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                       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, 1999

                         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, 2000 the aggregate market value of the registrant's
Limited Partner Units held by non-affiliates was $611,739,230, which was
computed using the average of the high and low sales prices of the Limited
Partner Units on March 6, 2000.

         Limited Partner Units outstanding as of March 6, 2000: 29,000,000.

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                                TABLE OF CONTENTS

                                     PART I

<TABLE>
<S>            <C>                                                                                          <C>
ITEMS  1.      Business and Properties.......................................................................1
   AND  2.
ITEM    3.     Legal Proceedings............................................................................12
ITEM    4.     Submission of Matters to a Vote of Security Holders..........................................13

                                     PART II

ITEM    5.     Market for Registrant's Units and Related Unitholder Matters.................................13
ITEM    6.     Selected Financial Data......................................................................15
ITEM    7.     Management's Discussion and Analysis of Financial Condition and Results of Operations........16
ITEM   7A.     Quantitative and Qualitative Disclosures About Market Risks..................................26
ITEM    8.     Financial Statements and Supplementary Data..................................................27
ITEM    9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.........27

                                    PART III

ITEM   10.     Directors and Executive Officers of the Registrant...........................................27
ITEM   11.     Executive Compensation.......................................................................29
ITEM   12.     Security Ownership of Certain Beneficial Owners and Management...............................35
ITEM   13.     Certain Relationships and Related Transactions...............................................35

                                     PART IV

ITEM   14.     Exhibits, Financial Statement Schedules and Reports on Form 8-K..............................36
</TABLE>




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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. Texas Eastern Products Pipeline Company (the "Company" or
"General Partner") owns a 1% general partner interest in the Partnership and 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 industry segments - refined products
and liquefied petroleum gases ("LPGs") transportation; and crude oil and natural
gas liquids ("NGLs") transportation and marketing. 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.

         In June 1997, Duke Energy Corporation ("Duke Energy") was formed
through a merger between PanEnergy Corp ("PanEnergy") and Duke Power Company.
The Company, previously a wholly-owned subsidiary of PanEnergy, became an
indirect wholly-owned subsidiary of Duke Energy on the date of the merger.

         At December 31, 1999, the Partnership had outstanding 29,000,000
Limited Partnership Units and 3,916,547 Class B Limited Partnership 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 29,000,000 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, 1999. Collectively, the Limited Partner Units and Class
B Units are referred to as "Units." 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
from November 1, 1998.

REFINED PRODUCTS AND LPGS TRANSPORTATION

      Operations

         The operations of the refined products and LPGs transportation segment
are conducted through the Products OLP. The Products OLP 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; sale of
product inventory; fractionation of natural gas liquids and other ancillary
services.

         The Products OLP is one of the largest pipeline common carriers of
refined petroleum products and LPGs in the United States. The Products OLP owns
and operates an approximate 4,300-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 Products OLP also owns two marine receiving
terminals,




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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 Federal Energy Regulatory
Commission ("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 Partnership'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 Products OLP's business depends in large part on (i) the level of
demand for refined petroleum products and LPGs in the geographic locations
served by it and (ii) 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.

     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.



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<PAGE>   5

         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:

<TABLE>
<CAPTION>
                                                                          PRODUCT DELIVERIES (MMBBLS)
                                                                           YEARS ENDED DECEMBER 31,
                                                                     -------------------------------------
                                                                       1999          1998          1997
                                                                     ---------     ---------     ---------
<S>                                                                 <C>            <C>            <C>
Refined Products Transportation:
      Central (1)..................................................       67.7          71.5          69.4
      Midwest (2)..................................................       37.9          34.8          29.9
      Ohio and Kentucky............................................       27.0          24.2          20.7
                                                                     ---------     ---------     ---------
          Subtotal.................................................      132.6         130.5         120.0
                                                                     ---------     ---------     ---------
LPGs Mainline Transportation:
      Central, Midwest and Kentucky (1)(2).........................       22.9          18.5          23.8
      Ohio and Northeast (3).......................................       14.7          13.5          18.2
                                                                     ---------     ---------     ---------
          Subtotal.................................................       37.6          32.0          42.0
                                                                     ---------     ---------     ---------
Mont Belvieu Operations:
      LPGs.........................................................       28.5          25.1          27.8
                                                                     ---------     ---------     ---------
          Total Product Deliveries.................................      198.7         187.6         189.8
                                                                     =========     =========     =========
</TABLE>
---------------------

(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.



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<PAGE>   6



         Refined products and LPGs deliveries over the last three years were as
follows:


<TABLE>
<CAPTION>
                                                PRODUCT DELIVERIES (MMBbls)
                                                 YEARS ENDED DECEMBER 31,
                                           ------------------------------------
                                              1999         1998         1997
                                           ----------   ----------   ----------
<S>                                        <C>          <C>          <C>
Refined Products Transportation:
      Gasoline.......................            71.6         74.0         66.8
      Jet Fuels......................            26.9         23.8         22.4
      Middle Distillates (1).........            28.4         26.1         24.0
      MTBE/Toluene...................             5.7          6.6          6.8
                                           ----------   ----------   ----------
          Subtotal...................           132.6        130.5        120.0
                                           ----------   ----------   ----------
LPGs Mainline Transportation:
      Propane........................            30.8         25.5         34.7
      Butanes........................             6.8          6.5          7.3
                                           ----------   ----------   ----------
          Subtotal...................            37.6         32.0         42.0
                                           ----------   ----------   ----------
Mont Belvieu Operations:
      LPGs...........................            28.5         25.1         27.8
                                           ----------   ----------   ----------
          Total Product Deliveries...           198.7        187.6        189.8
                                           ==========   ==========   ==========
</TABLE>

(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 to Partnership-owned terminals,
connecting pipelines and customer-owned terminals. 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.

         Effective January 1, 1996, the Clean Air Act Amendments of 1990
mandated the use of reformulated gasolines in nine metropolitan areas of the
United States, including the Houston and Chicago areas served by the System. A
portion of the reformulated and oxygenated gasolines includes methyl tertiary
butyl ether ("MTBE") as a major blending component. Effective July 1, 1999, the
Products OLP canceled its tariff for deliveries of MTBE into the Chicago market
area due to 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. The
Partnership continues to transport MTBE to its marine terminal near Beaumont,
Texas.

     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 Products OLP'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




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unloading and truck loading facilities. Although the terminal is operated by the
Products OLP, the utilization of the terminal is committed by contract to a
major propane marketer through 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 Products OLP has approximately 33 million barrels of LPGs storage
capacity, including storage capacity leased to outside parties, at the Mont
Belvieu complex. The Products OLP'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.

     Product Sales and Other

         The Products OLP also derives revenue from the sale of product
inventory, terminaling activities and other ancillary services associated with
the transportation and storage of refined petroleum products and LPGs. Since
March 31, 1998, operations also include 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 (i)
retail service stations, (ii) truck stops, (iii) agricultural enterprises, (iv)
refineries, and (v) military and commercial jet fuel users.

         Propane shippers 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, 1999, the Products OLP had approximately 140 customers.
Transportation revenues (and percentage of total revenues) attributable to the
top 10 shippers were $105 million (46%), $90 million (42%), and $85 million
(38%) for the years ended December 31, 1999, 1998 and 1997, respectively. During
1999 and 1998, billings to Marathon Ashland, LLC, a major integrated oil
company, accounted for approximately 10% of the Products OLP's revenues. During
1997, no single customer accounted for 10% or greater of the Products OLP's
total 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


                                       5
<PAGE>   8

proximity to end users. The General Partner believes the Products OLP 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, Canada, compete with propane moved
on the Pipeline System.

CRUDE OIL AND NGLS TRANSPORTATION AND MARKETING

      Operations

         The Crude Oil OLP, through its wholly-owned subsidiary TEPPCO Crude
Oil, LLC ("TCO"), gathers, stores, transports and markets crude oil, NGLs, lube
oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky
Mountain region. The assets of TCO were acquired by the Partnership from a
subsidiary of Duke Energy, on November 1, 1998.

         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. TCO's margins from
its gathering, transportation and marketing operations are generated by the
difference between the price of crude oil at the point of purchase and the price
of crude oil at the point of sale, minus the associated costs of aggregation and
transportation.

         Generally, as the Crude Oil OLP 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. 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, 1999.

         Volume information for the year ended December 31, 1999 and the two
month period ended December 31, 1998 is presented below:

<TABLE>
<CAPTION>
                                                                   TWO MONTHS
                                                  YEAR ENDED          ENDED
                                                 DECEMBER 31,     DECEMBER 31,
                                                     1999             1998
                                                --------------   ---------------
<S>                                             <C>              <C>
Barrels per day:
           Crude oil transportation.........            91,143            90,963
           Crude oil marketing..............           263,703           278,176
           NGL transportation...............            12,548            11,919

Lubricants and chemicals (total gallons):...         8,891,056         1,140,000
</TABLE>



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<PAGE>   9

      Properties

         The Crude Oil OLP is based in Oklahoma City. It operates crude oil
gathering and trunkline pipelines principally in Oklahoma and Texas, and two NGL
trunkline pipelines in South Texas. The Crude Oil OLP'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 975 miles of
pipeline and 780,000 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 670
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. Other
crude oil assets, located primarily in Texas and Louisiana, consist of 310 miles
of pipeline and 240,000 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 5,000 barrels per day and currently transports NGLs for Duke Energy
Field Services ("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.

         Through its wholly-owned subsidiary Lubrication Services, LLC ("LSI"),
the Crude Oil OLP 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

         The Crude Oil OLP 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

         The Crude Oil OLP'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 the Crude Oil OLP's business. The Crude
Oil OLP manages its exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures. The Crude Oil OLP utilizes
letters of credit and guarantees for certain of its receivables.

         The Crude Oil OLP's credit standing is a major consideration for
parties with whom the Crude Oil OLP does business. In connection with the Crude
Oil OLP's acquisition of this business, Duke Capital, an affiliate of




                                       7
<PAGE>   10

Duke Energy, agreed to provide up to $100 million of guarantee credit to the
Crude Oil OLP 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.

CAPITAL EXPENDITURES

         Capital expenditures by the Partnership totaled $77.4 million for the
year ended December 31, 1999. This amount includes capitalized interest of $2.1
million. Approximately $43.8 million of spending was used for on-going
construction of three new pipelines between the Partnership's terminal in Mont
Belvieu, Texas and Port Arthur, Texas. The project includes three 12-inch
diameter common-carrier pipelines and associated facilities. Each pipeline will
be approximately 70 miles in length. Upon completion, the new pipelines will
transport ethylene, propylene and natural gasoline. The cost of this project is
expected to total approximately $75 million. The Partnership has entered into an
agreement for turnkey construction of the pipelines and related facilities and
has separately entered into agreements for guaranteed throughput commitments.
The anticipated commencement date is the fourth quarter of 2000. Of the
remaining capital expenditures during 1999, $23.4 million related to the
Products OLP and $8.1 million related to the Crude Oil OLP. Approximately $24.9
million of capital expenditures related to life-cycle replacements and upgrading
current facilities, and approximately $6.6 million of capital expenditures
related to other pipeline expansion projects and revenue-generating projects.

         The Partnership estimates that capital expenditures for 2000 will be
approximately $82 million (which includes $4 million of capitalized interest).
Approximately $31 million is expected to be used to complete construction of the
three new pipelines between Mont Belvieu and Port Arthur and approximately $10
million will be used to replace seven pipelines under the Houston Ship Channel
as required by the United States Army Corp of Engineers for the deepening of the
channel. Approximately $14 million of the remaining amount is expected to be
used for the Products OLP and $23 million is expected to be used for the Crude
Oil OLP. Substantially all remaining expenditures related to the Products OLP
are expected to be used for life-cycle replacements and upgrading current
facilities. Approximately $17 million of planned expenditures of the Crude Oil
OLP are expected to be used in revenue-generating projects, with the remaining
$6 million being 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").



                                       8
<PAGE>   11

         In May 1999, the Products OLP filed an application with the FERC to
charge Market Based Rates for substantially all refined products transportation
tariffs. Such application is currently under review by the FERC. The FERC
approved a request of the Products OLP waiving the requirement to adjust refined
products transportation tariffs pursuant to the PPI Index while its Market Based
Rates application is under review. Under the PPI Index, refined products
transportation rates in effect on June 30, 1999 would have been reduced by
approximately 1.83% effective July 1, 1999. If any portion of the Market Based
Rates application is denied by the FERC, the Products OLP has agreed to refund,
with interest, amounts collected after June 30, 1999, under the tariff rates in
excess of the PPI Index. As a result of the refund obligation potential, the
Partnership has deferred all revenue recognition of rates charged in excess of
the PPI Index. At December 31, 1999, the amount deferred for possible rate
refunds, including interest, totaled approximately $0.8 million.

         In July 1999, certain shippers filed protests with the FERC on the
Products OLP's application for Market Based Rates in four destination markets.
The Partnership believes it will prevail in a competitive market determination
in those destination markets under protest.

         Effective July 1, 1999, the Products OLP 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 effect 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.



                                       9
<PAGE>   12

         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.

         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 all 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 eight facilities.

     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 defined as hazardous waste. Certain wastewater and other wastes
generated from the Partnership's business activities



                                       10
<PAGE>   13

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 $0.8 million at December 31, 1999 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.



                                       11
<PAGE>   14

SAFETY REGULATION

         The Partnership is subject to regulation by the United States
Department of Transportation ("DOT") under the Hazardous Liquid Pipeline Safety
Act of 1979 ("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 Partnership believes it is in material compliance with HLPSA requirements.

         The Partnership is also subject to the requirements of the federal
Occupational Safety and Health Act ("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.

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, 1999, the General Partner had 757
employees.

ITEM 3. LEGAL PROCEEDINGS

TOXIC TORT LITIGATION - SEYMOUR, INDIANA

         In the fall of 1999, the Company and the Partnership became involved in
a lawsuit 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), plaintiffs contend, among other things,
that the Company and other defendants stored and disposed of toxic and hazardous
substances and hazardous wastes in such a manner which caused the materials to
be released into the air, soil and water. They further contend that such release
caused damages to the plaintiffs. In their Complaint, 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. Furthermore, the plaintiffs are seeking compensatory, punitive and
treble damages. The Company has filed an Answer to the Complaint, denying the
allegations, as well as various other motions. This case




                                       12
<PAGE>   15

is in the early stages of discovery and is not covered by insurance. The Company
is defending itself vigorously against this lawsuit. The Partnership cannot
estimate the loss, if any, associated with this pending lawsuit.

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 financial condition, operations or
cash flows.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         NONE

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS

         On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All references to the number of Units and per Unit amounts have been adjusted to
reflect the two-for-one split for all periods presented.

         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 1999 and 1998, respectively, as reported
in The Wall Street Journal, were as follows:

<TABLE>
<CAPTION>
                                                                       1999                              1998
                                                           ----------------------------      ----------------------------
QUARTER                                                       HIGH              LOW             HIGH              LOW
-------                                                    ----------        ----------      ----------        ----------
<S>                                                        <C>               <C>             <C>               <C>
First..................................................    $  26.1875        $  22.3750      $  30.3750        $  25.0000
Second.................................................       28.2500           22.9375         30.6875           25.5000
Third..................................................       26.4375           20.0000         29.4375           25.5000
Fourth.................................................       23.8750           17.1250         30.5625           23.2500
</TABLE>

         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, 2000 to be approximately
21,000.

         The quarterly cash distributions applicable to 1998 and 1999 were as
follows:

<TABLE>
<CAPTION>
                                                                                                         AMOUNT
RECORD DATE                                        PAYMENT DATE                                         PER UNIT
-----------                                        ------------                                         --------

<S>                                                <C>                                                  <C>
April 30, 1998.................................    May 8, 1998......................................    $  0.425
July 31, 1998..................................    August 7, 1998...................................       0.450
October 30, 1998...............................    November 6, 1998.................................       0.450
January 29, 1999...............................    February 5, 1999.................................       0.450

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
</TABLE>


                                       13
<PAGE>   16

         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.























                                       14
<PAGE>   17

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."

<TABLE>
<CAPTION>
                                                                                       YEARS ENDED DECEMBER 31,
                                                              ---------------------------------------------------------------
                                                                 1999        1998 (1)       1997         1996         1995
                                                              ----------     --------     ---------    ---------    ---------
                                                                               (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S>                                                             <C>            <C>        <C>            <C>             <C>
INCOME STATEMENT DATA:
   Operating revenues:
      Sales of crude oil and petroleum products .....         $1,692,767     $214,463     $      --    $      --    $      --
      Transportation -- refined products ............            123,004      119,854       107,304       98,641       96,190
      Transportation -- LPGs ........................             67,701       60,902        79,371       80,219       70,576
      Transportation -- crude oil and NGLs ..........             11,846        3,392            --           --           --
      Mont Belvieu operations .......................             12,849       10,880        12,815       11,811       13,570
      Other .........................................             26,716       20,147        22,603       25,354       23,380
                                                              ----------     --------     ---------    ---------    ---------
               Total operating revenues .............          1,934,883      429,638       222,093      216,025      203,716
   Purchases of crude oil and petroleum products ....          1,666,042      212,371            --           --           --
   Operating expenses ...............................            136,095      110,363       106,771      105,182      103,938
   Depreciation and amortization ....................             32,656       26,938        23,772       23,409       23,286
                                                              ----------     --------     ---------    ---------    ---------
   Operating income .................................            100,090       79,966        91,550       87,434       76,492
   Interest expense -- net ..........................            (29,430)     (28,989)      (32,229)     (33,534)     (34,987)
   Other income -- net ..............................              1,460        2,364         1,979        4,748        5,212
                                                              ----------     --------     ---------    ---------    ---------
   Income before extraordinary item .................             72,120       53,341        61,300       58,648       46,717
   Extraordinary loss on debt extinguishment,
      net of minority interest (2) ..................                 --      (72,767)           --           --           --
                                                              ----------     --------     ---------    ---------    ---------
   Net income (loss) ................................         $   72,120     $(19,426)    $  61,300    $  58,648    $  46,717
                                                              ==========     ========     =========    =========    =========
Basic and diluted income per Unit: (3)
   Before extraordinary item ........................         $     1.91     $   1.61     $    1.95    $    1.89    $    1.54
   Extraordinary loss on debt extinguishment (2) ....                 --        (2.21)           --           --           --
                                                              ----------     --------     ---------    ---------    ---------
   Net income (loss) per Unit .......................         $     1.91     $  (0.60)    $    1.95    $    1.89    $    1.54
                                                              ==========     ========     =========    =========    =========
BALANCE SHEET DATA (AT PERIOD END):
   Property, plant and equipment -- net .............         $  720,919     $671,611     $ 567,681    $ 561,068    $ 533,470
   Total assets .....................................          1,041,373      916,919       673,909      671,241      669,915
   Long-term debt (net of current maturities)........            455,753      427,722       309,512      326,512      339,512
   Class B Units ....................................            105,859      105,036            --           --           --
   Partners' capital ................................            229,767      227,186       302,967      290,311      276,381
CASH FLOW DATA:
   Net cash from operations .........................         $  103,070     $ 93,215     $  83,604    $  86,121    $  78,456
   Capital expenditures .............................            (77,431)     (23,432)      (32,931)     (51,264)     (25,967)
   Cash investments -- net ..........................              3,040        2,357        18,860        4,148        6,527
   Distributions ....................................            (69,259)     (56,774)      (49,042)     (45,174)     (40,342)
</TABLE>

--------------------

(1)      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.

(2)      Extraordinary item reflects the loss related to the early
         extinguishment of the First Mortgage Notes on January 27, 1998.

(3)      Per Unit amounts for all periods have been adjusted to reflect the
         two-for-one split on August 10, 1998. Per Unit calculation includes
         3,916,547 Class B Units issued for the acquisition of the crude oil and
         NGL assets, effective November 1, 1998.



                                       15
<PAGE>   18

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 1999, 1998 and 1997 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 Products OLP and the Crude Oil OLP, the
Partnership operates in two industry segments - 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 Products OLP segment is involved in the transportation, storage and
terminaling of petroleum products 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 Products OLP.
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 Crude Oil OLP segment is involved in the transportation,
aggregation and marketing of crude oil, NGLs, lube oils and specialty chemicals.
Revenues are earned from the gathering, storage, transportation and marketing of
crude oil, NGLs, lube oils and specialty chemicals principally in Oklahoma,
Texas and the Rocky Mountain region. Marketing operations consist primarily of
purchasing crude oil along its gathering and pipeline systems and third party
pipelines to facilitate the aggregation, transportation and ultimate sale of
crude oil to local refineries or transportation to major oil hubs. Operations of
this segment are included from November 1, 1998, the date of its acquisition
from a Duke Energy subsidiary.

RESULTS OF OPERATIONS

         Summarized below is financial data by business segment (in thousands):

<TABLE>
<CAPTION>
                                                                       YEARS ENDED DECEMBER 31,
                                                            ------------------------------------------
                                                                1999           1998            1997
                                                            ------------   ------------   ------------
<S>                                                         <C>            <C>            <C>
Operating revenues:
    Refined Products and LPGs Transportation ...........    $    230,270   $    211,783   $    222,093
    Crude Oil and NGLs Transportation and Marketing.....       1,704,613        217,855             --
                                                            ------------   ------------   ------------
       Total operating revenues ........................       1,934,883        429,638        222,093
                                                            ------------   ------------   ------------

Operating income:
   Refined Products and LPGs Transportation ............          89,393         78,641         91,550
   Crude Oil and NGLs Transportation and Marketing......          10,697          1,325             --
                                                            ------------   ------------   ------------
       Total operating income ..........................         100,090         79,966         91,550
                                                            ------------   ------------   ------------

Income before extraordinary item:
    Refined Products and LPGs Transportation ...........          61,227         52,002         61,300
    Crude Oil and NGLs Transportation and Marketing.....          10,893          1,339             --
                                                            ------------   ------------   ------------
      Total income before extraordinary item ...........    $     72,120   $     53,341   $     61,300
                                                            ============   ============   ============
</TABLE>



                                       16
<PAGE>   19

         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 for the year
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 crude oil and NGLs
transportation and marketing segment, which was acquired effective November 1,
1998, and a $9.2 million increase in income provided by the refined products and
LPGs transportation segment. The increase in income provided by the refined
products and LPGs transportation 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.

         For the year ended December 31, 1998, the Partnership reported a net
loss of $19.4 million, which included the extraordinary loss for early
extinguishment of debt of $72.8 million. Excluding the extraordinary loss, net
income for the year would have been $53.3 million, compared with net income of
$61.3 million for 1997. The $8.0 million decrease in income before loss on debt
extinguishment resulted from a $9.3 million decrease in income provided by the
refined products and LPGs transportation segment, partially offset by $1.3
million in income provided by the crude oil and NGLs transportation and
marketing segment, which was acquired effective November 1, 1998. The decrease
in income provided by the refined products and LPGs transportation segment
resulted primarily from a $10.3 million decrease in operating revenues and a
$2.6 million increase in costs and expenses, partially offset by a $3.9 million
decrease in interest expense. See discussion below of factors affecting net
income for the comparative periods by business segment.

REFINED PRODUCTS AND LPGS TRANSPORTATION SEGMENT

   Volume and average tariff information for 1999, 1998 and 1997 is presented
below:

<TABLE>
<CAPTION>
                                                                                       PERCENTAGE
                                                                                        INCREASE
                                                       YEARS ENDED DECEMBER 31,        (DECREASE)
                                                    ------------------------------   ----------------
                                                      1999       1998      1997       1999      1998
                                                    --------   --------   --------   ------     -----
                                                        (IN THOUSANDS, EXCEPT TARIFF INFORMATION)
<S>                                                 <C>            <C>            <C>            <C>
Volumes Delivered
   Refined products ...........................      132,642    130,467    119,971        2%        9%
   LPGs .......................................       37,575     32,048     41,991       17%      (24%)
   Mont Belvieu operations ....................       28,535     25,072     27,869       14%      (10%)
                                                    --------   --------   --------   ------     -----
      Total ...................................      198,752    187,587    189,831        6%       (1%)
                                                    ========   ========   ========   ======     =====

Average Tariff per Barrel
   Refined products ...........................     $   0.93   $   0.92   $   0.89        1%        3%
   LPGs .......................................         1.80       1.90       1.89       (5%)       1%
   Mont Belvieu operations ....................         0.16       0.16       0.15       --         7%
      Average system tariff per barrel ........     $   0.98   $   0.98   $   1.00       --        (2%)
                                                    ========   ========   ========   ======     =====
</TABLE>

    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 a $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




                                       17
<PAGE>   20

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 feed stock 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 Producer Price Index for finished
goods less 1% ("PPI Index"), effective July 1, 1999. The Partnership has
deferred recognition of approximately $0.8 million of revenue 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 $6.8 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 feed stock 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




                                       18
<PAGE>   21

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 against the 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.

   1998 Compared to 1997

         Operating revenues for the year ended 1998 decreased 5% to $211.8
million from $222.1 million for the year ended 1997. This $10.3 million decrease
resulted from an $18.5 million decrease in LPGs transportation revenues, a $2.5
million decrease in other operating revenues and a $1.9 million decrease in
revenues generated from Mont Belvieu operations, partially offset by a $12.6
million increase in refined products transportation revenues.

         Refined products transportation revenues increased $12.6 million for
the year ended December 31, 1998, compared with the prior year, as a result of
the 9% increase in volumes delivered and a 3% increase in the refined products
average tariff per barrel. The 9% increase in volumes delivered in 1998 was
attributable to (i) favorable Midwest price differentials for motor fuel,
distillate, jet fuel and natural gasoline; and (ii) the full-period impact of
capacity expansions of the mainline System between El Dorado, Arkansas, and
Seymour, Indiana, the Ark-La-Tex System between Shreveport, Louisiana, and El
Dorado, and the connection to the Colonial pipeline at Beaumont, Texas. The 3%
increase in the refined products average tariff per barrel reflects new tariff
structures for volumes transported on the expanded portion of the Ark-La-Tex
system and barrels originating from the pipeline connection with Colonial's
pipeline.

         LPGs transportation revenues decreased $18.5 million for the year ended
December 31, 1998, compared with the prior year, due to a 24% decrease in
volumes delivered, partially offset by a 1% increase in the LPGs average tariff
per barrel. Propane revenues decreased $16.7 million, or 25%, from the prior
year primarily due to decreased propane deliveries in the Midwest and Northeast
market areas attributable to warmer winter and spring weather during 1998 and
unfavorable differentials versus competing Canadian product. Butane revenues
decreased $1.7 million, or 13%, from the prior year due primarily to unfavorable
blending economics in the Midwest and termination of a throughput agreement
during the second quarter of 1998. Decreased petrochemical demand along the
upper Texas Gulf Coast resulted in a 32% decrease in short-haul propane
deliveries. The 1% increase in the LPGs average tariff per barrel resulted from
an increase in 1998 of the ratio of long-haul to short-haul propane deliveries.

         Revenues generated from Mont Belvieu operations decreased $1.9 million
for the year ended December 31, 1998, compared with the prior year, primarily
due to lower storage revenue, lower product receipt charges and decreased
propane dehydration fees. Additionally, Mont Belvieu shuttle deliveries
decreased 10% during the year ended 1998, compared with the prior year, due to
lower petrochemical and refinery demand for LPGs along the upper Texas Gulf
Coast. The decrease in the Mont Belvieu shuttle deliveries was largely offset by
a 7% increase in the average tariff per barrel attributable to a lower
percentage in 1998 of contract deliveries, which generally carry lower tariffs.

         Other operating revenues decreased $2.5 million during the year ended
December 31, 1998, compared with 1997, primarily due to decreased product
inventory volumes sold, unfavorable product location exchange differentials
incurred to position system inventory, lower amounts of butane received in the
Midwest for summer storage and decreased terminaling revenues. These decreases
were partially offset by $5.5 million of operating revenues from the
fractionator facilities acquired on March 31, 1998.



                                       19
<PAGE>   22

         Costs and expenses increased $2.6 million during the year ended
December 31, 1998, compared with the prior year, due to a $3.7 million increase
in operating, general and administrative expenses and a $2.3 million increase in
depreciation and amortization charges, partially offset by a $3.0 million
decrease in operating fuel and power expense and a $0.4 million decrease in
taxes - other than income. The increase in operating, general and administrative
expenses was primarily attributable to $3.4 million of expense to write down the
book-value of product inventory to market-value, credits of $3.0 million
recorded during 1997 for insurance recovery of past litigation costs related to
the Seymour, Indiana, terminal, a $0.9 million increase in expenses related to
Year 2000 activities, $0.6 million of expense related to the fractionator
facilities acquired on March 31, 1998, and increased product measurement losses.
These increases in operating, general and administrative expenses were partially
offset by expenses recorded for environmental remediation at the Partnership's
Seymour terminal in the third quarter of 1997, and lower supplies and services
related to pipeline operations and maintenance. 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. Operating fuel and power expense decreased from the prior
year due primarily to increased mainline pumping efficiencies, lower long-haul
LPGs volumes and lower summer peak power rates in Arkansas.

         Interest expense decreased $3.9 million during the year ended December
31, 1998, compared with 1997, as a result of the repayment on January 27, 1998
of the remaining $326.5 million principal balance of the First Mortgage Notes,
partially offset by interest expense on the $390.0 million principal amount of
the Senior Notes issued on January 27, 1998, and interest expense on the $38.0
million term-loan used to finance the purchase of the fractionation assets on
March 31, 1998. The weighted average interest rate of the $326.5 million
principal amount of the First Mortgage Notes was 10.09%, compared with the
weighted average interest rate of the $390.0 million principal amount of the
Senior Notes of 7.02%. The interest rate on the $38.0 million term loan is
6.53%. Interest capitalized decreased $0.7 million from the prior year as a
result of lower construction balances related to capital projects.

         Other income - net increased during the year ended December 31, 1998,
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 a $0.5 million loss on the sale of
non-carrier assets in August 1997. These factors were partially offset by lower
interest income earned on cash investments in 1998.







                                       20
<PAGE>   23

CRUDE OIL AND NGLs TRANSPORTATION AND MARKETING SEGMENT

         The crude oil and NGLs transportation and marketing segment was added
to the Partnership's operations with the acquisition of the assets of a Duke
Energy subsidiary effective November 1, 1998. The acquisition was accounted for
as a purchase for accounting purposes. Accordingly, only operations from
November 1, 1998 have been included in the Partnership's financial statements.

         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 is
calculated as revenues generated from crude oil and lube oil sales and crude oil
and NGLs transportation less the cost of crude oil and lube oil purchases.
Margin and volume information for the year ended December 31, 1999 and the two
month period ended December 31, 1998 is presented below:

<TABLE>
<CAPTION>
                                                            YEAR ENDED                  TWO MONTHS ENDED
                                                         DECEMBER 31, 1999              DECEMBER 31, 1998
                                                     -------------------------     --------------------------
<S>                                                  <C>             <C>           <C>              <C>
Margins (dollars in thousands):
   Crude oil transportation ...................      $   17,873            46%     $     2,787            51%
   Crude oil marketing ........................          12,065            31%           1,253            23%
   NGL transportation .........................           6,123            16%           1,062            19%
   Lubrication oil sales ......................           2,510             7%             382             7%
                                                     ----------      --------      -----------      ---------
        Total margin ..........................      $   38,571           100%     $     5,484           100%
                                                     ==========      ========      ===========      =========

Barrels per day:
   Crude oil transportation ...................          91,143                         90,963
   Crude oil marketing ........................         263,703                        278,176
   NGL transportation .........................          12,548                         11,919

Lubrication oil volume (total gallons): .......       8,891,056                      1,140,000

Margin per barrel:
   Crude oil transportation ...................      $    0.537                    $     0.504
   Crude oil marketing ........................      $    0.125                    $     0.071
   NGL transportation .........................      $    1.337                    $     1.515

Lubrication oil margin (per gallon): ..........      $    0.282                    $     0.335
</TABLE>

     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 LLC ("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.



                                       21
<PAGE>   24

     Two Months Ended December 31, 1998

         Net income contributed by the crude oil transportation and marketing
segment totaled $1.3 million for the two months ended December 31, 1998;
comprised of $5.5 million of gross margin, offset by $3.2 million of operating,
general and administrative expenses (including operating fuel and power), $0.9
million of depreciation and amortization charges, and $0.1 million of taxes -
other than income.

         During the two months ended December 31, 1998, crude oil transportation
and NGL transportation contributed 51% and 19% of the margin, respectively,
while crude oil marketing operations accounted for 23% of the margin. Operations
of LSI contributed $0.4 million, or 7%, of the margin for the two month period
ended December 31, 1998. Operating, general and administrative expenses of the
crude oil and NGLs transportation and marketing segment totaled $3.2 million, or
58% of the margin. Depreciation and amortization expenses and taxes - other than
income totaled $1.0 million, or 18% of the margin.

FINANCIAL CONDITION AND LIQUIDITY

         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. The $14.6 million increase of cash used for working capital changes
resulted primarily from timing of collections and payments related to crude oil
marketing activity. Net cash from operations for the year ended December 31,
1997 totaled $83.6 million, which was comprised of $85.1 million of income
before charges for depreciation and amortization, partially offset by $1.5
million of cash used for working capital changes. Net cash from operations
includes interest payments of $30.7 million, $27.0 million and $33.6 million for
each of the years ended 1999, 1998 and 1997, respectively.

         The Partnership routinely invests excess cash in liquid investments as
part of its cash management program. Investments of cash in discounted
commercial paper and Eurodollar time deposits with original maturities at date
of purchase of 90 days or less are included in cash and cash equivalents.
Short-term investments of cash consist of investment-grade corporate notes with
maturities during 2000. Long-term investments are comprised of investment-grade
corporate notes with varying maturities between 2001 and 2004. Interest income
earned on all investments is included in cash from operations. Cash flows from
investing activities included proceeds from investments of $6.3 million, $3.1
million and $25.0 million for each of the years ended 1999, 1998 and 1997,
respectively. Cash flows from investing activities also included additional
investments of $3.2 million, $0.7 million and $6.2 million for each of the years
ended 1999, 1998 and 1997, respectively. Cash balances related to the investment
of cash and proceeds from the investment of cash were $39.3 million, $57.2
million and $56.1 million for the years ended December 31, 1999, 1998 and 1997,
respectively.

         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 crude oil system in Southeast Texas. Capital expenditures
during 1999 included $43.8 million of spending for on-going construction of
three new pipelines between the Partnership's terminal in Mont Belvieu, Texas
and Port Arthur, Texas. The project includes three 12-inch diameter
common-carrier pipelines and associated facilities. Each pipeline will be
approximately 70 miles in length. Upon completion, the new pipelines will
transport ethylene, propylene and natural gasoline. The cost of this project is
expected to total approximately $75 million. The Partnership has entered into an
agreement for turnkey construction of the pipelines and related facilities and
has separately entered into agreements for guaranteed throughput commitments.
The anticipated commencement date is the fourth quarter of 2000. 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 assets, partially offset by $0.5 million received
from the sale of non-carrier assets. Cash flows used in investing activities for
the year ended December 31, 1997 included $32.9 million of capital expenditures,





                                       22
<PAGE>   25

partially offset by $1.4 million received from the sale of non-carrier assets
and $1.0 million of insurance proceeds related to the replacement value of a
20-inch diameter auxiliary pipeline at the Red River in central Louisiana, which
was damaged in 1994 and subsequently removed from service.

         On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All per Limited Partner Unit amounts have been adjusted to reflect the
two-for-one Unit split.

         The Partnership paid cash distributions of $69.3 million ($1.85 per
Unit), $56.8 million ($1.75 per Unit), and $49.0 million ($1.55 per Unit) for
each of the years ended December 31, 1999, 1998 and 1997, respectively. On
January 14, 2000, the Partnership declared a cash distribution of $0.475 per
Limited Partner Unit and Class B Unit for the quarter ended December 31, 1999.
The distribution of $18.3 million was paid on February 4, 2000, to Unitholders
of record on January 31, 2000.

         On January 27, 1998, the Products OLP 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 Products OLP, 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 repayment of the First Mortgage Notes and the issuance of the
Senior Notes reduced the level of cash required for debt service until 2008. 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 Products OLP and
will rank on a parity with all other unsecured and unsubordinated indebtedness
of the Products OLP. 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.

         In connection with the purchase of fractionation assets from DEFS as of
March 31, 1998, TEPPCO Colorado received a $38 million bank loan from SunTrust
Bank. Proceeds from the loan were received on April 21, 1998. The loan bears
interest at a rate of 6.53%, which is payable quarterly. The principal balance
of the loan is payable in full on April 21, 2001. The Products OLP is guarantor
on the loan.

         On May 17, 1999, the Products OLP entered into a $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. The loan
agreement has a term of five years. SunTrust Bank is the administrator of the
loan. At December 31, 1999, $25 million has been borrowed under the term loan
agreement. Principal will be paid quarterly beginning in 2001. The interest rate
for the $75 million term loan is based on the borrower's option of either
SunTrust Bank's prime rate, the federal funds rate or LIBOR rate in effect at
the time of the borrowings and is adjusted monthly, bimonthly, quarterly or
semi-annually. Interest is payable quarterly from the time of borrowing. The
current interest rate for amounts outstanding under the term loan is 7.27%.
Commitment fees for the term loan agreement totaled approximately $78,000 for
the period from May 17, 1999 through December 31, 1999.

         On May 17, 1999, the Products OLP entered into a $25 million revolving
credit agreement and TCO entered into a $30 million revolving credit agreement.
SunTrust Bank is the administrative agent on both revolving credit agreements.
The $25 million revolving credit agreement has a five year term and the $30
million revolving



                                       23
<PAGE>   26

credit agreement has a three year term. The interest rate on both agreements is
based on the borrower's option of either SunTrust Bank's prime rate, the federal
funds rate or LIBOR rate in effect at the time of the borrowings and is payable
quarterly. Interest rates are adjusted monthly, bimonthly, quarterly or
semi-annually. The Products OLP has not borrowed any amounts under the revolving
credit facility. TCO had $3 million principal amount outstanding under its
revolving credit agreement as of December 31, 1999. Commitment fees for the
revolving credit agreements totaled approximately $83,000 for the period from
May 17, 1999 through December 31, 1999.

         Each of the loan agreements with SunTrust Bank discussed above contains
restrictive financial covenants that require the Operating Partnerships to
maintain a minimum level of partners' capital as well as debt-to-earnings,
interest coverage and capital expenditure coverage ratios. At December 31, 1999,
the Operating Partnerships were in compliance with all financial covenants
related to these loan agreements.

         In connection with the purchase of assets from a Duke Energy subsidiary
by the Crude Oil OLP, Duke Capital, an affiliate of Duke Energy, agreed to
guarantee the payment by the Crude Oil OLP under certain commercial contracts
with third parties. Duke Capital will provide up to $100 million of guarantee
credit to TCO and its subsidiaries for a period of three years from November 30,
1998. Pursuant to this agreement, the Partnership has agreed to pay Duke Capital
a commitment fee of $100,000 per year.

         In March 2000, the Partnership, CMS Energy Corporation and Marathon
Ashland Petroleum LLC announced an agreement to form a limited liability company
that will own and operate an interstate refined petroleum products pipeline
extending from the upper Texas Gulf Coast to Illinois. Each of the companies
will own a one-third interest in the limited liability company. The
Partnership's participation in this joint venture will replace its previously
announced expansion plan to construct a new pipeline parallel to the
Partnership's two existing pipelines from Beaumont, Texas, to Little Rock,
Arkansas.

         The limited liability company will build a 70-mile, 24-inch diameter
pipeline connecting the Partnership'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, which has been named
Centennial Pipeline, will pass through portions of seven states -- 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 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 by the end of 2001. The Centennial Pipeline
will intersect the Partnership's existing mainline near Lick Creek, Illinois,
where a new two million barrel refined petroleum products storage terminal will
be built.

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, 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 $0.8 million at December 31, 1999 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.

     Year 2000 Issues

         In 1997, the Company initiated a program to prepare the Partnership's
process controls and business computer systems for the "Year 2000" issue.
Process controls are the automated equipment including hardware and software
systems which run operational activities. Business computer systems are the
computer hardware and software used by the Partnership. The Partnership incurred
approximately $5.6 million of expense from 1997 through 1999 related to the Year
2000 issue. The Partnership did not encounter any critical system application or
hardware failures during the date roll over to the Year 2000, and has not
experienced any disruptions of business activities as a result of Year 2000
failures encountered by customers, suppliers and service providers.




                                       24
<PAGE>   27

      Market and Regulatory Environment

         Tariff 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").

         During June 1997, the Partnership filed rate increases on selective
refined products tariffs and LPGs tariffs, averaging 1.7%. These rate increases
became effective July 1, 1997 without suspension or refund obligation. On July
1, 1998, general rate decreases of 0.62% for both refined products tariffs and
LPGs tariffs became effective. The rate decreases were calculated pursuant to
the index methodology promulgated by the FERC.

         In May 1999, the Products OLP filed an application with the FERC to
charge Market Based Rates for substantially all refined products transportation
tariffs. Such application is currently under review by the FERC. The FERC
approved a request of the Products OLP waiving the requirement to adjust refined
products transportation tariffs pursuant to the PPI Index while its Market Based
Rates application is under review. Under the PPI Index, refined products
transportation rates in effect on June 30, 1999 would have been reduced by
approximately 1.83% effective July 1, 1999. If any portion of the Market Based
Rates application is denied by the FERC, the Products OLP has agreed to refund,
with interest, amounts collected after June 30, 1999, under the tariff rates in
excess of the PPI Index. As a result of the refund obligation potential, the
Partnership has deferred all revenue recognition of rates charged in excess of
the PPI Index. At December 31, 1999, the amount deferred for possible rate
refunds, including interest, totaled approximately $0.8 million.

         In July 1999, certain shippers filed protests with the FERC on the
Products OLP's application for Market Based Rates in four destination markets.
The Partnership believes it will prevail in a competitive market determination
in those destination markets under protest.

         Effective July 1, 1999, the Products OLP 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
Products OLP 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.

     Other

         In February 2000, the Partnership and Louis Dreyfus Plastics
Corporation ("Louis Dreyfus") announced a joint development alliance whereby the
Partnership's Mont Belvieu petroleum liquids storage and transportation shuttle
system assets will be marketed by Louis Dreyfus. The alliance will expand
services to the upper Texas Gulf Coast energy marketplace. The alliance is a
service-oriented, fee-based venture with no commodity trading.

         In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This statement establishes
standards for and disclosures of derivative instruments and hedging activities.
In July 1999,





                                       25
<PAGE>   28

the FASB issued SFAS No. 137 to delay the effective date of SFAS No. 133 until
fiscal years beginning after June 15, 2000. The Partnership expects to adopt
this standard effective January 1, 2001. The Partnership has not determined the
impact of this statement on its 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 realized, that they will have the
expected consequences to or effect on the Partnership or its business or
operations.

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.

         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. 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, 1999.

         At December 31, 1999, the Products OLP 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").
Additionally, the Products OLP had a $38 million bank loan outstanding from
SunTrust Bank. The SunTrust loan bears interest at a fixed rate of 6.53% and is
payable in full in April 2001. At December 31, 1999, the estimated fair value of
the Senior Notes and the SunTrust loan was approximately $356.0 million and
$38.1 million, respectively.

         At December 31, 1999, the Products OLP had $25 million outstanding
under a variable interest rate term loan and the Crude Oil OLP had $3 million
outstanding under its revolving credit agreement. The interest rates for these
credit facilities are based on the borrower's option of either SunTrust Bank's
prime rate, the federal funds rate or LIBOR rate 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, 1999, and assuming market interest rates increase 1%, the potential annual
increase in interest expense is approximately $0.3 million.



                                       26
<PAGE>   29

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

         NONE

                                    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
Duke Energy. All officers serve at the discretion of the directors.

         William L. Thacker, age 54, 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.

         Fred J. Fowler, age 54, is Vice Chairman of the Board of the General
Partner and is Chairman of the Compensation Committee. He was elected a director
in November 1998. 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.

         Richard J. Osborne, age 49, was elected a director of the General
Partner in October 1998. Mr. Osborne is executive vice president and chief
financial officer of Duke Energy. He previously served as vice president and
chief financial officer of Duke Energy from 1991 to 1997. Mr. Osborne joined
Duke Energy in 1975.

         Jim W. Mogg, age 51, was elected a director of the General Partner in
October 1997. Mr. Mogg is president and chief executive officer of Duke Energy
Field Services, Inc. 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.

         Ruth G. Shaw, age 52, was elected a director of the General Partner in
December 1997. Ms. Shaw is executive vice president and chief administrative
officer of Duke Energy. Ms. Shaw joined Duke Power Company in 1992 as vice
president of corporate communications. In April 1994, she was elected senior
vice president, corporate resources and chief administrative officer. Ms. Shaw
is a director of First Union Corp. and Avado Brands, Inc.

         Carl D. Clay, age 67, 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 61, is a director of the General Partner having been
elected in 1989. He is the Chairman of the Audit Committee and serves on the
Compensation Committee of the General Partner. Mr. Cody is presently of counsel
to McKinney and Stringer, 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.



                                       27
<PAGE>   30

         John P. DesBarres, age 60, 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.

         Milton Carroll, age 50, was elected a director of the General Partner
in November 1997 and is a member of the Compensation and Audit Committees. Mr.
Carroll founded and has been president and chief executive officer of Instrument
Products, Inc., a manufacturer of oil field tools and other precision products,
since 1977. Mr. Carroll is a director of Reliant Energy, Ocean Energy Inc., and
Blue Cross Blue Shield of Texas.

         Charles H. Leonard, age 51, 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 52, is Vice President, General Counsel and Secretary
of the General Partner, having been elected in 1991. He was elected as Secretary
in 1998. Mr. Ruth was Vice President and Assistant General Counsel of the
General Partner from 1989 to 1991.

         Thomas R. Harper, age 59, is Vice President, Product Transportation and
Refined Products Marketing of the General Partner. Mr. Harper joined the Company
in 1987 as Director of Product Transportation, and was elected to his present
position in 1988.

         David L. Langley, age 52, is Vice President, Business Development and
LPG Services of the General Partner. Mr. Langley has been with the Company in
various managerial positions since 1975 and was elected Vice President, LPG
Business Center, in 1988. He was elected to his current position in 1990.

         Ernest P. Hagan, age 55, is Vice President, Operations, of the General
Partner, having been elected in October 1996. Mr. Hagan was previously Director
of Engineering and Right-of-Way from 1994 until October 1996, and from 1986
until 1994 he was Region Manager of the Southwest Region. Mr. Hagan joined the
Company in 1971.

         Sharon S. Stratton, age 61, 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 joined PanEnergy in 1976.

         J. Michael Cockrell, age 53, is Vice President of the General Partner,
having been elected in January 1999. Mr. Cockrell 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.

         William S. Dickey, age 42, is Vice President of the General Partner,
having been elected in January 1999. Mr. Dickey also serves as Senior Vice
President and Chief Financial Officer of TCO. He previously served as vice
president and chief financial officer of Duke Energy Field Services from 1994 to
1998. Mr. Dickey joined PanEnergy in 1987.

         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, 1999, except that one such report covering one
transaction in Limited Partner Units was filed late by J. Michael Cockrell.


                                       28
<PAGE>   31

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.

         Directors of the General Partner who are neither officers nor employees
of either the Company or Duke Energy 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, Fowler, Mogg and Osborne and Ms. Shaw 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 full-time employees of Duke Energy, 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, 1999, 1998 and 1997, with
respect to its Chief Executive Officer and the four most highly compensated
executive officers (collectively, the "Named Executive Officers").





                                       29
<PAGE>   32

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                                              LONG TERM COMPENSATION
                                               ANNUAL COMPENSATION            OTHER         --------------------------
                                        ---------------------------------     ANNUAL          OPTION                      ALL OTHER
          NAME AND                                                BONUS    COMPENSATION      AWARDS (#)     PAYOUTS    COMPENSATION
     PRINCIPAL POSITION                   YEAR    SALARY ($)    ($) (2)       ($) (3)         (4) (5)        ($)(6)        ($) (7)
                                        -------   ----------   ----------   ------------    ------------   ----------- -------------

<S>                                     <C>       <C>          <C>            <C>            <C>           <C>            <C>
William L. Thacker ...................    1999      261,321      106,100        57,809         50,000        133,124        22,924
      Chairman, President and             1998      250,000       86,400        77,114         39,000        148,858        24,666
      Chief Executive Officer             1997      237,708       98,200        78,551          8,800        358,168        21,529

J. Michael Cockrell (1) ..............    1999      179,393       51,000        27,750         15,000             --        14,064
      Vice President

Charles H. Leonard ...................    1999      153,507       62,200            --         16,000         98,679        12,687
     Senior Vice President,               1998      149,333       39,200        14,820         12,000         95,331        13,406
     Chief Financial Officer              1997      145,750       52,000        29,985             --         25,444        12,960
     and Treasurer

William S. Dickey (1) ................    1999      149,423       42,000        16,650          9,000             --        10,599
     Vice President

James C. Ruth ........................    1999      142,344       57,600        28,904         16,000         60,741        11,738
     Vice President and                   1998      138,333       36,200        38,557         12,000         41,095        15,079
     General Counsel                      1997      134,333       46,000        39,276             --         27,901        14,968
</TABLE>

-------------------

(1)      Mr. Cockrell and Mr. Dickey were elected to their positions in January
         1999. They were 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 were made
         in the subsequent year.

(3)      Amounts represent quarterly distribution equivalents under the terms of
         the Company's Long Term Incentive Compensation Plan ("LTICP") and
         Retention Incentive Compensation Plan ("RICP").

(4)      Amounts represent awards pursuant to the Texas Eastern Products
         Pipeline Company 1994 Long Term Incentive Plan ("1994 LTIP") for Mr.
         Thacker, Mr. Leonard and Mr. Ruth. See "Compensation Pursuant to
         General Partner Plans" for further discussion of the 1994 LTIP.

(5)      Amounts represent awards pursuant to the RICP for Mr. Cockrell and Mr.
         Dickey. See "Compensation Pursuant to General Partner Plans" for
         further discussion of 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. Also, for Mr. Thacker in 1997,
         amounts include crediting of phantom units awarded in a prior year
         under the terms of the LTICP.

(7)      Includes (i) Company matching contributions under the Duke Energy
         Retirement Savings Plan, a funded, qualified, defined contribution
         retirement plan; (ii) Company matching contribution credits under the
         Duke Energy Corporation Executive Savings Plan, an unfunded, non
         qualified plan; and (iii) the imputed value of premiums paid by the
         Company for insurance on the Named Executive Officers' lives.

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



                                       30
<PAGE>   33

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 Samuel N. Brown, J. Michael Cockrell, William S.
Dickey 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 (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 Unitholders 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. On January 4, 2000, all
remaining outstanding phantom units were redeemed. See Item 13, "Certain
Relationships and Related Transactions.

     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




                                       31
<PAGE>   34
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.

       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.

      Phantom Unit Retention Plan

         Effective August 25, 1999, the General Partner established the Phantom
Unit Retention Plan ("PURP") to provide non-executive officer key employees with
an incentive award based upon the grant of phantom units. The PURP is
administered by the Committee, which has sole and absolute discretion to
determine the amount of an award. 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. Each participant also receives a quarterly distribution
equivalent on all phantom units awarded, until redemption of such phantom units.

         The following table shows all grants of unit options under the 1994
LTIP to the Named Executive Officers in 1999. No Stock appreciation rights
(SARs) were granted in 1999 nor were the exercise prices on unit options
previously awarded under the 1994 LTIP amended or adjusted.

                      OPTION/SAR GRANTS IN LAST FISCAL YEAR

<TABLE>
<CAPTION>
                                            INDIVIDUAL GRANTS
                   ---------------------------------------------------------------------
                                                                              GRANT DATE
                     NUMBER OF     PERCENT OF                                   VALUE
                     SECURITIES    TOTAL OPTIONS/                            -----------
                     UNDERLYING    SARS GRANTED     EXERCISE OR               GRANT DATE
                    OPTIONS/SARs   TO EMPLOYEES      BASE PRICE   EXPIRATION   PRESENT
                   GRANTED (1)(#)  IN FISCAL YEAR     ($/UNIT)      DATE      VALUE (2)$
                   --------------  --------------   -----------   ---------  -----------
<S>                <C>             <C>               <C>          <C>        <C>
Mr. Thacker ...       50,000           31               25.25      1/14/09   $  125,500
Mr. Leonard ...       16,000           10               25.25      1/14/09   $   40,160
Mr. Ruth ......       16,000           10               25.25      1/14/09   $   40,160
</TABLE>
---------------------

(1)      On January 14, 1999, Messrs. Thacker, Leonard and Ruth were granted
         options to purchase 50,000 Limited Partner Units, 16,000 Limited
         Partner Units and 16,000 Limited Partner Units, respectively, under the




                                       32
<PAGE>   35

         terms of the 1994 LTIP at an exercise price of $25.25 per Limited
         Partner Unit, which was the fair market value of a Limited Partner Unit
         on the date of grant. No Performance Units were granted in 1999.

(2)      Based on the Black-Scholes option valuation model. The key input
         variables used in valuing the options were: risk-free interest rate
         based on 6-year Treasury strips - 4.7%; dividend yield - 7.6%; Unit
         price volatility - 23%. Expected dividend yield and price volatility
         was based on historical Limited Partner Unit data. No adjustments for
         non-transferability or risk of forfeiture were made. The actual value,
         if any, a grantee may realize will depend on the excess of the Limited
         Partner Unit price over the exercise price on the date the option is
         exercised, so that there is no assurance the value realized will be at
         or near the value estimated by the Black-Scholes model.

         The following table provides information concerning the unit options
exercised under the 1994 LTIP by each of the Named Executive Officers during
1999 and the value of unexercised unit options under the 1994 LTIP to the Named
Executive Officers as of December 31, 1999. 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, 1999. The fair market value is the average of the high and
low prices of a Limited Partner Unit on that date as reported in The Wall Street
Journal. 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

<TABLE>
<CAPTION>

                                                                                                      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
----------------------------   --------------    ------------      ----------------------          --------------
<S>                               <C>              <C>                  <C>                       <C>
Mr. Thacker ................      3,402            $ 39,603             34,725/78,933               $ 82,759/ $  0
Mr. Leonard ................      7,366            $ 81,849              7,328/24,000               $ 19,136/ $  0
Mr. Ruth ...................      2,866            $ 29,096              12,726/24,000              $ 50,175/ $  0
</TABLE>

-------------------------

(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.

     1997 Employee Incentive Compensation Plan

         The General Partner has adopted the 1997 Employee Incentive
Compensation Plan ("1997 EICP"), which provides an award of shadow units to all
employees who are not eligible to participate in the MICP. The 1997 EICP is
administered by the Committee, which maintains an incentive award account for
each participant. Each participant is eligible for an annual award of up to 600
shadow units, depending on the level of earnings achieved by the Partnership
each year, which generally entitles such participant to receive a credit equal
to the quarterly distribution that such participant would have received had the
participant been the owner of Units. The Committee may add a premium from 10% to
30% to the credit if certain safety and operational goals are attained. Payment
of the credits is contingent upon the participant remaining in the employment of
the General Partner during the year in which the shadow units are outstanding.
Awards to participants are paid in cash following the close of each year in an
amount equal to the credits in the participant's incentive award account with
respect to such year.



                                       33
<PAGE>   36

PENSION PLAN

         From January 1, 1999, the Company's employees, along with employees of
other Duke Energy affiliates, participated in either of two noncontributory,
qualified, defined benefit retirement plans: the Retirement Cash Balance Plan or
the Retirement Income Plan. The Retirement Income Plan ceased admitting new
participants after December 31, 1998 and merged into the Retirement Cash Balance
Plan on April 30, 1999. In addition, the Named Executive Officers participate in
the Executive Cash Balance Plan, which is a noncontributory, non qualified,
defined benefit retirement plan. A portion of the benefits earned in the
Executive Cash Balance Plan is attributable to compensation in excess of the
Internal Revenue Service annual compensation limit ($160,000 for 1999) and
deferred compensation, as well as reductions caused by maximum benefit
limitations that apply to qualified plans from the benefits that would otherwise
be provided under the Retirement Cash Balance Plan and the Retirement Income
Plan. Effective January 1, 1999 the Retirement Benefit Equalization Plan was
established to restore benefit reductions caused by the maximum benefit
limitations that apply to qualified plans from benefits that would otherwise be
provided under the Retirement Cash Balance Plan and the Retirement Income Plan
for eligible employees who do not participate in the Executive Cash Balance
Plan. Benefits under the Retirement Cash Balance Plan, the Retirement Income
Plan, the Executive Cash Balance Plan and the Retirement Benefit Equalization
Plan are based on eligible pay, generally consisting of base pay, short term
incentive pay, and lump-sum merit increases. The Retirement Cash Balance Plan,
the Retirement Income Plan and the Retirement Benefit Equalization Plan exclude
deferred compensation, other than deferrals pursuant to Sections 401(k) and 125
of the Internal Revenue Code.

         Under the cash balance benefit accrual formula that applies in
determining benefits under the Retirement Income Plan and the Retirement Cash
Balance Plan on and after January 1, 1999, 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:

<TABLE>
<CAPTION>
                                                             MONTHLY PAY
                                                               CREDIT
AGE AND SERVICE                                              PERCENTAGE
                                                           ---------------
<S>                                                          <C>
34 or less .............................................         4%
35 to 49 ...............................................         5%
50 to 64 ...............................................         6%
65 or more .............................................         7%
</TABLE>

         The above monthly pay credit is increased by an additional 4% of any
portion of eligible pay above the Social Security taxable wage base ($76,200 for
2000). However, for certain other employees of the Company, the monthly pay
credit percentage is a flat 3% of eligible pay. Employee accounts also receive
monthly interest credits on their balances. The rate of the interest credit is
adjusted quarterly and equals the 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.

         Prior to application of the cash balance formula, benefits for eligible
employees were determined under other formulas. To transition from a prior
formula to the new formula, an eligible employee's accrued benefit earned under
the prior formula is preserved as a minimum, and the employee's plan account
receives an opening balance derived from a variety of factors.

         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 plan(s)
attributable to such salaries would be as follows: William L. Thacker, $157,779;
J. Michael Cockrell, $40,083; Charles H. Leonard, $103,965; William S. Dickey,
$84,603; and James C. Ruth, $189,495. 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 $76,200.


                                       34
<PAGE>   37
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         (a) Security Ownership of Certain Owners.

         As of March 6, 2000, Duke Energy, through its ownership of the Company
and other subsidiaries, owns 2,500,000 Limited Partner Units, representing 8.62%
of the Limited Partner Units outstanding; and 3,916,547 Class B Units,
representing 100% of the Class B Units, or 19.49% of the two classes of Units
combined.

         (b) Security Ownership of Management

         The following table sets forth certain information, as of March 6,
2000, 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, 2000, more than 1% of the Limited Partner
Units outstanding at that date.

<TABLE>
<CAPTION>
                                                                                     NUMBER OF
NAME                                                                                 UNITS (1)
----                                                                               -------------

<S>                                                                                <C>
Milton Carroll ..................................................................            500
Carl D. Clay (2) ................................................................          3,200
Derrill Cody ....................................................................         13,000
John P. DesBarres ...............................................................         20,000
Fred J. Fowler (3) ..............................................................          3,100
Jim W. Mogg (4) .................................................................          3,200
Richard J. Osborne ..............................................................          1,000
Ruth G. Shaw ....................................................................            900
William L. Thacker ..............................................................         32,968
J. Michael Cockrell .............................................................          4,000
William S. Dickey ...............................................................             --
Charles H. Leonard ..............................................................            406
James C. Ruth ...................................................................          3,643
All directors and officers (consisting of 19 people, including those named above)        127,352
</TABLE>

------------------------

(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 Mr. Fowler's son.

(4)      Includes 2,000 Units held in trust accounts for daughters.

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 $2.1 million in 1999.



                                       35
<PAGE>   38

         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 1999, incentive distributions paid to the General Partner totaled
$7.7 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, 1999, 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, 1999, 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.

<TABLE>
<CAPTION>
EXHIBIT
NUMBER                              DESCRIPTION
-------                             -----------

<S>      <C>
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 3.3 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).
</TABLE>


                                       36
<PAGE>   39

<TABLE>
<S>      <C>
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 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).


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.

*10.8    Duke Energy Corporation Executive Cash Balance Plan.

*10.9    Duke Energy Corporation Retirement Benefit Equalization Plan.

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).

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    Credit Agreement between TEPPCO Colorado, LLC, SunTrust Bank, Atlanta,
         and Certain Lenders, dated April 21, 1998 (Filed as Exhibit 10.15 to
         Form 10-Q of TEPPCO
</TABLE>




                                       37
<PAGE>   40
<TABLE>
<S>      <C>
         Partners, L.P. (Commission File No. 1-10403) for the quarter ended
         March 31, 1998 and incorporated herein by reference).

10.15    First Amendment to Credit Agreement between TEPPCO Colorado, LLC,
         SunTrust Bank, Atlanta, and Certain Lenders, effective June 29, 1998
         (Filed as Exhibit 10.15 to Form 10-Q of TEPPCO Partners, L.P.
         (Commission File No. 1-10403) for the quarter ended June 30, 1998 and
         incorporated herein by reference).

10.16    Contribution Agreement between Duke Energy Transport and Trading
         Company and TEPPCO Partners, L.P., dated October 15, 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).

10.17    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 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).

10.18    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 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).

10.19    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 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).

10.20    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).


10.21    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).

10.22    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).

10.23    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).

10.24    Credit Agreement between TE Products Pipeline Company, Limited
         Partnership, SunTrust Bank, Atlanta, and Certain Lenders, dated May 17,
         1999 (Filed as Exhibit 10.26 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).

10.25    Credit Agreement between TEPPCO Crude Oil, LLC, SunTrust Bank, Atlanta,
         and Certain Lenders, dated May 17, 1999 (Filed as Exhibit 10.27 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).

10.26    Second Amendment to Credit Agreement between TEPPCO Colorado, LLC,
         SunTrust Bank, Atlanta, and Certain Lenders, effective May 17, 1999
         (Filed as Exhibit 10.28 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).

10.27    Form of Employment and Non-Compete Agreement between the Company and
         Samuel N. Brown, J. Michael Cockrell, William S. Dickey, and Sharon S.
         Stratton effective
</TABLE>


                                       38
<PAGE>   41
<TABLE>
<S>      <C>
         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).


10.28    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).

10.29    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).

10.30    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).

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).

*24      Power of Attorney.

*27      Financial Data Schedule as of and for the year ended December 31, 1999.
</TABLE>

---------------

*        Filed herewith.

(b)      Reports on Form 8-K filed during the quarter ended December 31, 1999:

         None



                                       39
<PAGE>   42

                                   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
                                         as General Partner

                                    By:  /s/ CHARLES H. LEONARD
                                         --------------------------------------
                                                  Charles H. Leonard,
                                         Senior Vice President, Chief Financial
                                                Officer and Treasurer
DATED: March 10, 2000

         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.

<TABLE>
<CAPTION>
             SIGNATURE                                          TITLE                                     DATE
             ---------                                          -----                                     ----
<S>                                   <C>                                                                 <C>
        WILLIAM L. THACKER*              Chairman of the Board, President and Chief Executive             March 10, 2000
------------------------------------      Officer of Texas Eastern Products Pipeline Company
         William L. Thacker

         CHARLES H. LEONARD               Senior Vice President, Chief Financial Officer and              March 10, 2000
------------------------------------     Treasurer of Texas Eastern Products Pipeline Company
         Charles H. Leonard                  (Principal Accounting and Financial Officer)


          FRED J. FOWLER*                        Vice Chairman of the Board of Texas                      March 10, 2000
------------------------------------              Eastern Products Pipeline Company
           Fred J. Fowler

          MILTON CARROLL*                             Director of Texas Eastern                           March 10, 2000
------------------------------------                  Products Pipeline Company
           Milton Carroll

           CARL D. CLAY*                              Director of Texas Eastern                           March 10, 2000
------------------------------------                  Products Pipeline Company
            Carl D. Clay

           DERRILL CODY*                              Director of Texas Eastern                           March 10, 2000
------------------------------------                  Products Pipeline Company
            Derrill Cody

         JOHN P. DESBARRES*                           Director of Texas Eastern                           March 10, 2000
------------------------------------                  Products Pipeline Company
         John P. DesBarres

            JIM W. MOGG*                              Director of Texas Eastern                           March 10, 2000
------------------------------------                  Products Pipeline Company
            Jim W. Mogg

        RICHARD J. OSBORNE*                                                                               March 10, 2000
------------------------------------                  Director of Texas Eastern
         Richard J. Osborne                           Products Pipeline Company

           RUTH G. SHAW*
------------------------------------                  Director of Texas Eastern                           March 10, 2000
            Ruth G. Shaw                              Products Pipeline Company
</TABLE>


* Signed on behalf of the Registrant and each of these persons:

         By:     /s/ CHARLES H. LEONARD
            ---------------------------------------
             (Charles H. Leonard, Attorney-in-Fact)



                                       40



<PAGE>   43

                        CONSOLIDATED FINANCIAL STATEMENTS
                            OF TEPPCO PARTNERS, L.P.

                          INDEX TO FINANCIAL STATEMENTS



<TABLE>
<CAPTION>
                                                                          PAGE
                                                                          ----
<S>                                                                       <C>
Independent Auditors' Report .........................................     F-2

Consolidated Balance Sheets as of December 31, 1999 and 1998 .........     F-3

Consolidated Statements of Income for the years ended
   December 31, 1999, 1998 and 1997 ..................................     F-4

Consolidated Statements of Cash Flows for the years ended
   December 31, 1999, 1998 and 1997 ..................................     F-5

Consolidated Statements of Partners' Capital for the years
   ended December 31, 1999, 1998 and 1997 ............................     F-6

Notes to Consolidated Financial Statements ...........................     F-7
</TABLE>





                                       F-1


<PAGE>   44
                          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, 1999 and 1998, 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, 1999. 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 generally accepted auditing
standards. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1999 in conformity with generally accepted accounting
principles.



                                                                        KPMG LLP




Houston, Texas
January 14, 2000



                                      F-2
<PAGE>   45



                              TEPPCO PARTNERS, L.P.

                           CONSOLIDATED BALANCE SHEETS
                                 (IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                                       DECEMBER 31,
                                                                              ---------------------------
                                                                                  1999           1998
                                                                              ------------   ------------

<S>                                                                           <C>            <C>
                                       ASSETS
Current assets:
   Cash and cash equivalents ..............................................   $     32,593   $     47,423
   Short-term investments .................................................          1,475          3,269
   Accounts receivable, trade .............................................        205,766        113,541
   Inventories ............................................................         16,766         17,803
   Other ..................................................................          6,409          3,909
                                                                              ------------   ------------
           Total current assets ...........................................        263,009        185,945
                                                                              ------------   ------------
Property, plant and equipment, at cost (Net of accumulated depreciation
   and amortization of $220,467 and $193,858) .............................        720,919        671,611
Investments ...............................................................          5,242          6,490
Intangible assets .........................................................         34,926         36,842
Other assets ..............................................................         17,277         16,031
                                                                              ------------   ------------
           Total assets ...................................................   $  1,041,373   $    916,919
                                                                              ============   ============

                      LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
   Accounts payable and accrued liabilities ...............................   $    201,660   $    117,933
   Accounts payable, general partner ......................................          4,741          2,815
   Accrued interest .......................................................         13,297         13,039
   Other accrued taxes ....................................................          8,822          6,739
   Other ..................................................................         14,972          9,649
                                                                              ------------   ------------
           Total current liabilities ......................................        243,492        150,175
                                                                              ------------   ------------
Senior Notes ..............................................................        389,753        389,722
Other long-term debt ......................................................         66,000         38,000
Other liabilities and deferred credits ....................................          3,073          3,407
Minority interest .........................................................          3,429          3,393
Redeemable Class B Units held by related party ............................        105,859        105,036
Partners' capital (deficit):
   General partner's interest .............................................            657           (380)
   Limited partners' interests ............................................        229,110        227,566
                                                                              ------------   ------------
           Total partners' capital ........................................        229,767        227,186
                                                                              ------------   ------------
Commitments and contingencies
           Total liabilities and partners' capital ........................   $  1,041,373   $    916,919
                                                                              ============   ============
</TABLE>


          See accompanying Notes to Consolidated Financial Statements.


                                      F-3

<PAGE>   46

                              TEPPCO PARTNERS, L.P.

                        CONSOLIDATED STATEMENTS OF INCOME
                     (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)


<TABLE>
<CAPTION>
                                                                                    YEARS ENDED DECEMBER 31,
                                                                           --------------------------------------------
                                                                              1999             1998            1997
                                                                           ------------    ------------    ------------
<S>                                                                        <C>             <C>             <C>
Operating revenues:
   Sales of crude oil and petroleum products ...........................   $  1,692,767    $    214,463    $         --
   Transportation -- refined products ..................................        123,004         119,854         107,304
   Transportation -- LPGs ..............................................         67,701          60,902          79,371
   Transportation -- crude oil and NGLs ................................         11,846           3,392              --
   Mont Belvieu operations .............................................         12,849          10,880          12,815
   Other ...............................................................         26,716          20,147          22,603
                                                                           ------------    ------------    ------------
           Total operating revenues ....................................      1,934,883         429,638         222,093
                                                                           ------------    ------------    ------------

Costs and expenses:
   Purchases of crude oil and petroleum products .......................      1,666,042         212,371              --
   Operating, general and administrative ...............................         94,340          73,850          66,982
   Operating fuel and power ............................................         31,265          27,131          30,151
   Depreciation and amortization .......................................         32,656          26,938          23,772
   Taxes -- other than income taxes ....................................         10,490           9,382           9,638
                                                                           ------------    ------------    ------------
           Total costs and expenses ....................................      1,834,793         349,672         130,543
                                                                           ------------    ------------    ------------
           Operating income ............................................        100,090          79,966          91,550
Interest expense .......................................................        (31,563)        (29,784)        (33,707)
Interest capitalized ...................................................          2,133             795           1,478
Other income -- net ....................................................          2,196           2,908           2,604
                                                                           ------------    ------------    ------------
           Income before minority interest and loss on debt
             extinguishment.............................................         72,856          53,885          61,925
Minority interest ......................................................           (736)           (544)           (625)
                                                                           ------------    ------------    ------------
     Income before loss on debt extinguishment .........................         72,120          53,341          61,300
Extraordinary loss on debt extinguishment, net of  minority interest....             --         (72,767)             --
                                                                           ------------    ------------    ------------
          Net income (loss) ............................................   $     72,120    $    (19,426)   $     61,300
                                                                           ============    ============    ============

Net income (loss) allocated to Limited Partner Unitholders .............         55,349         (18,722)         56,560
Net income allocated to Class B Unitholder .............................          7,475           1,036              --
Net income (loss) allocated to General Partner .........................          9,296          (1,740)          4,740
                                                                           ------------    ------------    ------------
          Total Net Income Allocated ...................................   $     72,120    $    (19,426)   $     61,300
                                                                           ============    ============    ============

BASIC AND DILUTED INCOME (LOSS) PER LIMITED PARTNER AND CLASS B UNIT:
     Income before extraordinary loss on debt extinguishment ...........   $       1.91    $       1.61    $       1.95
     Extraordinary loss on debt extinguishment .........................             --           (2.21)             --
                                                                           ------------    ------------    ------------
          Net income (loss) ............................................   $       1.91    $      (0.60)   $       1.95
                                                                           ============    ============    ============

Weighted average Limited Partner and Class B Units outstanding: ........         32,917          29,655          29,000
</TABLE>

          See accompanying Notes to Consolidated Financial Statements.

                                      F-4

<PAGE>   47

                              TEPPCO PARTNERS, L.P.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                  YEARS ENDED DECEMBER 31,
                                                                         --------------------------------------------
                                                                             1999            1998             1997
                                                                         ------------    ------------    ------------
<S>                                                                      <C>             <C>             <C>
Cash flows from operating activities:
   Net income (loss) .................................................   $     72,120    $    (19,426)   $     61,300
   Adjustments to reconcile net income to cash provided by
     operating activities:
      Depreciation and amortization ..................................         32,656          26,938          23,772
      Extraordinary loss on early extinguishment of debt .............             --          72,767              --
      Loss (gain) on sale of property, plant and equipment ...........             --            (356)            467
      Equity in loss of affiliate ....................................            393             189              --
      Increase in accounts receivable ................................        (92,225)        (93,715)         (1,500)
      Decrease (increase) in inventories .............................          1,037             493          (2,180)
      Decrease (increase) in other current assets ....................         (2,500)            264            (802)
      Increase in accounts payable and accrued expenses ..............         93,317         106,350           2,322
      Other ..........................................................         (1,728)           (289)            225
                                                                         ------------    ------------    ------------
           Net cash provided by operating activities .................        103,070          93,215          83,604
                                                                         ------------    ------------    ------------

Cash flows from investing activities:
   Proceeds from cash investments ....................................          6,275           3,105          25,040
   Purchases of cash investments .....................................         (3,235)           (748)         (6,180)
   Insurance proceeds related to damaged assets ......................             --              --           1,046
   Purchase of fractionator assets and related intangible assets .....             --         (40,000)             --
   Purchase of crude oil and NGL systems .............................         (2,250)         (1,989)             --
   Proceeds from the sale of property, plant and equipment ...........             --             525           1,377
   Capital expenditures ..............................................        (77,431)        (23,432)        (32,931)
                                                                         ------------    ------------    ------------
           Net cash used in investing activities .....................        (76,641)        (62,539)        (11,648)
                                                                         ------------    ------------    ------------

Cash flows from financing activities:
   Principal payment, First Mortgage Notes ...........................             --        (326,512)        (13,000)
   Prepayment premium, First Mortgage Notes ..........................             --         (70,093)             --
   Issuance of Senior Notes ..........................................             --         389,694              --
   Debt issuance cost, Senior Notes ..................................             --          (3,651)             --
   Issuance of term loan .............................................         25,000          38,000              --
   Proceeds from revolving credit facility ...........................          8,000              --              --
   Repayments on revolving credit facility ...........................         (5,000)             --              --
   General partner's contributions ...................................             --           2,122              --
   Distributions .....................................................        (69,259)        (56,774)        (49,042)
                                                                         ------------    ------------    ------------
           Net cash used in financing activities .....................        (41,259)        (27,214)        (62,042)
                                                                         ------------    ------------    ------------

Net increase (decrease) in cash and cash equivalents .................        (14,830)          3,462           9,914
Cash and cash equivalents at beginning of period .....................         47,423          43,961          34,047
                                                                         ------------    ------------    ------------
Cash and cash equivalents at end of period ...........................   $     32,593    $     47,423    $     43,961
                                                                         ============    ============    ============

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) .......   $     28,625    $     26,179    $     32,084
</TABLE>


          See accompanying Notes to Consolidated Financial Statements.

                                      F-5

<PAGE>   48

                              TEPPCO PARTNERS, L.P.

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
                                 (IN THOUSANDS)


<TABLE>
<CAPTION>
                                                          GENERAL        LIMITED
                                                         PARTNER'S       PARTNERS'
                                                         INTEREST        INTERESTS         TOTAL
                                                       ------------    ------------    ------------

<S>                                                   <C>             <C>             <C>
Partners' capital at December 31, 1996 .............   $      4,616    $    285,695    $    290,311
    1997 net income allocation .....................          4,740          56,560          61,300
    1997 cash distributions ........................         (3,596)        (44,951)        (48,547)
    Option exercises, net of Unit repurchases ......             --             (97)            (97)
                                                       ------------    ------------    ------------
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
                                                       ============    ============    ============
</TABLE>


          See accompanying Notes to Consolidated Financial Statements.


                                      F-6

<PAGE>   49

                              TEPPCO PARTNERS, L.P.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

     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. Texas
Eastern Products Pipeline Company (the "Company" or "General Partner") owns a 1%
general partner interest in the Partnership and 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. and 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.

     On June 18, 1997, PanEnergy Corp ("PanEnergy") and Duke Power Company
completed a previously announced merger. At closing, the combined companies
became Duke Energy Corporation ("Duke Energy"). The Company, previously a
wholly-owned subsidiary of PanEnergy, became an indirect wholly-owned subsidiary
of Duke Energy on the date of the merger.

     During 1990, 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, 1999, 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, 1999, no such Limited Partner
Units had been sold by the Company.

     On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All references to the number of Units and per Unit amounts in the consolidated
financial statements and related notes have been restated to reflect the
two-for-one split for all periods presented.

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 Products
OLP and the Crude Oil OLP, 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.



                                      F-7

<PAGE>   50
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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, the
uncertainty of potential recoveries from third parties and the evolving nature
of environmental laws and regulations.

BUSINESS SEGMENTS

     The Partnership operates in two industry segments: refined products and
liquefied petroleum gases ("LPGs") transportation; and crude oil and natural gas
liquids ("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 crude oil and NGLs transportation segment was acquired as a unit, 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."

REVENUE RECOGNITION

     Substantially all revenues of the Products OLP are derived from interstate
and intrastate transportation of petroleum products, storage and terminaling of
petroleum products, fractionation of natural gas liquids (effective March 31,
1998), 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 net of product cost when the
products are sold. Fractionation revenues are recognized ratably over the
contract year as products are delivered to DEFS.

     Revenues of the Crude Oil OLP 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, LLC ("TCO"), which typically occurs upon receipt of the
product by TCO. 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 their sales contracts so that crude oil price fluctuations do not
materially affect the margin which they receive. 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.


                                      F-8

<PAGE>   51
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


USE OF COMMODITY DERIVATIVES

     The Partnership, primarily through its Crude Oil OLP, manages its exposure
from existing contractual commitments and commodity price risk through forward
and futures contracts. For derivative contracts to qualify as a hedge, the price
movements in the commodity derivative must be highly correlated with the
underlying hedged commodity. 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 such
instruments are reported in the consolidated balance sheet as current assets or
current liabilities. 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 strict policies which limit its exposure to
market risk and require daily reporting to management of potential financial
exposure. At December 31, 1999 and 1998, outstanding commodity derivative
contracts held for trading purposes were not material.

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
Products OLP 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 rate used to capitalize interest on borrowed
funds was 7.01%, 7.02% and 10.09% for 1999, 1998 and 1997, 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, 1999 and
1998, the Partnership's reported amount of net assets for financial reporting
purposes exceeded its tax basis by approximately $293 million and $272 million,
respectively.


                                      F-9

<PAGE>   52
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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 Units and Class B outstanding (a total of 32.9 million Units for
1999, 29.7 million Units for 1998, and 29.0 million Units for 1997). 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 $9.3 million (representing 12.89%) of net income for the
year ended December 31, 1999, $1.7 million (representing 8.96%) of the net loss
for the year ended December 31, 1998, and $4.7 million (representing 7.73%) of
net income for the year ended December 31, 1997.

     Diluted net income per Limited Partner 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 1999, 1998 and 1997 the denominator was increased by
12,141 Units, 45,278 Units and 39,120 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 items,
minimum pension liability adjustments and unrealized gains and losses on certain
investments to be reported in a financial statement. As of December 31, 1999,
1998, and 1997, the Partnership's comprehensive income (loss) equaled its
reported income (loss).

NEW ACCOUNTING PRONOUNCEMENTS

     In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." This
statement establishes standards for and disclosures of derivative instruments
and hedging activities. In July 1999, the FASB issued SFAS No. 137 to delay the
effective date of SFAS No. 133 until fiscal years beginning after June 15, 2000.
The Partnership expects to adopt this standard effective January 1, 2001. The
Partnership has not determined the impact of this statement on its financial
condition and results of operations.

     In December 1998, the Emerging Issues Task Force ("EITF") reached a
consensus on Issue 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." Issue 98-10 was effective for fiscal years
beginning after December 15, 1998, and requires certain energy trading contracts
to be recorded at fair value on the balance sheet, with the change in fair value
included in earnings. The implementation of this consensus was immaterial to the
Partnership.

                                      F-10

<PAGE>   53
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 3.  ACQUISITIONS

     Effective March 31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado"), a
wholly-owned subsidiary of the Products OLP, purchased two fractionation
facilities located in Weld County, Colorado, from Duke Energy Field Services,
Inc. ("DEFS"), a wholly-owned subsidiary of Duke Energy. The transaction totaled
approximately $40 million and was accounted for under the purchase method of
accounting.

     Effective November 1, 1998, the Crude Oil OLP, through its wholly-owned
subsidiary TEPPCO Crude Oil, LLC ("TCO"), acquired substantially all of the
assets of Duke Energy Transport and Trading Company ("DETTCO") from Duke Energy
for approximately $106 million. In consideration for such assets, Duke Energy
received 3,916,547 Class B Limited Partnership Units ("Class B Units"). The
Class B Units are substantially identical to the 29,000,000 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, 1999. Collectively, the Limited Partner Units
and Class B Units are referred to as "Units." 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 from November 1, 1998.

     The following table presents the unaudited pro forma results of the
Partnership as though the acquisitions of the fractionation facilities and the
DETTCO assets occurred at January 1, 1997 (in thousands, except per Unit
amounts).

<TABLE>
<CAPTION>
                                                                       YEARS ENDED DECEMBER 31,
                                                                    ----------------------------
                                                                        1998            1997
                                                                    ------------    ------------
<S>                                                                 <C>             <C>
Revenues ........................................................   $  1,412,929    $  1,430,451
Operating income ................................................         90,074         105,942
Income before extraordinary loss on debt extinguishment .........         62,781          73,197
Net Income (loss) ...............................................         (9,986)         73,197

Basic and diluted income per Unit before extraordinary item .....   $       1.71    $       2.05
Basic and diluted net income (loss) per Unit ....................   $      (0.28)   $       2.05
</TABLE>

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 1999, 1998 and 1997, direct expenses incurred by the general partner in
the amount of $49.6 million, $38.8 million and $38.2 million, respectively, were
charged to the Partnership. Substantially all such costs related to payroll and
payroll related expenses, which included $2.9 million, $1.0 million and $1.8
million of expense for incentive compensation plans for each of the years ended
1999, 1998 and 1997, respectively. The increase in direct expenses in 1999 from
the prior years was primarily attributable to labor cost related to the addition
of the Crude Oil OLP, effective November 1, 1998.


                                      F-11

<PAGE>   54
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     For 1999, 1998 and 1997, expenses for administrative service and overhead
allocated to the Partnership by the general partner (including Duke Energy and
its affiliates) amounted to $2.1 million, $2.7 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, TEPPCO
Colorado 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
$7.3 million for the year ended December 31, 1999, 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 $0.8 million
for the year ended December 31, 1999, and $0.7 million from April 1, 1998
through December 31, 1998.

     Included with the DETTCO assets purchased effective November 1, 1998 was
the 90-mile long 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 the year ended December 31, 1999 and $0.2
million for the two months ended December 31, 1998.

NOTE 5. INVESTMENTS

SHORT-TERM INVESTMENTS

     The Partnership routinely invests cash in liquid short-term investments as
part of its cash management program. Investments with maturities at date of
purchase of 90-days or less are considered cash and cash equivalents. All
short-term investments are classified as held-to-maturity securities and are
stated at amortized cost. At December 31, 1999 and 1998, short-term investments
consisted of $1.5 million and $3.3 million, respectively, of investment-grade
corporate notes, with maturities at such date of less than one-year. The
aggregate fair value of such securities approximates amortized cost at December
31, 1999 and 1998.

LONG-TERM INVESTMENTS

     At December 31, 1999 and 1998, the Partnership had $5.2 million and $6.5
million, respectively, invested in investment-grade corporate notes, which have
varying maturities until 2004. These securities are classified as
held-to-maturity securities and are stated at amortized cost. The aggregate fair
value of such securities approximates amortized cost at December 31, 1999 and
1998.


                                      F-12

<PAGE>   55
                              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:

<TABLE>
<CAPTION>
                                                                                     DECEMBER 31,
                                                                             ---------------------------
                                                                                 1999           1998
                                                                             ------------   ------------
                                                                                   (IN THOUSANDS)
<S>                                                                          <C>            <C>
Gasolines ................................................................   $      3,270   $      4,224
Propane ..................................................................            223          1,503
Butanes ..................................................................            605          1,654
Fuel oil .................................................................            386            564
Crude oil ................................................................          6,627          2,886
Other products ...........................................................          2,301          3,306
Materials and supplies ...................................................          3,354          3,666
                                                                             ------------   ------------
           Total .........................................................   $     16,766   $     17,803
                                                                             ============   ============
</TABLE>


     The costs of inventories did not exceed market values at December 31, 1999
and 1998.

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

     Major categories of property, plant and equipment were as follows:

<TABLE>
<CAPTION>
                                                                                     DECEMBER 31,
                                                                             ---------------------------
                                                                                 1999            1998
                                                                             ------------   ------------
                                                                                   (IN THOUSANDS)
<S>                                                                          <C>            <C>
Land and right of way ....................................................   $     54,240   $     53,901
Line pipe and fittings ...................................................        521,688        520,213
Storage tanks ............................................................        112,132        105,844
Buildings and improvements ...............................................          8,253          7,578
Machinery and equipment ..................................................        155,933        151,808
Construction work in progress ............................................         89,140         26,125
                                                                             ------------   ------------
           Total property, plant and equipment ...........................   $    941,386   $    865,469
           Less accumulated depreciation and amortization ................        220,467        193,858
                                                                             ------------   ------------
                Net property, plant and equipment ........................   $    720,919   $    671,611
                                                                             ============   ============
</TABLE>

     Depreciation and amortization expense on property, plant and equipment was
$30.7 million, $25.5 million and $23.8 million for the years ended December 31,
1999, 1998 and 1997, respectively.

NOTE 8. LONG TERM DEBT

SENIOR NOTES

     On January 27, 1998, the Products OLP 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 Products OLP, 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 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


                                      F-13

<PAGE>   56
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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 Products OLP and
will rank on a parity with all other unsecured and unsubordinated indebtedness
of the Products OLP. 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.

     At December 31, 1999, the estimated fair value of the Senior Notes was
approximately $356.0 million. 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

     In connection with the purchase of the fractionation assets from DEFS as of
March 31, 1998, TEPPCO Colorado received a $38 million bank loan from SunTrust
Bank. Proceeds from the loan were received on April 21, 1998. TEPPCO Colorado
paid interest to DEFS at a per annum rate of 5.75% on the amount of the total
purchase price outstanding for the period from March 31, 1998 until April 21,
1998. The SunTrust loan bears interest at a rate of 6.53%, which is payable
quarterly. The principal balance of the loan is payable in full on April 21,
2001. The Products OLP is guarantor on the loan. At December 31, 1999, the
estimated fair value of the loan was approximately $38.1 million. 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.

     On May 17, 1999, the Products OLP entered into a $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. The loan
agreement has a term of five years. SunTrust Bank is the administrator of the
loan. At December 31, 1999, $25 million was outstanding under the term loan
agreement. Principal will be paid quarterly as follows, with the remaining
principal balance payable on May 17, 2004.

<TABLE>
<CAPTION>
                    QUARTERLY PERIODS ENDING                           PAYMENT AMOUNT
                  ----------------------------                         --------------
<S>                                                                    <C>
                  June 2001 through March 2002                         $2.50 million
                  June 2002 through March 2003                         $3.75 million
                  June 2003 through March 2004                         $5.00 million
</TABLE>

     The interest rate for the $75 million term loan is based on the borrower's
option of either SunTrust Bank's prime rate, the federal funds rate or LIBOR
rate in effect at the time of the borrowings and is adjusted monthly, bimonthly,
quarterly or semi-annually. Interest is payable quarterly from the time of
borrowing. The interest rate for amounts outstanding under the term loan at
December 31, 1999 was 7.27%. Commitment fees for the term loan totaled
approximately $78,000 for the period from May 17, 1999 through December 31,
1999.

     Both the $38 million term loan and the $75 million term loan with SunTrust
Bank contain restrictive financial covenants that require the Products OLP to
maintain a minimum level of partners' capital as well as debt-to-earnings,
interest coverage and capital expenditure coverage ratios. At December 31, 1999,
the Products OLP was in compliance with all financial covenants related to these
loan agreements.


                                      F-14

<PAGE>   57
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


WORKING CAPITAL FACILITIES

     On May 17, 1999, the Products OLP entered into a $25 million revolving
credit agreement and TCO entered into a $30 million revolving credit agreement.
SunTrust Bank is the administrative agent on both revolving credit agreements.
The $25 million revolving credit agreement has a five year term and the $30
million revolving credit agreement has a three year term. The interest rate on
both agreements is based on the borrower's option of either SunTrust Bank's
prime rate, the federal funds rate or LIBOR rate in effect at the time of the
borrowings and is payable quarterly. Interest rates are adjusted monthly,
bimonthly, quarterly or semi-annually. The Products OLP has not made any
borrowings under this revolving credit facility. TCO had $3 million principal
amount outstanding under its revolving credit agreement as of December 31, 1999.
Commitment fees for the revolving credit agreements totaled approximately
$83,000 for the period from May 17, 1999 through December 31, 1999.

     The revolving credit agreements with SunTrust Bank contain restrictive
financial covenants that require the Products OLP and the Crude Oil OLP to
maintain a minimum level of partners' capital as well as debt-to-earnings,
interest coverage and capital expenditure coverage ratios. At December 31, 1999,
the Operating Partnerships were in compliance with all financial covenants
related to these loan agreements.

     In connection with the purchase of the DETTCO assets by TCO, Duke Capital
also agreed to guarantee the payment by TCO and its subsidiaries under certain
commercial contracts between TCO and its subsidiaries and third parties. Duke
Capital will provide up to $100 million of guarantee credit to TCO and its
subsidiaries for a period of three years from November 30, 1998. Pursuant to
this agreement, the Partnership has agreed to pay Duke Capital a commitment fee
of $100,000 per year.

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

     As discussed in Note 1 above, all per Limited Partner Unit references have
been adjusted to reflect the two-for-one split on August 10, 1998.

     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 Agreement, the Company receives
incremental incentive cash distributions on the portion that cash distributions
on a per Unit basis exceed certain target thresholds as follows:


                                      F-15

<PAGE>   58
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<TABLE>
<CAPTION>
                                                                                                  GENERAL
                                                                              UNITHOLDERS         PARTNER
                                                                             --------------    -------------
<S>                                                                          <C>               <C>
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%
</TABLE>

     The following table reflects the allocation of total distributions paid for
the years ended December 31, 1999, 1998 and 1997 (in thousands, except per Unit
amounts).

<TABLE>
<CAPTION>
                                                                YEARS ENDED DECEMBER 31,
                                                       ------------------------------------------
                                                           1999           1998           1997
                                                       ------------   ------------   ------------
<S>                                                    <C>            <C>            <C>
Limited Partner Units ..............................   $     53,650   $     50,750   $     44,950
1% General Partner Interest ........................            609            513            454
General Partner Incentive ..........................          7,650          4,938          3,143
                                                       ------------   ------------   ------------
      Total Partners' Capital Cash Distributions ...         61,909         56,201         48,547
Class B Units ......................................          6,651             --             --
Minority Interest ..................................            699            573            495
                                                       ------------   ------------   ------------
      Total Cash Distributions Paid ................   $     69,259   $     56,774   $     49,042
                                                       ============   ============   ============

Total Cash Distributions Paid Per Unit .............   $       1.85   $       1.75   $       1.55
                                                       ============   ============   ============
</TABLE>

     On February 4, 2000, the Partnership paid a cash distribution of $0.475 per
Limited Partner Unit and Class B Unit for the quarter ended December 31, 1999.
The fourth quarter 1999 cash distribution totaled $18.3 million.

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:

<TABLE>
<CAPTION>
                                                           PERFORMANCE
                                                              UNITS           EARNINGS          EXPIRATION
                                                           OUTSTANDING       THRESHOLD             YEAR
                                                          --------------    ------------       -------------
<S>                                                       <C>                <C>                <C>
Performance Unit Grants:
   1994 .................................................         80,000      $     1.00           2006
   1995 .................................................         70,000      $     1.25           2007
   1997 .................................................         11,000      $    1.875           2009
</TABLE>


                                      F-16

<PAGE>   59
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



<TABLE>
<CAPTION>
                                                             OPTIONS           OPTIONS               EXERCISE
                                                           OUTSTANDING       EXERCISABLE               RANGE
                                                          --------------    --------------       -----------------
<S>                                                       <C>               <C>                  <C>
Limited Partner Unit Options:
  Outstanding at December 31, 1996....................            93,298            32,294         $13.81 - $14.34
      Granted.........................................            11,100                --                  $21.66
      Became exercisable..............................                --            37,674         $13.81 - $14.34
      Exercised.......................................          (11,870)          (11,870)         $13.81 - $14.34
                                                          --------------    --------------
  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
                                                          ==============    ==============
</TABLE>

     As discussed in Note 2, the Partnership uses the intrinsic value method for
recognizing stock-based expense. The exercise price of all options awarded under
the 1994 LTIP equaled the market price of the Partnership's 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 $37,138, $93,771 and $226,152 during 1997, 1998 and 1999,
respectively. Under the provisions of SFAS No. 123, the pro forma disclosures
above include only the effects of Unit options granted by the Partnership
subsequent to December 31, 1994. The disclosures as required by SFAS 123 are not
representative of the effects on reported net income for future years as options
vest over several years and additional awards may be granted in subsequent
years.

     For purposes of determining compensation costs using the provisions of SFAS
123, the fair value of 1999, 1998 and 1997 option grants were determined using
the Black-Scholes option-valuation model. The key input variables used in
valuing the options were:

<TABLE>
<CAPTION>
                                     1999             1998           1997
                                 ------------    ------------    ------------
<S>                              <C>             <C>             <C>
Risk-free interest rate ......            4.7%            5.5%            6.3%
Dividend yield ...............            7.6%            7.8%            7.2%
Unit price volatility ........             23%             18%             18%
Expected option lives ........        6 years         6 years         5 years
</TABLE>

NOTE 12. LEASES

     The Partnership utilizes leased assets in several areas of its operations.
Total rental expense during 1999, 1998 and 1997 was $8.7 million, $4.8 million
and $3.9 million, respectively. The minimum rental payments under the
Partnership's various operating leases for the years 2000 through 2004 are $6.7
million, $6.2 million, $4.0 million, $3.3 million and $3.0 million,
respectively. Thereafter, payments aggregate $5.9 million through 2007.

     In May 1997, the Partnership completed construction to connect the pipeline
system to Colonial Pipeline Company's ("Colonial") pipeline at Beaumont, Texas.
The Partnership entered into a 10-year capacity lease with Colonial, whereby the
Partnership guaranteed a minimum monthly through-put rate for the connection.
The minimum lease payments related to this agreement are included in the amounts
disclosed above.


                                      F-17

<PAGE>   60
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 13. EMPLOYEE BENEFITS

RETIREMENT PLANS

     The Company's employees are included with other affiliates of Duke Energy
in a noncontributory, trustee-administered pension plan. Through December 31,
1998, the plan provided retirement benefits (i) for eligible employees of
certain subsidiaries that are generally based on an employee's years of benefit
accrual service and highest average eligible earnings, and (ii) for eligible
employees of certain other subsidiaries under a cash balance formula. In 1998, a
significant amount of lump sum payouts were made from the plan resulting in a
settlement gain of $10 million. The Company's portion of this gain was $0.6
million. Effective January 1, 1999 the benefit formula for all eligible
employees, was changed to a cash balance formula. Under a cash balance formula,
a plan participant accumulates a retirement benefit based upon a percentage of
current pay, which may vary with age and years of service, and current interest
credits. The components of net pension benefit costs for the years ended
December 31, 1999, 1998 and 1997 were as follows (in thousands):

<TABLE>
<CAPTION>
                                                           1999       1998       1997
                                                          -------    -------    -------
<S>                                                       <C>        <C>        <C>
Service cost benefit earned during the year ...........   $ 1,651    $ 1,699    $ 1,509
Interest cost on projected benefit obligation .........     2,666      2,041      2,359
Expected return on plan assets ........................    (2,243)    (1,555)    (1,773)
Amortization of prior service cost ....................         2        (27)       (30)
Amortization of net transition (asset) liability ......        15         (5)        (3)
Recognized net actuarial loss .........................       285         --         --
Settlement gain .......................................        --       (554)        --
                                                          -------    -------    -------
      Net pension benefits costs ......................   $ 2,376    $ 1,599    $ 2,062
                                                          =======    =======    =======
</TABLE>

      The assumptions affecting pension expense include:

<TABLE>
<CAPTION>
                                                             1999    1998    1997
                                                             -----   -----   -----

<S>                                                          <C>     <C>     <C>
Discount rate .........................................      7.50%   6.75%   7.25%
Salary increase .......................................      4.50%   4.67%   4.15%
Expected long-term rate of return on plan assets ......      9.25%   9.25%   9.25%
</TABLE>

     Duke Energy also sponsors an employee savings plan which covers
substantially all employees. Plan contributions on behalf of the Company of $2.2
million, $1.4 million and $1.4 million were expensed in 1999, 1998 and 1997,
respectively.

OTHER POSTRETIREMENT BENEFITS

     Duke Energy and most of its subsidiaries provide certain health care and
life insurance benefits for retired employees on a contributory and
non-contributory basis. Employees become eligible for these benefits if they
have met certain age and service requirements at retirement, as defined in the
plans. Under plan amendments effective late 1998 and early 1999, health care
benefits for future retirees were changed to limit employer contributions and
medical coverage.

     Such benefit costs are accrued over the active service period of employees
to the date of full eligibility for the benefits. The net unrecognized
transition obligation, resulting from the implementation of accrual accounting,
is being amortized over approximately 20 years.

     Duke Energy is using an investment account under section 401(h) of the
Internal Revenue Code, a retired lives reserve (RLR) and multiple voluntary
employees' beneficiary association (VEBA) trusts under section 501(c)(9) of the
Internal Revenue Code to partially fund post retirement benefits. The 401(h)
vehicles, which provide for tax deductions for contributions and tax-free
accumulation of investment income, partially fund


                                      F-18

<PAGE>   61
                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

postretirement health care benefits. The RLR, which has tax attributes similar
to 401(h) funding, partially funds postretirement life insurance obligations.
Certain subsidiaries use the VEBA trusts to partially fund accrued
postretirement health care benefits and fund post retirement life insurance
obligations. The components of net postretirement benefits cost for the years
ended December 31, 1999, 1998 and 1997 were as follows (in thousands):

<TABLE>
<CAPTION>
                                                                           1999            1998           1997
                                                                       ------------    ------------    ------------

<S>                                                                    <C>             <C>             <C>
Service cost benefit earned during the year ........................   $        172    $        439    $        350
Interest cost on accumulated postretirement benefit obligation .....            500             796             703
Expected return on plan assets .....................................           (299)           (240)           (172)
Amortization of prior service cost .................................           (384)              3               4
Amortization of net transition liability ...........................            217             202             202
Recognized net actuarial loss ......................................             --             173              68
                                                                       ------------    ------------    ------------
      Net postretirement benefits costs ............................   $        206    $      1,373    $      1,155
                                                                       ============    ============    ============
</TABLE>


       The assumptions affecting postretirement benefits expense include:


<TABLE>
<CAPTION>
                                                             1999          1998          1997
                                                          ----------    ----------    ----------

<S>                                                       <C>           <C>           <C>
Discount rate .........................................         7.50%         6.75%         7.25%
Salary increase .......................................         4.50%         4.67%         4.33%
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%
</TABLE>

     For measurement purposes, a 5% weighted average rate of increase in the per
capita cost of covered health care benefits was assumed for 1999. Assumed health
care cost trend rates have a significant effect on the amounts reported for the
health care plans. The below table indicates the effect on the total service and
interest costs component and on the postretirement benefit obligation of a 1%
increase or 1% decrease in the assumed health care cost trend rates in each
future year (in thousands).

<TABLE>
<CAPTION>
                                                                   1%            1%
                                                               INCREASE      DECREASE
                                                               ----------   ----------
<S>                                                            <C>          <C>
Effect on total of service and interest cost components ....   $        9   $       (8)
Effect on postretirement benefit obligation ................   $      128   $     (108)
</TABLE>

POSTEMPLOYMENT BENEFITS

     The Partnership accrues expense for certain benefits provided to former or
inactive employees after employment but before retirement. During 1999, 1998 and
1997, the Partnership recorded $0.3 million, $0.5 million and $0.5 million,
respectively, of expense for such benefits.

NOTE 14. CONTINGENCIES

     In the fall of 1999, the Company and the Partnership became involved in a
lawsuit 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), plaintiffs contend, among other things,
that the Company and other defendants stored and disposed of toxic and hazardous
substances and hazardous wastes in such a manner which caused the materials to
be released into the air, soil and water. They further contend that such release
caused damages to the plaintiffs. In their Complaint, the plaintiffs allege
strict liability for both personal injury and property damage together with
gross negligence, continuing nuisance, trespass, criminal mischief and

                                      F-19

<PAGE>   62

                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


loss of consortium. Furthermore, the plaintiffs are seeking compensatory,
punitive and treble damages. The Company has filed an Answer to the Complaint,
denying the allegations, as well as various other motions. This case is in the
early stages of discovery and is not covered by insurance. The Company is
defending itself vigorously against this lawsuit. The Partnership cannot
estimate the loss, if any, associated with this pending lawsuit.

     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 or results of operations.

     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, 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 $0.8 million at December 31, 1999 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.

     Tariff 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").

     In May 1999, the Products OLP filed an application with the FERC to charge
Market Based Rates for substantially all refined products transportation
tariffs. Such application is currently under review by the FERC. The FERC
approved a request of the Products OLP waiving the requirement to adjust refined
products transportation tariffs pursuant to the PPI Index while its Market Based
Rates application is under review. Under the PPI Index, refined products
transportation rates in effect on June 30, 1999 would have been reduced by
approximately 1.83% effective July 1, 1999. If any portion of the Market Based
Rates application is denied by the FERC, the Products OLP has agreed to refund,
with interest, amounts collected after June 30, 1999, under the tariff rates in
excess of the PPI Index. As a result of the refund obligation potential, the
Partnership has deferred all revenue recognition of rates charged in excess of
the PPI Index. At December 31, 1999, the amount deferred for possible rate
refunds, including interest, totaled approximately $0.8 million.

     In July 1999, certain shippers filed protests with the FERC on the Products
OLP's application for Market Based Rates in four destination markets. The
Partnership believes it will prevail in a competitive market determination in
those destination markets under protest.


                                      F-20

<PAGE>   63

                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     Substantially all of the petroleum products transported and stored by the
Partnership are owned by its customers. At December 31, 1999, the Partnership
had approximately 12.8 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 it believes to be adequate to cover product losses through
circumstances beyond its control.

NOTE 15. SEGMENT DATA

     The Partnership operates in two industry segments: refined products and
LPGs transportation, which operates through the Products OLP; and crude oil and
NGLs transportation and marketing, which operates through the Crude Oil OLP.

     Operations of the Products OLP 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 Products
OLP is one of the largest pipeline common carriers of refined petroleum products
and LPGs in the United States. The Partnership owns and operates an approximate
4,300-mile pipeline system extending from southeast Texas through the central
and midwestern United States to the northeastern United States.

     The Crude Oil OLP 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. The Crude Oil OLP's gathering,
transportation and storage assets include approximately 2,400 miles of pipeline
and 1.6 million barrels of storage.

     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 with the
acquisition from DETTCO 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, 1999 and 1998. Segment data has not been provided for
the year ended December 31, 1997, as the Partnership operated as one business
segment prior to November 1, 1998.

<TABLE>
<CAPTION>
                                             PRODUCTS OLP    CRUDE OIL OLP   CONSOLIDATED
                                             ------------    ------------    ------------
1999                                                        (IN THOUSANDS)
<S>                                          <C>             <C>             <C>
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
                                             ============    ============    ============

Identifiable 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
</TABLE>


                                      F-21

<PAGE>   64

                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<TABLE>
<CAPTION>
                                             PRODUCTS       CRUDE OIL
                                               OLP              OLP       CONSOLIDATED
                                           ------------    ------------    ------------
1998                                                      (IN THOUSANDS)
<S>                                        <C>             <C>             <C>
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
                                           ============    ============    ============

Identifiable 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
</TABLE>

NOTE 16. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
                                                                  FIRST          SECOND           THIRD         FOURTH
                                                                 QUARTER         QUARTER         QUARTER        QUARTER
                                                               ------------    ------------    ------------   ------------
                                                                        (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S>                                                            <C>             <C>             <C>            <C>
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

1998 (1)
Operating revenues .........................................   $     50,205    $     51,560    $     54,229   $    273,644
Operating income ...........................................         19,514          18,929          19,722         21,801
Income before extraordinary item (2) .......................         13,155          12,546          12,734         14,906
Net income (loss) ..........................................   $    (59,612)   $     12,546    $     12,734   $     14,906
Basic and diluted income per Limited Partner and
      Class B Unit, before extraordinary item (2) (3) ......   $       0.41    $       0.39    $       0.39   $       0.42
Basic and diluted net income (loss) per Limited
      Partner and Class B Unit (3) .........................   $      (1.87)   $       0.39    $       0.39   $       0.42
</TABLE>

----------------

(1)  Per Unit amounts for 1998 have been adjusted to reflect the two-for-one
     split on August 10, 1998.

(2)  Extraordinary item reflects the $73.5 million loss related to the early
     extinguishment of the First Mortgage Notes on January 27, 1998.

(3)  Per Unit calculation includes 3,916,547 Class B Units issued for the
     acquisition of the crude oil and NGL assets, effective November 1, 1998.


                                      F-22


<PAGE>   65
                                 EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER                                DESCRIPTION
-------                               -----------
<S>      <C>
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 3.3 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).
</TABLE>


<PAGE>   66

<TABLE>
<S>      <C>
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 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).


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.

*10.8    Duke Energy Corporation Executive Cash Balance Plan.

*10.9    Duke Energy Corporation Retirement Benefit Equalization Plan.

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).

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    Credit Agreement between TEPPCO Colorado, LLC, SunTrust Bank, Atlanta,
         and Certain Lenders, dated April 21, 1998 (Filed as Exhibit 10.15 to
         Form 10-Q of TEPPCO
</TABLE>

<PAGE>   67

         Partners, L.P. (Commission File No. 1-10403) for the quarter ended
         March 31, 1998 and incorporated herein by reference).

10.15    First Amendment to Credit Agreement between TEPPCO Colorado, LLC,
         SunTrust Bank, Atlanta, and Certain Lenders, effective June 29, 1998
         (Filed as Exhibit to Form 10-Q of TEPPCO Partners, L.P. (Commission
         File No. 1-10403) for the quarter ended June 30, 1998 and incorporated
         herein by reference).

10.16    Contribution Agreement between Duke Energy Transport and Trading
         Company and TEPPCO Partners, L.P., dated October 15, 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).

10.17    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 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).

10.18    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 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).

10.19    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 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).

10.20    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).

10.21    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).

10.22    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).

10.23    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).

10.24    Credit Agreement between TE Products Pipeline Company, Limited
         Partnership, SunTrust Bank, Atlanta, and Certain Lenders, dated May 17,
         1999 (Filed as Exhibit 10.26 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).

10.25    Credit Agreement between TEPPCO Crude Oil, LLC, SunTrust Bank, Atlanta,
         and Certain Lenders, dated May 17, 1999 (Filed as Exhibit 10.27 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).

10.26    Second Amendment to Credit Agreement between TEPPCO Colorado, LLC,
         SunTrust Bank, Atlanta, and Certain Lenders, effective May 17, 1999
         (Filed as Exhibit 10.28 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).

10.27    Form of Employment and Non-Compete Agreement between the Company and
         Samuel N. Brown, J. Michael Cockrell, William S. Dickey, and Sharon S.
         Stratton effective


<PAGE>   68
<TABLE>
<S>      <C>
         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).


10.28    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).

10.29    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).

10.30    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).

21.1     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).

*24      Power of Attorney.

*27      Financial Data Schedule as of and for the year ended December 31, 1999.
</TABLE>

---------------

* Filed herewith.