10-K 1 h84803e10-k.txt TEPPCO PARTNERS LP - YEAR ENDED DECEMBER 31, 2000 1 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 COMMISSION FILE NUMBER 1-10403 TEPPCO PARTNERS, L.P. (Exact name of Registrant as specified in its charter)

DELAWARE 76-0291058 (State of Incorporation or Organization) (I.R.S. Employer Identification Number)

2929 ALLEN PARKWAY P.O. BOX 2521 HOUSTON, TEXAS 77252-2521 (Address of principal executive offices, including zip code) (713) 759-3636 (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED Limited Partner Units representing Limited New York Stock Exchange Partner Interests

Securities registered pursuant to Section 12(g) of the Act: NONE 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 twelve 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 / / 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. / / At March 6, 2001 the aggregate market value of the registrant's Limited Partner Units held by non-affiliates was $884,183,957, which was computed using the average of the high and low sales prices of the Limited Partner Units on March 6, 2001. Limited Partner Units outstanding as of March 6, 2001: 34,950,000. 2 TABLE OF CONTENTS PART I ITEMS 1. AND 2. Business and Properties............................................ 1 ITEM 3. Legal Proceedings..................................................15 ITEM 4. Submission of Matters to a Vote of Security Holders................15 PART II ITEM 5. Market for Registrant's Units and Related Unitholder Matters.......16 ITEM 6. Selected Financial Data............................................17 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..............................................18 ITEM 7A. Quantitative and Qualitative Disclosures About Market Risks........28 ITEM 8. Financial Statements and Supplementary Data........................28 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...............................................28 PART III ITEM 10. Directors and Executive Officers of the Registrant.................29 ITEM 11. Executive Compensation.............................................31 ITEM 12. Security Ownership of Certain Beneficial Owners and Management.....37 ITEM 13. Certain Relationships and Related Transactions.....................38 PART IV ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....38 i 3 ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership, was formed in March 1990. The Partnership operates through TE Products Pipeline Company, Limited Partnership (the "Products OLP") and TCTM, L.P. (the "Crude Oil OLP"). Collectively the Products OLP and the Crude Oil OLP are referred to as "the Operating Partnerships." The Partnership owns a 99% interest as the sole limited partner interest in both the Products OLP and the Crude Oil OLP. On March 31, 2000, Texas Eastern Products Pipeline Company, a Delaware corporation and general partner of the Partnership and the Operating Partnerships, was converted into Texas Eastern Products Pipeline Company, LLC (the "Company" or "General Partner"), a Delaware limited liability company. Additionally on March 31, 2000, Duke Energy Corporation ("Duke Energy"), contributed its ownership of the General Partner to Duke Energy Field Services, LP ("DEFS"). DEFS is a joint venture between Duke Energy and Phillips Petroleum Company. Duke Energy holds a majority interest in DEFS. The Company owns a 1% general partner interest in the Partnership and a 1% general partner interest in each Operating Partnership. The General Partner performs all management and operating functions required for the Partnership and the Operating Partnerships. The Partnership operates in two segments - refined products and liquefied petroleum gases ("LPGs") transportation ("Downstream Segment"); and crude oil and natural gas liquids ("NGLs") transportation and marketing ("Upstream Segment"). See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15 of the Notes to Consolidated Financial Statements contained elsewhere herein for additional segment information. At December 31, 2000, the Partnership had outstanding 32,700,000 Limited Partner Units and 3,916,547 Class B Limited Partner Units ("Class B Units"). All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets in 1998. The Class B Units are substantially identical to the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the Limited Partner Unitholders. The Company has the option to seek approval for the conversion of the Class B Units into Limited Partnership Units; however, if such conversion is denied, the holder of the Class B Units will have the right to sell them to the Partnership at 95.5% of the market price of the Limited Partner Units at the time of sale. As a result of such option, the Class B Units were not included in partners' capital at December 31, 2000. Collectively, the Limited Partner Units and Class B Units are referred to as "Units." The Partnership's strategy is to improve service in its current markets, maintain the integrity of its pipeline systems and pursue a growth strategy that is balanced between internal projects and targeted acquisitions. The Partnership intends to leverage the advantages inherent in its pipeline systems to maintain its status as the incremental provider of choice in its market area. The Partnership also intends to grow by acquiring assets, from both third parties and affiliates, which complement existing businesses. The Company routinely evaluates opportunities to acquire assets and businesses that will complement existing operations with a view to increasing earnings and cash available for distribution to Unitholders. Additional acquisitions may be funded with borrowings under existing credit facilities, the issuance of debt in the capital markets, the sale of additional units and cash flow from operations. REFINED PRODUCTS AND LPGS TRANSPORTATION Operations The operations of the Downstream Segment are conducted through the Products OLP. The Downstream Segment conducts business and owns properties located in 13 states. Operations consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas complex; intrastate transportation of petrochemicals; fractionation of natural gas liquids and other ancillary services. l 4 In August 2000, the Partnership announced the execution of definitive agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial Pipeline, LLC ("Centennial"). Centennial will own and operate an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant will own a one-third interest in Centennial. Centennial Pipeline will build a 74-mile, 24-inch diameter pipeline connecting the Products OLP's facility in Beaumont, Texas, with the start of an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The pipeline will pass through portions of Texas, Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Illinois. CMS Panhandle Pipe Line Companies, which owns the existing 720-mile pipeline, has made a filing with the Federal Energy Regulatory Commission ("FERC") to take the line out of natural gas service as part of the regulatory process. Conversion of the pipeline to refined products service is expected to be completed in early 2002. The Centennial Pipeline will intersect the Downstream Segment's existing mainline near Creal Springs, Illinois, where a new two million barrel refined petroleum products storage terminal will be built. The Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. The Downstream Segment owns and operates an approximate 4,500-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the "Pipeline System" or "Pipeline" or "System") extending from southeast Texas through the central and midwestern United States to the northeastern United States. The Pipeline System includes delivery terminals for outloading product to other pipelines, tank trucks, rail cars or barges, as well as substantial storage capacity at Mont Belvieu, Texas, the largest LPGs storage complex in the United States, and at other locations. The Downstream Segment also owns two marine receiving terminals, one near Beaumont, Texas, and the other at Providence, Rhode Island. The Providence terminal is not physically connected to the Pipeline. As an interstate common carrier, the Pipeline System offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum products and LPGs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. In addition to the revenues received by the Pipeline System from its interstate tariffs, it also receives revenues from the shuttling of LPGs between refinery and petrochemical facilities on the upper Texas Gulf Coast and ancillary transportation, storage and marketing services at key points along the System. Substantially all the petroleum products transported and stored in the Pipeline System are owned by the Downstream Segement's customers. Petroleum products are received at terminals located principally on the southern end of the Pipeline System, stored, scheduled into the Pipeline in accordance with customer nominations and shipped to delivery terminals for ultimate delivery to the final distributor (e.g., gas stations and retail propane distribution centers) or to other pipelines. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of petroleum products. The Pipeline System is the only pipeline that transports LPGs to the Northeast. The Downstream Segment's business depends in large part on the level of demand for refined petroleum products and LPGs in the geographic locations served by it and the ability and willingness of customers having access to the Pipeline System to supply such demand by deliveries through the System. The Partnership cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental regulation, technological advances in fuel economy and energy-generation devices, all of which could reduce the demand for refined petroleum products and LPGs in the areas served by the Partnership. Products are transported in liquid form from the upper Texas Gulf Coast through two parallel underground pipelines that extend to Seymour, Indiana. From Seymour, segments of the Pipeline System extend to the Chicago, Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia, Pennsylvania, areas. The Pipeline System east of Todhunter, Ohio, is dedicated solely to LPGs transportation and storage services. The Pipeline System includes 30 storage facilities with an aggregate storage capacity of 13 million barrels of refined petroleum products and 38 million barrels of LPGs, including storage capacity leased to outside parties. The Pipeline System makes deliveries to customers at 53 locations including 18 Partnership owned truck racks, rail car facilities and marine facilities. Deliveries to other pipelines occur at various facilities owned by the Partnership or by third parties. 2 5 Pipeline System The Pipeline System is comprised of a 20-inch diameter line extending in a generally northeasterly direction from Baytown, Texas (located approximately 30 miles east of Houston), to a point in southwest Ohio near Lebanon and Todhunter. A second line, which also originates at Baytown, is 16 inches in diameter until it reaches Beaumont, Texas, at which point it reduces to a 14-inch diameter line. This second line extends along the same path as the 20-inch diameter line to the Pipeline System's terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour, Indiana. The Pipeline System also has smaller diameter lines that extend laterally from El Dorado to Helena and Arkansas City, Arkansas, from Tyler, Texas, to El Dorado and from McRae, Arkansas, to West Memphis, Arkansas. The lines from El Dorado to Helena and Arkansas City have 10-inch diameters. The line from Tyler to El Dorado varies in diameter from 8 inches to 10 inches. The line from McRae to West Memphis has a 12-inch diameter. The Pipeline System also includes a 14-inch diameter line from Seymour, Indiana, to Chicago, Illinois, and a 10-inch diameter line running from Lebanon to Lima, Ohio. This 10-inch diameter pipeline connects to the Buckeye Pipe Line Company system that serves, among others, markets in Michigan and eastern Ohio. Also, the Pipeline System has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport and a 8-inch diameter pipeline connection to the George Bush Intercontinental Airport, Houston. In addition, there are numerous smaller diameter lines associated with the gathering and distribution system. The Pipeline System continues eastward from Todhunter, Ohio, to Greensburg, Pennsylvania, at which point it branches into two segments, one ending in Selkirk, New York (near Albany), and the other ending at Marcus Hook, Pennsylvania (near Philadelphia). The Pipeline east of Todhunter and ending in Selkirk is an 8-inch diameter line, whereas the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches. East of Todhunter, Ohio, the Partnership transports only LPGs through the Pipeline. The Pipeline System has been constructed and is in general compliance with applicable federal, state and local laws and regulations, and accepted industry standards and practices. The Partnership performs regular maintenance on all the facilities of the Pipeline System and has an ongoing process of inspecting segments of the Pipeline System and making repairs and replacements when necessary or appropriate. In addition, the Partnership conducts periodic air patrols of the Pipeline System to monitor pipeline integrity and third-party right of way encroachments. Major Business Sector Markets The Pipeline System's major operations are the transportation, storage and terminaling of refined petroleum products and LPGs along its mainline system, and the storage and short-haul transportation of LPGs associated with its Mont Belvieu operations. Product deliveries, in millions of barrels (MMBbls) on a regional basis, over the last three years were as follows: 3 6

PRODUCT DELIVERIES(MMBbls) YEARS ENDED DECEMBER, 31 ---------------------------- 2000 1999 1998 ------ ------- ------- Refined Products Transportation: Central (1) ............................. 63.4 67.7 71.5 Midwest (2) ............................. 36.7 37.9 34.8 Ohio and Kentucky ....................... 28.0 27.0 24.2 ----- ----- ----- Subtotal .......................... 128.1 132.6 130.5 ----- ----- ----- LPGs Mainline Transportation: Central, Midwest and Kentucky (1)(2) .. 23.4 22.9 18.5 Ohio and Northeast (3) ................ 16.2 14.7 13.5 ----- ----- ----- Subtotal ........................ 39.6 37.6 32.0 ----- ----- ----- Mont Belvieu Operations: LPGs .................................. 27.2 28.5 25.1 ----- ----- ----- Total Product Deliveries ........ 194.9 198.7 187.6 ===== ===== =====

---------- (1) Arkansas, Louisiana, Missouri and Texas. (2) Illinois and Indiana. (3) New York and Pennsylvania. The mix of products delivered varies seasonally, with gasoline demand generally stronger in the spring and summer months and LPGs demand generally stronger in the fall and winter months. Weather and economic conditions in the geographic areas served by the Pipeline System also affect the demand for and the mix of the products delivered. Refined products and LPGs deliveries over the last three years were as follows:

PRODUCT DELIVERIES(MMBbls) YEARS ENDED DECEMBER, 31 -------------------------- 2000 1999 1998 ------ ------ ------ Refined Products Transportation: Gasoline ......................................... 67.8 71.6 74.0 Jet Fuels ................................... 28.1 26.9 23.8 Middle Distillates (1) ...................... 26.6 28.4 26.1 MTBE/Toluene ................................ 5.6 5.7 6.6 ------ ------ ------ Subtotal .............................. 128.1 132.6 130.5 ------ ------ ------ LPGs Mainline Transportation: Propane ..................................... 33.1 30.8 25.5 Butanes ..................................... 6.5 6.8 6.5 ------ ------ ------ Subtotal .............................. 39.6 37.6 32.0 ------ ------ ------ Mont Belvieu Operations: LPGs ........................................ 27.2 28.5 25.1 ------ ------ ------ Total Product Deliveries .............. 194.9 198.7 187.6 ====== ====== ======

---------- (1) Primarily diesel fuel, heating oil and other middle distillates. Refined Petroleum Products Transportation The Pipeline System transports refined petroleum products from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and Midwest regions of the United States with deliveries in Texas, Louisiana, Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points, refined petroleum products are delivered 4 7 to Partnership-owned terminals, connecting pipelines and customer-owned terminals. The Downstream Segment canceled its tariff for deliveries of methyl tertiary butyl ether ("MTBE") into the Chicago market area on July 1, 1999, and will cancel contract deliveries of MTBE at its marine terminal near Beaumont, Texas, effective April 22, 2001. Governmental regulation, technological advances in fuel economy, energy generation devices and future fuel conservation measures could reduce the demand for refined petroleum products in the market areas we serve. The volume of refined petroleum products transported by the Pipeline System is directly affected by the demand for such products in the geographic regions the System serves. Such market demand varies based upon the different end uses to which the refined products deliveries are applied. Demand for gasoline, which accounts for a substantial portion of the volume of refined products transported through the Pipeline System, depends upon price, prevailing economic conditions and demographic changes in the markets served. Demand for refined products used in agricultural operations is affected by weather conditions, government policy and crop prices. Demand for jet fuel depends upon prevailing economic conditions and military usage. Market prices for refined petroleum products affect the demand in the markets served by the Downstream Segment. Therefore, quantities and mix of products transported may vary. Transportation tariffs of refined petroleum products vary among specific product types. As a result, market price volatility may affect transportation revenues from period to period. LPGs Mainline Transportation The Pipeline System transports LPGs from the upper Texas Gulf Coast to the Central, Midwest and Northeast regions of the United States. The Pipeline System east of Todhunter, Ohio, is devoted solely to the transportation of LPGs. Since LPGs demand is generally stronger in the winter months, the Pipeline System often operates at or near capacity during such time. Propane deliveries are generally sensitive to the weather and meaningful year-to-year variations have occurred and will likely continue to occur. The Downstream Segment's ability to serve markets in the Northeast is enhanced by its propane import terminal at Providence, Rhode Island. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. Although the terminal is operated by the Downstream Segment, the utilization of the terminal is committed by contract to a major propane marketer through April 30, 2001. In February 2001, the Company signed an agreement with DEFS whereby propane received at the Providence terminal will be marketed by DEFS, beginning May 2001. Mont Belvieu LPGs Storage and Pipeline Shuttle A key aspect of the Pipeline System's LPGs business is its storage and pipeline asset base in the Mont Belvieu, Texas, complex serving the fractionation, refining and petrochemical industries. The complex is the largest of its kind in the United States and provides substantial capacity and flexibility in the transportation, terminaling and storage of natural gas liquids, LPGs, petrochemicals and olefins. The Downstream Segment has approximately 36 million barrels of LPGs storage capacity, including storage capacity leased to outside parties, at the Mont Belvieu complex. The Downstream Segment's Mont Belvieu short-haul transportation shuttle system, consisting of a complex system of pipelines and interconnects, ties Mont Belvieu to virtually every refinery and petrochemical facility on the upper Texas Gulf Coast. In February 2000, the Partnership and Louis Dreyfus Plastics Corporation ("Louis Dreyfus") announced a joint development alliance whereby the Partnership's Mont Belvieu LPGs storage and transportation shuttle system services are jointly marketed by Louis Dreyfus and the Partnership. The purpose of the alliance is to expand services to the upper Texas Gulf Coast energy marketplace by increasing throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The Downstream Segment operates the facilities for the alliance. The alliance is a service-oriented, fee-based venture with no commodity trading activity. 5 8 Product Sales and Other The Downstream Segment also derives revenue from the sale of product inventory, terminaling activities, other ancillary services associated with the transportation and storage of refined petroleum products and LPGs, and the fractionation of NGLs. Customers The Pipeline System's customers for the transportation of refined petroleum products include major integrated oil companies, independent oil companies and wholesalers. End markets for these deliveries are primarily retail service stations, truck stops, agricultural enterprises, refineries, and military and commercial jet fuel users. Propane customers include wholesalers and retailers who, in turn, sell to commercial, industrial, agricultural and residential heating customers, as well as utilities who use propane as a fuel source. Refineries constitute the Partnership's major customers for butane and isobutane, which are used as a blend stock for gasolines and as a feed stock for alkylation units, respectively. At December 31, 2000, the Downstream Segment had approximately 140 customers. Transportation revenues (and percentage of total revenues) attributable to the top 10 customers were $102 million (43%), $105 million (46%), and $90 million (42%) for the years ended December 31, 2000, 1999 and 1998, respectively. During 2000, billings to Marathon Ashland Petroleum, LLC, a major integrated oil company, accounted for approximately 10% of the Downstream Segment's revenues. Loss of a business relationship with a significant customer could have an adverse affect on the consolidated financial position, results of operations and liquidity of the Partnership. Competition The Pipeline System conducts operations without the benefit of exclusive franchises from government entities. Interstate common carrier transportation services are provided through the System pursuant to tariffs filed with the FERC. Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined petroleum products and LPGs, the Pipeline System's most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. The General Partner believes the Downstream Segment is competitive with other pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations. Trucks, barges and railroads competitively deliver products in some of the areas served by the Pipeline System. Trucking costs, however, render that mode of transportation less competitive for longer hauls or larger volumes. Barge fees for the transportation of refined products are generally lower than the Partnership's tariffs. The Partnership faces competition from rail movements of LPGs in several geographic areas. The most significant area is the Northeast, where rail movements of propane from Sarnia, Ontario, Canada, compete with propane moved on the Pipeline System. CRUDE OIL AND NGLS TRANSPORTATION AND MARKETING Operations The operations of the Upstream Segment are conducted through its wholly-owned subsidiaries (collectively "TCO"), which gather, store, transport and market crude oil, NGLs, lube oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. TCO was formed by the Company in connection with the acquisition of certain assets from DEFS on November 1, 1998. The acquisition of assets was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated statements of income for periods subsequent to October 31, 1998. 6 9 On July 20, 2000, the Company completed an acquisition of ARCO Pipe Line Company ("ARCO"), a wholly owned subsidiary of Atlantic Richfield Company, for $322.6 million, which included $4.1 million of acquisition related costs. The purchase included ARCO's 50-percent ownership interest in Seaway Crude Pipeline Company ("Seaway"). Seaway's crude pipeline carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma. The Partnership assumed ARCO's role as operator of this pipeline. The Company also acquired ARCO's crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location; an undivided ownership interest in both the Rancho Pipeline, a crude oil pipeline from West Texas to Houston, and the Basin Pipeline, a crude oil pipeline running from Jal, New Mexico, through Midland to Cushing, both of which are operated by another joint owner; and the receipt and delivery pipelines known as the West Texas Trunk System, which is located around the Midland terminal. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated statements of income for periods subsequent to July 20, 2000. On December 31, 2000, the Company completed an acquisition of certain pipeline assets from DEFS for $91.7 million, which included $0.7 million of acquisition related costs. The purchase included two natural gas liquids pipelines in East Texas. The Panola Pipeline, a 189-mile pipeline from Carthage, Texas, to Mont Belvieu, Texas, has a capacity of approximately 38,000 barrels per day. The San Jacinto Pipeline, a 34-mile pipeline from Carthage to Longview, Texas, has a capacity of approximately 11,000 barrels per day. A lease of a 34-mile condensate pipeline from Carthage to Marshall, Texas, was also assumed. All three pipelines originate at DEFS' East Texas Plant Complex in Panola County, Texas. TCO generally utilizes its asset base to aggregate crude oil and provide transportation and specialized services to its regional customers. TCO generally purchases crude oil at prevailing prices from producers at the wellhead, aggregates such crude oil into its equity owned pipelines or third party owned pipelines utilizing its truck fleet and transports the crude oil for ultimate sale to or exchange with its customers. Margin of the Upstream Segment is calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expense caused by the level of marketing activity. Generally, as TCO purchases crude oil, it simultaneously establishes a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation with respect to futures contracts on the New York Mercantile Exchange ("NYMEX"). The Partnership seeks to maintain a balanced position until it makes physical delivery of the crude oil, thereby minimizing or eliminating exposure to price fluctuations occurring after the initial purchase. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged or eliminated. It is the Partnership's policy not to acquire crude oil, futures contracts or other derivative products for the purpose of speculating on price changes. Risk management policies have been established by the Risk Management Committee to monitor and control these market risks. The Risk Management Committee is comprised of senior executives of the Partnership. Market risks associated with commodity derivatives were not material at December 31, 2000. Volume information for the years ended December 31, 2000 and 1999, and the two month period ended December 31, 1998, is presented below (in thousands):

TWO MONTHS YEARS ENDED ENDED DECEMBER 31, DECEMBER 31, -------------------- -------------- 2000 1999 1998 -------- -------- -------------- Total barrels: Crude oil transportation .......... 46,225 33,267 5,549 Crude oil marketing ............... 107,607 96,252 16,969 Crude oil terminaling ............. 56,473 -- -- NGL transportation ................ 5,201 4,580 727 Lubricants and chemicals (total gallons) 7,974 8,891 1,140

7 10 Properties The Upstream Segment operates crude oil gathering and trunkline pipelines principally in Oklahoma and Texas, NGL trunkline pipelines in South and East Texas, owns undivided joint interests in crude trunkline pipelines in Texas and Oklahoma, and operates the Seaway Crude Pipeline System from Freeport, Texas to Cushing, Oklahoma. The Upstream Segment also owns crude oil terminaling and storage facilities in Midland, Texas, and Cushing. The Upstream Segment's crude oil pipelines include two major systems and various smaller systems. The Red River System, located on the Texas-Oklahoma border, is the larger system, with 1,460 miles of pipeline and 820,000 barrels of storage. The majority of this pipeline's crude oil is delivered to Cushing, Oklahoma via connecting pipelines or to two local refineries. The South Texas System, located west of Houston, consists of 690 miles of pipeline and 630,000 barrels of storage. The majority of the crude oil on this system is delivered on a tariff basis to Houston area refineries. The West Texas Trunk System consists of 240 miles of smaller diameter receipt and delivery pipelines which transport crude oil from several West Texas and Southeast New Mexico gathering systems to the Upstream Segment's terminal in Midland, Texas. Other crude oil assets, located primarily in Texas and Louisiana, consist of 310 miles of pipeline and 295,000 barrels of storage. The NGL pipelines are located along the Texas Gulf Coast. The Dean NGL Pipeline consists of 338 miles of pipeline originating in South Texas and terminating at Mont Belvieu, Texas, and has a capacity of 20,000 barrels per day. The Dean NGL Pipeline is currently supported by a 17,000 barrel per day volume commitment through 2002. The Wilcox NGL Pipeline is 90 miles long, has a capacity of 7,000 barrels per day and currently transports NGLs for DEFS from two of their natural gas processing plants. The Wilcox NGL Pipeline is currently supported by demand fees that are paid by DEFS through 2005. Joint Interest and Equity Investments The Partnership's undivided joint interest investments include an approximate 13-percent joint venture interest in the Basin Pipeline System and an approximate 25-percent joint venture interest in the Rancho Pipeline System. Equilon Pipeline Company LLC operates both of these pipeline systems. The Basin Pipeline System is a 416-mile, crude oil pipeline transporting Permian Basin crude oil from Jal, New Mexico, through Midland, Texas, for ultimate delivery into Cushing, Oklahoma. The Rancho Pipeline is a 400-mile, 24-inch diameter crude oil pipeline from West Texas to Houston. Seaway is a partnership between TCO and Phillips Petroleum Company ("Phillips"). The 30-inch diameter, 500-mile pipeline transports crude oil from the U.S. Gulf Coast to Cushing, a central crude distribution point for the central United States and a delivery point for the NYMEX. Seaway has the capability to provide marine terminaling and storage services for all Houston area refineries. The Freeport, Texas, marine terminal is the origin point for the 30-inch diameter crude pipeline. Two large diameter lines carry crude oil from the Freeport marine terminal to the adjacent Jones Creek Tank Farm, which has six tanks capable of handling approximately 2.6 million barrels of crude. A crude oil marine terminal facility at Texas City, Texas, is used to supply refineries in the Houston area. Two pipelines connect the Texas City marine terminal to tank farms in Texas City and Galena Park, Texas, where there are seven tanks with a combined capacity of approximately 3 million barrels. The Seaway partnership agreement provides for varying participation ratios throughout the life of Seaway. From July 20, 2000, through May 2002, TCO will receive 80% of revenue and expense of Seaway. From June 2002 until May 2006, TCO will receive 60% of revenue and expense of Seaway. Thereafter, TCO will receive 40% of revenue and expense of Seaway. Line Transfers, Pumpovers and Other TCO provides a trade documentation service to its customers, primarily at Cushing, Oklahoma, and Midland, Texas, whereby TCO documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers. This service is related to the trading activity of NYMEX open-interest crude oil contracts. This service provides a documented record of receipts, deliveries and transactions to each customer, including 8 11 confirmation of trade matches, inventory management and scheduled movements. Line transfer revenues are included as part of other operating revenues in the consolidated statements of income. The line transfer services also attract physical barrels to TCO's facilities for final delivery to the ultimate owner. A pumpover occurs when the last title transfer is executed and the physical barrels are delivered out of TCO's custody. TCO owns approximately 700,000 barrels of operational storage to facilitate the pumpover business. Revenues from pumpover services are included as part of crude oil transportation revenues in the consolidated statements of income and represents the crude oil terminaling component of margin. Through Lubrication Services, L.P. ("LSI"), TCO distributes lube oils and specialty chemicals to natural gas pipelines, gas processors, and industrial and commercial accounts. LSI's distribution networks are located in Colorado, Oklahoma, Southwest Kansas, East Texas, and Northwest Louisiana. Customers TCO purchases crude oil primarily from major integrated oil companies and independent oil producers. Crude oil sales are primarily to major integrated oil companies and independent refiners. The loss of any single customer would not have a material adverse effect on the consolidated financial position, results of operations and liquidity of the Partnership. Competition TCO's most significant competitors in its pipeline operations are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where its pipeline systems deliver crude oil and NGLs. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service, knowledge of products and markets, and proximity to refineries and connecting pipelines. The crude oil gathering and marketing business is characterized by thin margins and intense competition for supplies of lease crude oil. A decline in domestic crude oil production has intensified competition among gatherers and marketers. Within the past few years, the number of companies involved in the gathering of crude oil in the United States has decreased as a result of business consolidations. Credit As crude oil or lube oils are marketed, the Partnership must determine the amount, if any, of credit to be extended to any given customer. Due to the nature of individual sales transactions, risk of non-payment and non-performance by customers is a major consideration in TCO's business. TCO manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. TCO utilizes letters of credit and guarantees for certain of its receivables. TCO's credit standing is a major consideration for parties with whom it does business. In connection with TCO's acquisition of this business, Duke Capital, an affiliate of Duke Energy, agreed to provide up to $100 million of guarantee credit to TCO through November 2001. TITLE TO PROPERTIES The Partnership believes it has satisfactory title to all of its assets. Such properties are subject to liabilities in certain cases, such as customary interests generally contracted in connection with acquisition of the properties, liens for taxes not yet due, easements, restrictions, and other minor encumbrances. The Partnership believes none of these liabilities materially affects the value of such properties or the Partnership's interest therein or will materially interfere with their use in the operation of the Partnership's business. 9 12 CAPITAL EXPENDITURES Capital expenditures by the Partnership totaled $68.5 million for the year ended December 31, 2000. This amount includes capitalized interest of $4.6 million. Approximately $29.9 million was used to complete construction of three new pipelines between the Partnership's terminal in Mont Belvieu, Texas and Port Arthur, Texas. The project included three 12-inch diameter common-carrier pipelines and associated facilities. Each pipeline is approximately 70 miles in length. The new pipelines will transport ethylene, propylene and natural gasoline. The Partnership has entered into a twenty-year agreement for guaranteed throughput commitments that total approximately $0.9 million per month, which began in November 2000. The cost of this project totaled approximately $73.7 million. Of the remaining capital expenditures during 2000, $22.0 million related to the Downstream Segment and $12.0 million related to the Upstream Segment. Approximately $21.9 million of capital expenditures related to life-cycle replacements and upgrading current facilities, and approximately $12.1 million of capital expenditures related to other pipeline expansion projects and revenue-generating projects. The Partnership estimates that capital expenditures, excluding acquisitions, for 2001 will be approximately $82 million (which includes $3 million of capitalized interest). Approximately $43 million is expected to be used to expand the Partnership's capacity to support the receipt connection point at Beaumont, Texas, and delivery location at Creal Springs, Illinois, with Centennial. The timing of these expenditures is dependent on the FERC ruling on the abandonment filing by CMS Panhandle Pipe Line Company. Approximately $26 million of the remaining amount is expected to be used for the Downstream Segment and $13 million is expected to be used for the Upstream Segment. Approximately one-half of these expenditures are expected to be used in revenue-generating projects, with the remaining amount to be used for life-cycle replacements and upgrading current facilities. REGULATION The Partnership's interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act ("ICA"), the Energy Policy Act of 1992 ("Act") and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate oil pipeline rates be posted publicly and that these rates be "just and reasonable" and nondiscriminatory. Rates of interstate oil pipeline companies, like the Partnership, are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% ("PPI Index"). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings ("Market Based Rates") or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). On May 11, 1999, the Downstream Segment filed an application with the FERC requesting permission to charge market-based rates for substantially all refined products transportation tariffs. Along with its application for market-based rates, the Downstream Segment filed a petition for waiver, pending the FERC's determination on its application for market-based rates, of the requirements that would otherwise have been imposed by the FERC's regulations requiring the Downstream Segment to reduce its rates in conformity with the PPI Index. On June 30, 1999, FERC granted the waiver stating that it was temporary in nature and that the Downstream Segment would be required to make refunds, with interest, of all amounts collected under rates in excess of the PPI Index ceiling level after July 1, 1999, if the Downstream Segment's application for market-based rates was ultimately denied. As a result of the refund obligation potential, the Partnership has deferred all revenue recognition of rates charged in excess of the PPI Index. As of December 31, 2000, the amount deferred for possible rate refund, including interest totaled approximately $2.3 million. On July 31, 2000, the FERC issued an order granting the Downstream Segment market-based rates in certain markets and set for hearing the Downstream Segment's application for market-based rates in the Little Rock, Arkansas; Shreveport-Arcadia, Louisiana; Cincinnati-Dayton, Ohio and Memphis, Tennessee, destination markets and the Shreveport, Louisiana, origin market. The FERC also directed the FERC trial staff to convene a conference to explore the facts and issues regarding the Western Gulf Coast origin market. After the matter was set for hearing, the Downstream Segment and the protesting shippers entered into a settlement agreement resolving their respective 10 13 differences. On January 9, 2001, the presiding Administrative Law Judge assigned to the hearing determined that the offer of settlement provided resolution of issues set for hearing in the Downstream Segment pending case in a fair and reasonable manner and in the public interest and certified the offer of settlement and recommended it to the FERC for approval. The certification of the settlement is currently before the FERC. The Partnership believes that the Administrative Law Judge's decision in this matter will be upheld by the FERC. The settlement, if it is approved by FERC, will require the Downstream Segment to withdraw the application for market-based rates to the Little Rock, Arkansas, destination market and the Arcadia, Louisiana, destination in the Shreveport-Arcadia, Louisiana, destination market. The Downstream Segment also has agreed to recalculate rates to these destination markets to conform with the PPI Index from July 1, 1999 and make appropriate refunds. The refund obligation under the proposed settlement as of December 31, 2000 would be $0.8 million. Effective July 1, 1999, the Downstream Segment established Settlement Rates with certain shippers of LPGs under which the rates in effect on June 30, 1999, would not be adjusted for a period of either two or three years. Other LPGs transportation tariff rates were reduced pursuant to the PPI Index (approximately 1.83%), effective July 1, 1999. In a 1995 decision involving an unrelated oil pipeline limited partnership, the FERC partially disallowed the inclusion of income taxes in that partnership's cost of service. In another FERC proceeding involving a different oil pipeline limited partnership, the FERC held that the oil pipeline limited partnership may not claim an income tax allowance for income attributable to non-corporate limited partners, both individuals and other entities. These FERC decisions do not affect the Partnership's current rates and rate structure because the Partnership does not use the cost of service methodology to support its rates. However, the FERC decisions might become relevant to the Partnership should it (i) elect in the future to use the cost-of-service methodology or (ii) be required to use such methodology to defend its indexed rates against a shipper protest alleging that an indexed rate increase substantially exceeds actual cost increases. Should such circumstances arise, there can be no assurance with respect to the effect of such precedents on the Partnership's rates in view of the uncertainties involved in this issue. ENVIRONMENTAL MATTERS The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from its operations, could result in substantial costs and liabilities to the Partnership. Water The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act ("CWA"), imposes strict controls against the discharge of oil and its derivatives into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing an oil or hazardous substance spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in surface waters or into the groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum tank spill, rupture or leak. Contamination resulting from spills or release of refined petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along the Pipeline System as a result of past operations, the Partnership believes any such contamination could be controlled or remedied without having a material adverse effect on the financial condition of the Partnership, but such costs are site specific, and there can be no assurance that the effect will not be material in the aggregate. 11 14 The primary federal law for oil spill liability is the Oil Pollution Act of 1990 ("OPA"), which addresses three principal areas of oil pollution -- prevention, containment and cleanup, and liability. It applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the appropriate agency being either the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety ("OPS") or the Environmental Protection Agency ("EPA"). Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resources damages. The General Partner believes that the Partnership is in material compliance with regulations pursuant to OPA and similar state laws. The EPA has adopted regulations that require the Partnership to have permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which the Partnership operates. Such permits may require the Partnership to monitor and sample the effluent. The General Partner believes that the Partnership is in material compliance with effluent limitations at existing facilities. Air Emissions The operations of the Partnership are subject to the federal Clean Air Act and comparable state and local statutes. The Clean Air Act Amendments of 1990 (the "Clean Air Act") will require most industrial operations in the United States to incur future capital expenditures in order to meet the air emission control standards that are to be developed and implemented by the EPA and state environmental agencies during the next decade. Pursuant to the Clean Air Act, any Partnership facilities that emit volatile organic compounds or nitrogen oxides and are located in ozone non-attainment areas will face increasingly stringent regulations, including requirements that certain sources install the reasonably available control technology. The EPA is also required to promulgate new regulations governing the emissions of hazardous air pollutants. Some of the Partnership's facilities are included within the categories of hazardous air pollutant sources which will be affected by these regulations. The Partnership does not anticipate that changes currently required by the Clean Air Act hazardous air pollutant regulations will have a material adverse effect on the Partnership. The Clean Air Act also introduced the new concept of federal operating permits for major sources of air emissions. Under this program, one federal operating permit (a "Title V" permit) is issued. The permit acts as an umbrella that includes other federal, state and local preconstruction and/or operating permit provisions, emission standards, grandfathered rates, and record keeping, reporting, and monitoring requirements in a single document. The federal operating permit is the tool that the public and regulatory agencies use to review and enforce a site's compliance with all aspects of clean air regulation at the federal, state and local level. The Partnership has completed applications for all twelve facilities for which such regulations apply and has received the final permit for nine facilities. Risk Management Plans The Partnership is also subject to the Environmental Protection Agency's Risk Management Plan ("RMP") regulations at certain locations. This regulation is intended to work with the Occupational Safety and Health Act ("OSHA") Process Safety Management regulation (see "Safety Regulation" following) to minimize the offsite consequences of catastrophic releases. The regulation requires a regulated source, in excess of threshold quantities, develop and implement a risk management program that includes a five-year accident history, an offsite consequence analyses, a prevention program, and an emergency response program. The General Partner believes the Partnership is in material compliance with the RMP regulations, and that the operating expenses of the RMP regulations will not have a material adverse impact on the Partnership's financial position or results of operations. Solid Waste The Partnership generates hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. Amendments to RCRA require the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria. In 1990, the EPA issued the Toxicity Characteristic Leaching Procedure, which substantially expanded the number of materials 12 15 defined as hazardous waste. Certain wastewater and other wastes generated from the Partnership's business activities previously classified as nonhazardous are now classified as hazardous due to the presence of dissolved aromatic compounds. The Partnership utilizes waste minimization and recycling processes and has installed pre-treatment facilities to reduce the volume of its hazardous waste. The Partnership currently has three permitted on-site waste water treatment facilities. Operating expenses of these facilities have not had a material adverse effect on the financial position or results of operations of the Partnership. Superfund The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a facility and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. CERCLA also authorizes the EPA and, in some instances, third parties to take actions 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. In the course of its ordinary operations, the Pipeline System generates wastes that may fall within CERCLA's definition of a "hazardous substance." Should a disposal facility previously used by the Partnership require clean up in the future, the Partnership may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. The Company was notified by the EPA in the fall of 1998 that it might have potential liability for waste material allegedly disposed by the Company at the Casmalia Disposal Site in Santa Barbara County, California. The EPA has offered the Company a de minimus settlement offer of $0.3 million to settle liability associated with the Company's alleged involvement. The Company believes based on the information furnished by the EPA that it has been erroneously named as an entity that disposed of waste material at the Casmalia Disposal Site. The Company intends to continue to vigorously pursue dismissal from this matter. In December 1999, the Company was notified by EPA of potential liability for alleged waste disposal at Container Recycling, Inc., located in Kansas City, Kansas. The Company was also asked to respond to an EPA Information Request. The Company's response has been filed with the EPA Region VII office. Based on information the Company has received from the EPA, as well as through its internal investigations, the Company intends to pursue dismissal from this matter. Other Environmental Proceedings The Partnership and the Indiana Department of Environmental Management ("IDEM") have entered into an Agreed Order that will ultimately result in a remediation program for any on-site and off-site groundwater contamination attributable to the Partnership's operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership's proposed remediation program, has been approved by IDEM. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision has been issued, the Partnership will enter into an Agreed Order for the continued operation and maintenance of the program. The Partnership has accrued $0.6 million at December 31, 2000, for future costs of the remediation program for the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse impact on the Partnership's financial condition, results of operations or liquidity. The Partnership received a compliance order from the Louisiana Department of Environmental Quality ("DEQ") during 1994 relative to potential environmental contamination at the Partnership's Arcadia, Louisiana, facility, which may be attributable to the operations of the Partnership and adjacent petroleum terminals of other companies. The Partnership and all adjacent terminals have been assigned to the Groundwater Division of DEQ, in which a consolidated plan will be developed. The Partnership has finalized a negotiated Compliance Order with DEQ that will allow the Partnership to continue with a remediation plan similar to the one previously agreed to by DEQ and implemented by the Company. In the opinion of the General Partner, the completion of the remediation program being proposed by the Partnership will not have a future material adverse impact on the Partnership. 13 16 SAFETY REGULATION The Partnership is subject to regulation by the United States Department of Transportation ("DOT") under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act ("HLPSA"), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of its pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The HLPSA is scheduled to be reauthorized in 2001. The Partnership does not expect the legislation changes to have a material impact on its financial condition, results of operations or liquidity. The Partnership is subject to the OPS regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks, and amends certain training requirements in existing regulations. A written qualification program must be completed by April 27, 2001, and individuals performing a covered task must be qualified by October 28, 2002. The Partnership is also subject to the OPS regulation for High Consequence Areas ("HCA"). This regulation specifies how to assess, evaluate, repair and validate the integrity of pipeline segments that could impact populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways, in the event of a release. The pipeline segments that could impact HCA's must be identified by December 31, 2001. The regulation requires an integrity management program that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of pipeline segments in HCA's. An integrity management program must be completed by March 31, 2002. The initial integrity tests in HCA's start with a seven-year cycle on March 31, 2001, with all subsequent inspections conducted on a five-year cycle. The program requires periodic review of pipeline segments in HCA's to ensure adequate preventative and mitigative measures exist. Through this program the Partnership will evaluate a range of threats to each pipeline segment's integrity by analyzing available information about the pipeline segment and consequences of a failure in a HCA. The regulation requires prompt action to address integrity issues raised by the assessment and analysis. The Partnership does not anticipate that implementation of these regulations will have a material adverse effect on the Partnership. The Partnership is also subject to the requirements of the federal OSHA and comparable state statutes. The Partnership believes it is in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require the Partnership to organize and disclose information about the hazardous materials used in its operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. In general, the Partnership expects to increase its expenditures during the next decade to comply with higher industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although the General Partner does not believe that they will have a future material adverse impact on the Partnership. The Partnership is subject to OSHA Process Safety Management ("PSM") regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds; or any process which involves a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. The Partnership utilizes certain covered processes and maintains storage of LPGs in pressurized tanks, caverns and wells, in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without benefit of chilling or refrigeration are exempt. The Partnership believes it is in material compliance with the PSM regulations. 14 17 EMPLOYEES The Partnership does not have any employees, officers or directors. The General Partner is responsible for the management of the Partnership and Operating Partnerships. As of December 31, 2000, the General Partner had 798 employees. ITEM 3. LEGAL PROCEEDINGS TOXIC TORT LITIGATION - SEYMOUR, INDIANA In the fall of 1999 and on December 1, 2000, the Company and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, in Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the Company and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. In both cases plaintiffs contend, among other things, that the Company and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their Complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. The Company has filed an Answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The Partnership cannot estimate the loss, if any, associated with these pending lawsuits. OTHER LITIGATION In addition to the litigation discussed above, the Partnership has been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. The General Partner believes that the outcome of such lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on the Partnership's consolidated financial condition, results of operations or cash flows. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS NONE 15 18 PART II ITEM 5. MARKET FOR REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS The Limited Partner Units of the Partnership are listed and traded on the New York Stock Exchange under the symbol TPP. The high and low trading prices of the Limited Partner Units in 2000 and 1999, respectively, as reported in The Wall Street Journal, were as follows:

2000 1999 ---------------------- ---------------------- QUARTER HIGH LOW HIGH LOW --------- ---------- --------- ---------- First........................................... $22.94 $19.00 $26.19 $22.38 Second.......................................... 24.38 19.88 28.25 22.94 Third........................................... 26.75 22.75 26.44 20.00 Fourth.......................................... 27.00 21.63 23.88 17.13

Based on the information received from its transfer agent and from brokers/nominees, the Company estimates the number of beneficial Unitholders of Limited Partner Units of the Partnership as of March 6, 2001 to be approximately 25,000. The quarterly cash distributions applicable to 1999 and 2000 were as follows:

AMOUNT RECORD DATE PAYMENT DATE PER UNIT ----------- ------------ ------------ April 30, 1999.............................. May 7, 1999................................. $ 0.450 July 30, 1999............................... August 6, 1999.............................. 0.475 October 29, 1999............................ November 5, 1999............................ 0.475 January 31, 2000............................ February 4, 2000............................ 0.475 April 28, 2000.............................. May 5, 2000................................. $ 0.500 July 31, 2000............................... August 4, 2000.............................. 0.500 October 30, 2000............................ November 3, 2000............................ 0.525 January 31, 2001............................ February 2, 2001............................ 0.525

The Partnership makes quarterly cash distributions of its Available Cash, as defined by the Partnership Agreements. Available Cash consists generally of all cash receipts less cash disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies the General Partner deems appropriate and necessary. The Partnership is a publicly traded master limited partnership that is not subject to federal income tax. Instead, Unitholders are required to report their allocable share of the Partnership's income, gain, loss, deduction and credit, regardless of whether the Partnership makes distributions. Distributions of cash by the Partnership to a Unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Units held by the Unitholder. 16 19 ITEM 6. SELECTED FINANCIAL DATA The following tables set forth, for the periods and at the dates indicated, selected consolidated financial and operating data for the Partnership. The financial data was derived from the consolidated financial statements of the Partnership and should be read in conjunction with the Partnership's audited consolidated financial statements included in the Index to Financial Statements on page F-1 of this report. See also Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

YEARS ENDED DECEMBER 31, -------------------------------------------------------------------------- 2000 (1) 1999 1998 (2) 1997 1996 ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) INCOME STATEMENT DATA: Operating revenues: Sales of crude oil and petroleum products ..... $ 2,821,943 $ 1,692,767 $ 214,463 $ -- $ -- Transportation -- refined products ............ 119,331 123,004 119,854 107,304 98,641 Transportation -- LPGs ........................ 73,896 67,701 60,902 79,371 80,219 Transportation -- crude oil and NGLs .......... 24,533 11,846 3,392 -- -- Mont Belvieu operations ....................... 13,334 12,849 10,880 12,815 11,811 Other ......................................... 34,904 26,716 20,147 22,603 25,354 ----------- ----------- ----------- ----------- ----------- Total operating revenues .................... 3,087,941 1,934,883 429,638 222,093 216,025 Purchases of crude oil and petroleum products ... 2,794,604 1,666,042 212,371 -- -- Operating expenses .............................. 150,149 136,095 110,363 106,771 105,182 Depreciation and amortization ................... 35,163 32,656 26,938 23,772 23,409 ----------- ----------- ----------- ----------- ----------- Operating income ................................ 108,025 100,090 79,966 91,550 87,434 Interest expense - net .......................... (44,423) (29,430) (28,989) (32,229) (33,534) Equity Earnings - Seaway ........................ 12,214 -- -- -- -- Other income - net .............................. 1,560 1,460 2,364 1,979 4,748 ----------- ----------- ----------- ----------- ----------- Income before extraordinary item .............. 77,376 72,120 53,341 61,300 58,648 Extraordinary loss on debt extinguishment, net of minority interest (3) ....................... -- -- (72,767) -- -- ----------- ----------- ----------- ----------- ----------- Net income (loss) ............................. $ 77,376 $ 72,120 $ (19,426) $ 61,300 $ 58,648 =========== =========== =========== =========== =========== Basic and diluted income per Unit: (4) Before extraordinary item ..................... $ 1.89 $ 1.91 $ 1.61 $ 1.95 $ 1.89 Extraordinary loss on debt extinguishment (3) . -- -- (2.21) -- -- ----------- ----------- ----------- ----------- ----------- Net income (loss) per Unit ................. $ 1.89 $ 1.91 $ (0.60) $ 1.95 $ 1.89 =========== =========== =========== =========== =========== BALANCE SHEET DATA (AT PERIOD END): Property, plant and equipment - net ............. $ 949,705 $ 720,919 $ 671,611 $ 567,681 $ 561,068 Total assets .................................... 1,622,810 1,041,373 916,919 673,909 671,241 Long-term debt (net of current maturities) ...... 835,784 455,753 427,722 309,512 326,512 Class B Units ................................... 105,411 105,859 105,036 -- -- Partners' capital ............................... 315,057 229,767 227,186 302,967 290,311 CASH FLOW DATA: Net cash from operations ........................ $ 108,045 $ 103,070 $ 93,215 $ 83,604 $ 86,121 Asset purchases ................................. (422,148) (2,250) (41,989) -- -- Capital expenditures ............................ (68,481) (77,431) (23,432) (32,931) (51,264) Distributions ................................... (82,231) (69,259) (56,774) (49,042) (45,174)

---------- (1) Data reflects the operations of the ARCO assets acquired on July 20, 2000. (2) Data reflects the operations of the fractionator assets effective March 31, 1998, and the operations of the crude oil and NGL assets purchased effective November 1, 1998. (3) Extraordinary item reflects the loss related to the early extinguishment of the First Mortgage Notes on January 27, 1998. (4) Per Unit calculation for all periods reflects the two-for-one split on August 1, 1998. Per Unit calculation includes 3,916,547 Class B Units issued on November 1, 1998, and 3,700,000 Limited Partner Units issued on October 25, 2000. 17 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL The following information is provided to facilitate increased understanding of the 2000, 1999 and 1998 consolidated financial statements and accompanying notes of the Partnership included in the Index to Financial Statements on page F-1 of this report. Material period-to-period variances in the consolidated statements of income are discussed under "Results of Operations." The "Financial Condition and Liquidity" section analyzes cash flows and financial position. Discussion included in "Other Matters" addresses key trends, future plans and contingencies. Throughout these discussions, management addresses items that are reasonably likely to materially affect future liquidity or earnings. Through its ownership of the Downstream Segment and the Upstream Segment, the Partnership operates in two segments, respectively: refined products and LPGs transportation, and crude oil and NGLs transportation and marketing. The Partnership's reportable segments offer different products and services and are managed separately because each requires different business strategies. The Downstream Segment is involved in the transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs. Revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex, sale of product inventory and other ancillary services. Labor and electric power costs comprise the two largest operating expense items of the Downstream Segment. Higher natural gas prices increase the cost of electricity used to power pump stations on the Pipeline System. Operations are somewhat seasonal with higher revenues generally realized during the first and fourth quarters of each year. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. The Upstream Segment is involved in the transportation, aggregation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals. Revenues are earned from the gathering, storage, transportation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of purchasing and aggregating crude oil along its own and third party gathering and pipeline systems and arranging the necessary logistics for the ultimate sale of crude oil to local refineries, marketers or other end users. Operations of this segment are included from November 1, 1998, the date of its acquisition from DEFS. On July 20, 2000, the Company completed its acquisition of ARCO, for $322.6 million, which included $4.1 million of acquisition related costs. The purchase included ARCO's 50-percent ownership interest in Seaway. The Partnership assumed ARCO's role as operator of this pipeline. The Company also acquired ARCO's crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location, an undivided ownership interest in both the Rancho Pipeline and the Basin Pipeline, both of which are operated by another joint owner and the receipt and delivery pipelines known as the West Texas Trunk System, located around the Midland terminal. The transaction was accounted for under the purchase method for accounting purposes. The results of operations of assets acquired have been included in the Upstream Segment since the purchase on July 20, 2000. 18 21 RESULTS OF OPERATIONS Summarized below is financial data by business segment (in thousands):

YEARS ENDED DECEMBER 31, ------------------------------------ 2000 1999 1998 ---------- ---------- -------- Operating revenues: Downstream Segment ...................... $ 236,687 $ 230,270 $211,783 Upstream Segment ........................ 2,851,254 1,704,613 217,855 ---------- ---------- -------- Total operating revenues ............. 3,087,941 1,934,883 429,638 ---------- ---------- -------- Operating income: Downstream Segment ...................... 89,999 89,393 78,641 Upstream Segment ........................ 18,026 10,697 1,325 ---------- --------- -------- Total operating income ............... 108,025 100,090 79,966 ---------- --------- -------- Income before extraordinary item: Downstream Segment ...................... 60,695 61,227 52,002 Upstream Segment ........................ 16,681 10,893 1,339 ---------- ---------- -------- Total income before extraordinary item $ 77,376 $ 72,120 $ 53,341 ========== ========== ========

For the year ended December 31, 2000, the Partnership reported net income of $77.4 million, compared with $72.1 million for the year ended December 31, 1999. The $5.3 million increase in income resulted from a $5.8 million increase in income provided by the Upstream Segment, which included $4.7 million of net income attributable to the acquired ARCO assets. The increase in income provided by the Upstream Segment was comprised of a $13.3 million increase in margin, a $4.8 million increase in other operating revenues and $12.2 million of equity earnings of Seaway, partially offset by a $10.8 million increase in costs and expenses (excluding purchases of crude oil and petroleum products) and a $13.6 million increase in interest expense. Net income of the Downstream Segment decreased $0.5 million from the prior year primarily due to a $5.8 million increase in costs and expenses and a $1.4 million increase in interest expense (net of capitalized interest), partially offset by a $6.4 million increase in operating revenues. For the year ended December 31, 1999, the Partnership reported net income of $72.1 million, compared with a net loss of $19.4 million for year ended December 31, 1998. The net loss in 1998 included an extraordinary charge of $72.8 million for early extinguishment of debt, net of $0.7 million allocated to minority interest. Excluding the extraordinary loss, net income would have been $53.3 million for year ended December 31, 1998. The $18.8 million increase in income before the loss on debt extinguishment resulted from a $9.6 million increase in income provided by the Upstream Segment, which was acquired effective November 1, 1998, and a $9.2 million increase in income provided by the Downstream Segment. The increase in income provided by the Downstream Segment resulted primarily from a $18.5 million increase in operating revenues, partially offset by a $7.7 million increase in costs and expenses and a $1.2 million decrease in other income - net. 19 22 DOWNSTREAM SEGMENT Volume and average tariff information for 2000, 1999 and 1998 is presented below:

PERCENTAGE INCREASE YEARS ENDED DECEMBER 31, (DECREASE) --------------------------------------- --------------------------- 2000 1999 1998 2000 1999 ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS, EXCEPT TARIFF INFORMATION) Volumes Delivered Refined products .................... 128,151 132,642 130,467 (3)% 2% LPGs ................................ 39,633 37,575 32,048 5% 17% Mont Belvieu operations ............. 27,159 28,535 25,072 (5)% 14% ----------- ----------- ----------- ----------- ----------- Total ............................. 194,943 198,752 187,587 (2)% 6% =========== =========== =========== =========== =========== Average Tariff per Barrel Refined products .................... $ 0.93 $ 0.93 $ 0.92 -- 1% LPGs ................................ 1.86 1.80 1.90 3% (5)% Mont Belvieu operations ............. 0.16 0.16 0.16 -- -- Average system tariff per barrel .. $ 1.01 $ 0.98 $ 0.98 3% -- =========== =========== =========== =========== ===========

2000 Compared to 1999 Operating revenues for the year ended 2000 increased 3% to $236.7 million from $230.3 million for the year ended 1999. This $6.4 million increase resulted from a $6.2 million increase in LPGs transportation revenues, a $3.4 million increase in other operating revenues and a $0.5 million increase in revenues generated from Mont Belvieu operations. These increases were partially offset by a $3.7 million decrease in refined products transportation revenues. Refined products transportation revenues decreased $3.7 million for the year ended December 31, 2000, compared with the prior year, as a result of a 3% decrease in total refined products volumes delivered. Motor fuel volumes delivered decreased by 2.5 million barrels and distillate volumes delivered decreased by 1.8 million barrels due primarily to a local refinery expansion in the West Memphis market and unfavorable price differentials in the Midwest market area. Natural gasoline volumes delivered declined 1.3 million barrels due primarily to the expiration of a contract in late 1999 for deliveries to the Chicago area, along with unfavorable processing and blending economics in the Chicago market area. These decreases were primarily offset by a 1.2 million barrel increase in jet fuel volumes delivered due to continued strong demand in the Chicago market area and at the Cincinnati airport that is supplied by the Partnership. The Partnership deferred recognition of approximately $1.5 million of revenue during the year ended December 31, 2000, with respect to potential refund obligations for rates charged in excess of the PPI Index while its application for Market Based Rates is under review by FERC. See further discussion regarding Market Based Rates included in "Other Matters - Market and Regulatory Environment." LPGs transportation revenues increased $6.2 million for the year ended December 31, 2000, compared with the prior year, due to a 5% increase in volumes delivered and a 3% increase in the average LPGs tariff per barrel. Colder winter weather during the first and fourth quarters of 2000, coupled with lower customer storage levels contributed to a 1.2 million barrel increase in propane volumes delivered in the Northeast market area and a 0.9 million barrel increase in propane volumes delivered in the Midwest market area. Increased refinery demand in the Northeast market area resulted in a 0.2 million barrel increase in butane volumes delivered. The larger percentage of long-haul deliveries during 2000 resulted in a 3% increase in the average LPGs tariff per barrel. Revenues generated from Mont Belvieu operations increased $0.5 million for the year ended December 31, 2000, compared with the prior year, primarily due to increased brine handling fees and higher storage revenue. 20 23 Other operating revenues increased $3.4 million during the year ended December 31, 2000, compared with 1999, primarily due to $1.8 million of deficiency revenue recognized in the fourth quarter of 2000 related to the beginning of a 20-year contract for petrochemical deliveries at Port Arthur, Texas, and a $0.5 million increase in gains on the sale of product inventory attributable to higher market prices in 2000. The additional increases resulted from increased refined products terminaling revenue and increased custody transfer services at Mont Belvieu facilities. Costs and expenses increased $5.8 million during the year ended December 31, 2000, compared with the prior year, due to a $2.9 million increase in operating, general and administrative expenses, a $2.3 million increase in operating fuel and power expense and a $0.6 million increase in depreciation and amortization charges. The increase in operating, general and administrative expenses was primarily attributable to $0.9 million of expense recognized in the first quarter of 2000 to write-off project evaluation costs, a $2.3 million increase in general and administrative supplies and services, a $1.5 million increase in legal services, a $1.0 million increase in pipeline operations and maintenance expenses, a $0.7 million increase in labor related expenses and a $0.3 million increase in product measurement losses. The write-off of project evaluation costs resulted from the announcement in March 2000 of the Partnership's abandonment of its plan to construct a pipeline from Beaumont, Texas, to Little Rock, Arkansas, in favor of participation in the Centennial joint venture. These increases in operating, general and administrative expenses were partially offset by a $3.9 million decrease in expenses associated with Year 2000 activities incurred in 1999. The increase in operating fuel and power expense from the prior year resulted primarily from higher fuel prices charged by electric utilities in 2000. Depreciation and amortization expense increased as a result of $0.3 million in depreciation expense related to the completion of the petrochemical pipelines and other capital additions placed in service throughout 2000. Interest expense increased $3.8 million during the year ended December 31, 2000, compared with 1999, as a result of borrowings under a term loan to finance construction of the petrochemical pipelines between Mont Belvieu and Port Arthur, Texas. Additionally, amortization of debt issue costs increased $0.8 million during the year ended December 31, 2000. The increase in interest expense was offset by increased interest capitalized of $2.4 million during the year ended December 31, 2000, as a result of higher balances associated with construction of the petrochemical pipelines. Other income - net increased $0.2 million during the year ended December 31, 2000, compared with the prior year, as a result of gains on the sale of right-of-way easements during the second quarter of 2000, coupled with increased interest income earned on cash investments in 2000. 1999 Compared to 1998 Operating revenues for the year ended 1999 increased 9% to $230.3 million from $211.8 million for the year ended 1998. This $18.5 million increase resulted from an $3.1 million increase in refined products transportation revenues, a $6.8 million increase in LPGs transportation revenues, a $2.0 million increase in revenues generated from Mont Belvieu operations and a $6.6 million increase in other operating revenues. Refined products transportation revenues increased $3.1 million for the year ended December 31, 1999, compared with the prior year, as a result of a 2% increase in total refined products volumes delivered and a 1% increase in the refined products average tariff per barrel. Strong economic demand coupled with lower refinery production resulted in a 3.1 million barrel increase in jet fuel volumes delivered and a 2.3 million barrel increase in distillate volumes delivered. Jet fuel volumes delivered also benefited as a result of new military supply agreements that became effective in the fourth quarter of 1998. These increases were partially offset by a 1.8 million barrel decrease in motor fuel volumes delivered due to unfavorable Midwest price differentials and reduced refinery production received into the Ark-La-Tex system and a 0.6 million barrel decrease in natural gasoline volumes delivered attributable to lower feedstock and blending demand. Additionally, MTBE volumes delivered decreased 0.9 million barrels as a result of the Partnership canceling its tariffs to Midwest destinations, effective July 1, 1999. This action was taken with the consent of MTBE shippers as a result of lower demand for MTBE transportation caused by changing blending economics, and resulted in increased pipeline capacity and tankage available for other products. The 1% increase in the refined products average tariff per barrel was primarily attributable to a higher percentage of long-haul distillate volumes delivered in the Midwest, partially offset by the 1.83% general tariff reduction pursuant to the PPI Index, effective July 1, 1999. The Partnership deferred recognition of approximately 21 24 $0.8 million of revenue in 1999, with respect to potential refund obligations for rates charged in excess of the PPI Index while its application for Market Based Rates is under review by FERC. LPGs transportation revenues increased $6.8 million for the year ended December 31, 1999, compared with the prior year due to a 17% increase in volumes delivered, partially offset by a 5% decrease in the average LPGs tariff per barrel. Propane volumes delivered in the Northeast increased 14% from the prior year primarily due to colder winter weather during the first and fourth quarters of 1999. Propane deliveries in the Midwest market area and the upper Texas Gulf Coast increased 19% and 44%, respectively, from the prior year primarily due to increased petrochemical feedstock demand. The 5% decrease in the average LPGs tariff per barrel resulted from the larger percentage of short-haul barrels during 1999, coupled with the reduction in tariffs rates pursuant to the PPI Index, effective July 1, 1999. Revenues generated from Mont Belvieu operations increased $2.0 million for the year ended December 31, 1999, compared with the prior year, primarily due to higher storage revenue and increased petrochemical and refinery demand for shuttle deliveries of LPGs along the upper Texas Gulf Coast. Other operating revenues increased $6.6 million during the year ended December 31, 1999, compared with 1998, primarily due to a $3.6 million increase in gains on the sale of product inventory, a $1.8 million increase in operating revenues from the fractionator facilities acquired on March 31, 1998, and lower exchange losses incurred to position product in the Midwest market area. Costs and expenses increased $7.7 million during the year ended December 31, 1999, compared with the prior year, due to a $3.4 million increase in operating, general and administrative expenses, a $2.7 million increase in operating fuel and power expense, a $1.1 million increase in depreciation and amortization charges, and a $0.5 million increase in taxes - other than income. The increase in operating, general and administrative expenses was primarily attributable to a $2.8 million increase in expenses associated with Year 2000 activities; a $1.5 million increase in rental fees from higher volume through the connection from Colonial Pipeline at Beaumont; a $1.5 million increase in labor related expenses attributable to merit increases and increased incentive compensation accruals, partially offset by lower post retirement benefit accruals; and increased outside services for pipeline maintenance. These increases in operating, general and administrative expenses were partially offset by $3.4 million of expense recorded in 1998 to write down the book-value of product inventory to market-value, and lower product measurement losses. The increase in operating fuel and power expense from the prior year resulted from increased pipeline throughput. Depreciation and amortization expense increased as a result of amortization of the value assigned to the Fractionation Agreement beginning on March 31, 1998, and capital additions placed in service. The increase in taxes - other than income was primarily due to a higher property base in 1999 and credits recorded during 1998 for the over accrual of previous years' property taxes. Interest expense increased $1.6 million during the year ended December 31, 1999, compared with 1998. Approximately $0.6 million of the increase was attributable to a full year of interest expense in 1999 on the $38 million term-loan used to finance the purchase of the fractionation assets on March 31, 1998. The remaining increase resulted from $25 million of borrowings during the second quarter of 1999 under a term loan to finance construction of the pipelines between Mont Belvieu and Port Arthur, Texas. Capitalized interest increased during 1999, compared with 1998, as a result of higher balances associated with construction-in-progress of the new pipelines between Mont Belvieu and Port Arthur. Other income - net decreased $1.2 million during the year ended December 31, 1999, compared with the prior year, as a result of a $0.4 million gain on the sale of non-carrier assets in June 1998, and lower interest income earned on cash investments in 1999. 22 25 UPSTREAM SEGMENT Margin of the Upstream Segment is calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expense caused by the level of marketing activity. Margin and volume information for the years ended December 31, 2000 and 1999, and the two month period ended December 31, 1998, is presented below (in thousands, except per barrel and per gallon amounts):

TWO MONTHS YEAR ENDED ENDED DECEMBER 31, DECEMBER 31, ------------------------- ----------- 2000 1999 1998 ----------- ----------- ----------- Margins: Crude oil transportation ................ $ 23,486 $ 17,873 $ 2,787 Crude oil marketing ..................... 13,320 12,065 1,253 Crude oil terminaling ................... 4,554 -- -- NGL transportation ...................... 7,009 6,123 1,062 Lubrication oil sales ................... 3,503 2,510 382 ----------- ----------- ----------- Total margin ....................... $ 51,872 $ 38,571 $ 5,484 =========== =========== =========== Total barrels: Crude oil transportation ................ 46,225 33,267 5,549 Crude oil marketing ..................... 107,607 96,252 16,969 Crude oil terminaling ................... 56,473 -- -- NGL transportation ...................... 5,201 4,580 727 Lubrication oil volume (total gallons): .... 7,974 8,891 1,140 Margin per barrel: Crude oil transportation ................ $ 0.508 $ 0.537 $ 0.504 Crude oil marketing ..................... $ 0.124 $ 0.125 $ 0.071 Crude oil terminaling ................... $ 0.081 -- -- NGL transportation ...................... $ 1.348 $ 1.337 $ 1.515 Lubrication oil margin (per gallon): ....... $ 0.439 $ 0.282 $ 0.335

2000 Compared to 1999 Margin increased $13.3 million for the year ended December 31, 2000, compared with the prior year. The increase was comprised of a $5.6 million increase in crude oil transportation; a $4.6 million increase in crude oil terminaling attributable to pumpover fees charged at Midland, Texas, and Cushing, Oklahoma, related to the ARCO assets acquired in July 2000; a $1.3 million increase in crude oil marketing activity; a $1.0 million increase in lubrication oil sales; and a $0.9 million increase in NGL transportation. The increase in crude oil transportation margin was primarily attributable to $3.3 million contributed by the ARCO assets acquired and $2.3 million from increased volume and higher transportation rates on the South Texas and Red River systems, which benefited from higher crude oil market prices. The increase in crude oil marketing margin resulted from an increase in volumes marketed and higher sales prices on volumes in third party pipeline systems. Total lubrication oil volumes decreased 10% from the prior year due primarily to the discontinuation of low margin fuel oil sales, effective April 2000. The increase in NGL transportation margin was attributable to increased volumes and higher prices on loss allowance barrels received on the Dean Pipeline. 23 26 Other operating revenue of the Upstream Segment included $4.8 million of revenue related to documentation and other services to support customer's trading activity at Midland, Texas, and Cushing, Oklahoma. Such revenues were added to the Partnership's business on July 20, 2000, with the acquired ARCO assets. Costs and expenses, excluding expenses associated with purchases of crude oil and petroleum products, increased $10.8 million for the year ended December 31, 2000, compared with the prior year, attributable primarily to $6.9 million in costs and expenses from the acquired ARCO assets and a $3.9 million increase in other operating, general and administrative expenses. The costs and expenses associated with the acquired ARCO assets included $4.3 million in operating, general and administrative expenses, $1.3 million in depreciation and amortization charges, $1.1 million in operating fuel and power and $0.2 million in taxes - other than income taxes. The remaining increase in operating, general and administrative expenses of the Upstream Segment resulted primarily from pipeline system maintenance on the South Texas System in the third quarter, increased labor related costs, additional operating costs associated with asset acquisitions in North Texas and increased general and administrative expenses for telecommunications and contract labor charges. Net income of the Upstream Segment included $12.2 million of equity earnings in Seaway Crude Pipeline. Equity earnings in Seaway Crude Pipeline were added to the Partnership's business on July 20, 2000, with the acquired ARCO assets. Interest expense increased $13.6 million for the year ended December 31, 2000, compared with the prior year, primarily due to interest expense on the term loan and revolving credit facilities used to finance the acquisition of ARCO assets. Year Ended December 31, 1999 Net income contributed by the crude oil transportation and marketing segment totaled $10.9 million for the year ended December 31, 1999, comprised of $38.6 million of gross margin and $0.5 million of other income (primarily consists of interest income earned on cash investments), partially offset by $21.6 million of operating, general and administrative expenses (including operating fuel and power), $5.6 million of depreciation and amortization charges, $0.7 million of taxes - other than income and $0.2 million of interest expense. For the year ended December 31, 1999, crude oil transportation and NGL transportation contributed 46% and 16% of the margin, respectively, while crude oil marketing operations accounted for 31% of the margin. Operations of Lubrication Services L.P. ("LSI") contributed $2.5 million, or 7%, of the margin for the year ended December 31, 1999. Operating, general and administrative expenses (including operating fuel and power) totaled $21.6 million, or 56% of the margin, during the year ended December 31, 1999. Depreciation and amortization expenses and taxes - other than income totaled $6.3 million, or 16% of the margin. FINANCIAL CONDITION AND LIQUIDITY Net cash from operations for the year ended December 31, 2000, totaled $108.0 million, comprised of $112.5 million of income before charges for depreciation and amortization, partially offset by $4.5 million of cash used for working capital changes. Net cash from operations for the year ended December 31, 1999, totaled $103.1 million, comprised of $104.8 million of income before charges for depreciation and amortization, partially offset by $1.7 million of cash used for working capital changes. Net cash from operations for the year ended December 31, 1998, totaled $93.2 million, comprised of $80.3 million of income before the extraordinary loss on early extinguishment of debt and charges for depreciation and amortization, and $12.9 million of cash provided from working capital changes. Net cash from operations for the year ended December 31, 2000, 1999, and 1998 included interest payments of $36.8 million, $28.6 million, and $26.2 million, respectively. Cash flows used in investing activities during the year ended December 31, 2000, were comprised of $322.6 million for the purchase of ARCO assets, $99.5 million for NGL and crude oil systems purchased in East Texas and North Texas, $68.5 million of capital expenditures, and $5.0 million of cash contributions for the Partnership's interest in the Centennial joint venture. Cash flows used in investing activities for the year ended December 31, 1999, included $77.4 million of capital expenditures and $2.3 million for the purchase of a 125-mile 24 27 crude oil system in Southeast Texas. Capital expenditures during the years ended December 31, 2000 and 1999, included $29.9 million and $43.8 million, respectively, of spending for construction of three new petrochemical pipelines between the Partnership's terminal in Mont Belvieu, Texas, and Port Arthur, Texas. Cash flows used in investing activities for the year ended December 31, 1998 included $40.0 million for the purchase price of the fractionation assets and related intangible assets, $23.4 million of capital expenditures and $2.0 million related to the acquisition of the crude oil assets, partially offset by $0.5 million received from the sale of non-carrier assets. On January 27, 1998, the Downstream Segment completed the issuance of $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes"). The 6.45% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028 may be redeemed at any time after January 15, 2008, at the option of the Downstream Segment, in whole or in part, at a premium. Net proceeds from the issuance of the Senior Notes totaled approximately $386 million and was used to repay in full the $61.0 million principal amount of the 9.60% Series A First Mortgage Notes, due 2000, and the $265.5 million principal amount of the 10.20% Series B First Mortgage Notes, due 2010. The premium for the early redemption of the First Mortgage Notes totaled $70.1 million. The Partnership recorded an extraordinary charge of $73.5 million during the first quarter of 1998 (including $0.7 million allocated to minority interest), which represents the redemption premium of $70.1 million and unamortized debt issue costs related to the First Mortgage Notes of $3.4 million. The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations of the Downstream Segment and will rank on a parity with all other unsecured and unsubordinated indebtedness of the Downstream Segment. The indenture governing the Senior Notes contains covenants, including, but not limited to, covenants limiting (i) the creation of liens securing indebtedness and (ii) sale and leaseback transactions. However, the indenture does not limit the Partnership's ability to incur additional indebtedness. On July 14, 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility. On July 21, 2000, the Partnership borrowed $75 million under the term loan and $340 million under the revolving credit facility. The funds were used to finance the acquisition of the ARCO assets and to repay principal and interest on existing credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. The revolving credit facility has a three year maturity. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The revolving credit facility contains restrictive financial covenants that require the Partnership to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. At December 31, 2000, $446 million was outstanding under the revolving credit facility at a weighted average interest rate of 8.23%. On July 21, 2000, the Partnership entered into a three year swap agreement to hedge its exposure on the variable rate credit facilities. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership will pay a fixed rate of interest of 7.17% and will receive a floating rate based on a three month USD LIBOR rate. The Partnership paid cash distributions of $82.2 million ($2.00 per Unit), $69.3 million ($1.85 per Unit), and $56.8 million ($1.75 per Unit) for each of the years ended December 31, 2000, 1999, and 1998, respectively. Additionally, on January 18, 2001, the Partnership declared a cash distribution of $0.525 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2000. The distribution of $24.0 million was paid on February 2, 2001, to Unitholders of record on January 31, 2001. On October 25, 2000, the Partnership completed the issuance of 3.7 million Limited Partner Units at $25.06 per Unit. The net proceeds from the offering totaled approximately $88.5 million and was used to repay the $75 million principal amount of the term loan and $11 million of the outstanding principal amount of the revolving credit facility. On February 6, 2001, the Partnership completed the issuance of 2.0 million Limited Partner Units at $25.50 per Unit. The net proceeds from the offering totaled approximately $48.5 million and was used to reduce borrowings under the revolving credit facility. On March 6, 2001, 250,000 Units were issued in connection with the over-allotment provision of the offering on February 6, 2001. Proceeds from the Units issued from the over- 25 28 allotment totaled $6.1 million. The offerings bring the total number of Limited Partner and Class B Units outstanding to 38.9 million as of March 6, 2001. OTHER MATTERS Regulatory and Environmental The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes the operations of the Pipeline System are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the Pipeline System, could result in substantial costs and liabilities to the Partnership. The Partnership does not anticipate that changes in environmental laws and regulations will have a material adverse effect on its financial position, results of operations or cash flows in the near term. The Partnership and the Indiana Department of Environmental Management ("IDEM") have entered into an Agreed Order that will ultimately result in a remediation program for any on-site and off-site groundwater contamination attributable to the Partnership's operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership's proposed remediation program, has been approved by IDEM. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision has been issued, the Partnership will enter into an Agreed Order for the continued operation and maintenance of the program. The Partnership has accrued $0.6 million at December 31, 2000, for future costs of the remediation program for the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse impact on the Partnership's financial condition, results of operations or liquidity. The Partnership received a compliance order from the Louisiana Department of Environmental Quality ("DEQ") during 1994 relative to potential environmental contamination at the Partnership's Arcadia, Louisiana, facility, which may be attributable to the operations of the Partnership and adjacent petroleum terminals of other companies. The Partnership and all adjacent terminals have been assigned to the Groundwater Division of DEQ, in which a consolidated plan will be developed. The Partnership has finalized a negotiated Compliance Order with DEQ that will allow the Partnership to continue with a remediation plan similar to the one previously agreed to by DEQ and implemented by the Company. In the opinion of the General Partner, the completion of the remediation program being proposed by the Partnership will not have a future material adverse impact on the Partnership. Market and Regulatory Environment Rates of interstate oil pipeline companies are currently regulated by the FERC, primarily through an index methodology, whereby a pipeline company is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% ("PPI Index"). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings ("Market Based Rates") or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). On May 11, 1999, the Downstream Segment filed an application with the FERC requesting permission to charge market-based rates for substantially all refined products transportation tariffs. Along with its application for market-based rates, the Downstream Segment filed a petition for waiver pending the FERC's determination on its application for market-based rates, of the requirements that would otherwise have been imposed by the FERC's regulations requiring the Downstream Segment to reduce its rates in conformity with the PPI Index. On June 30, 1999, the FERC granted the waiver stating that it was temporary in nature and that the Downstream Segment would be required to make refunds, with interest, of all amounts collected under rates in excess of the PPI Index ceiling level after July 1, 1999, if the Downstream Segment's application for market-based rates was ultimately denied. As a result of the refund obligation potential, the Partnership has deferred all revenue recognition of rates charged in 26 29 excess of the PPI Index. On December 31, 2000, the amount deferred for possible rate refund, including interest totaled approximately $2.3 million. On July 31, 2000, the FERC issued an order granting the Downstream Segment market-based rates in certain markets and set for hearing the Downstream Segment's application for market-based rates in the Little Rock, Arkansas; Shreveport-Arcadia, Louisiana; Cincinnati-Dayton, Ohio; and Memphis, Tennessee, destination markets and the Shreveport, Louisiana, origin market. The FERC also directed the FERC trial staff to convene a conference to explore the facts and issues regarding the Western Gulf Coast origin market. After the matter was set for hearing, the Downstream Segment and the protesting shippers entered into a settlement agreement resolving their respective differences. On January 9, 2001, the presiding Administrative Law Judge assigned to the hearing determined that the offer of settlement provided resolution of issues set for hearing in the Downstream Segment pending case in a fair and reasonable manner and in the public interest and certified the offer of settlement and recommended it to the FERC for approval. The certification of the settlement is currently before the FERC. The Partnership believes that the Administrative Law Judge's decision in this matter will be upheld by the FERC. The settlement, if it is approved by FERC, will require the Downstream Segment to withdraw the application for market-based rates to the Little Rock, Arkansas, destination market and the Arcadia, Louisiana, destination in the Shreveport-Arcadia, Louisiana, destination market. The Downstream Segment also has agreed to recalculate rates to these destination markets to conform with the PPI Index from July 1, 1999, and make appropriate refunds. The refund obligation under the proposed settlement as of December 31, 2000, would be $0.8 million. Effective July 1, 1999, the Downstream Segment established Settlement Rates with certain shippers of LPGs under which the rates in effect on June 30, 1999, would not be adjusted for a period of either two or three years. Other LPGs transportation tariff rates were reduced pursuant to the PPI Index (approximately 1.83%), effective July 1, 1999. Effective July 1, 1999, the Downstream Segment canceled its tariff for deliveries of MTBE into the Chicago market area reflecting reduced demand for transportation of MTBE into such area. The MTBE tariffs were canceled with the consent of MTBE shippers and resulted in increased pipeline capacity and tankage available for other products. On October 16, 2000, the Partnership received a settlement notice from ARCO for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of the ARCO assets. A large portion of the requested adjustment relates to ARCO's indemnity for payment of accrued income taxes. The Partnership is disputing a substantial portion of the adjustments. The Partnership does not believe that payment of any amount ultimately determined would have a material adverse impact on the Partnership's financial condition and results of operations. The matters discussed herein include "forward-looking statements" within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this document that address activities, events or developments that the Partnership expects or anticipates will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of the Partnership's business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by the Partnership in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Partnership's expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by the Partnership, competitive actions by other pipeline companies, changes in laws or regulations, and other factors, many of which are beyond the control of the Partnership. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and there can be no assurance that actual results or developments anticipated by the Partnership will be realized or, even if substantially realized, that they will have the expected consequences to or effect on the Partnership or its business or operations. 27 30 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS The Partnership may be exposed to market risk through changes in commodity prices and interest rates as discussed below. The Partnership has no foreign exchange risks. Risk management policies have been established by the Risk Management Committee to monitor and control these market risks. The Risk Management Committee is comprised of senior executives of the Company. The Partnership mitigates exposure to commodity price fluctuations by maintaining a balanced position between crude oil purchases and sales. As a hedging strategy to manage crude oil price fluctuations, the Partnership enters into futures contracts on the New York Mercantile Exchange, and makes limited use of other derivative instruments. It is the Partnership's general policy not to acquire crude oil futures contracts or other derivative products for the purpose of speculating on price changes, however, the Partnership may take limited speculative positions to capitalize on crude oil price fluctuations. Any contracts held for trading purposes or speculative positions are accounted for using the mark-to-market method. Under this methodology, contracts are adjusted to market value, and the gains and losses are recognized in current period income. Market risks associated with commodity derivatives were not material at December 31, 2000. At December 31, 2000, the Downstream Segment had outstanding $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes"). At December 31, 2000 and 1999, the estimated fair value of the Senior Notes was approximately $385 million and $356 million, respectively. At December 31, 2000, the Partnership had $446 million outstanding under a variable interest rate revolving credit agreement. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semi-annually. Utilizing the balances of variable interest rate debt outstanding at December 31, 2000, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is approximately $4.5 million. On July 21, 2000, the Partnership entered into a three-year swap agreement to partially hedge its exposure on the new variable rate credit facilities. The swap agreement is based on the notional amount of $250 million. Under the swap agreement, the Partnership will pay a fixed rate of interest of 7.17% and will receive a floating rate based on the three month USD LIBOR rate. At December 31, 2000, the estimated fair value of the swap agreement was a loss of approximately $10 million. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments, including certain derivative instruments embedded in other contracts, be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use and designation of the derivative at its inception. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results of the hedged item in the statement of income, and requires the Company to formally document, designate and assess the effectiveness of the hedge transaction to receive hedge accounting. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Overall hedge effectiveness is measured at least quarterly. Any changes in the fair value of the derivative instrument resulting from hedge ineffectiveness, as defined by SFAS 133 and measured based on the cumulative changes in the fair value of the derivative instrument and the cumulative changes in the estimated future cash flows of the hedged item, are recognized immediately in earnings. The Company has designated its swap agreement as a cash flow hedge. Adoption of SFAS 133 resulted in the recognition of approximately $10 million of derivative liabilities on the Partnership's balance sheet and $10 million of hedging losses included in accumulated other comprehensive income, which is a component of Partners' capital, as the cumulative effect of a change in accounting principle as of January 1, 2001. Amounts were determined as of January 1, 2001 based on the market quote of the Partnership's interest rate swap agreement. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The consolidated financial statements of the Partnership, together with the independent auditors' report thereon of KPMG LLP, begin on page F-1 of this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable 28 31 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The Partnership does not have directors or officers. Set forth below is certain information concerning the directors and executive officers of the General Partner. All directors of the General Partner are elected annually by DEFS. All officers serve at the discretion of the directors. William L. Thacker, age 55, was elected a director of the General Partner in 1992 and Chairman of the Board in October 1997. Mr. Thacker was elected President and Chief Operating Officer in September 1992 and Chief Executive Officer in January 1994. Prior to joining the Company, Mr. Thacker was president of Unocal Pipeline Company from 1986 until 1992. Jim W. Mogg, age 52, was elected a director of the General Partner in October 1997 and Vice Chairman of the Board and Chairman of the Compensation Committee in April 2000. Mr. Mogg is chairman, president and chief executive officer of DEFS. Mr. Mogg was previously president of Centana Energy Corporation and senior vice president for Panhandle Eastern Pipe Line Company. Mr. Mogg joined Panhandle Eastern Pipe Line Company in 1973. Mark A. Borer, age 46, was elected a director of the General Partner in April 2000. Mr. Borer is senior vice president for the Southern Division of DEFS, having joined DEFS in 1999, and in addition to the Southern Division, he is also responsible for DEFS's natural gas liquids marketing organization. Before joining DEFS he was vice president of natural gas marketing for Union Pacific Fuels, Inc. from 1992 until 1999. Milton Carroll, age 50, was elected a director of the General Partner in November 1997, is a member of the Compensation Committee and is Chairman of the Audit Committee. Mr. Carroll is the founder, and has been president and chief executive officer of Instrument Products, Inc., a manufacturer of oil field equipment and other precision products, since 1977. Mr. Carroll is a director of Reliant Energy, Ocean Energy Inc., and Blue Cross Blue Shield of Texas. Carl D. Clay, age 68, is a director of the General Partner and a member of the Compensation and Audit Committees. He was elected in January 1995. Mr. Clay retired from Marathon Oil Company in 1994 after 33 years during which he served as director of transportation and logistics and president of Marathon Pipe Line Company. Derrill Cody, age 62, is a director of the General Partner having been elected in 1989. He serves on the Compensation Committee and was Chairman of the Audit Committee until April 2000. Mr. Cody is currently of counsel to McKinney and Stringer, P. C., which represents Duke Energy in certain matters. He is also an advisor to Duke Energy pursuant to a personal contract. Mr. Cody served as chief executive officer of Texas Eastern Gas Pipeline Company from 1987 to 1989. Mr. Cody is also a director of Barrett Resources Corporation. John P. DesBarres, age 61, is a director of the General Partner, having been elected in May 1995. He is a member of the Compensation and Audit Committees. Mr. DesBarres was formerly chairman, president and chief executive officer of Transco Energy Company from 1992 to 1995. He joined Transco in 1991 as president and chief executive officer. Prior to joining Transco, Mr. DesBarres served as chairman, president and chief executive officer for Santa Fe Pacific Pipelines, Inc. from 1988 to 1991. Mr. DesBarres is a director of American Electric Power. Fred J. Fowler, age 55, was elected a director in November 1998 and served as Vice Chairman of the Board and Chairman of the Compensation Committee until April 2000. Mr. Fowler is group president, energy transmission of Duke Energy. Mr. Fowler joined PanEnergy in 1985 and served in a variety of positions in marketing, transportation and exchange. He was appointed group vice president of PanEnergy in 1996. William W. Slaughter, age 53, was elected a director of the General Partner in April 2000. Mr. Slaughter is executive vice president of DEFS. He has been advisor to the chief executive officer of DEFS since January 1999. Mr. Slaughter was vice president of energy services for Duke Energy from 1997 until 1998, and was vice president of 29 32 corporate strategic planning for PanEnergy and president of PanEnergy International Development Corporation from 1994 to 1997. Barry R. Pearl, age 51, was elected President and Chief Operating Officer in February 2001. Prior to joining the Company, Mr. Pearl was vice president - finance and administration, treasurer, secretary and chief financial officer of Maverick Tube Corporation since June 1998. Mr. Pearl was senior vice president and chief financial officer of Santa Fe Pacific Pipeline Partners, L.P. from 1995 until 1998, and senior vice president, business development from 1992 to 1995. Charles H. Leonard, age 52, is Senior Vice President, Chief Financial Officer and Treasurer of the General Partner. Mr. Leonard joined the Company in 1988 as Vice President and Controller. In November 1989, he was elected Vice President and Chief Financial Officer. He was elected Senior Vice President in March 1990, and Treasurer in October 1996. James C. Ruth, age 53, is Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President, General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998. Thomas R. Harper, age 60, is Vice President, Commercial Downstream of the General Partner, having been elected in September 2000. Mr. Harper was previously Vice President, Product Transportation and Refined Products Marketing from 1988 until September 2000. Mr. Harper joined the Company in 1987 as Director of Product Transportation. David L. Langley, age 53, is Senior Vice President, Corporate Development of the General Partner, having been elected in February 2001. Mr. Langley was previously Vice President, Corporate Development since September 2000, and Vice President, Business Development and LPG Services from 1990 until September 2000. Mr. Langley has been with the Company in various managerial positions since 1975. Ernest P. Hagan, age 56, is Vice President, Centennial, of the General Partner, having been elected in September 2000. Mr. Hagan was previously Vice President, Operations, from 1996 until September 2000, and Director of Engineering and Right-of-Way from 1994 until October 1996. From 1986 until 1994 he was Region Manager of the Southwest Region. Mr. Hagan will retire from the General Partner, effective March 31, 2001. Sharon S. Stratton, age 62, is Vice President, Human Resources of the General Partner, having been elected in January 1999. Ms. Stratton served as Director, Human Resources of the General Partner from 1992 to 1998. She previously served in a variety of human resource positions with PanEnergy. Ms. Stratton will retire from the General Partner, effective March 31, 2001. J. Michael Cockrell, age 54, is Vice President, Commercial Upstream of the General Partner, having been elected in September 2000. Mr. Cockrell was elected Vice President of the General Partner in January 1999 and also serves as President of TCO. He joined PanEnergy in 1987 and served in a variety of positions in supply and development, including president of Duke Energy Transport and Trading Company ("DETTCO"). Leonard W. Mallett, age 44, is Vice President, Operations of the General Partner, having been elected in September 2000. Mr. Mallett was previously Region Manager of the Southwest Region of the Company from 1994 until 1999 and Director, Engineering, from 1992 until 1994. Mr. Mallett joined the Company in 1979 as an engineer. Stephen W. Russell, age 49, is Vice President, Support Services of the General Partner, having been elected in September 2000. Mr. Russell was previously Region Manager of the Southwest Region from July 1999 until September 2000, and Technical Operations Superintendent of the Southwest Region from 1994 until 1999. Mr. Russell joined the Company in 1988 as Project Manager in Engineering. David E. Owen, age 51, was elected Vice President of the General Partner in February 2001. Mr. Owen will become Vice President, Human Resources effective April 1, 2001. He was previously northern division human 30 33 resources manager of DEFS from May 2000 until he joined the Company. Prior to DEFS, Mr. Owen held positions with ARCO International Oil and Gas Company from October 1996 until January 2000 . Based on information furnished to the Company and written representation that no other reports were required, to the Company's knowledge, all applicable Section 16(a) filing requirements were complied with during the year ended December 31, 2000 except for reports covering certain transactions that were filed late by Messrs. Carroll, Harper, Mallett, Mogg and Thacker. ITEM 11. EXECUTIVE COMPENSATION The officers of the General Partner manage and operate the Partnership's business. The Partnership does not directly employ any of the persons responsible for managing or operating the Partnership's operations, but instead reimburses the General Partner for the services of such persons. See Note 4 of the Notes to Consolidated Financial Statements contained elsewhere herein for additional information. Directors of the General Partner who are neither officers nor employees of either the Company or DEFS receive a stipend of $15,000 per annum, $750 for attendance at each meeting of the Board of Directors, $750 for attendance at each meeting of a committee of the Board of Directors and reimbursement of expenses incurred in connection with attendance at a meeting of the Board of Directors or a committee of the Board of Directors. Each non-employee director who serves as chairman of a committee of the Board of Directors receives an additional stipend of $2,000 per annum. Effective September 1, 1999, non-employee directors may elect to defer payment of retainer and attendance fees until termination of service on the Board of Directors. Such deferral may be either 50% or 100% in either a fixed income investment account that is credited with annual interest (currently 7%) or an investment account based upon the market value of Limited Partner Units. Effective April 1, 1999, each quarter that a non-employee director continues to serve on the Board of Directors, such director will be credited with an amount equal to the market value of 62.5 Limited Partner Units and distribution equivalents on previously awarded amounts. In general, such amounts will not become distributable until the non-employee director terminates service on the Board of Directors. When a non-employee director terminates service on the Board of Directors, payment will be distributed to the director on the basis of the distribution schedule chosen by such director. Messrs. Thacker, Mogg, Borer, Fowler and Slaughter were not compensated for their services as directors, and it is not anticipated that any compensation for service as a director will be paid in the future to directors who are either officers or full-time employees of Duke Energy, DEFS, the General Partner or any of their affiliates. The following table reflects cash compensation paid or accrued by the General Partner for the years ended December 31, 2000, 1999 and 1998, with respect to its Chief Executive Officer and the four most highly compensated executive officers (collectively, the "Named Executive Officers"). 31 34 SUMMARY COMPENSATION TABLE

LONG TERM COMPENSATION ANNUAL COMPENSATION OTHER ----------------------- ----------------------------- ANNUAL LTIP ALL OTHER NAME AND BONUS COMPENSATION AWARDS (#) PAYOUTS COMPENSATION PRINCIPAL POSITION YEAR SALARY ($) ($) (2) ($) (3) (4) (5) ($)(6) ($) (7) ------------------ ---- ---------- ------- ------------- ------------ --------- ------------ William L. Thacker........ 2000 269,434 149,400 15,200 7,500 188,335 25,039 Chairman, President and 1999 261,321 106,100 57,809 50,000 133,124 22,924 Chief Executive Officer 1998 250,000 86,400 77,114 39,000 148,858 24,666 J. Michael Cockrell (1)... 2000 182,021 78,000 30,000 -- -- 14,853 Vice President 1999 179,393 51,000 27,750 15,000 -- 14,064 Charles H. Leonard........ 2000 155,965 83,400 5,000 2,500 52,354 13,818 Senior Vice President, 1999 153,507 62,200 -- 16,000 98,679 12,687 Chief Financial Officer 1998 149,333 39,200 14,820 12,000 95,331 13,406 and Treasurer James C. Ruth............. 2000 147,899 76,400 5,000 2,500 40,182 13,013 Senior Vice President and 1999 142,344 57,600 28,904 16,000 60,741 11,738 General Counsel 1998 138,333 36,200 38,557 12,000 41,095 15,079 David L. Langley.......... 2000 140,804 76,400 5,000 2,500 18,690 12,230 Senior Vice President 1999 138,359 52,300 17,343 16,000 17,970 11,380 1998 134,800 34,800 23,134 12,000 50,516 12,968

(1) Mr. Cockrell was elected to his position in January 1999. He was previously employed by DETTCO prior to the acquisition by the Partnership in November 1999. (2) Amounts represent bonuses accrued during the year under the Management Incentive Compensation Plan ("MICP"). Payments under the MICP are made in the subsequent year. (3) Amounts represent quarterly distribution equivalents under the terms of the Company's 2000 Long Term Incentive Plan ("2000 LTIP"), Long Term Incentive Compensation Plan ("LTICP") and Retention Incentive Compensation Plan ("RICP"). (4) Amounts for Mr. Thacker, Mr. Leonard, Mr. Ruth and Mr. Langley represent awards in 1998 and 1999 pursuant to the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan ("1994 LTIP") and awards in 2000 pursuant to the 2000 LTIP. (5) Amount for Mr. Cockrell represents award pursuant to the RICP. (6) Amounts represent the value of redemptions under the 1996 amendment to the LTICP and credits earned to Performance Unit accounts and options exercised under the terms of 1994 LTIP. (7) Includes (i) Company matching contributions under funded, qualified, defined contribution retirement plans; (ii) Company matching contribution credits under unfunded, non qualified plans; and (iii) the imputed value of premiums paid by the Company for insurance on the Named Executive Officers' lives. 32 35 EXECUTIVE EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS On September 1, 1992, William L. Thacker, Jr. and the Company entered into an employment agreement, which set a minimum base salary of $190,000 per year. The Company may terminate the employment agreement for cause, death or disability. In addition, the Company or Mr. Thacker may terminate the agreement upon written notice. Additionally, the Company granted 16,000 phantom units with distribution equivalents to Mr. Thacker pursuant to the LTICP discussed below. Mr. Thacker participates in other Company sponsored benefit plans on the same basis as other senior executives of the Company. On December 1, 1998, the Company entered into employment agreements with Ernest P. Hagan, Thomas R. Harper, David L. Langley, Charles H. Leonard and James C. Ruth. Additionally, effective January 1, 1999, the Company entered into employment agreements with J. Michael Cockrell and Sharon S. Stratton. The agreements may be terminated for death, disability or by the Company with or without cause. In the event one of the named executives' employment is terminated due to death or disability or by the Company for cause, such executive is entitled only to base salary earned through the date of termination. In the event of termination for any other reason, such executive is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times such executive's base annual salary and two times the current target bonus approved under the MICP by the Compensation Committee. In the event that an executive is involuntarily terminated following a change in control, such executive is entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus. COMPENSATION PURSUANT TO GENERAL PARTNER PLANS Management Incentive Compensation Plan The General Partner has established the MICP, which provides for the payment of additional cash compensation to participants if certain Partnership performance and personal objectives are met each year. The Compensation Committee of the General Partner (the "Committee") determines at the beginning of each year which employees are eligible to become participants in the MICP. Each participant is assigned a target award by the Committee. Such target award determines the additional compensation to be paid if all Partnership performance and personal objectives are met and all Minimum Quarterly Distributions have been made for the year. The amount of the awards may range from 10% to 56% of a participant's base salary. Awards are paid as soon as practicable following approval by the Committee after the close of a year. Long Term Incentive Compensation Plan The LTICP provides key employees with an incentive award based upon the grant of phantom units. The LTICP is administered by the Committee, which has sole and absolute discretion to determine the amount of an award. The credit of phantom units under the terms of the LTICP is contingent upon minimum quarterly cash distributions ($0.275 per Unit) being made to the Unit holders and the General Partner. The Committee may also establish performance targets for crediting of phantom units. The award consists of phantom units with a total market value, as of the date of the award, that may not exceed 100% of the base salary of a participant. The phantom units are credited to each participant at the rate of 10% per year beginning on the first anniversary date of the award. A final credit of 60% of the phantom units awarded will occur on the fifth anniversary date of the award. The phantom units may be redeemed by a participant at any time following credit to a participant in accordance with terms and conditions prescribed by the Committee. The redemption price of the phantom units is based on the market value of a Limited Partner Unit as of the date of redemption. In the event of a change of control, all phantom units awarded to a participant will be redeemed. Each participant also receives a quarterly distribution equivalent in cash based upon a percentage of the distributions to the General Partner for such quarter. In 1995, the LTICP was amended to require annual redemptions, effective January 1, 1996, of 20% of the phantom units previously credited to each participant. No awards were made under the LTICP in 2000. On January 4, 2000, all remaining outstanding phantom units were redeemed. See Item 13, "Certain Relationships and Related Transactions." 33 36 1994 Long Term Incentive Plan The 1994 LTIP provides key employees with an incentive award whereby a participant is granted an option to purchase Units together with a stipulated number of Performance Units. Each Performance Unit creates a credit to a participant's Performance Unit account when earnings exceed a threshold, which was $1.00, $1.25 and $1.875 per Limited Partner Unit for the awards made in 1994, 1995, and 1997, respectively. When earnings for a calendar year (exclusive of certain special items) exceed the threshold, the excess amount is credited to the participant's Performance Unit account. The balance in the account may be used to exercise Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. Options may also be exercised by normal means once vesting requirements are met. No awards were made under the 1994 LTIP in 2000. The following table provides information concerning the Unit options exercised under the 1994 LTIP by each of the Named Executive Officers during 2000 and the value of unexercised Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2000. The value assigned to each unexercised, "in the money" option is based on the positive spread between the exercise price of such option and the fair market value of a Limited Partner Unit on December 31, 2000. The fair market value is the average of the high and low prices of a Limited Partner Unit as reported in The Wall Street Journal on the last business day in 2000. In assessing the value, it should be kept in mind that no matter what theoretical value is placed on an option on a particular date, its ultimate value will be dependent on the market value of the Partnership's Limited Partner Unit price at a future date. The future value will depend in part on the efforts of the Named Executive Officers to foster the future success of the Partnership for the benefit of all Unitholders. AGGREGATED OPTIONS/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES

VALUE OF UNEXERCISED NUMBER OF SECURITIES IN-THE MONEY UNDERLYING UNEXERCISED OPTIONS/SARS SHARES OPTIONS/SARS AT FY-END AT FY-END ($) ACQUIRED ON VALUE (#) EXERCISABLE/ EXERCISABLE/ NAME EXERCISE (#) REALIZED($) UNEXERCISABLE (1) UNEXERCISABLE ---- ------------ ----------- ---------------------- --------------- Mr. Thacker................. 5,076 $42,462 62,249/46,333 $134,530/$0 Mr. Leonard................. 3,000 $33,873 13,661/14,667 $ 3,506/$0 Mr. Ruth.................... 669 $ 5,952 21,390/14,667 $ 86,109/$0 Mr. Langley................. -- -- 19,333/14,667 $ 64,125/$0

(1) Future exercisability of currently unexercisable options depends on the grantee remaining employed by the Company throughout the vesting period of the options, subject to provisions applicable at retirement, death, or total disability. 2000 Long Term Incentive Plan Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (the "2000 LTIP") to provide key employees incentives to achieve improvements in the Partnership's financial performance. Generally, upon the close of a three-year performance period, if he is then still an employee of the General Partner, a participant in the 2000 LTIP will be entitled to receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom Limited Partner Units granted under the award multiplied by (3) the average of the closing prices of a Limited Partner Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant's performance percentage is based upon the improvement of the Partnership's Economic Value Added (as defined below) during a three-year performance period over the economic value added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement 34 37 (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant's separation from service and the denominator of which is the number of days in the performance period. During 2000, Mr. Thacker, Mr. Leonard, Mr. Ruth and Mr. Langley were granted awards under the 2000 LTIP of 7,500, 2,500, 2,500 and 2,500 phantom Limited Partner Units, respectively. The performance period applicable to such awards is the three-year period that commenced on January 1, 2000 and ends on December 31, 2002. Each participant's performance percentage is the result of [(A) minus (B)] multiplied by (C) where (A) is the Economic Value Added for the performance period, (B) is $47,088,000 (which represents the Economic Value Added for the three-year period immediately preceding the performance period) and (C) is .0000001219. Thus, no amounts will be payable under the 2000 LTIP unless Economic Value Added for the performance period exceeds $47,088,000. Economic Value Added means the Partnership's average annual EBITDA for the performance period minus the product of the Partnership's average asset base and the Partnership's cost of capital for the performance period. For purposes of the 2000 LTIP, EBITDA means the Partnership's earnings before interest income and expense, income taxes, depreciation and amortization as presented in the Partnership's financial statements prepared in accordance with generally accepted accounting principles, except that in its discretion the Compensation Committee of the General Partner may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of the Partnership's gross property, plant and equipment, plus products linefill, crude linefill, goodwill, maintenance capital and expansion capital, minus retired capital. The Partnership's cost of capital is the weighted average cost of the Partnership's accumulated long and short-term debt for the performance period. In addition to the payment described above, during the performance period, for so long as the participant is an employee of the General Partner, the General Partner will pay to the Participant the amount of cash distributions the Partnership would have paid to the participant had he been the owner of the number of Limited Partner Units equal to the number of phantom Limited Partner Units granted to the participant under his award. The following table provides information concerning awards under the 2000 LTIP to each of the Named Executive Officers during 2000.

NUMBER ESTIMATED FUTURE PAYOUTS (1) OF ------------------------------------------------- PHANTOM PERFORMANCE THRESHOLD TARGET MAXIMUM NAME UNITS PERIOD (#) (2) (#) (3) (#) (4) ---- ------- ----------- --------- ------- -------- Mr. Thacker.............. 7,500 3 years 0 8,022 N/A Mr. Leonard.............. 2,500 3 years 0 2,674 N/A Mr. Ruth................. 2,500 3 years 0 2,674 N/A Mr. Langley.............. 2,500 3 years 0 2,674 N/A

(1) Phantom units will be settled in cash based upon the then-market price of the Units at the end of the performance period as described above. (2) No amounts will be payable under the 2000 LTIP unless Economic Value Added for the performance period exceeds $47,088,000. (3) In number of phantom units. Pursuant to Instruction 5 to Regulation 402(e) of the Securities and Exchange Commission, these amounts assume that the 18.6 percent increase in Economic Value Added for 2000 as compared with 1999 is maintained for each of the three years in the performance period. There can be no assurance that any specific amount of Economic Value Added will be attained for such period. (4) There is no maximum limitation on potential payouts under the 2000 LTIP. 35 38 Retention Incentive Compensation Plan Effective January 1, 1999, the General Partner established the Retention Incentive Compensation Plan ("RICP") to provide key employees with an incentive award based upon the grant of phantom units. The RICP is administered by the Committee, which has sole and absolute discretion to determine the amount of an award. The Committee may also establish performance targets for crediting of phantom units. The phantom units are credited to each participant at the rate of 25% per year beginning on the first anniversary date of the award. The phantom units may be redeemed by a participant at any time following credit to a participant in accordance with terms and conditions prescribed by the Committee. The redemption price of the phantom units is based on the market value of a Limited Partner Unit as of the date of redemption. Each participant also receives a quarterly distribution equivalent on all phantom units awarded, until redemption of such phantom units. No awards were made under the RICP in 2000. PENSION PLAN Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company's employees participated in the Duke Energy Retirement Cash Balance Plan, which is a noncontributory, trustee-administered pension plan. Effective January 1, 1999 the benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit based upon pay credits and current interest credits. The pay credits are based on a participant's salary, age, and service. In addition, the Named Executive Officers participate in the Duke Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy Executive Cash Balance Plan was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. Benefits under the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance were based on eligible pay, generally consisting of base pay, short term incentive pay, and lump-sum merit increases. The Duke Energy Retirement Cash Balance Plan excludes deferred compensation, other than deferrals pursuant to Sections 401(k) and 125 of the Internal Revenue Code. As part of the change in ownership, the Company is no longer responsible for liabilities associated with the Duke Energy Retirement Cash Balance Plan or the Duke Energy Executive Cash Balance Plan. Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan ("Retirement Cash Balance Plan") and the TEPPCO Supplemental Benefit Plan ("Supplemental Benefit Plan"). The benefits and provisions of these plans are substantially identical to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan previously in effect prior to April 1, 2000. Under the cash balance benefit accrual formula that applies in determining benefits under the Retirement Cash Balance Plan, an eligible employee's plan account receives a pay credit at the end of each month in which the employee remains eligible and receives eligible pay for services. The monthly pay credit is equal to a percentage of the employee's monthly eligible pay. The percentage depends on age added to completed years of services at the beginning of the year, as shown below:

MONTHLY PAY CREDIT AGE AND SERVICE PERCENTAGE --------------- ---------- 34 or less......................................... 4% 35 to 49........................................... 5% 50 to 64........................................... 6% 65 or more......................................... 7%

The above monthly pay credit is increased by an additional 4% of any portion of eligible pay above the Social Security taxable wage base ($80,400 for 2001). Employee accounts also receive monthly interest credits on their balances. The rate of the interest credit is adjusted quarterly and is derived from the average annual yield on 30-year U.S. Treasury Bonds during the third week of the last month of the previous quarter, subject to a minimum rate of 4% per year and a maximum rate of 9% per year. 36 39 Assuming that the Named Executive Officers continue in their present positions at their present salaries until retirement at age 65, their estimated annual pensions in a single life annuity form under the applicable pension plan(s) (including the Duke Energy Retirement Cash Balance Plan, the Duke Energy Executive Cash Balance Plan, the Retirement Cash Balance Plan and the Supplemental Benefit Plan) attributable to such salaries would be as follows: William L. Thacker, $157,678; J. Michael Cockrell, $41,690; Charles H. Leonard, $105,297; James C. Ruth, $187,197; and David L. Langley, $174,794. Such estimates were calculated assuming interest credits at a rate of 7% per annum and using a future Social Security taxable wage base equal to $80,400. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security Ownership of Certain Beneficial Owners As of March 6, 2001, Duke Energy, through its ownership of the Company and other subsidiaries, owns 2,500,000 Limited Partner Units, representing 7.15% of the Limited Partner Units outstanding; and 3,916,547 Class B Units, representing 100% of the Class B Units, or 16.51% of the two classes of Units combined. (b) Security Ownership of Management The following table sets forth certain information, as of March 6, 2001, concerning the beneficial ownership of Limited Partner Units by each director and Named Executive Officer of the General Partner and by all directors and officers of the General Partner as a group. Such information is based on data furnished by the persons named. Based on information furnished to the General Partner by such persons, no director or officer of the General Partner owned beneficially, as of March 6, 2001, more than 1% of the 35.0 million Limited Partner Units outstanding at that date.

NUMBER OF NAME UNITS (1) ---- --------- Mark A. Borer............................................................................. 500 Milton Carroll............................................................................ 532 Carl D. Clay (2).......................................................................... 3,200 J. Michael Cockrell....................................................................... 4,000 Derrill Cody.............................................................................. 13,000 John P. DesBarres......................................................................... 20,000 Fred J. Fowler (3)........................................................................ 3,100 David L. Langley.......................................................................... 22,000 Charles H. Leonard........................................................................ 406 Jim W. Mogg (4)........................................................................... 3,427 James C. Ruth............................................................................. 3,643 William W. Slaughter...................................................................... 8,000 William L. Thacker........................................................................ 37,987 All directors and officers (consisting of 22 people, including those named above)......... 139,608

(1) Unless otherwise indicated, the persons named above have sole voting and investment power over the Units reported. Includes Units that the named person has the right to acquire within 60 days. (2) Includes 1,800 Units in wife's name. (3) Includes 200 Units owned by son. (4) Includes 2,227 Units held in trust accounts for daughters. 37 40 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Partnership is managed and controlled by the General Partner pursuant to the Partnership Agreements. Under the Partnership Agreements, the General Partner is reimbursed for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership. These expenses include salaries, fees and other compensation and benefit expenses of employees, officers and directors, insurance, other administrative or overhead expenses and all other expenses necessary or appropriate to conduct the Partnership's business. The costs allocated to the Partnership by the General Partner for administrative services and overhead totaled $0.8 million in 2000. The Partnership Agreements provide for incentive distributions payable to the General Partner out of the Partnership's Available Cash (as defined in the Partnership Agreements) in the event quarterly distributions to Unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a target of $0.275 per Limited Partner Unit, the General Partner will receive incentive distributions equal to (i) 15% of that portion of the distribution per Limited Partner Unit which exceeds the minimum quarterly distribution amount of $0.275 but is not more than $0.325, plus (ii) 25% of that portion of the quarterly distribution per Limited Partner Unit which exceeds $0.325 but is not more than $0.45, plus (iii) 50% of that portion of the quarterly distribution per Limited Partner Unit which exceeds $0.45. During 2000, incentive distributions paid to the General Partner totaled $12.9 million. In connection with the formation of the Partnership in 1990, the Company received 2,500,000 Deferred Partnership Interests ("DPIs"). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss. As of December 31, 2000, 94% of the DPIs have been converted into an equal number of Limited Partner Units, and the balance of such DPIs may be converted immediately prior to the sale of the DPIs by the Company. Pursuant to its Partnership Agreement, the Partnership has registered the resale of such Limited Partner Units with the Securities and Exchange Commission. Such Limited Partner Units may be sold from time to time on the New York Stock Exchange or otherwise at prices and terms then prevailing or in negotiated transactions. As of December 31, 2000, no such Limited Partner Units had been sold by the Company. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this Report: (1) Financial Statements: See Index to Financial Statements on page F-1 of this report for financial statements filed as part of this report. (2) Financial Statement Schedules: None (3) Exhibits. Exhibit Number Description 3.1 Certificate of Limited Partnership of the Partnership (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 3.2 Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 3.3 Second Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated November 30, 1998 (Filed as Exhibit 3.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 38 41 3.4 Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated July 21, 1998 and incorporated herein by reference). 3.5 Agreement of Limited Partnership of TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 3.5 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 4.1 Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 4.2 Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership's Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference). 4.3 Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.1 Assignment and Assumption Agreement, dated March 24, 1988, between Texas Eastern Transmission Corporation and the Company (Filed as Exhibit 10.8 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). +10.2 Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference). 10.3 Agreement Regarding Environmental Indemnities and Certain Assets (Filed as Exhibit 10.5 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). +10.4 Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference). +10.5 Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). +10.6 Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference). +10.7 Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.8 Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.9 Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.10 Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference). +10.11 Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference). 39 42 +10.12 Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference). 10.13 Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 10.14 Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.15 Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.16 Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). +10.17 Form of Employment Agreement between the Company and Ernest P. Hagan, Thomas R. Harper, David L. Langley, Charles H. Leonard and James C. Ruth, dated December 1, 1998 (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.18 Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.19 Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.20 Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). +10.21 Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). +10.22 Form of Employment and Non-Compete Agreement between the Company and Samuel N. Brown, J. Michael Cockrell, and Sharon S. Stratton effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.23 Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.24 Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.25 Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 40 43 10.26 Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference). 10.27 Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipeline Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference). +*10.28 Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, Effective January 1, 2000. +*10.29 TEPPCO Supplemental Benefits Plan, effective April 1, 2000. *12.1 Statement of Computation of Ratio of Earnings to Fixed Charges. 22.1 Subsidiaries of the Partnership (Filed as Exhibit 22.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). *23 Consent of KPMG LLP. *24 Powers of Attorney. ------------------- * Filed herewith. + A management contract or compensation plan or arrangement. (b) Reports on Form 8-K filed during the quarter ended December 31, 2000: Report dated July 21, 2000, on Form 8-K/A was filed on October 3, 2000, pursuant to Item 2. and Item 7. of such form. Report dated October 19, 2000, on Form 8-K was filed on October 23, 2000, pursuant to Item 5. and Item 7. of such form. SIGNATURES TEPPCO Partners, L.P., pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. TEPPCO Partners, L.P. --------------------- (Registrant) (A Delaware Limited Partnership) By: Texas Eastern Products Pipeline Company, LLC, as General Partner By: /s/ WILLIAM L. THACKER ------------------------------------------ William L. Thacker, Chairman and Chief Executive Officer By: /s/ CHARLES H. LEONARD ------------------------------------------ Charles H. Leonard, Senior Vice President, Chief Financial Officer and Treasurer Dated: March 9, 2001 41 44 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 date indicated.

SIGNATURE TITLE DATE --------- ----- ---- WILLIAM L. THACKER* Chairman of the Board and Chief Executive March 9, 2001 ---------------------------- Officer of Texas Eastern Products Pipeline Company, LLC William L. Thacker CHARLES H. LEONARD Senior Vice President, Chief Financial Officer and March 9, 2001 ---------------------------- Treasurer of Texas Eastern Products Pipeline Company, LLC Charles H. Leonard (Principal Accounting and Financial Officer) JIM W. MOGG* Vice Chairman of the Board of Texas March 9, 2001 ---------------------------- Eastern Products Pipeline Company, LLC Jim W. Mogg MARK A. BORER * Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC Mark A. Borer MILTON CARROLL* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC Milton Carroll CARL D. CLAY* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC Carl D. Clay DERRILL CODY* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC Derrill Cody JOHN P. DESBARRES* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC John P. DesBarres FRED J. FOWLER* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC Fred J. Fowler WILLIAM W. SLAUGHTER* Director of Texas Eastern March 9, 2001 ---------------------------- Products Pipeline Company, LLC William W. Slaughter

* Signed on behalf of the Registrant and each of these persons: By: /s/ CHARLES H. LEONARD --------------------------------------- (Charles H. Leonard, Attorney-in-Fact) 42 45 CONSOLIDATED FINANCIAL STATEMENTS OF TEPPCO PARTNERS, L.P. INDEX TO FINANCIAL STATEMENTS

PAGE ---- Independent Auditors' Report................................................................... F-2 Consolidated Balance Sheets as of December 31, 2000 and 1999................................... F-3 Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998......... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998..... F-5 Consolidated Statements of Partners' Capital for the years ended December 31, 2000, 1999 and 1998............................................................................... F-6 Notes to Consolidated Financial Statements..................................................... F-7

F-1 46 INDEPENDENT AUDITORS' REPORT To the Partners of TEPPCO Partners, L.P.: We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2000 and 1999, and the related consolidated statements of income, partners' capital, and cash flows for each of the years in the three-year period ended December 31, 2000. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. KPMG LLP Houston, Texas January 18, 2001 F-2 47 TEPPCO PARTNERS, L.P. CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)

DECEMBER 31, --------------------------- 2000 1999 ---------- ---------- ASSETS Current assets: Cash and cash equivalents................................................ $ 27,096 $ 32,593 Accounts receivable, trade............................................... 303,394 205,766 Inventories.............................................................. 24,784 16,766 Other ................................................................... 8,123 7,884 ---------- ---------- Total current assets............................................... 363,397 263,009 ---------- ---------- Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $251,165 and $220,467)............................... 949,705 720,919 Equity investments......................................................... 241,648 -- Intangible assets.......................................................... 38,388 34,926 Other assets............................................................... 29,672 22,519 ---------- ---------- Total assets....................................................... $1,622,810 $1,041,373 ========== ========== LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Accounts payable and accrued liabilities................................. $ 293,720 $ 201,660 Accounts payable, general partner........................................ 6,637 4,741 Accrued interest......................................................... 18,633 13,297 Other accrued taxes...................................................... 10,501 8,822 Other ................................................................... 28,780 14,972 ---------- ---------- Total current liabilities.......................................... 358,271 243,492 ---------- ---------- Senior Notes............................................................... 389,784 389,753 Other long-term debt....................................................... 446,000 66,000 Other liabilities and deferred credits..................................... 3,991 3,073 Minority interest.......................................................... 4,296 3,429 Redeemable Class B Units held by related party............................. 105,411 105,859 Partners' capital: General partner's interest............................................... 1,824 657 Limited partners' interests.............................................. 313,233 229,110 ---------- ---------- Total partners' capital............................................ 315,057 229,767 ---------- ---------- Commitments and contingencies Total liabilities and partners' capital............................ $1,622,810 $1,041,373 ========== ==========

See accompanying Notes to Consolidated Financial Statements. F-3 48 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

YEARS ENDED DECEMBER 31, ------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Operating revenues: Sales of crude oil and petroleum products ...................... $ 2,821,943 $ 1,692,767 $ 214,463 Transportation -- refined products ............................. 119,331 123,004 119,854 Transportation -- LPGs ......................................... 73,896 67,701 60,902 Transportation -- crude oil and NGLs ........................... 24,533 11,846 3,392 Mont Belvieu operations ........................................ 13,334 12,849 10,880 Other .......................................................... 34,904 26,716 20,147 ----------- ----------- ----------- Total operating revenues ................................. 3,087,941 1,934,883 429,638 ----------- ----------- ----------- Costs and expenses: Purchases of crude oil and petroleum products .................. 2,794,604 1,666,042 212,371 Operating, general and administrative .......................... 104,918 94,340 73,850 Operating fuel and power ....................................... 34,655 31,265 27,131 Depreciation and amortization .................................. 35,163 32,656 26,938 Taxes -- other than income taxes ............................... 10,576 10,490 9,382 ----------- ----------- ----------- Total costs and expenses ................................. 2,979,916 1,834,793 349,672 ----------- ----------- ----------- Operating income ......................................... 108,025 100,090 79,966 Interest expense ................................................. (48,982) (31,563) (29,784) Interest capitalized ............................................. 4,559 2,133 795 Equity earnings -- Seaway Crude Pipeline Company ............... 12,214 -- -- Other income -- net .............................................. 2,349 2,196 2,908 ----------- ----------- ----------- Income before minority interest and extraordinary loss on debt extinguishment ....................................... 78,165 72,856 53,885 Minority interest ................................................ (789) (736) (544) ----------- ----------- ----------- Income before extraordinary loss on debt extinguishment .. 77,376 72,120 53,341 Extraordinary loss on debt extinguishment, net of minority interest -- -- (72,767) ----------- ----------- ----------- Net income (loss) ........................................ $ 77,376 $ 72,120 $ (19,426) =========== =========== =========== Net income (loss) allocated to Limited Partner Unitholders ....... 56,091 55,349 (18,722) Net income allocated to Class B Unitholder ....................... 7,385 7,475 1,036 Net income (loss) allocated to General Partner ................... 13,900 9,296 (1,740) ----------- ----------- ----------- Total net income (loss) allocated ........................ $ 77,376 $ 72,120 $ (19,426) =========== =========== =========== BASIC AND DILUTED INCOME (LOSS) PER LIMITED PARTNER AND CLASS B UNIT: Income before extraordinary loss on debt extinguishment .. $ 1.89 $ 1.91 $ 1.61 Extraordinary loss on debt extinguishment ................ -- -- (2.21) ----------- ----------- ----------- Net income (loss) ..................................... $ 1.89 $ 1.91 $ (0.60) =========== =========== =========== Weighted average Limited Partner and Class B Units outstanding: 33,594 32,917 29,655

See accompanying Notes to Consolidated Financial Statements. F-4 49 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)

YEARS ENDED DECEMBER 31, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Cash flows from operating activities: Net income (loss) ................................................. $ 77,376 $ 72,120 $ (19,426) Adjustments to reconcile net income to cash provided by operating activities: Depreciation and amortization ................................... 35,163 32,656 26,938 Extraordinary loss on early extinguishment of debt .............. -- -- 72,767 Gain on sale of property, plant and equipment ................... -- -- (356) Equity in (income) loss of affiliate ............................ (10,084) 393 189 Non-cash portion of interest expense ............................ 2,218 337 270 Increase in accounts receivable ................................. (90,006) (92,225) (93,715) Decrease (increase) in inventories .............................. (7,567) 1,037 493 Decrease (increase) in other current assets ..................... 1,165 (2,500) 264 Increase in accounts payable and accrued expenses ............... 106,662 93,317 106,350 Other ........................................................... (6,882) (2,065) (559) ----------- ----------- ----------- Net cash provided by operating activities .................. 108,045 103,070 93,215 ----------- ----------- ----------- Cash flows from investing activities: Proceeds from cash investments .................................... 3,475 6,275 3,105 Purchases of cash investments ..................................... (2,000) (3,235) (748) Purchase of ARCO assets ........................................... (322,640) -- -- Purchase of fractionator assets and related intangible assets ..... -- -- (40,000) Purchase of crude oil assets and NGL system ....................... (99,508) (2,250) (1,989) Proceeds from the sale of property, plant and equipment ........... -- -- 525 Investment in Centennial Pipeline Company ......................... (5,040) -- -- Capital expenditures .............................................. (68,481) (77,431) (23,432) ----------- ----------- ----------- Net cash used in investing activities ...................... (494,194) (76,641) (62,539) ----------- ----------- ----------- Cash flows from financing activities: Principal payment, First Mortgage Notes ........................... -- -- (326,512) Prepayment premium, First Mortgage Notes .......................... -- -- (70,093) Issuance of Senior Notes .......................................... -- -- 389,694 Debt issuance cost ................................................ (7,074) -- (3,651) Proceeds from term and revolving credit facilities ................ 552,000 33,000 38,000 Repayments on term and revolving credit facilities ................ (172,000) (5,000) -- Issuance of Limited Partner Units, net ............................ 88,158 -- -- General partner's contributions ................................... 1,799 -- 2,122 Distributions ..................................................... (82,231) (69,259) (56,774) ----------- ----------- ----------- Net cash provided by (used in) financing activities ........ 380,652 (41,259) (27,214) ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents ................ (5,497) (14,830) 3,462 Cash and cash equivalents at beginning of period .................... 32,593 47,423 43,961 ----------- ----------- ----------- Cash and cash equivalents at end of period .......................... $ 27,096 $ 32,593 $ 47,423 =========== =========== =========== Non cash investing and financing activities: Fair value of crude oil and NGL systems purchased ................ $ -- $ -- $ 109,000 Liabilities assumed .............................................. -- -- (5,000) Issuance of Class B Units ........................................ -- -- 104,000 Supplemental disclosure of cash flows: Interest paid during the year (net of capitalized interest) ...... $ 36,793 $ 28,625 $ 26,179

See accompanying Notes to Consolidated Financial Statements. F-5 50 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (IN THOUSANDS)

GENERAL LIMITED PARTNER'S PARTNERS' INTEREST INTERESTS TOTAL ------------ ------------ ------------ Partners' capital at December 31, 1997 ............... $ 5,760 $ 297,207 $ 302,967 Capital contributions .............................. 1,051 -- 1,051 1998 net loss allocation ........................... (1,740) (18,722) (20,462) 1998 cash distributions ............................ (5,451) (50,750) (56,201) Option exercises, net of Unit repurchases .......... -- (169) (169) ------------ ------------ ------------ Partners' capital (deficit) at December 31, 1998 ..... (380) 227,566 227,186 1999 net income allocation ......................... 9,296 55,349 64,645 1999 cash distributions ............................ (8,259) (53,650) (61,909) Option exercises, net of Unit repurchases .......... -- (155) (155) ------------ ------------ ------------ Partners' capital at December 31, 1999 ............... 657 229,110 229,767 Capital contributions .............................. 890 -- 890 Issuance of Limited Partner Units, net ............. -- 88,158 88,158 2000 net income allocation ......................... 13,900 56,091 69,991 2000 cash distributions ............................ (13,623) (59,943) (73,566) Option exercises, net of Unit repurchases .......... -- (183) (183) ------------ ------------ ------------ Partners' capital at December 31, 2000 ............... $ 1,824 $ 313,233 $ 315,057 ============ ============ ============

See accompanying Notes to Consolidated Financial Statements. F-6 51 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership, was formed in March 1990. The Partnership operates through TE Products Pipeline Company, Limited Partnership (the "Downstream Segment") and TCTM, L.P. (the "Upstream Segment"). Collectively the Downstream Segment and the Upstream Segment are referred to as "the Operating Partnerships." The Partnership owns a 99% interest as the sole limited partner interest in both the Downstream Segment and Upstream Segment. On March 31, 2000, Texas Eastern Products Pipeline Company, a Delaware corporation and general partner of the Partnership and the Operating Partnerships, was converted into Texas Eastern Products Pipeline Company, LLC (the "Company" or "General Partner"), a Delaware limited liability company. Additionally on March 31, 2000, Duke Energy Corporation ("Duke Energy"), contributed its ownership of the General Partner to Duke Energy Field Services, LP ("DEFS"). DEFS is a joint venture between Duke Energy and Phillips Petroleum Company. Duke Energy holds a majority interest in DEFS. The Company owns a 1% general partner interest in the Partnership and a 1% general partner interest in each Operating Partnership. The Company, as general partner, performs all management and operating functions required for the Partnership pursuant to the Agreements of Limited Partnership of TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership and TCTM, L.P. (the "Partnership Agreements"). The General Partner is reimbursed by the Partnership for all reasonable direct and indirect expenses incurred in managing the Partnership. At formation, the Partnership completed an initial public offering of 26,500,000 Units representing Limited Partner Interests ("Limited Partner Units") at $10 per Unit. In connection with the formation of the Partnership, the Company received 2,500,000 Deferred Participation Interests ("DPIs"). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss. As of December 31, 2000, 94% of the DPIs have been converted into an equal number of Limited Partner Units, and the balance of such DPIs may be converted immediately prior to the sale of the DPIs by the Company. Pursuant to its Partnership Agreement, the Partnership has registered the resale of such Limited Partner Units with the Securities and Exchange Commission. Such Limited Partner Units may be sold from time to time on the New York Stock Exchange or otherwise at prices and terms then prevailing or in negotiated transactions. As of December 31, 2000, no such Limited Partner Units had been sold by the Company. At December 31, 2000, the Partnership had outstanding 32,700,000 Limited Partner Units and 3,916,547 Class B Limited Partner Units ("Class B Units"). All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets in 1998. The Class B Units are substantially identical to the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the Limited Partner Unitholders. The Company has the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if such conversion is denied, the holder of the Class B Units will have the right to sell them to the Partnership at 95.5% of the market price of the Limited Partner Units at the time of sale. As a result of such option, the Class B Units were not included in partners' capital at December 31, 2000. Collectively, the Limited Partner Units and Class B Units are referred to as "Units." F-7 52 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The financial statements include the accounts of the Partnership on a consolidated basis. The Company's 1% general partner interest in the Downstream Segment and the Upstream Segment, is accounted for as a minority interest. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to current presentation. 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 periods. Actual results could differ from those estimates. ENVIRONMENTAL EXPENDITURES The Partnership accrues for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. The Partnership's accrued undiscounted environmental liabilities are monitored on a regular basis by management. Liabilities for environmental costs at a specific site are initially recorded when the Partnership's liability for such costs, including direct internal and legal costs, is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of the Partnership's ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. BUSINESS SEGMENTS The Partnership operates in two segments: refined products and liquefied petroleum gases ("LPGs") transportation (Downstream Segment); and crude oil and natural gas liquids ("NGLs") transportation and marketing (Upstream Segment). The Partnership's reportable segments offer different products and services and are managed separately because each requires different business strategies. The Upstream Segment was acquired as a unit in November 1998, and the management at the time of the acquisition was retained. The Partnership's interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"). Refined products, LPGs, crude oil and NGLs are referred to herein, collectively, as "petroleum products" or "products." F-8 53 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) REVENUE RECOGNITION Substantially all revenues of the Downstream Segment are derived from interstate and intrastate transportation of petroleum products, storage and terminaling of petroleum products, intrastate transportation of petrochemicals, fractionation of natural gas liquids and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS. Revenues of the Upstream Segment are derived from the gathering, storage, transportation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals principally in Oklahoma, Texas and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas (effective July 20, 2000). Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to the Partnership's crude oil marketing company, TEPPCO Crude Oil, L.P. ("TCO"), which typically occurs upon receipt of the product by TCO. Revenues related to trade documentation and pumpover services are recognized as completed. Except for crude oil purchased from time to time as inventory, TCO's policy is to purchase only crude oil for which it has a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As TCO purchases crude oil, it establishes a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation either physically or a futures contract on the New York Mercantile Exchange ("NYMEX"). Through these transactions, TCO seeks to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged. USE OF DERIVATIVES The Partnership may use derivative instruments, such as futures, swaps and options, to manage its exposure to commodity price risk and interest rate risk. For derivative contracts to qualify as a hedge, the price movements in the derivative instrument must be highly correlated with the underlying hedged commodity or obligation. Contracts that qualify as hedges and held for non-trading purposes are accounted for using the deferral method of accounting. Under this method, gains and losses are not recognized until the underlying physical transaction occurs. Deferred gains and losses related to futures are reported in the consolidated balance sheet as current assets or current liabilities. Deferred gains and losses related to swaps and options are carried off-balance sheet until instruments are settled. It is the Partnership's general policy not to acquire crude oil futures contracts or other derivative products for the purpose of speculating on price changes, however, the Partnership may take limited speculative positions to capitalize on crude oil price fluctuations. Contracts held for trading purposes are accounted for using the mark-to-market method. Under this methodology, contracts are adjusted to market value, and the gains and losses are recognized in current period income. The Partnership monitors open derivative positions with policies which limit its exposure to market risk and require reporting to management of potential financial exposure. At December 31, 2000 and 1999, outstanding commodity derivative contracts held for trading purposes were not material. Net payments or receipts under the Partnership's interest swap agreements are recorded as adjustments to interest expense. F-9 54 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) INVENTORIES Inventories consist primarily of petroleum products and crude oil which are valued at the lower of cost (weighted average cost method) or market. The Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. PROPERTY, PLANT AND EQUIPMENT Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. Replacements and renewals of minor items of property are charged to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum). Upon sale or retirement of properties regulated by the FERC, cost less salvage is normally charged to accumulated depreciation, and no gain or loss is recognized. CAPITALIZATION OF INTEREST The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 7.45%, 7.01% and 7.02% for 2000, 1999 and 1998, respectively. INCOME TAXES The Partnership is a limited partnership. As a result, the Partnership's income or loss for federal income tax purposes is included in the tax return of the individual partners, and may vary substantially from income or loss reported for financial reporting purposes. Accordingly, no recognition has been given to federal income taxes for the Partnership's operations. At December 31, 2000 and 1999, the Partnership's reported amount of net assets for financial reporting purposes exceeded its tax basis by approximately $318 million and $293 million, respectively. CASH FLOWS For purposes of reporting cash flows, all liquid investments with maturities at date of purchase of 90-days or less are considered cash equivalents. NET INCOME PER UNIT Basic net income per Unit is computed by dividing net income, after deduction of the general partner's interest, by the weighted average number of Limited Partner and Class B Units outstanding (a total of 33.6 million Units for 2000, 32.9 million Units for 1999, and 29.7 million Units for 1998). The general partner's percentage interest in net income is based on its percentage of cash distributions from Available Cash for each year (see Note 10). The general partner was allocated $13.9 million (representing 17.96%) of net income for the year ended December 31, 2000, $9.3 million (representing 12.89%) of net income for the year ended December 31, 1999, and $1.7 million (representing 8.96%) of the net loss for the year ended December 31, 1998. F-10 55 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Diluted net income per Unit is similar to the computation of basic net income per Unit above, except that the denominator was increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the years ended December 31, 2000, 1999 and 1998 the denominator was increased by 20,926 Units, 12,141 Units and 45,278 Units, respectively. UNIT OPTION PLAN The Partnership follows the intrinsic value based method of accounting for its stock-based compensation plans (see Note 11). Under this method, the Partnership records no compensation expense for unit options granted when the exercise price of options granted is equal to the fair market value of the Units on the date of grant. COMPREHENSIVE INCOME Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive Income" requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. For the years ended December 31, 2000, 1999, and 1998, the Partnership's comprehensive income (loss) equaled its reported net income (loss). NEW ACCOUNTING PRONOUNCEMENTS Effective January 1, 2001, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments, including certain derivative instruments embedded in other contracts, be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use and designation of the derivative at its inception. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results of the hedged item in the statement of income, and requires the Partnership to formally document, designate and assess the effectiveness of the hedge transaction to receive hedge accounting. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Overall hedge effectiveness is measured at least quarterly. Any changes in the fair value of the derivative instrument resulting from hedge ineffectiveness, as defined by SFAS 133 and measured based on the cumulative changes in the fair value of the derivative instrument and the cumulative changes in the estimated future cash flows of the hedged item, are recognized immediately in earnings. The Partnership has designated its swap agreement as a cash flow hedge. Adoption of SFAS 133 resulted in the recognition of approximately $10 million of derivative liabilities on the Partnership's balance sheet and $10 million of hedging losses included in accumulated other comprehensive income, which is a component of Partners' capital, as the cumulative effect of a change in accounting principle as of January 1, 2001. Amounts were determined as of January 1, 2001 based on the market quote of the Partnership's interest swap agreement. NOTE 3. ACQUISITIONS On July 20, 2000, the Company completed an acquisition of ARCO Pipe Line Company ("ARCO"), a wholly owned subsidiary of Atlantic Richfield Company, for $322.6 million, which included $4.1 million of acquisition related costs. The purchase included ARCO's 50-percent ownership interest in Seaway Crude Pipeline Company ("Seaway"), which owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma. The Partnership assumed ARCO's role as operator of this pipeline. The Company also acquired: (i) ARCO's crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location; (ii) an undivided ownership interest in both the Rancho Pipeline, a crude oil pipeline from West Texas to Houston, and the Basin Pipeline, a crude oil pipeline running from Jal, New Mexico, through Midland to Cushing, both of which are operated by another joint owner; and (iii) the receipt and delivery pipelines known as the West Texas Trunk System, which is located around the Midland terminal. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated statements of income from July 20, 2000. F-11 56 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The following table presents the unaudited pro forma results of the Partnership as though the acquisition of ARCO occurred at the beginning of the respective year (in thousands, except per Unit amounts).

YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 ---------- ----------- Revenues ................................ $3,104,177 $1,959,863 Operating income ........................ 110,138 101,637 Net Income .............................. 75,821 71,650 Basic and diluted net income per Unit ... $ 1.85 $ 1.90

On December 31, 2000, the Company completed an acquisition of certain pipeline assets from DEFS for $91.7 million, which included $0.7 million of acquisition related costs. The purchase included two natural gas liquids pipelines in East Texas. The Panola Pipeline, a pipeline from Carthage, Texas, to Mont Belvieu, Texas, and the San Jacinto Pipeline, a pipeline from Carthage to Longview, Texas. A lease of a condensate pipeline from Carthage to Marshall, Texas, was also assumed. All three pipelines originate at DEFS' East Texas Plant Complex in Panola County, Texas. The acquisition of assets was accounted for under the purchase method of accounting. NOTE 4. RELATED PARTY TRANSACTIONS The Partnership has no employees and is managed by the Company. Pursuant to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to business activities of the Partnership (see Note 1). For the years ended December 31, 2000, 1999 and 1998, direct expenses incurred by the general partner in the amount of $50.4 million, $49.6 million and $38.8 million, respectively, were charged to the Partnership. Substantially all such costs related to payroll and payroll related expenses, which included $3.2 million, $2.9 million and $1.0 million of expense for incentive compensation plans, respectively. For the years ended December 31, 2000, 1999 and 1998, expenses for administrative service and overhead allocated to the Partnership by the general partner (including Duke Energy and its affiliates) amounted to $0.8 million, $2.1 million and $2.7 million, respectively. Such costs incurred by the general partner included general and administrative costs related to business activities of the Partnership. Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado"), a wholly owned subsidiary of the Downstream Segment, and DEFS entered into a twenty-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.5 and $7.3 million for the years ended December 31, 2000 and 1999, respectively, and $5.5 million for the period from April 1, 1998 through December 31, 1998. TEPPCO Colorado and DEFS also entered into a Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9 million and $0.8 million for the years ended December 31, 2000 and 1999, respectively, and $0.7 million for the period from April 1, 1998 through December 31, 1998. Included with certain crude oil assets purchased from DEFS effective November 1, 1998 was the Wilcox NGL Pipeline located along the Texas Gulf Coast. The Wilcox NGL Pipeline transports NGLs for DEFS from two of their processing plants and is currently supported by demand fees that are paid by DEFS through 2005. Such fees totaled $1.1 million for each of the years ended December 31, 2000 and 1999, and $0.2 million for the two months ended December 31, 1998. F-12 57 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 5. EQUITY INVESTMENTS Seaway is a partnership between the Upstream Segment and Phillips Petroleum Company ("Phillips"). The Upstream Segment purchased its 50-percent ownership interest in Seaway on July 20, 2000 (see Note 3). The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway Partnership. From July 20, 2000, through May 2002, the Upstream Segment receives 80% of revenue and expense of Seaway. From June 2002 until May 2006, the Upstream Segment receives 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to the Upstream Segment. The Partnership uses the equity method of accounting for its investment in Seaway. Summarized financial information for Seaway as of December 31, 2000 and for the period from July 20, 2000 through December 31, 2000, is presented below (in thousands): Current assets ........................................... $ 36,883 Noncurrent assets ........................................ 288,191 Current liabilities ...................................... 9,220 Partners capital ......................................... 325,072 Revenues ................................................. 31,989 Net income ............................................... 12,449 The Partnership's investment in Seaway at December 31, 2000, includes an excess investment amount of $26.4 million, net of accumulated amortization of $0.7 million. Such excess investment relates to the Partnership's allocation of the purchase price on July 20, 2000, in excess of its proportionate share of the net assets of Seaway. The excess investment is being amortized using the straight-line method over 20 years. In August 2000, the Partnership announced the execution of definitive agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial Pipeline, LLC ("Centennial"). Centennial will own and operate an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant will own a one-third interest in Centennial. During 2000, the Partnership contributed approximately $5.0 million for its investment in Centennial. Such amount is included in the equity investment balance at December 31, 2000. F-13 58 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 6. INVENTORIES Inventories are valued at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows:

DECEMBER 31, ----------------------- 2000 1999 --------- -------- (IN THOUSANDS) Crude oil ............................. $ 14,635 $ 6,627 Gasolines ............................. 3,795 3,270 Propane ............................... -- 223 Butanes ............................... 267 605 Fuel oil .............................. 82 386 Other products ........................ 2,693 2,301 Materials and supplies ................ 3,312 3,354 -------- -------- Total ............................... $ 24,784 $ 16,766 ======== ========

The costs of inventories did not exceed market values at December 31, 2000 and 1999. NOTE 7. PROPERTY, PLANT AND EQUIPMENT Major categories of property, plant and equipment were as follows:

DECEMBER 31, ----------------------- 2000 1999 ---------- ---------- (IN THOUSANDS) Land and right of way ................................. $ 77,798 $ 54,240 Line pipe and fittings ................................ 739,372 521,688 Storage tanks ......................................... 125,890 112,132 Buildings and improvements ............................ 13,127 8,253 Machinery and equipment ............................... 178,227 155,933 Construction work in progress ......................... 66,456 89,140 ---------- ---------- Total property, plant and equipment ................. $1,200,870 $ 941,386 Less accumulated depreciation and amortization ...... 251,165 220,467 ---------- ---------- Net property, plant and equipment ................. $ 949,705 $ 720,919 ========== ==========

Depreciation expense on property, plant and equipment was $33.0 million, $30.7 million and $25.5 million for the years ended December 31, 2000, 1999 and 1998, respectively. NOTE 8. LONG TERM DEBT SENIOR NOTES On January 27, 1998, the Downstream Segment completed the issuance of $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes"). The 6.45% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028 may be redeemed at any time after January 15, 2008, at the option of the Downstream Segment, in whole or in part, at a premium. Net proceeds from F-14 59 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) the issuance of the Senior Notes totaled approximately $386 million and was used to repay in full the $61.0 million principal amount of the 9.60% Series A First Mortgage Notes, due 2000, and the $265.5 million principal amount of the 10.20% Series B First Mortgage Notes, due 2010. The premium for the early redemption of the First Mortgage Notes totaled $70.1 million. The Partnership recorded an extraordinary charge of $73.5 million during the first quarter of 1998 (including $0.7 million allocated to minority interest), which represents the redemption premium of $70.1 million and unamortized debt issue costs related to the First Mortgage Notes of $3.4 million. The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations of the Downstream Segment and will rank on a parity with all other unsecured and unsubordinated indebtedness of the Downstream Segment. The indenture governing the Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit the Partnership's ability to incur additional indebtedness. At December 31, 2000 and 1999, the estimated fair value of the Senior Notes was approximately $385 million and $356 million, respectively. Market prices for recent transactions and rates currently available to the Partnership for debt with similar terms and maturities were used to estimate fair value. OTHER LONG TERM DEBT AND CREDIT FACILITIES In connection with the purchase of fractionation assets from DEFS as of March 31, 1998, TEPPCO Colorado received a $38 million bank loan. The interest rate on this loan was 6.53%, which was payable quarterly. The original maturity date was April 21, 2001. This loan was refinanced by the Partnership on July 21, 2000, through the credit facility discussed below. On May 17, 1999, the Downstream Segment entered into a five-year $75 million term loan agreement to finance construction of three new pipelines between the Partnership's terminal in Mont Belvieu, Texas and Port Arthur, Texas. This loan was refinanced by the Partnership on July 21, 2000, through the credit facility discussed below. On May 17, 1999, the Downstream Segment entered into a five-year $25 million revolving credit agreement and the Upstream Segment entered into a three-year $30 million revolving credit agreement. Both of the credit facilities were terminated in connection with the refinancing on July 21, 2000 discussed below. The Downstream Segment did not make any borrowings under this revolving credit facility. The Upstream Segment had a $3 million principal amount outstanding under its revolving credit agreement as of July 21, 2000. On July 14, 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility. On July 21, 2000, the Partnership borrowed $75 million under the term loan and $340 million under the revolving credit facility. The funds were used to finance the acquisition of the ARCO assets (see Note 3) and to refinance existing credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. The revolving facility has a three year maturity. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreements contain restrictive financial covenants that require the Partnership to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. At December 31, 2000, $446 million was outstanding under the revolving credit facility at a weighted average interest rate of 8.23%. At December 31, 2000, the carrying value of the revolving credit facility approximated its fair value. F-15 60 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) On July 21, 2000, the Partnership entered into a three year swap agreement to hedge its exposure on the variable rate credit facilities. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership will pay a fixed rate of interest of 7.17% and will receive a floating rate based on a three month USD LIBOR rate. At December 31, 2000, the estimated fair value of the swap agreement was a loss of approximately $10 million. NOTE 9. CONCENTRATIONS OF CREDIT RISK The Partnership's primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. The Partnership has a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership's overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. The Partnership's customers' historical and future credit positions are thoroughly analyzed prior to extending credit. The Partnership manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees. NOTE 10. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH The Partnership makes quarterly cash distributions of all of its Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the general partner in its sole discretion. Pursuant to the Partnership Agreements, the Company receives incremental incentive cash distributions on the portion that cash distributions on a per Unit basis exceed certain target thresholds as follows:

GENERAL UNITHOLDERS PARTNER ----------- ------- Quarterly Cash Distribution per Unit: Up to Minimum Quarterly Distribution ($0.275 per Unit) ................. 98% 2% First Target - $0.276 per Unit up to $0.325 per Unit ................... 85% 15% Second Target - $0.326 per Unit up to $0.45 per Unit ................... 75% 25% Over Second Target - Cash distributions greater than $0.45 per Unit .... 50% 50%

The following table reflects the allocation of total distributions paid for the years ended December 31, 2000, 1999 and 1998 (in thousands, except per Unit amounts).

YEARS ENDED DECEMBER 31, --------------------------------- 2000 1999 1998 --------- --------- --------- Limited Partner Units ......................... $ 59,943 $ 53,650 $ 50,750 1% General Partner Interest ................... 685 609 513 General Partner Incentive ..................... 12,938 7,650 4,938 --------- --------- --------- Total Partners' Capital Cash Distributions .. 73,566 61,909 56,201 Class B Units ................................. 7,833 6,651 -- Minority Interest ............................. 832 699 573 --------- --------- --------- Total Cash Distributions Paid ............... $ 82,231 $ 69,259 $ 56,774 ========= ========= ========= Total Cash Distributions Paid Per Unit ........ $ 2.00 $ 1.85 $ 1.75 ========= ========= =========

On February 2, 2001, the Partnership paid a cash distribution of $0.525 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2000. The fourth quarter 2000 cash distribution totaled $24.0 million. F-16 61 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 11. UNIT OPTION PLAN During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan ("1994 LTIP"). The 1994 LTIP provides key employees with an incentive award whereby a participant is granted an option to purchase Limited Partner Units together with a stipulated number of Performance Units. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted. Each Performance Unit creates a credit to a participant's Performance Unit account when earnings exceed a threshold. When earnings for a calendar year (exclusive of certain special items) exceed the threshold, the excess amount is credited to the participant's Performance Unit account. The balance in the account may be used to exercise Limited Partner Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Under the agreement for such Limited Partner Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. Options may also be exercised by normal means once vesting requirements are met. A summary of Performance Units and Limited Partner Unit options granted under the terms of the 1994 LTIP is presented below:

PERFORMANCE EARNINGS EXPIRATION UNITS THRESHOLD YEAR ----------- --------- ----------- Performance Unit Grants: 1994 ........................................... 80,000 $ 1.00 2006 1995 ........................................... 70,000 $ 1.25 2007 1997 ........................................... 11,000 $ 1.875 2009

OPTIONS OPTIONS EXERCISE OUTSTANDING EXERCISABLE RANGE ----------- ------------ --------------- Limited Partner Unit Options: Outstanding at December 31, 1997 .............. 92,528 58,098 $13.81 - $14.34 Granted ..................................... 111,000 -- $25.69 Became exercisable .......................... -- 26,993 $13.81 - $21.66 Exercised ................................... (12,732) (12,732) $13.81 - $14.34 --------- --------- Outstanding at December 31, 1998 .............. 190,796 72,359 $13.81 - $21.66 Granted ..................................... 162,000 -- $25.25 Became exercisable .......................... -- 40,737 $21.66 - $25.69 Exercised ................................... (14,000) (14,000) $13.81 - $14.34 --------- --------- Outstanding at December 31, 1999 .............. 338,796 99,096 $13.81 - $25.69 Forfeited ................................... (28,000) (4,000) $25.25 - $25.69 Became exercisable .......................... -- 85,365 $21.66 - $25.69 Exercised ................................... (19,932) (19,932) $13.81 - $14.34 --------- --------- Outstanding at December 31, 2000 .............. 290,864 160,529 $13.81 - $25.69 ========= =========

As discussed in Note 2, the Partnership uses the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of the Partnership's Limited Partner Units on the date of grant. Accordingly, no compensation was recognized at the date of grant. Had compensation expense been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," compensation expense related to option grants would have totaled $93,771, $226,152 and $202,634 during 1998, 1999 and 2000, respectively. The disclosures as required by SFAS 123 are not representative of the effects on proforma net income for future years as options vest over several years and additional awards may be granted in subsequent years. F-17 62 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of 1999 and 1998 option grants were determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were:

1999 1998 ------- ------- Risk-free interest rate ...................... 4.7% 5.5% Dividend yield ............................... 7.6% 7.8% Unit price volatility ........................ 23% 18% Expected option lives ........................ 6 years 6 years

NOTE 12. LEASES The Partnership utilizes leased assets in several areas of its operations. Total rental expense during 2000, 1999 and 1998 was $10.4 million, $8.7 million and $4.8 million, respectively. The minimum rental payments under the Partnership's various operating leases for the years 2001 through 2005 are $8.7 million, $7.0 million, $6.3 million, $5.6 million and $5.4 million, respectively. Thereafter, payments aggregate $4.6 million through 2007. NOTE 13. EMPLOYEE BENEFITS RETIREMENT PLANS Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company's employees participated in the Duke Energy Retirement Cash Balance Plan, which is a noncontributory, trustee-administered pension plan. Effective January 1, 1999 the benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit based upon pay credits and current interest credits. The pay credits are based on a participant's salary, age, and service. Prior to January 1, 1999, the benefit formula for all eligible employees was a final average pay formula. In addition, certain executive officers participated in the Duke Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy Executive Cash Balance Plan was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan ("Retirement Cash Balance Plan") and the TEPPCO Supplemental Benefit Plan ("Supplemental Benefit Plan"). The benefits and provisions of these plans are substantially identical to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan previously in effect prior to April 1, 2000. The components of net pension benefits costs for the years ended December 31, 2000, 1999 and 1998 were as follows (in thousands):

2000 1999 1998 ------- ------- ------- Service cost benefit earned during the year .... $ 2,054 $ 1,651 $ 1,699 Interest cost on projected benefit obligation .. 782 2,666 2,041 Expected return on plan assets ................. (663) (2,243) (1,555) Amortization of prior service cost ............. -- 2 (27) Amortization of net transition (asset) liability 4 15 (5) Recognized net actuarial loss .................. -- 285 -- Settlement gain ................................ -- -- (554) ------- ------- ------- Net pension benefits costs ................... $ 2,177 $ 2,376 $ 1,599 ======= ======= =======

F-18 63 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The assumptions affecting pension expense include:

2000 1999 1998 ------- ------- ------- Discount rate ...................................... 7.50% 7.50% 6.75% Salary increase .................................... 4.50% 4.50% 4.67% Expected long-term rate of return on plan assets.... 9.25% 9.25% 9.25%

Duke Energy also sponsors an employee savings plan which covers substantially all employees. Plan contributions on behalf of the Company of $2.2 million, $2.2 million and $1.4 million were expensed in 2000, 1999 and 1998, respectively. OTHER POSTRETIREMENT BENEFITS Prior to April 1, 2000, the Company's employees were provided with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees became eligible for these benefits if they had met certain age and service requirements at retirement, as defined in the plans. As part of the change in ownership, the Company is no longer responsible for the liability associated with these plans. The components of net postretirement benefits cost for the years ended December 31, 2000, 1999 and 1998 were as follows (in thousands):

2000 1999 1998 ----- ----- ------- Service cost benefit earned during the year .................. $ 39 $ 172 $ 439 Interest cost on accumulated postretirement benefit obligation 134 500 796 Expected return on plan assets ............................... (85) (299) (240) Amortization of prior service cost ........................... (96) (384) 3 Amortization of net transition liability ..................... 54 217 202 Recognized net actuarial loss ................................ -- -- 173 ----- ----- ------- Net postretirement benefits costs .......................... $ 46 $ 206 $ 1,373 ===== ===== =======

The assumptions affecting postretirement benefits expense include:

2000 1999 1998 ------- ------- ------- Discount rate ...................................... 7.50% 7.50% 6.75% Salary increase .................................... 4.50% 4.50% 4.67% Expected long-term rate of return on 401(h) assets.. 9.25% 9.25% 9.25% Expected long-term rate of return on RLR assets .... 6.75% 6.75% 6.75% Expected long-term rate of return on VEBA assets ... 9.25% 9.25% 9.25% Assumed tax rate ................................... 39.60% 39.60% 39.60%

NOTE 14. CONTINGENCIES TOXIC TORT LITIGATION - SEYMOUR, INDIANA In the fall of 1999 and on December 1, 2000, the Company and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, in Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the Company and F-19 64 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. In both cases plaintiffs contend, among other things, that the Company and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their Complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. The Company has filed an Answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The Partnership cannot estimate the loss, if any, associated with these pending lawsuits. The Partnership is involved in various other claims and legal proceedings incidental to its business. In the opinion of management, these claims and legal proceedings will not have a material adverse effect on the Partnership's consolidated financial position, results of operations or cash flows. The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the pipeline system, could result in substantial costs and liabilities to the Partnership. The Partnership does not anticipate that changes in environmental laws and regulations will have a material adverse effect on its financial position, results of operations or cash flows in the near term. The Partnership and the Indiana Department of Environmental Management ("IDEM") have entered into an Agreed Order that will ultimately result in a remediation program for any on-site and off-site groundwater contamination attributable to the Partnership's operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership's proposed remediation program, has been approved by IDEM. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision has been issued, the Partnership will enter into an Agreed Order for the continued operation and maintenance of the program. The Partnership has accrued $0.6 million at December 31, 2000 for future costs of the remediation program for the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse impact on the Partnership's financial condition, results of operations or liquidity. The Partnership received a compliance order from the Louisiana Department of Environmental Quality ("DEQ") during 1994 relative to potential environmental contamination at the Partnership's Arcadia, Louisiana facility, which may be attributable to the operations of the Partnership and adjacent petroleum terminals of other companies. The Partnership and all adjacent terminals have been assigned to the Groundwater Division of DEQ, in which a consolidated plan will be developed. The Partnership has finalized a negotiated Compliance Order with DEQ that will allow the Partnership to continue with a remediation plan similar to the one previously agreed to by DEQ and implemented by the Company. In the opinion of the General Partner, the completion of the remediation program being proposed by the Partnership will not have a future material adverse impact on the Partnership. Rates of interstate oil pipeline companies are currently regulated by the FERC, primarily through an index methodology, whereby a pipeline company is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% ("PPI Index"). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings ("Market Based Rates") or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). F-20 65 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) On May 11, 1999, the Downstream Segment filed an application with the FERC requesting permission to charge market-based rates for substantially all refined products transportation tariffs. Along with its application for market-based rates, the Downstream Segment filed a petition for waiver pending the FERC's determination on its application for market-based rates, of the requirements that would otherwise have been imposed by the FERC's regulations requiring the Downstream Segment to reduce its rates in conformity with the PPI Index. On June 30, 1999, the FERC granted the waiver stating that it was temporary in nature and that the Downstream Segment would be required to make refunds, with interest, of all amounts collected under rates in excess of the PPI Index ceiling level after July 1, 1999, if the Downstream Segment's application for market-based rates was ultimately denied. As a result of the refund obligation potential, the Partnership has deferred all revenue recognition of rates charged in excess of the PPI Index. On December 31, 2000, the amount deferred for possible rate refund, including interest totaled approximately $2.3 million. On July 31, 2000, the FERC issued an order granting the Downstream Segment market-based rates in certain markets and set for hearing the Downstream Segment's application for market-based rates in the Little Rock, Arkansas; Shreveport-Arcadia, Louisiana; Cincinnati-Dayton, Ohio and Memphis, Tennessee destination markets and the Shreveport, Louisiana origin market. The FERC also directed the FERC trial staff to convene a conference to explore the facts and issues regarding the Western Gulf Coast origin market. After the matter was set for hearing, the Downstream Segment and the protesting shippers entered into a settlement agreement resolving their respective differences. On January 9, 2001, the presiding Administrative Law Judge assigned to the hearing determined that the offer of settlement provided resolution of issues set for hearing in the Downstream Segment pending case in a fair and reasonable manner and in the public interest and certified the offer of settlement and recommended it to the FERC for approval. The certification of the settlement is currently before the FERC. The Partnership believes that the Administrative Law Judge's decision in this matter will be upheld by the FERC. The settlement, if it is approved by FERC, will require the Downstream Segment to withdraw the application for market-based rates to the Little Rock, Arkansas destination market and the Arcadia, Louisiana destination in the Shreveport-Arcadia, Louisiana destination market. The Downstream Segment also has agreed to recalculate rates to these destination markets to conform with the PPI Index from July 1, 1999 and make appropriate refunds. The refund obligation under the proposed settlement as of December 31, 2000 would be $0.8 million. On October 16, 2000 the Partnership received a settlement notice from ARCO for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of the ARCO assets. A large portion of the requested adjustment relates to ARCO's indemnity for payment of accrued income taxes. The Partnership is disputing a substantial portion of the adjustments. The Partnership does not believe that payment of any amount ultimately determined would have a material adverse impact on the Partnership's financial condition and results of operations. Substantially all of the petroleum products transported and stored by the Partnership are owned by the Partnership's customers. At December 31, 2000, the Partnership had approximately 16.4 million barrels of products in its custody owned by customers. The Partnership is obligated for the transportation, storage and delivery of such products on behalf of its customers. The Partnership maintains insurance adequate to cover product losses through circumstances beyond its control. NOTE 15. SEGMENT DATA The Partnership operates in two segments: refined products and LPGs transportation, which operates through the Downstream Segment; and crude oil and NGLs transportation and marketing, which operates through the Upstream Segment. F-21 66 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Operations of the Downstream Segment consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas complex; sale of product inventory; fractionation of natural gas liquids and other ancillary services. The Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. The Partnership owns and operates a pipeline system extending from southeast Texas through the central and midwestern United States to the northeastern United States. The Upstream Segment gathers, stores, transports and markets crude oil principally in Oklahoma, Texas and the Rocky Mountain region; operates two trunkline NGL pipelines in South Texas; and distributes lube oils and specialty chemicals to industrial and commercial accounts. Effective with the purchase of assets from ARCO (see Note 3), the operations of the Upstream Segment also include the Partnership's 50% ownership interest in Seaway, other crude oil transportation pipelines in West Texas, undivided joint interest ownership of two crude oil pipelines systems in Texas and Oklahoma, and other terminaling and documentation services. The accounting policies of the segments are the same as those described in the summary of significant accounting policies discussed above (see Note 2). The crude oil and NGLs transportation and marketing segment was added by acquisition, effective November 1, 1998. The acquisition was accounted for under the purchase method of accounting. The below table includes financial information by business segment for the years ended December 31, 2000, 1999 and 1998.

DOWNSTREAM UPSTREAM SEGMENT SEGMENT CONSOLIDATED ------------- ------------- ------------- 2000 (IN THOUSANDS) ---- Unaffiliated revenues ..................... $ 236,687 $ 2,851,254 $ 3,087,941 Operating expenses, including power ....... 118,945 2,825,808 2,944,753 Depreciation and amortization expense ..... 27,743 7,420 35,163 ------------- ------------- ------------- Operating income ........................ 89,999 18,026 108,025 Interest expense, net ..................... (30,573) (13,850) (44,423) Equity earnings -- Seaway ................. -- 12,214 12,214 Other income, net ......................... 1,269 291 1,560 ------------- ------------- ------------- Net income ................................ $ 60,695 $ 16,681 $ 77,376 ============= ============= ============= Total assets .............................. $ 755,508 $ 867,302 $ 1,622,810 Accounts receivable, trade ................ 26,182 277,212 303,394 Accounts payable and accrued liabilities .. $ 12,177 $ 281,543 $ 293,720

DOWNSTREAM UPSTREAM SEGMENT SEGMENT CONSOLIDATED ------------- ------------- ------------- 1999 (IN THOUSANDS) ---- Unaffiliated revenues ..................... $ 230,270 $ 1,704,613 $ 1,934,883 Operating expenses, including power ....... 113,768 1,688,369 1,802,137 Depreciation and amortization expense ..... 27,109 5,547 32,656 ------------- ------------- ------------- Operating income ........................ 89,393 10,697 100,090 Interest expense, net ..................... (29,212) (218) (29,430) Other income, net ......................... 1,046 414 1,460 ------------- ------------- ------------- Net income ................................ $ 61,227 $ 10,893 $ 72,120 ============= ============= ============= Total assets .............................. $ 721,797 $ 319,576 $ 1,041,373 Accounts receivable, trade ................ 22,358 183,408 205,766 Accounts payable and accrued liabilities .. $ 7,412 $ 194,248 $ 201,660

F-22 67 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

DOWNSTREAM UPSTREAM SEGMENT SEGMENT CONSOLIDATED ------------- ------------- ------------- 1998 (IN THOUSANDS) ---- Unaffiliated revenues ..................... $ 211,783 $ 217,855 $ 429,638 Operating expenses, including power ....... 107,102 215,632 322,734 Depreciation and amortization expense ..... 26,040 898 26,938 ------------- ------------- ------------- Operating income ........................ 78,641 1,325 79,966 Interest expense, net ..................... (28,982) (7) (28,989) Other income, net ......................... 2,343 21 2,364 ------------- ------------- ------------- Income before extraordinary item ........ 52,002 1,339 53,341 ============= ============= ============= Total assets .............................. $ 694,636 $ 222,283 $ 916,919 Accounts receivable, trade ................ 17,740 95,801 113,541 Accounts payable and accrued liabilities .. $ 8,513 $ 109,420 $ 117,933

NOTE 16. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) 2000 (1) ---- Operating revenues .................................. $ 750,692 $ 747,704 $ 749,898 $ 839,647 Operating income .................................... 30,767 20,151 21,907 35,200 Net income .......................................... $ 23,881 $ 13,570 $ 17,189 $ 22,736 Basic and diluted income per Limited Partner and Class B Unit (1) .................................. $ 0.60 $ 0.35 $ 0.41 $ 0.53 1999 Operating revenues .................................. $ 286,090 $ 455,351 $ 554,368 $ 639,074 Operating income .................................... 30,469 21,016 20,406 28,199 Net income .......................................... 23,372 14,029 13,370 21,349 Basic and diluted income per Limited Partner and Class B Unit ................................... $ 0.64 $ 0.38 $ 0.32 $ 0.57

---------- (1) Per Unit calculation includes 3,700,000 Limited Partner Units issued on October 25, 2000. F-23 68 Index To Exhibits

Exhibit Number Description ------- ----------- 3.1 Certificate of Limited Partnership of the Partnership (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 3.2 Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 3.3 Second Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated November 30, 1998 (Filed as Exhibit 3.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 3.4 Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated July 21, 1998 and incorporated herein by reference). 3.5 Agreement of Limited Partnership of TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 3.5 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 4.1 Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 4.2 Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership's Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference). 4.3 Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.1 Assignment and Assumption Agreement, dated March 24, 1988, between Texas Eastern Transmission Corporation and the Company (Filed as Exhibit 10.8 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). +10.2 Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference). 10.3 Agreement Regarding Environmental Indemnities and Certain Assets (Filed as Exhibit 10.5 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). +10.4 Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference). +10.5 Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). +10.6 Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference). +10.7 Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.8 Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.9 Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). +10.10 Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference). +10.11 Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).

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Exhibit Number Description ------- ----------- +10.12 Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference). 10.13 Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 10.14 Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.15 Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.16 Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). +10.17 Form of Employment Agreement between the Company and Ernest P. Hagan, Thomas R. Harper, David L. Langley, Charles H. Leonard and James C. Ruth, dated December 1, 1998 (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 10.18 Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.19 Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.20 Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). +10.21 Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). +10.22 Form of Employment and Non-Compete Agreement between the Company and Samuel N. Brown, J. Michael Cockrell, and Sharon S. Stratton effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.23 Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.24 Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). +10.25 Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

70

Exhibit Number Description ------- ----------- 10.26 Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference). 10.27 Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipeline Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference). +*10.28 Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, Effective January 1, 2000. +*10.29 TEPPCO Supplemental Benefits Plan, effective April 1, 2000. *12.1 Statement of Computation of Ratio of Earnings to Fixed Charges. 22.1 Subsidiaries of the Partnership (Filed as Exhibit 22.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). *23 Consent of KPMG LLP. *24 Powers of Attorney.

------------------- * Filed herewith. + A management contract or compensation plan or arrangement.