an employee's contribution (subject to certain limitations in the plan), with matching contribution being made 50% in cash and 50% in common stock (the number of shares for the stock match being based on the market value of the common stock at the time the shares are granted). For the years ended December 31, 2000, 1999 and 1998, defined contribution plan expense was $1.0 million, $0.7 million and $0.2 million, respectively. NOTE 14 -- LONG-TERM INCENTIVE PLANS Our general partner has adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of our general partner's board of directors. Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2001, an aggregate of approximately 610,100 restricted units have been granted to employees of our general partner. In addition, 15,000 restricted units have been granted to non-employee directors of our general partner. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of the subordinated units to common units. Grants made to non- employee directors of our general partner are eligible to vest prior to termination of the subordination period. If a grantee terminates employment or membership on the board for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. Following the subordination period, the Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units. The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration will be paid to us by the plan participants upon receipt of the common units. Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided. F-20
Upon exercise of a unit option, our general partner will deliver common units acquired by it in the open market, purchased directly from us or any other person, or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of the common unitholders. Our general partner's board of directors in its discretion may terminate the Long-Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the Long-Term Incentive Plan or any part of the plan from time to time, including increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant. We apply APB 25 and related interpretations in accounting for unit option plans. In accordance with APB 25, no compensation expense has been recognized for the unit option plan. Since no options have been granted to date, there is no pro forma effect of a fair value based method of accounting in accordance with SFAS No. 123 "Accounting for Stock-Based Compensation" ("SFAS 123"). Transaction Grant Agreements. In addition to the grants made under the Restricted Unit Plan described above, our general partner, at no cost to us, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of our general partner and its affiliates. Generally, under these grants, the common units vest based on attaining a targeted operating surplus for a given year. Approximately 75,000 and 6,000 of the common units vest for 2001 and 2002, respectively, if the operating surplus generated in each year equals or exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and the related distribution on our general partner interest. If a tranche of common units does not vest for a particular year due to a common unit arrearage, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 58,000 and 11,000 of the common units vest for 2001and 2002, respectively, if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and subordinated units and the related distributions on our general partner interest. Approximately 69,000 and 113,000 (excluding approximately 20,000 units withheld for payment of federal income taxes) of the units vested for 1999 and 2000, respectively and approximately 47,000 common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as our general partner prior to January 1, 2002. We recognized noncash compensation expense of approximately $3.1 million and $1.0 million for the years ended December 31, 2000 and 1999, respectively, related to the transaction grants which vested for 2000 and 1999. These amounts are included in general and administrative expense on the Consolidated Statements of Operations. We reflected a capital contribution from our general partner for like amounts. There were no transaction grants which vested for 1998. NOTE 15 -- COMMITMENTS AND CONTINGENCIES We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be canceled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 2000, are summarized below (in thousands): 2001 $ 6,420 2002 3,716 2003 3,727 2004 3,744 2005 3,764 Thereafter 2,797 F-21
Total lease expense incurred for 2000 and 1999 was $6.7 million and $8.9 million, respectively. Lease expense incurred for the period from November 23, 1998 to December 31, 1998 and from January 1, 1998 to November 22, 1998 was $0.2 million and $0.9 million, respectively. During 1997, the All American Pipeline experienced a leak in a segment of its pipeline in California that resulted in an estimated 12,000 barrels of crude oil being released into the soil. Immediate action was taken to repair the pipeline leak, contain the spill and to recover the released crude oil. We have expended approximately $400,000 to date in connection with this spill and do not expect any additional expenditures to be material, although we can provide no assurances in that regard. Prior to being acquired by our predecessor in 1996, the Ingleside Terminal experienced releases of refined petroleum products into the soil and groundwater underlying the site due to activities on the property. We are undertaking a voluntary state-administered remediation of the contamination on the property to determine the extent of the contamination. We have proposed extending the scope of our study and are awaiting the state's response. We have spent approximately $140,000 to date in investigating the contamination at this site. We do not anticipate the total additional costs related to this site to exceed $250,000, although no assurance can be given that the actual cost could not exceed such estimate. In addition, a portion of any such costs may be reimbursed to us from Plains Resources. Litigation Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit alleged that Plains All American and certain of our general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name our general partner and Plains Resources as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of Plains Resources' common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of our common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and Plains Resources reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, we deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and Plains Resources, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to Plains Resources by agreement between special independent committees of the board of directors of our general partner and the board of directors of Plains Resources. All such amounts were reflected in our financial statements at December 31, 2000. The settlement is subject to a number of conditions, including final approval by the court. A hearing is set for March 30, 2001. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named our general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Susser v. Plains All American Inc. as the complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. The plaintiffs in the Delaware derivative litigation seek that the defendants . account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses; . establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices detrimental to Plains All American; . pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees; and . provide the plaintiffs any additional relief as may be just and proper under the circumstances. F-22
We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court of the Southern District of Texas entitled Fernandes v. Plains All American Inc., et al, naming our general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation, described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. We intend to vigorously defend the claims made in the Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial position or results of operation. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. While we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED) <TABLE> <CAPTION> FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER (1) TOTAL ------------- ------------ ----------- ---------------- --------- (IN THOUSANDS, EXCEPT PER UNIT DATA) <S> <C> <C> <C> <C> <C> 2000 - ---- Revenues, as reclassified (2) $2,002,507 $1,481,834 $1,555,863 $1,600,983 $ 6,641,187 Revenues, as previously reported 999,319 738,967 756,926 - 2,495,212 Gross margin (3) 36,552 32,774 25,960 32,434 127,720 Operating income 17,788 20,164 10,700 13,724 62,376 Net income before extraordinary item 64,300 17,063 4,516 6,770 92,649 Extraordinary item (4,145) (11,002) - - (15,147) Net income 60,155 6,061 4,516 6,770 77,502 Net income per limited partner unit Before extraordinary item 1.83 0.49 0.13 0.19 2.64 Extraordinary item (0.12) (0.32) - - (0.44) After extraordinary item 1.71 0.17 0.13 0.19 2.20 Cash distributions per common unit (4) $ 0.450 $ 0.463 $ 0.463 $ 0.463 $ 1.839 1999 - ---- Revenues, as reclassified (2) $1,128,839 $2,535,200 $3,000,282 $4,246,102 $10,910,423 Revenues, as previously reported 471,209 885,046 1,127,808 2,255,829 4,739,892 Gross margin (3) (1,546) 4,985 (38,922) (20,643) (56,126) Operating loss (6,965) (4,624) (53,839) (32,663) (98,091) Net loss before extraordinary item (10,061) (9,154) (60,131) (22,469) (101,815) Extraordinary item - - - (1,545) (1,545) Net loss (10,061) (9,154) (60,131) (24,014) (103,360) Net loss per limited partner unit Before extraordinary item (0.33) (0.29) (1.88) (0.64) (3.16) Extraordinary item - - - (0.05) (0.05) After extraordinary item (0.33) (0.29) (1.88) (0.69) (3.21) Cash distributions per common unit (4) $ 0.450 $ 0.463 $ 0.481 $ 0.450 $ 1.844 </TABLE> - ------------------------ (1) For 2000, includes a $5.0 million charge to reserve for potentially uncollectible accounts receivable. (2) These amounts represent the reclassification from previously reported amounts due to the adoption of EITF 99-19 (see Note 2). (3) For the third and fourth quarters of 2000, includes the effects of the charge for litigation related to the unauthorized trading losses and the effects of the unauthorized trading losses for all quarters of 1999 (see Note 3). (4) Represents cash distributions declared and paid per common unit for the period indicated. Distributions are paid in the following calendar quarter. F-23
NOTE 17 -- OPERATING SEGMENTS Our operations consist of two operating segments: (1) Pipeline Operations - engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; (2) Marketing, Gathering, Terminalling and Storage Operations - engages in purchases and resales of crude oil at various points along the distribution chain and the leasing of certain terminalling and storage assets. Prior to the July 1998 acquisition of the All American Pipeline and SJV Gathering System, our predecessor had only marketing, gathering, terminalling and storage operations. We evaluate segment performance based on gross margin, gross profit and income before provision in lieu of income taxes and extraordinary items. The following table summarizes segment revenues, gross margin, gross profit and income (loss) before provision in lieu of income taxes and extraordinary items: <TABLE> <CAPTION> MARKETING, GATHERING, TERMINALLING (IN THOUSANDS) PIPELINE & STORAGE (a) TOTAL (a) - ----------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> 2000 Revenues: External Customers $505,712 $ 6,135,475 $ 6,641,187 Intersegment (b) 68,745 - 68,745 Other 9,045 1,731 10,776 -------- ----------- ----------- Total revenues of reportable segments $583,502 $ 6,137,206 $ 6,720,708 ======== =========== =========== Segment gross margin (c) $ 51,787 $ 75,933 $ 127,720 Segment gross profit (d) 49,996 36,903 86,899 Net income (loss) before extraordinary item 94,461 (1,812) 92,649 Interest expense 5,738 22,953 28,691 Depreciation and amortization 7,030 17,493 24,523 Capital expenditures 1,544 11,059 12,603 Total assets 324,751 561,050 885,801 - ----------------------------------------------------------------------------------------------------------- 1999 Revenues: External Customers $854,377 $10,056,046 $10,910,423 Intersegment (b) 131,445 - 131,445 Other 195 763 958 -------- ----------- ----------- Total revenues of reportable segments $986,017 $10,056,809 $11,042,826 ======== =========== =========== Segment gross margin (c) $ 58,001 $ (114,127) $ (56,126) Segment gross profit (d) 55,384 (134,721) (79,337) Net income (loss) before extraordinary item 46,075 (147,890) (101,815) Interest expense 13,572 7,567 21,139 Depreciation and amortization 10,979 6,365 17,344 Capital expenditures 69,375 119,911 189,286 Total assets 524,438 698,599 1,223,037 - ----------------------------------------------------------------------------------------------------------- NOVEMBER 23, 1998 TO DECEMBER 31, 1998 Revenues: External Customers $ 54,089 $ 344,829 $ 398,918 Intersegment (b) 2,029 429 2,458 Other - 12 12 -------- ----------- ----------- Total revenues of reportable segments $ 56,118 $ 345,270 $ 401,388 ======== =========== =========== Segment gross margin (c) $ 3,546 $ 1,553 $ 5,099 Segment gross profit (d) 3,329 999 4,328 Net income 1,035 742 1,777 Interest expense 1,321 50 1,371 Depreciation and amortization 973 219 1,192 Capital expenditures 352 2,535 2,887 Total assets 471,864 135,322 607,186 - ----------------------------------------------------------------------------------------------------------- Table continued on following page </TABLE> F-24
<TABLE> <CAPTION> MARKETING, GATHERING, TERMINALLING (IN THOUSANDS) PIPELINE & STORAGE (a) TOTAL (a) - --------------------------------------------------------------------------------------------------------- January 1, 1998 to November 22, 1998 (Predecessor) <S> <C> <C> <C> Revenues: External Customers $200,139 $2,918,214 $3,118,353 Intersegment (b) 21,166 2,391 23,557 Other 603 (31) 572 -------- ---------- ---------- Total revenues of reportable segments $221,908 $2,920,574 $3,142,482 ======== ========== ========== Segment gross margin (c) $ 13,222 $ 13,059 $ 26,281 Segment gross profit (d) 12,394 9,361 21,755 Net income before provision in lieu of income taxes 2,152 4,736 6,888 Interest expense 7,787 3,473 11,260 Depreciation and amortization 3,058 1,121 4,179 Provision in lieu of income taxes 822 1,809 2,631 Capital expenditures 393,379 4,677 398,056 - --------------------------------------------------------------------------------------------------------- </TABLE> a) Revenues for the marketing, gathering, terminalling and storage segment include the effects of the adoption of EITF 99-19 (see Note 2). For the years ending December 31, 2000 and 1999 and the periods November 23, 1998 to December 31, 1998 and January 1, 1998 to November 22, 1998, revenues have been reclassified by $2.5 billion, $6.2 billion, $0.2 billion and $2.1 billion, respectively. b) Intersegment sales were conducted on an arm's length basis. c) Gross margin is calculated as revenues less cost of sales and operations expenses. d) Gross profit is calculated as revenues less costs of sales and operations expenses and general and administrative expenses. NOTE 18 -- SUBSEQUENT EVENTS Acquisitions Murphy Oil Company Ltd. Midstream Operations On March 1, 2001, we signed an agreement to purchase substantially all of the crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. ("Murphy") for approximately $155.0 million in cash, plus an additional cash payment, to be determined prior to closing in accordance with the agreement, for excess inventory in the systems (estimated to be approximately $5.0 million). The principal assets to be acquired include approximately 450 miles of crude oil and condensate transmission mainlines and associated gathering and lateral lines, and approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently inactive 108-mile mainline system and 121 trailers used primarily for crude oil transportation. Murphy has agreed to continue to transport production from fields currently delivering crude oil to these pipeline systems, under a new long-term contract. The current volume is approximately 11,000 barrels per day. The pipeline systems transport approximately 200,000 barrels per day of light, medium and heavy crudes, as well as condensate. Canadian Marketing Assets We have entered into a letter of intent to purchase the assets of a Canadian marketing company. The expected purchase price is approximately $43.0 million, of which approximately $18.0 million will be subject to certain performance targets. The marketing company currently gathers approximately 75,000 barrels per day of crude oil and markets approximately 26,000 barrels per day of natural gas liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel tank facility and working capital of approximately $8.5 million. Initial financing for the acquisitions will be provided via an expansion of our existing revolving credit, letter of credit and inventory facility. The expanded facility will initially be underwritten by Fleet Boston and will consist of a $100.0 million five-year term loan and a $30.0 million revolving credit facility that will expire in April 2005. F-25