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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





FORM 10-K


þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934




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
Partner Interests |  | New York Stock Exchange 

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  þ  No  o

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. Yes  o

Indicate by check mark whether the registrant is an accelerated filer (as defined in
Rule 12b-2 of the Act). Yes  þ  No  o

At June 30, 2003, the aggregate market value of the registrants Limited Partner Units
held by non-affiliates was $2,103,612,900, which was computed using the average of the
high and low sales prices of the Limited Partner Units on June 30, 2003.

Limited Partner Units outstanding as of February 20, 2004: 62,998,554.

Documents Incorporated by Reference: None

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TABLE OF CONTENTS



|                                              |                                                                                               |  |  |  |  |  |  | 
|--------------------------------------------- | --------------------------------------------------------------------------------------------- |  |  |  |  |  |  | 
|                                              | Items 1 and 2. Business and Properties                                                       
|                                              | Item 3. Legal Proceedings                                                                    
|                                              | Item 4. Submission of Matters to a Vote of Security Holders                                  
|PART II                                      
|                                              | Item 5. Market for Registrants Units and Related Unitholder Matters                         
|                                              | Item 6. Selected Financial Data                                                              
|                                              | Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
|                                              | Item 7A. Quantitative and Qualitative Disclosures About Market Risk                          
|                                              | Item 8. Financial Statements and Supplementary Data                                          
|                                              | Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
|                                              | Item 9A. Controls and Procedures                                                             
|PART III                                     
|                                              | Item 10. Directors and Executive Officers of the Registrant                                  
|                                              | Item 11. Executive Compensation                                                              
|                                              | Item 12. Security Ownership of Certain Beneficial Owners and Management                      
|                                              | Item 13. Certain Relationships and Related Transactions                                      
|                                              | Item 14. Principal Accounting Fees and Services                                              
|PART IV                                      
|                                              | Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K                     
|SIGNATURES                                   
|INDEX TO EXHIBIT                             
|Statement of Computation of Ratio of Earnings
|Consent of KPMG LLP                          
|Powers of Attorney                           
|Certification of CEO pursuant to Section 302 
|Certification of CFO pursuant to Section 302 
|Certification of CEO pursuant to Section 906 
|Certification of CFO pursuant to Section 906 
|Charter of the Audit Committee of the Board  



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TABLE OF CONTENTS

|                  |  |                                                                                       |  |          |    |  |  |  |  | 
|----------------- |  | ------------------------------------------------------------------------------------- |  | -------- | -- |  |  |  |  | 
|                  |  |                                                                                       |  | PART I   |    |  |  | 
|ITEMS
1.   AND 2. |  | Business and Properties                                                               |  |          | 1  | 
|ITEM 3.           |  | Legal Proceedings                                                                     |  |          | 23 | 
|ITEM 4.           |  | Submission of Matters to a Vote of Security Holders                                   |  |          | 24 | 
|                  |  |                                                                                       |  | PART II  |    |  |  | 
|ITEM 5.           |  | Market for Registrants Units and Related Unitholder Matters                          |  |          | 24 | 
|ITEM 6.           |  | Selected Financial Data                                                               |  |          | 26 | 
|ITEM 7.           |  | Managements Discussion and Analysis of Financial Condition and Results of Operations |  |          | 27 | 
|ITEM 7A.          |  | Quantitative and Qualitative Disclosures About Market Risk                            |  |          | 53 | 
|ITEM 8.           |  | Financial Statements and Supplementary Data                                           |  |          | 54 | 
|ITEM 9.           |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  |          | 54 | 
|ITEM 9A.          |  | Controls and Procedures                                                               |  |          | 54 | 
|                  |  |                                                                                       |  | PART III |    |  |  | 
|ITEM 10.          |  | Directors and Executive Officers of the Registrant                                    |  |          | 55 | 
|ITEM 11.          |  | Executive Compensation                                                                |  |          | 59 | 
|ITEM 12.          |  | Security Ownership of Certain Beneficial Owners and Management                        |  |          | 65 | 
|ITEM 13.          |  | Certain Relationships and Related Transactions                                        |  |          | 66 | 
|ITEM 14.          |  | Principal Accounting Fees and Services                                                |  |          | 69 | 
|                  |  |                                                                                       |  | PART IV  |    |  |  | 
|ITEM 15.          |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                       |  |          | 69 | 

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FORWARD-LOOKING STATEMENTS

The matters discussed in this Report 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 we expect or anticipate 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 our 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 us in
light of our experience and our perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate under the circumstances. However, whether actual results and
developments will conform with our 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 us, competitive actions by other pipeline companies, changes
in laws or regulations and other factors, many of which are beyond our control.
Consequently, all of the forward-looking statements made in this document are
qualified by these cautionary statements, and we cannot assure you that actual
results or developments that we anticipate will be realized or, even if
substantially realized, will have the expected consequences to or effect on us
or our business or operations.




Items 1 and 2.Business and Properties

General

TEPPCO Partners, L.P. (the Partnership), a Delaware limited partnership,
is a master limited partnership formed in March 1990. We operate through TE
Products Pipeline Company, Limited Partnership (TE Products), TCTM, L.P.
(TCTM) and TEPPCO Midstream Companies, L.P. (TEPPCO Midstream).
Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the
Operating Partnerships. Texas Eastern Products Pipeline Company, LLC (the
Company or General Partner), a Delaware limited liability company, serves
as our general partner and owns a 2% general partner interest in us. The
General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC
(DEFS), a joint venture between Duke Energy Corporation (Duke Energy) and
ConocoPhillips. Duke Energy holds an interest of approximately 70% in DEFS,
and ConocoPhillips holds the remaining 30%. The Company, as general partner,
performs all management and operating functions required for us, except for the
management and operations of certain of the TEPPCO Midstream assets that are
managed by DEFS on our behalf. We reimburse the General Partner for all
reasonable direct and indirect expenses incurred in managing us. TEPPCO GP,
Inc. (TEPPCO GP), our subsidiary, is the general partner of our Operating
Partnerships. We hold a 99.999% limited partner interest in the Operating
Partnerships and TEPPCO GP holds a 0.001% general partner interest.

As used in this Report, we, us, our, and the Partnership means
TEPPCO Partners, L.P. and, where the context requires, includes our
subsidiaries.

We operate and report in three business segments: transportation and
storage of refined products, liquefied petroleum gases (LPGs) and
petrochemicals (Downstream Segment); gathering, transportation, marketing and
storage of crude oil; and distribution of lubrication oils and specialty
chemicals (Upstream Segment); and gathering of natural gas, fractionation of
natural gas liquids (NGLs) and transportation of NGLs (Midstream Segment).
Our reportable segments offer different products and services and are managed
separately because each requires different business strategies.

Effective January 1, 2002, we realigned our three business segments to
reflect our entry into the natural gas gathering business and the expanded
scope of our NGLs operations. We transferred the fractionation of NGLs, which
was previously reflected as part of the Downstream Segment, to the Midstream
Segment. The operation of the NGL pipelines, which was previously reflected as
part of the Upstream Segment, was also transferred to the Midstream Segment.
We have adjusted our period-to-period comparisons to conform with the current
presentation.

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Our interstate transportation operations, including rates charged to
customers, are subject to regulations prescribed by the Federal Energy
Regulatory Commission (FERC). We refer to refined products, LPGs,
petrochemicals, crude oil, NGLs and natural gas in this Report, collectively,
as petroleum products or products.

At December 31, 2003 and 2002, we had outstanding 62,998,554 and
53,809,597 Limited Partner Units, respectively. At December 31, 2002, we had
outstanding 3,916,547 Class B Limited Partner Units (Class B Units). All of
the Class B Units were issued to Duke Energy Transport and Trading Company, LLC
(DETTCO) in connection with an acquisition of assets initially acquired in
the Upstream Segment in 1998. The Class B Units shared in income and
distributions on the same basis as the Limited Partner Units, but they were not
listed on the New York Stock Exchange. The Class B Units were not included in
partners capital at December 31, 2002, as the Class B Units could have been
converted into Limited Partner Units upon approval by the unitholders. We had
the option to seek approval for the conversion of the Class B Units into
Limited Partner Units; however, if the conversion was denied, DETTCO, as holder
of the Class B Units, would have had the right to sell them to us at 95.5% of
the 20-day average market closing price of the Limited Partner Units, as
determined under our Partnership Agreement. On April 2, 2003, we repurchased
and retired all of the 3,916,547 previously outstanding Class B Units with
proceeds from the issuance of additional Limited Partner Units (see Note 12.
Partners Capital and Distributions). Collectively, the Limited Partner Units
and Class B Units are referred to as Units.

Our strategy is to expand and improve service in our current markets,
maintain the integrity of our pipeline systems and pursue growth initiatives
that are balanced between internal projects and acquisitions. We intend to
leverage the advantages inherent in our pipeline systems to maintain our status
as a preferred provider in our market areas. We also intend to grow by
acquiring assets, from both third parties and affiliates, which complement
existing businesses or to establish new core businesses. We routinely evaluate
opportunities to acquire assets and businesses that will complement existing
operations with a view to increasing earnings and cash available for
distribution to our unitholders. We may fund additional acquisitions with cash
flow from operations, borrowings under existing credit facilities, the issuance
of debt in the capital markets, the sale of additional Units, or any
combination thereof.

Downstream Segment  Transportation and Storage of Refined Products, LPGs and Petrochemicals

Operations

We conduct business in our Downstream Segment through the following:



| |  |  | TE Products,                                                                          
| | - |  | --------------------------------------------------------------------------------------
|
| |  |  | a subsidiary which owns the northern portion of the Dean Pipeline (Dean North),     
|
| |  |  | our 50% owned equity investment in Centennial Pipeline LLC (Centennial), and        
|
| |  |  | our 50% owned equity investment in Mont Belvieu Storage Partners, L.P. (MB Storage).

Our Downstream Segment owns, operates or has investments in properties
located in 14 states. The operations of the Downstream Segment consist of
interstate transportation, storage and terminaling of petroleum products;
short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex
through MB Storage; intrastate transportation of petrochemicals and other
ancillary services.

As an interstate common carrier, our TE Products pipeline offers
interstate transportation services, pursuant to tariffs filed with the FERC, to
any shipper of refined petroleum products and LPGs who requests these 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 our pipeline system from our interstate tariffs, we also
provide storage and marketing services at key points along our pipeline
systems. Substantially all of the petroleum products transported and stored in
our pipeline systems are owned by our 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 (including gas stations and retail propane distribution
centers) or to other pipelines. Pipelines are

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generally the lowest cost method for intermediate and long-haul overland
transportation of petroleum products. The TE Products pipeline system is the
only pipeline that transports LPGs from the upper Texas Gulf Coast to the
Northeast.

Our Downstream Segment depends in large part on the level of demand for
refined petroleum products and LPGs in the geographic locations that we serve
and the ability and willingness of customers having access to the pipeline
system to supply this demand. We cannot predict the impact of future fuel
conservation measures, alternate fuel requirements, governmental regulation or
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 we serve.

The following table lists the material properties and investments of and
ownership percentages in the Downstream Segment assets as of December 31, 2003:

|                                                                    |  |           |     |  
|------------------------------------------------------------------- |  | --------- | --- | -
|                                                                    |  | Our      
|                                                                    |  | Ownership
|                                                                    |  |          
|Refined products and LPGs pipelines                                 |  |           | 100 | %
|Mont Belvieu, Texas, to Port Arthur, Texas, petrochemical pipelines |  |           | 100 | %
|Northern portion of Dean Pipeline (1)                               |  |           | 100 | %
|Centennial Pipeline LLC (2)                                         |  |           | 50  | %
|Mont Belvieu Storage Partners, L.P. (3)                             |  |           | 50  | %



---

|(1) |  | Effective January 1, 2003, the northern portion of the Dean
Pipeline was converted to transport refinery grade propylene (RGP)
from Mont Belvieu, Texas, to Point Comfort, Texas.                                                            
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Accounted for as an equity investment. Effective February 10,
2003, TE Products acquired an additional 16.7% interest in Centennial,
bringing its ownership percentage to 50%.                                                                 
|   
|(3) |  | Accounted for as an equity investment. Effective January 1, 2003,
TE Products contributed substantially all of its Mont Belvieu LPG
assets to MB Storage, a newly formed partnership with Louis Dreyfus
Energy Services L.P. (Louis Dreyfus).

Centennial Pipeline Equity Investment

In August 2000, TE Products entered into agreements with Panhandle Eastern
Pipeline Company (PEPL), a subsidiary of CMS Energy Corporation, and Marathon
Ashland Petroleum LLC (Marathon) to form Centennial. Each participant
originally owned a one-third interest in Centennial. Centennial, which
commenced operations in April 2002, owns an interstate refined petroleum
products pipeline extending from the upper Texas Gulf Coast to central
Illinois. Centennial constructed a 74-mile, 24-inch diameter pipeline
connecting TE Products facility in Beaumont, Texas, with an existing 720-mile,
26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon,
Illinois. The Centennial pipeline intersects TE Products existing mainline
pipeline near Creal Springs, Illinois, where Centennial constructed a new two
million barrel refined petroleum products storage terminal. Marathon operates
the mainline Centennial pipeline, and TE Products operates the Beaumont
origination point and the Creal Springs terminal.

TE Products interest in Centennial is not subject to any encumbrances
from mortgages or other secured debt. Centennial has unsecured debt, one third
of which, up to $50.0 million in principal, was originally guaranteed by each
owner, including TE Products. On February 10, 2003, TE Products and Marathon
each acquired an additional interest in Centennial from PEPL for $20.0 million
each, increasing their percentage ownerships in Centennial to 50% each. TE
Products and Marathon have each guaranteed one-half of Centennials debt, up to
a maximum of $75.0 million each. Through December 31, 2003, including the
amount paid for the acquisition of the additional ownership interest in
February 2003, TE Products has invested $104.9 million in Centennial.

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Mont Belvieu Storage Equity Investment

In February 2000, we entered into a joint marketing and development
alliance with Louis Dreyfus in which our Mont Belvieu LPGs storage and shuttle
transportation system was jointly marketed by Louis Dreyfus and TE Products.
The purpose of the alliance was to expand services to the upper Texas Gulf
Coast energy marketplace by increasing pipeline throughput and the mix of
products handled through the existing system and establishing new receipt and
delivery connections. The alliance was a service-oriented, fee-based venture
with no commodity trading activity. TE Products operated the facilities for
the alliance. The alliance stipulated that if certain earnings thresholds were
achieved, a partnership between TE Products and Louis Dreyfus was to be created
effective January 1, 2003. All terms and earnings thresholds were met;
therefore, as of January 1, 2003, TE Products and Louis Dreyfus formed MB
Storage.

The economic terms of the MB Storage partnership are the same as those
under the joint marketing and development alliance. TE Products contributed
property, plant and equipment with a net book value of $67.4 million to MB
Storage. TE Products continues to operate the facilities for MB Storage.
Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage
that TE Products was required to reimburse if the original joint development
and marketing agreement was terminated by either party. This deferred
liability was also contributed and converted to the capital account of Louis
Dreyfus in MB Storage. TE Products and Louis Dreyfus each own a 50% ownership
interest in MB Storage. Through December 31, 2003, excluding the contribution
of property, plant and equipment upon formation of the partnership, TE Products
has contributed $2.5 million to MB Storage. In December 2003, we received a
distribution of $5.3 million from MB Storage.

TE Products interest in MB Storage is not subject to any encumbrances
from mortgages or other secured debt. TE Products receives the first $1.8
million per quarter (or $7.15 million on an annual basis) of MB Storages gross
income less mandatory capital expenditures plus capital contributions, as
defined in the operating agreement. Any amount of MB Storages gross income in
excess of the $7.15 million is allocated evenly between TE Products and Louis
Dreyfus, except for depreciation expense. Each partner is allocated
depreciation expense based upon assets each originally contributed to MB
Storage. Depreciation expense on assets constructed or acquired by MB Storage
is allocated evenly between TE Products and Louis Dreyfus. For the year ended
December 31, 2003, TE Products sharing ratio in the earnings of MB Storage was
approximately 70.4%.

MB Storages asset base in the Mont Belvieu fractionation and storage
complex, which is the largest complex of its kind in the United States, serving
the fractionation, refining and petrochemical industries, provides substantial
capacity and flexibility for the transportation, terminaling and storage of
NGLs, LPGs and refined products. MB Storage receives revenue from the
shuttling of product from refineries and fractionators to pipelines, refineries
and petrochemical facilities on the upper Texas Gulf Coast. MB Storage has
approximately 33 million barrels of LPGs storage capacity and approximately 5
million barrels of refined products storage capacity, including storage
capacity leased to outside parties, at the Mont Belvieu fractionation and
storage complex. MB Storage includes a short-haul transportation shuttle
system, consisting of a complex system of pipelines and interconnects, that
ties Mont Belvieu to virtually every refinery and petrochemical facility on the
upper Texas Gulf Coast. MB Storage also provides truck and rail car loading
capability. Total shuttle volumes for the three years ended December 31, 2003,
2002 and 2001, were 33.1 million barrels, 28.9 million barrels and 23.1 million
barrels, respectively.

Refined Products, LPGs and Petrochemical Pipeline Systems

TE Products is one of the largest pipeline common carriers of refined
petroleum products and LPGs in the United States. TE Products owns and operates
an approximately 4,600-mile pipeline system (together with the receiving,
storage and terminaling facilities mentioned below, the Products Pipeline
System) extending from southeast Texas through the central and midwestern
United States to the northeastern United States. The Products Pipeline System
includes delivery terminals for outloading product to other pipelines, tank
trucks, rail cars or barges, and substantial storage facilities at numerous
locations. TE Products also owns two marine receiving terminals, one near
Beaumont and the other at Providence, Rhode Island. The Providence terminal is
not physically connected to the Products Pipeline System. The Products
Pipeline System also includes three parallel 12-inch diameter petrochemical
pipelines between Mont Belvieu and Port Arthur, each approximately 70 miles in
length, and 138 miles of pipeline from Mont Belvieu to Point Comfort (the
northern portion of the Dean Pipeline).

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All properties comprising the Products Pipeline System are wholly owned by
our subsidiaries and none are mortgaged or encumbered to secure funded debt.
TE Products has guaranteed up to $75.0 million of Centennials unsecured debt
(see -Centennial Pipeline Equity Investmentabove) and has also guaranteed our
unsecured debt (see Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations  Financial Condition and Liquidity).

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 Products Pipeline System extend to the Chicago,
Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia, Pennsylvania, areas.
The Products Pipeline System east of Todhunter, Ohio, is dedicated solely to
LPGs transportation and storage services, primarily for propane.

Excluding the storage facilities of Centennial and MB Storage, the
Products Pipeline System includes 27 storage facilities with an aggregate
storage capacity of 16 million barrels of refined petroleum products and 6
million barrels of LPG storage, including storage capacity leased to outside
parties. The Products Pipeline System makes deliveries to customers at 56
locations including 19 truck racks, rail car facilities and marine facilities
that we own. Deliveries to other pipelines occur at various facilities owned
by TE Products or by third parties.

The Products 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, 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 Products Pipeline Systems terminal in El Dorado,
Arkansas, before continuing as a 16-inch diameter line to Seymour. The
Products Pipeline System also has smaller diameter lines that extend laterally
from El Dorado to Helena, Arkansas, from Tyler, Texas, to El Dorado and from
McRae, Arkansas, to West Memphis, Arkansas. The line from El Dorado to Helena
has a 10-inch diameter. 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 Products Pipeline System also includes a 14-inch diameter line
from Seymour 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. The Products Pipeline System also has a 6-inch diameter pipeline
connection to the Greater Cincinnati/Northern Kentucky International Airport
and an 8-inch diameter pipeline connection to the George Bush Intercontinental
Airport in Houston. In addition, the Products Pipeline System contains
numerous lines, ranging in size from 6 inches to 20 inches in diameter,
associated with the gathering and distribution system, extending from Baytown
to Beaumont; Texas City to Baytown; Pasadena, Texas to Baytown and Baytown to
Mont Belvieu.

The Products 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 Products Pipeline System east of
Todhunter and ending in Selkirk is an 8-inch diameter line, and the line
starting at Greensburg and ending at Marcus Hook varies in diameter from 6
inches to 8 inches.

In December 2002, we completed an upgrade of our Princeton, Indiana, LPG
truck rack to increase its capacity. During the fourth quarter of 2003, we
completed a Phase I project to expand our delivery capacity of LPGs in the
Northeast. The Phase I expansion increased delivery capability to the
Northeast during the peak winter months by approximately one million barrels.
The expansion consisted of the construction of three new pump stations located
between Middletown, Ohio, and Coshocton, Ohio. During the fourth quarter of
2003, we began projects to increase our truck rack capacity in the Northeast at
locations in New York and Pennsylvania in order to improve customer service to
those areas. These projects are scheduled to be completed in early 2004.
Additionally, in 2004, we have begun a Phase II project to further expand our
delivery capability to the Northeast by constructing three new pump stations
located between Coshocton and Greensburg, Pennsylvania, and two new pump
stations located between Greensburg and Watkins Glen, New York. The Phase II
projects are anticipated to be completed during the fourth quarter of 2004. We
have also approved a project for construction of a new truck loading terminal
in Bossier City, Louisiana, which is scheduled to be completed by the end of
2004.

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TE Products also owns three 12-inch diameter common carrier petrochemical
pipelines between Mont Belvieu and Port Arthur. Each of these pipelines is
approximately 70 miles in length. The pipelines transport ethylene, propylene
and natural gasoline. We entered into a 20-year agreement in 2002 with a major
petrochemical producer for guaranteed throughput commitments. During the years
ended December 31, 2003, 2002, and 2001, we recognized $11.9 million, $11.9
million and $10.7 million, respectively, of revenue under the throughput and
deficiency contract. We began transporting product through these pipelines in
September 2001.

Our Downstream Segment also includes the operations of the northern
portion of the Dean Pipeline. Beginning in January 2003, the northern portion
of the Dean Pipeline was converted to transport RGP from Mont Belvieu to Point
Comfort. The northern portion of the Dean Pipeline consists of 138 miles of
pipeline from Mont Belvieu to Point Comfort.

We believe that our Products Pipeline System is in compliance with
applicable federal, state and local laws and regulations and accepted industry
standards and practices. We perform regular maintenance on all the facilities
of the Products Pipeline System and have an ongoing process of inspecting the
Products Pipeline System and making repairs and replacements when necessary or
appropriate. In addition, we conduct periodic air patrols of the Products
Pipeline System to monitor pipeline integrity and third-party right of way
encroachments.

Major Business Sector Markets

Our major operations in the Downstream Segment consist of the
transportation, storage and terminaling of refined petroleum products and LPGs
along our mainline system. Product deliveries, in millions of barrels (MMBbls)
on a regional basis, for the years ended December 31, 2003, 2002 and 2001, were
as follows:

|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |       | 
|----------------------------------------- | ------------------------------------ | ----------------------------- | --- | --------------------------- | ----- | ---- | - | ---- | ----- |  | - | ---- | ----- | 
|                                          |                                      |                               |     | Product Deliveries (MMBbls)
|                                          |                                      |                               |     | Years Ended December 31,   
|                                          |                                      |                               |     |                            
|                                          |                                      |                               |     | 2003                        |       | 2002 |   | 2001
|                                          |                                      |                               |     |                             |       |      |   |     
|Refined Products Mainline Transportation: |                                      |                               |     |                             |       |      |   |      |       |  |   |     
|                                          | Central (1)                          |                               |     | 67.0                        |       |      |   | 62.9 |       |  |   | 62.0 |      
|                                          | Midwest (2)                          |                               |     | 57.7                        |       |      |   | 49.6 |       |  |   | 37.4 |      
|                                          | Ohio and Kentucky                    |                               |     | 29.4                        |       |      |   | 25.7 |       |  |   | 23.5 |      
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                                      | Subtotal                      |     |                             | 154.1 |      |   |      | 138.2 |  |   |      | 122.9 | 
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|LPGs Mainline Transportation:             |                                      |                               |     |                             |       |      |   |      |       |  |   |     
|                                          | Central, Midwest and Kentucky (1)(2) |                               |     | 23.4                        |       |      |   | 25.4 |       |  |   | 23.8 |      
|                                          | Ohio and Northeast (3)               |                               |     | 19.1                        |       |      |   | 15.1 |       |  |   | 16.2 |      
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                                      | Subtotal                      |     |                             | 42.5  |      |   |      | 40.5  |  |   |      | 40.0  | 
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                                      | Total Mainline Transportation |     |                             | 196.6 |      |   |      | 178.7 |  |   |      | 162.9 | 
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|Petrochemical Transportation (4)          |                                      |                               | 3.4 |                             |       |      |  |      |       |  |  |     
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                                      | Total Product Deliveries      |     |                             | 200.0 |      |   |      | 178.7 |  |   |      | 162.9 | 
|                                          |                                      |                               |     |                             |       |      |   |      |       |  |   |      |      



---

|(1) |  | Arkansas, Louisiana, Missouri and Texas.                                                                                                                                
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Illinois and Indiana.                                                                                                                                                   
|   
|(3) |  | New York and Pennsylvania.                                                                                                                                              
|   
|(4) |  | Includes Dean North RGP volumes. Petrochemical transportation between
Mont Belvieu and Port Arthur, Texas, has not been included as those
volumes are with one customer.

The mix of products delivered varies seasonally. Gasoline demand is
generally stronger in the spring and summer months and LPGs demand is generally
stronger in the fall and winter months. Weather and economic conditions in the
geographic areas served by our Products Pipeline System also affect the demand
for, and the mix of, the products delivered.

6



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##### Table of Contents



Refined products and LPGs deliveries for the years ended December 31,
2003, 2002 and 2001, were as follows:

|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |       | 
|----------------------------------------- | --------------- | ----------------------------- | --- | --------------------------- | ----- | ---- | - | ---- | ----- |  | - | ---- | ----- | 
|                                          |                 |                               |     | Product Deliveries (MMBbls)
|                                          |                 |                               |     | Years Ended December 31,   
|                                          |                 |                               |     |                            
|                                          |                 |                               |     | 2003                        |       | 2002 |   | 2001
|                                          |                 |                               |     |                             |       |      |   |     
|Refined Products Mainline Transportation: |                 |                               |     |                             |       |      |   |      |       |  |   |     
|                                          | Gasoline        |                               |     | 89.8                        |       |      |   | 81.9 |       |  |   | 69.4 |      
|                                          | Jet Fuels       |                               |     | 26.4                        |       |      |   | 25.3 |       |  |   | 25.4 |      
|                                          | Distillates (1) |                               |     | 37.9                        |       |      |   | 31.0 |       |  |   | 28.1 |      
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                 | Subtotal                      |     |                             | 154.1 |      |   |      | 138.2 |  |   |      | 122.9 | 
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|LPGs Mainline Transportation:             |                 |                               |     |                             |       |      |   |      |       |  |   |     
|                                          | Propane         |                               |     | 34.5                        |       |      |   | 32.9 |       |  |   | 32.8 |      
|                                          | Butanes         |                               |     | 8.0                         |       |      |   | 7.6  |       |  |   | 7.2  |      
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                 | Subtotal                      |     |                             | 42.5  |      |   |      | 40.5  |  |   |      | 40.0  | 
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                 | Total Mainline Transportation |     |                             | 196.6 |      |   |      | 178.7 |  |   |      | 162.9 | 
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|Petrochemical Transportation              |                 |                               | 3.4 |                             |       |      |  |      |       |  |  |     
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      
|                                          |                 | Total Product Deliveries      |     |                             | 200.0 |      |   |      | 178.7 |  |   |      | 162.9 | 
|                                          |                 |                               |     |                             |       |      |   |      |       |  |   |      |      



---

|(1) |  | Primarily diesel fuel, heating oil and other middle distillates.
|--- |  | ----------------------------------------------------------------

Refined Products Mainline Transportation

Our Products 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 terminals owned by TE Products,
connecting pipelines and customer-owned terminals.

The volume of refined petroleum products transported by our Products
Pipeline System is directly affected by the demand for refined products in the
geographic regions the system serves. This market demand varies based upon the
different end uses to which the refined products deliveries are applied. Demand
for gasoline, which accounted for approximately 58% of the volume of refined
products transported through the Products Pipeline System during 2003, depends
upon price, prevailing economic conditions and demographic changes in the
markets that we serve. Demand for distillates is affected by truck and
railroad freight, the price of natural gas used by utilities, which use
distillates as a substitute for natural gas when the price of natural gas is
high, and usage for agricultural operations, which is affected by weather
conditions, government policy and crop prices. Demand for jet fuel depends
upon prevailing economic conditions and military usage.

Market prices for refined petroleum products affect the demand in the
markets served by our Downstream Segment. Therefore, quantities and mix of
products transported may vary. Transportation tariffs of refined petroleum
products vary among specific product types. As a result, market price
volatility may affect transportation volumes and revenues from period to
period.

LPGs Mainline Transportation

Our Products Pipeline System transports LPGs from the upper Texas Gulf
Coast to the Central, Midwest and Northeast regions of the United States. The
Products Pipeline System east of Todhunter, Ohio, is devoted solely to the
transportation of LPGs. Because propane demand is generally sensitive to
weather in the winter months, year-to-year variations of propane deliveries
have occurred and will likely continue to occur. Our Products Pipeline System
also transports normal butane and isobutane in the Midwest and Northeast for
use in the production of motor gasoline.

Our ability in the Downstream Segment to serve propane markets in the
Northeast is enhanced by our marine import terminal at Providence. This
facility includes a 400,000-barrel refrigerated storage tank along with

7



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##### Table of Contents



ship unloading and truck loading facilities. Effective May 2001, we
entered into an agreement with an affiliate of DEFS to commit sole utilization
of the Providence terminal to an affiliate of DEFS. We operate the terminal
and provide propane loading services to an affiliate of DEFS. The agreement,
with an affiliate of DEFS, terminates in May 2004, and we are currently
renegotiating the agreement. During the years ended December 31, 2003, 2002
and 2001, revenues of $3.2 million, $2.3 million and $1.5 million from an
affiliate of DEFS, respectively, were recognized pursuant to this agreement.

Other Operating Revenues

Our Downstream Segment also earns revenue from terminaling activities and
other ancillary services associated with the transportation and storage of
refined petroleum products and LPGs. From time to time, we sell excess product
inventory. Other operating revenues include revenues related to the intrastate
transportation of petrochemicals under a throughput and deficiency contract.

Customers

Our customers for the transportation of refined petroleum products include
major integrated oil companies, independent oil companies, the airline industry
and wholesalers. End markets for these deliveries are primarily retail service
stations, truck stops, railroads, agricultural enterprises, refineries and
military and commercial jet fuel users.

Propane customers include wholesalers and retailers who, in turn, sell to
commercial, industrial, agricultural and residential heating customers, as well
as utilities who use propane as a back-up fuel source. Refineries constitute
our 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, 2003, our Downstream Segment had approximately 130
customers. During the year ended December 31, 2003, total revenues (and
percentage of total revenues) attributable to the top 10 customers were $149.5
million (56%), of which Marathon Ashland Petroleum LLC accounted for
approximately 18% of total Downstream Segment revenues. During the years ended
December 31, 2002 and 2001, total revenues (and percentage of total revenues)
attributable to the top 10 customers were $101.6 million (51%) and $115.0
million (44%), respectively. During the years ended December 31, 2002 and
2001, no single customer accounted for 10% or more of the Downstream Segments
revenues.

Credit Policies and Procedures

We manage our exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures. We utilize letters of
credit and guarantees for certain of our receivables. However, these
procedures and policies do not fully eliminate customer credit risk. During
the years ended December 31, 2003 and 2002, a few small to medium-sized
customers of the Downstream Segment filed for bankruptcy protection. During
the years ended December 31, 2003 and 2002, we expensed approximately $0.8
million and $0.7 million, respectively, of uncollectible receivables of the
Downstream Segment related to customer bankruptcies or other non-payments.

Competition

The Products 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
Products Pipeline Systems most significant competitors (other than indigenous
production in its markets) are pipelines in the areas where the Products
Pipeline System delivers products. Competition among common carrier pipelines
is based primarily on transportation charges, quality of customer service and
proximity to end users. We believe our Downstream Segment is competitive with
other

8



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##### Table of Contents



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 Products 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 TE Products tariffs. We face competition from rail movements of
LPGs from Sarnia, Ontario, Canada, and waterborne imports into New Hampshire.

Upstream Segment  Gathering, Transportation, Marketing and Storage of Crude Oil

Operations

We conduct business in our Upstream Segment through the following:



| |  |  | TCTM and certain of its wholly owned subsidiaries, and                      
| | - |  | ----------------------------------------------------------------------------
|
| |  |  | our 50% owned equity investment in Seaway Crude Pipeline Company (Seaway).

Our Upstream Segment gathers, transports, markets and stores crude oil,
and distributes lubrication oils and specialty chemicals, principally in
Oklahoma, Texas, New Mexico and the Rocky Mountain region. We commenced our
Upstream Segment business in connection with the acquisition of assets from an
affiliate of DEFS in November 1998. Our Upstream Segment uses its asset base
to aggregate crude oil and provide transportation and specialized services to
its regional customers. Our Upstream Segment purchases crude oil from various
producers and operators at the wellhead and makes bulk purchases of crude oil
at pipeline and terminal facilities. The crude oil is then sold to refiners
and other customers. The Upstream Segment transports crude oil through equity
owned pipelines, its trucking operations and third party pipelines.

Margins in the Upstream Segment are calculated as revenues generated from
the sale of crude oil and lubrication oil, and transportation of crude oil,
less the costs of purchases of crude oil and lubrication oil. Margins are a
more meaningful measure of financial performance than operating revenues and
operating expenses due to the significant fluctuations in revenues and expenses
caused by variations in the level of marketing activity and prices for products
marketed (see Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations  Upstream Segment for margin and volume
information).

TCTM purchases crude oil and simultaneously establishes a margin by
selling crude oil for physical delivery to third party users. We seek to
maintain a balanced marketing position until we make physical delivery of the
crude oil, thereby minimizing or eliminating our exposure to price fluctuations
occurring after the initial purchase. However, certain basis risks, which are
the risks that price relationships between delivery points, classes of products
or delivery periods will change, cannot be completely hedged or eliminated.
Risk management policies have been established by the Risk Management Committee
to monitor and control market risks. The Risk Management Committee is
comprised, in part, of certain senior executives of the Company.

9



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##### Table of Contents



Product deliveries on TCTMs 100% owned pipeline systems, undivided joint
interest pipelines and Seaway for the years ended December 31, 2003, 2002 and
2001, were as follows (in millions):

|                                         |                          |  |                          |       |      |  |      |       |  |  |     |       | 
|---------------------------------------- | ------------------------ |  | ------------------------ | ----- | ---- |  | ---- | ----- |  |  | --- | ----- | 
|                                         |                          |  | Years Ended December 31,
|                                         |                          |  |                         
|                                         |                          |  | 2003                     |       | 2002 |  | 2001
|                                         |                          |  |                          |       |      |  |     
|Barrels Delivered:                       |                          |  |                          |       |      |  |      |       |  |  |     |      
|                                         | Crude oil transportation |  |                          | 95.5  |      |  |      | 82.8  |  |  |     | 78.7  | 
|                                         | Crude oil marketing      |  |                          | 159.7 |      |  |      | 139.2 |  |  |     | 159.5 | 
|                                         | Crude oil terminaling    |  |                          | 115.1 |      |  |      | 127.4 |  |  |     | 121.9 | 
|Lubricants and chemicals (total gallons) |                          |  | 10.4                     |       |      |  | 9.6  |       |  |  | 8.8 |      
|Seaway:                                  |                          |  |                          |       |      |  |      |       |  |  |     |      
|                                         | Long-haul                |  |                          | 71.0  |      |  |      | 62.6  |  |  |     | 69.9  | 
|                                         | Short-haul               |  |                          | 179.8 |      |  |      | 183.8 |  |  |     | 175.7 | 

Properties

The major crude oil pipelines and pipeline systems of our Upstream Segment
are set forth in the following table, which include pipelines owned jointly
with other industry participants or producers:

|                        |  |           |                                 |          |  |                                   |  |                                                                                                                          
|----------------------- |  | --------- | ------------------------------- | -------- |  | --------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------
|                        |  | Our       |                                 |          |  |                                  
|Crude Oil Pipeline      |  | Ownership |                                 | Operator |  | Description                      
|                        |  |           |                                 |          |  |                                  
|Red River System        |  |           | 100%                            |          |  | TEPPCO Crude
Pipeline(TCPL) (1) |  | 1,690 miles of pipeline;
1,484,000 barrels of
storage  North Texas to
South Oklahoma                                    
|                        |  |           |                                 |          |  |                                   |  |                                                                                                                          
|South Texas System (2)  |  |           | 100%                            |          |  | TCPL                              |  | 900 miles of pipeline;
780,000 barrels of
storage  South Central
Texas to Houston, Texas
area                           
|                        |  |           |                                 |          |  |                                   |  |                                                                                                                          
|West Texas Trunk System |  |           | 100%                            |          |  | TCPL                              |  | 250 miles of smaller
diameter pipeline  connecting West Texas and
Southeast New Mexico to
TCTMs Midland, Texas
terminal
|                        |  |           |                                 |          |  |                                   |  |                                                                                                                          
|Seaway (3)              |  |           | 50% generalpartnership
interest |          |  | TCPL                              |  | 500-mile, 30-inch
diameter pipeline;
6,320,000 barrels of
storage  Texas Gulf
Coast to Cushing,
Oklahoma                
|                        |  |           |                                 |          |  |                                   |  |                                                                                                                          
|Basin                   |  |           | 13% joint ownership             |          |  | Plains AllAmerican
Pipeline, L.P. |  | 416-mile pipeline 
Permian Basin (New Mexico
and Texas) to Cushing,
Oklahoma                                            



---

|(1) |  | TCPL is a wholly owned subsidiary of TCTM.                                                                                   
|--- |  | -----------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Includes our remaining interest in the Rancho Pipeline and our acquisition of the Genesis assets.                            
|   
|(3) |  | TCPLs participation in revenues and expenses of Seaway vary as described below in Seaway Crude Pipeline Equity
Investment.

10



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##### Table of Contents



None of these pipelines or systems are mortgaged or encumbered to secure
funded debt. TCTM has provided guarantees of our unsecured debt (see Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
Operations).

The majority of the Red River System crude oil is delivered to Cushing,
Oklahoma, via third party pipelines, or to two local refineries. The majority
of the crude oil on the South Texas System is delivered on a tariff basis to
Houston area refineries. The West Texas Trunk System is a fee based system
which connects gathering systems to TCTMs Midland, Texas terminal. Other crude
oil assets, located primarily in Texas and Oklahoma, consist of 310 miles of
pipeline and 295,000 barrels of storage capacity.

In connection with our acquisition of ARCO Pipe Line Company (ARCO), a
wholly owned subsidiary of Atlantic Richfield Company, in 2000, we acquired an
approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a
crude oil pipeline system from West Texas to Houston. In March 2003, the
Rancho Pipeline ceased operations, and segments of the pipeline were sold to
certain of the owners which previously held undivided interests in the
pipeline. We acquired approximately 230 miles of the pipeline in exchange for
cash of $5.5 million and our interests in other portions of the Rancho
Pipeline. We sold part of the segment we acquired to other entities for cash
and assets valued at approximately $8.5 million. We recorded a net gain of
$3.9 million on the transactions, which is included in the gain on sale of
assets in our consolidated statements of income.

On November 1, 2003, we completed the purchase of crude supply and
transportation assets along the upper Texas Gulf Coast for $21.0 million from
Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (Genesis). The
transaction was funded with proceeds from our August 2003 equity offering (see
Note 12. Partners Capital and Distributions). We allocated the purchase
price, net of liabilities assumed, primarily to property, plant and equipment
and intangible assets (see Note 6. Acquisitions and Dispositions). The assets
acquired included approximately 150 miles of small diameter trunk lines, 26,000
barrels per day of throughput and 12,000 barrels per day of lease marketing and
supply business. We have integrated these assets into our South Texas pipeline
system which has allowed us to consolidate gathering and marketing assets in
key operating areas in a cost effective manner and will provide future growth
opportunities. Accordingly, the results of the acquisition are included in the
consolidated financial statements from November 1, 2003.

Seaway Crude Pipeline Equity Investment

Seaway is a partnership between a subsidiary of TCTM, TEPPCO Seaway, L.P.
(TEPPCO Seaway), and ConocoPhillips. TCTM acquired its 50% ownership
interest in Seaway on July 20, 2000, as part of its purchase of ARCO and
transferred the investment to TEPPCO Seaway. We assumed ARCOs role as
operator of this pipeline. The 30-inch diameter, 500-mile pipeline transports
crude oil from the U.S. Gulf Coast to Cushing, a central crude distribution
point for the central United States and a delivery point for the New York
Mercantile Exchange (NYMEX). The Freeport, Texas, marine terminal is the
origin point for the 30-inch diameter crude pipeline. Three large diameter
lines carry crude oil from the Freeport marine terminal to the adjacent Jones
Creek Tank Farm, which has six tanks capable of handling approximately 2.6
million barrels of crude oil. A crude oil marine terminal facility at Texas
City, Texas, is used to supply refineries in the Houston area. Two pipelines
connect the Texas City marine terminal to storage facilities in Texas City and
Galena Park, Texas, where there are seven tanks with a combined capacity of
approximately 3 million barrels. Seaway has the capability to provide marine
terminaling and crude oil storage services for all Houston area refineries.

The Seaway partnership agreement provides for varying participation ratios
throughout the life of Seaway. From July 20, 2000, through May 2002, we
received 80% of revenue and expense of Seaway. From June 2002 until May 2006,
we will receive 60% of revenue and expense of Seaway. Thereafter, we will
receive 40% of revenue and expense of Seaway. For the year ended December 31,
2002, our portion of equity earnings on a pro-rated basis averaged
approximately 67%.

Line Transfers, Pumpovers and Other

Our Upstream Segment provides trade documentation services to its
customers, primarily at Cushing and Midland. TCTM documents the transfer of
crude oil in its terminal facilities between contracting buyers and sellers.
This line transfer documentation service is related to the trading activity by
TCTMs customers of NYMEX open-

11



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##### Table of Contents



interest crude oil contracts and other physical trading activity. This
service provides a documented record of receipts, deliveries and transactions
to each customer, including confirmation of trade matches, inventory management
and scheduled movements. Line transfer revenues are included as part of other
operating revenues in our consolidated statements of income.

The line transfer services also attract physical barrels to TCTMs
facilities for final delivery to the ultimate owner. A pumpover occurs when
the last title transfer is executed and the physical barrels are delivered out
of TCTMs custody. TCTM owns and operates storage facilities primarily in
Midland and Cushing with an operational capacity of approximately 1.1 million
barrels to facilitate the pumpover business. Revenues from pumpover services
are included as part of crude oil transportation revenues in our consolidated
statements of income and represent the crude oil terminaling component of
margin. The line transfer and pumpover operations were acquired as part of our
purchase of ARCO in 2000.

Lubrication Services, L.P. (LSI), a subsidiary of TCTM, distributes
lubrication oils and specialty chemicals to natural gas pipelines, gas
processors and industrial and commercial accounts. LSIs distribution networks
are located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and
Louisiana. LSI also sells lubrication oils and specialty chemicals to DEFS.
For the years ended December 31, 2003, 2002, and 2001, revenues recognized by
LSI included $15.2 million, $14.6 million, and $12.3 million, respectively, for
the sale of lubrication oils and specialty chemicals to DEFS.

Customers

TCTM 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. Gross sales revenue of the Upstream
Segment attributable to the top 10 customers was $2.6 billion (67%) for the
year ended December 31, 2003, of which Valero Energy Corp. (Valero) accounted
for 18%. For the year ended December 31, 2002, gross sales revenue
attributable to the top 10 customers was $1.9 billion (66%), of which Valero
accounted for 18%. For the year ended December 31, 2001, gross sales revenue
attributable to the top 10 customers was $2.0 billion (61%), of which Valero
accounted for 16%.

Competition

The most significant competitors in pipeline operations in our Upstream
Segment 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 our pipeline systems deliver crude oil.
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 crude oil at the wellhead. Declines in domestic crude oil
production have intensified competition among gatherers and marketers.

A significant portion of the growth in our Upstream Segment has occurred
through acquisitions of pipeline gathering systems. Our acquisitions in this
Segment have provided increased efficiencies for the gathering and
transportation of crude oil with our existing pipeline systems as well as
expansion into new market areas. We experience competition from other
gatherers and marketers in bidding for potential acquisitions. 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 and
bankruptcies, which may decrease the number of potential acquisitions of crude
gathering systems available to us.

Credit Policies and Procedures

As crude oil or lubrication oils are marketed or transported, we 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 our business. We
manage our exposure to credit risk through credit analysis, credit approvals,
credit limits and monitoring procedures. We utilize letters of credit and
guarantees for certain of our receivables. However, these procedures and
policies do not fully eliminate customer credit risk. During the year ended
December 31, 2002, we expensed approximately $0.2 million of uncollectible

12



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##### Table of Contents



receivables of the Upstream Segment. During the years ended December 31,
2003 and 2001, no additional reserves were necessary for uncollectible
receivables of the Upstream Segment.

Midstream Segment  Gathering of Natural Gas, Transportation of NGLs and
Fractionation of NGLs

Operations

We conduct business in our Midstream Segment through the following:



| |  |  | Jonah Gas Gathering Company (Jonah) and Val Verde Gas
Gathering Company, L.P. (Val Verde), which gather natural gas,                                                                                                                                                                                           
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | TEPPCO Midstream and its wholly owned subsidiaries,
Chaparral Pipeline Company, L.P. and Quanah Pipeline Company,
L.P. (collectively referred to as Chaparral or Chaparral NGL
system), Panola Pipeline Company, L.P., Dean Pipeline Company,
L.P. and Wilcox Pipeline Company, L.P., which transport NGLs, and
|
| |  |  | TEPPCO Colorado, LLC (TEPPCO Colorado), which
fractionates NGLs.                                                                                                                                                                                                                                                 

Revenues of our Midstream Segment are earned from gathering fees based on
the volume and pressure of natural gas gathered, transportation of NGLs and
fractionation of NGLs in Colorado. Gathering and transportation revenues are
recognized as natural gas or NGLs are delivered to customers. Revenues are
also earned from the sale of condensate liquid extracted from the natural gas
stream to an Upstream Segment marketing affiliate. Fractionation revenues are
recognized ratably over the contract year as products are delivered to DEFS.
We generally do not take title to the natural gas gathered, NGLs transported or
NGLs fractionated, therefore, the results of operations of our Midstream
Segment are not directly affected by changes in the prices of natural gas or
NGLs. Our Midstream Segment has multiple long-term contracts with producers
connected to the Jonah and Val Verde systems. We cannot influence or control
the operation, development or production levels of the gas fields served by the
Jonah and Val Verde systems, which may be affected by price and price
volatility, market demand, depletion rates of existing wells and changes in
laws and regulations.

None of these pipelines or systems are mortgaged or encumbered to secure
funded debt. TEPPCO Midstream, Jonah and Val Verde have each provided
guarantees of our unsecured debt (see Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations).

Volume information for the years ended December 31, 2003, 2002 and 2001,
is presented below:

|                                                     |  |                          |       |      |  |      |       |  |  |  |      | 
|---------------------------------------------------- |  | ------------------------ | ----- | ---- |  | ---- | ----- |  |  |  | ---- | 
|                                                     |  | Years Ended December 31,
|                                                     |  |                         
|                                                     |  | 2003                     |       | 2002 |  | 2001
|                                                     |  |                          |       |      |  |     
|Gathering  Natural Gas (billion cubic feet (Bcf)) |  |                          | 461.2 |      |  |      | 340.7 |  |  |  | 45.5 | 
|Transportation  NGLs (million barrels)              |  |                          | 57.9  |      |  |      | 54.0  |  |  |  | 21.5 | 
|Fractionation  NGLs (million barrels)               |  |                          | 4.1   |      |  |      | 4.1   |  |  |  | 4.1  | 

The Jonah Gas Gathering System

On September 30, 2001, we completed the purchase of Jonah from Alberta
Energy Company for $359.8 million, with an additional payment of $7.3 million
made on February 4, 2002, for final purchase adjustments related primarily to
construction projects in progress at the time of closing. The acquisition
served as our entry into the natural gas gathering industry. We funded the
acquisition through a borrowing under a $400.0 million credit facility with
SunTrust Bank (see Note 11. Debt). We allocated the purchase price, net of
liabilities assumed, primarily to property, plant and equipment and intangible
assets for gas gathering contracts. We also recognized goodwill on the
purchase of approximately $2.8 million (see Note 6. Acquisitions and
Dispositions). We accounted for the acquisition under the purchase method of
accounting. Accordingly, the results of operations of the

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acquisition have been included in our consolidated financial statements
from September 30, 2001. Under a contractual agreement, DEFS manages and
operates Jonah on our behalf.

Since the acquisition, we have expanded both the pipeline capacity and
processing capacity of the Jonah system. In 2002, we completed the Phase I and
Phase II expansions of Jonah, which nearly doubled the capacity of the Jonah
system. The first expansion was completed in May 2002 at a cost of
approximately $25.0 million and increased system capacity by 62%, from
approximately 450 million cubic feet per day (MMcf/day) to approximately 730
MMcf/day. In October 2002, an additional expansion project was completed at a
cost of approximately $45.0 million, which increased the capacity of the Jonah
system from 730 MMcf/day to approximately 880 MMcf/day. In 2003, the Jonah
system was again expanded to include an 80-mile expansion on the system and the
building of a new 250 MMcf/day gas processing plant near Opal, Wyoming. Phase
III was substantially completed during the fourth quarter of 2003, and the
system was operational, with system capacity increasing to 1,180 MMcf/day. The
cost of the Phase III expansion through December 31, 2003, was approximately
$44.6 million. The total cost of the Phase III expansion will be approximately
$59.0 million, with the remaining work to be completed in 2004.

The Jonah system consists of approximately 500 miles of pipelines ranging
in size from three inches to 24 inches in diameter, three compressor stations
with an aggregate of approximately 44,000 horsepower and related metering
facilities. Gas gathered on the Jonah system is collected from approximately
500 producing wells in southwestern Wyomings Green River Basin, which is one
of the most prolific natural gas basins in the United States. The system also
includes two processing facilities that extract condensate prior to delivery of
natural gas to DEFS, Northwest, Kern River and Questar. Gas is also delivered
to gas processing facilities owned by others. From these processing
facilities, the natural gas is delivered to several interstate pipeline systems
located in the region for transportation to end-use markets throughout the
Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines
in the region include Kern River, Northwest, Colorado Interstate Gas and
Questar.

The Val Verde Gas Gathering System

On June 30, 2002, we completed the purchase of Val Verde for $444.2
million from Burlington Resources Gathering Inc., a subsidiary of Burlington
Resources Inc., including acquisition related costs of approximately $1.2
million. We funded the purchase through borrowings of $168.0 million under our
$500.0 million revolving credit facility, $72.0 million under our 364-day
revolving credit facility and $200.0 million under a six-month term loan with
SunTrust Bank (see Note 11. Debt). The remaining purchase price was funded
through working capital sources of cash. We allocated the purchase price, net
of liabilities assumed, primarily to property, plant and equipment and
intangible assets for gas gathering contracts (see Note 6. Acquisitions and
Dispositions). We accounted for the acquisition of these assets under the
purchase method of accounting. Accordingly, the results of the acquisition
have been included in our consolidated financial statements from June 30, 2002.
Under a contractual agreement, DEFS manages and operates Val Verde on our
behalf.

The Val Verde system consists of approximately 400 miles of pipeline
ranging in size from four inches to 36 inches in diameter, 14 compressor
stations operating over 93,000 horsepower of compression and a large amine
treating facility for the removal of carbon dioxide. The system has a pipeline
capacity of approximately one billion cubic feet of gas per day. The Val Verde
system gathers coal bed methane (CBM) from the Fruitland Coal Formation of
the San Juan Basin in New Mexico and Colorado, a long-term source of natural
gas supply in North America. The basin is one of the most prolific sources of
CBM and also contains significant conventional gas reserves. The system is one
of the largest CBM gathering and treating facilities in the United States,
gathering CBM from more than 500 separate wells throughout northern New Mexico
and southern Colorado, and provides gathering and treating services pursuant to
60 long-term contracts with approximately 40 different natural gas producers in
the San Juan Basin. Gas transported on the Val Verde system is delivered to
several interstate pipeline systems serving the western United States, as well
as local New Mexico markets.

In July 2003, the New Mexico Oil Conservation Division approved an
application for infill drilling to allow two wells per standard 320-acre gas
spacing unit in the Fruitland Coal Formation of the San Juan Basin. This
approval of infill drilling will provide potential opportunities for long-term
growth and increased throughput on the Val Verde system.

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On February 6, 2004, a lawsuit styled San Juan Citizens Alliance et al. v.
Norton et al.was filed against the United States Department of Interior and
the Bureau of Land Management (BLM) in the U.S. District Court, District of
Columbia, challenging a recent decision by the BLM. In that decision, the BLM
adopted a Resource Management Plan, which authorized the development of
additional gas wells on public lands in northwestern New Mexico. A substantial
portion of the development activity in the area that is the subject of the suit
involves the infill drilling in the Basin-Fruitland Coal Gas Pool which covers
most of the San Juan Basin. We believe the BLM followed the requirements of
the law and reached a balanced decision in adopting the Resource Management
Plan. However, an adverse decision could impact infill drilling activities in
the San Juan Basin.

NGL Transportation and Fractionation

The NGL pipelines of the Midstream Segment are located along the Texas
Gulf Coast, East Texas and from southeastern New Mexico and West Texas to Mont
Belvieu. They are all wholly owned and operated by either our subsidiaries or
under a contractual agreement with DEFS. Information about these NGL pipelines
is set forth in the following table:

|                                          |  |               |         |             |  |                                                                                           
|----------------------------------------- |  | ------------- | ------- | ----------- |  | ------------------------------------------------------------------------------------------
|                                          |  | Capacity      |         |            
|NGL Pipeline                              |  | (barrels/day) |         | Description
|                                          |  |               |         |            
|Chaparral                                 |  |               | 135,000 |             |  | 845 miles of pipeline  West Texas and New
Mexico to Mont Belvieu, Texas                  
|                                          |  |               |         |             |  |                                                                                           
|Quanah                                    |  |               | 22,000  |             |  | 180 miles of pipeline  Sutton County, Texas
to the Chaparral Pipeline near Midland, Texas
|                                          |  |               |         |             |  |                                                                                           
|Panola                                    |  |               | 43,000  |             |  | 189 miles of pipeline  Carthage, Texas to
Mont Belvieu, Texas                            
|                                          |  |               |         |             |  |                                                                                           
|San Jacinto                               |  |               | 12,000  |             |  | 34 miles of pipeline  Carthage, Texas to
Longview, Texas                                 
|                                          |  |               |         |             |  |                                                                                           
|The southern
portion of the Dean
Pipeline |  |               | 10,000  |             |  | 155 miles of pipeline  South Texas to Point
Comfort, Texas                               
|                                          |  |               |         |             |  |                                                                                           
|Wilcox                                    |  |               | 7,500   |             |  | 103 miles of pipeline  Southeast Texas                                                   

On March 1, 2002, we completed the purchase of the Chaparral NGL system
for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P.,
including acquisition related costs of approximately $0.4 million. The
Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu.
The pipeline delivers NGLs to fractionators and to MB Storages existing
storage facilities in Mont Belvieu. We funded the purchase through borrowings
under our $500.0 million revolving credit facility (see Note 11. Debt). We
allocated the purchase price to property, plant and equipment, and we accounted
for the acquisition of these assets under the purchase method of accounting.
Accordingly, the results of the acquisition have been included in our
consolidated financial statements from March 1, 2002. Under a contractual
agreement, DEFS manages and operates Chaparral on our behalf. An affiliate of
DEFS transports NGLs on the Chaparral NGL system. The fees paid to us by an
affiliate of DEFS for NGL transportation on the Chaparral NGL system totaled
$5.5 million and $4.5 million for the years ended December 31, 2003 and 2002,
respectively.

The Panola Pipeline and San Jacinto Pipeline originate at DEFS East Texas
Plant Complex in Panola County, Texas, and transport NGLs for DEFS and other
major integrated oil and gas companies. Revenues recognized from an affiliate
of DEFS for NGL transportation totaled $9.2 million, $12.0 million and $13.9
million for the years ended December 31, 2003, 2002 and 2001, respectively.

The southern portion of the Dean Pipeline originates in South Texas and
transports NGLs for DEFS into its pipeline in Point Comfort, Texas. Revenues
recognized from DEFS for NGL transportation totaled $1.0 million, $2.9 million
and $0.1 million for the years ended December 31, 2003, 2002 and 2001,
respectively.

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The Wilcox Pipeline transports NGLs for DEFS from two of its natural gas
processing plants. The Wilcox Pipeline is currently supported by a throughput
agreement with DEFS through 2005. The fees paid to us by DEFS under the
agreement were $1.5 million, $1.2 million and $1.2 million for the years ended December 31, 2003,
2002 and 2001, respectively.

TEPPCO Colorado has two NGL fractionation facilities which separate NGLs
into individual components. TEPPCO Colorado is currently supported by a
fractionation agreement with DEFS through 2018, under which TEPPCO Colorado
receives a variable fee for all fractionated volumes delivered to DEFS.
Revenues recognized from the fractionation facilities totaled $7.4 million for
each of the years ended December 31, 2003, 2002 and 2001. Under an operation
and maintenance agreement, DEFS also operates and maintains the fractionation
facilities on behalf of TEPPCO Colorado. For these services, TEPPCO Colorado
pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS.
Expenses related to the Operation and Maintenance Agreement totaled $0.9
million for each of the years ended December 31, 2003, 2002 and 2001.

Customers

The Midstream Segments customers for the gathering of natural gas include
major integrated oil and gas companies and large to medium-sized independent
producers. Natural gas from Jonah and Val Verde is delivered into major
interstate gas pipelines for delivery primarily to markets in the western
United States. The Midstream Segments customers for the transporting of NGLs
include DEFS and its affiliates and other major integrated oil and gas
companies. Condensate sales from the Jonah system are primarily to an Upstream
Segment marketing affiliate.

At December 31, 2003, the Midstream Segment had approximately 70
customers. Revenue attributable to the top 10 customers was $155.9 million
(84%) for the year ended December 31, 2003, of which EnCana Corporation
(formerly Alberta Energy Company), Burlington Resources Inc. and DEFS and
affiliates accounted for approximately 21%, 18% and 14% of revenues of the
Midstream Segment, respectively. At December 31, 2002, the Midstream Segment
had approximately 70 customers. Revenue attributable to the top 10 customers
was $117.5 million (85%) for the year ended December 31, 2002, of which DEFS
and affiliates, EnCana Corporation and Burlington Resources Inc. accounted for
approximately 21%, 19% and 15% of revenues of the Midstream Segment,
respectively. At December 31, 2001, the Midstream Segment had approximately 20
customers. Revenue attributable to the 10 customers was $37.0 million (99%)
for the year ended December 31, 2001, of which DEFS and affiliates, Enron Corp.
and Alberta Energy Company accounted for approximately 61%, 13% and 11% of
revenues of the Midstream Segment, respectively.

Credit Policies and Procedures

We manage our exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures. We utilize letters of
credit and guarantees for certain of our receivables. However, these
procedures and policies do not fully eliminate customer credit risk. In
December 2001, we expensed approximately $4.3 million of uncollected
transportation deficiency revenues due to the bankruptcy of Enron Corp. and
certain of its subsidiaries in December 2001. During the years ended December
31, 2003 and 2002, no additional reserves were necessary for uncollectible
receivables of the Midstream Segment.

Competition

The most significant competition for the NGL pipeline operations of our
Midstream Segment comes primarily from proprietary pipelines owned and operated
by major oil and gas companies or other large independent pipeline companies
with contiguous operations. The ability to compete in the NGL pipeline area is
based primarily on the quality of customer service and knowledge of products
and markets.

The majority of the recent growth in the Midstream Segment is due to the
acquisition of Jonah in the Green River Basin in southwestern Wyoming and Val
Verde in the San Juan Basin in New Mexico and Colorado. Typically, new
supplies of natural gas are necessary to offset the natural declines in
production from wells connected to any gathering system. The Jonah and
Pinedale fields that are the focus of the Jonah system in Wyoming are both
relatively young producing areas, characterized by long-lived production
profiles with many years of significant growth potential ahead. We expect to
aggressively market this system by obtaining contracts to gather additional
natural gas supplies.

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Competition in the natural gas gathering operations of our Midstream
Segment is based largely on reputation, efficiency, system reliability and
system capacity. Key competitors in the gathering and treating segment include
independent gas gatherers as well as other major integrated energy companies.
Alternate gathering facilities may be available to producers served by our
Midstream Segment, and those producers could also elect to construct
proprietary gas gathering systems. Success in the gas gathering and treating
business segment is based primarily on a thorough understanding of the needs of
the producers served, as well as a strong commitment to providing responsive,
high-quality customer service.

If the production ultimately delivered to one of our gathering systems
declines, revenues from such operations would also be adversely affected. If
these declines are sustained or substantial, then we could experience a
material adverse effect on our financial position, results of operations or
cash flows.

Title to Properties

We believe we have satisfactory title to all of our assets. The 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.
We believe none of these liabilities materially affect the value of our
properties or our interest in the properties or will materially interfere with
their use in the operation of our business.

Capital Expenditures

Capital expenditures, excluding acquisitions, totaled $140.6 million for
the year ended December 31, 2003. Revenue generating projects include those
projects which expand service into new markets or expand capacity into current
markets. Capital expenditures to sustain existing operations include projects
required by regulatory agencies or required life-cycle replacements. System
upgrade projects improve operational efficiencies or reduce cost. We
capitalize interest costs incurred during the period that construction is in
progress. The following table identifies capital expenditures by segment for
the year ended December 31, 2003 (in millions):

|                   |       |   |            |      |            |   |            |      |             |   |       |      |  |   |     |     |  |   |      |       | 
|------------------ | ----- | - | ---------- | ---- | ---------- | - | ---------- | ---- | ----------- | - | ----- | ---- |  | - | --- | --- |  | - | ---- | ----- | 
|                   |       |   |            |      |            |   | Sustaining |      |             |   |       |      |  |   |     |     |  |   |     
|                   |       |   | Revenue    |      | Existing   |   | System     |      | Capitalized |   |       |      | 
|                   |       |   | Generating |      | Operations |   | Upgrades   |      | Interest    |   | Total
|                   |       |   |            |      |            |   |            |      |             |   |      
|Downstream Segment |       | $ | 26.6       |      |            | $ | 18.3       |      |             | $ | 11.4  |      |  | $ | 2.8 |     |  | $ | 59.1 |      
|Midstream Segment  |       |   | 55.5       |      |            |   | 7.8        |      |             |   | 2.6   |      |  |   | 2.0 |     |  |   | 67.9 |      
|Upstream Segment   |       |   | 5.3        |      |            |   | 6.6        |      |             |   | 1.0   |      |  |   | 0.5 |     |  |   | 13.4 |      
|Other              |       |   |           |      |            |   | 0.2        |      |             |   |      |      |  |   |    |     |  |   | 0.2  |      
|                   |       |   |            |      |            |   |            |      |             |   |       |      |  |   |     |     |  |   |      |      
|                   | Total |   | $          | 87.4 |            |   | $          | 32.9 |             |   | $     | 15.0 |  |   | $   | 5.3 |  |   | $    | 140.6 | 
|                   |       |   |            |      |            |   |            |      |             |   |       |      |  |   |     |     |  |   |      |      

Revenue generating capital spending by the Downstream Segment totaled
$26.6 million and was used primarily for the expansion of our pumping capacity
of LPGs into the Northeast markets, expansion of our North Houston terminal
facility, increased storage capacity at the Princeton, Indiana, terminal and
expansion of delivery capacity at various other locations. Revenue generating
capital spending by the Midstream Segment totaled $55.5 million and was used
primarily for the upgrade of the Jonah system and additional well connections
on both the Jonah and Val Verde systems. Revenue generating capital spending
by the Upstream Segment totaled $5.3 million and was used primarily for the
expansion of our South Texas system and connections to various other production
facilities and pipelines. In order to sustain existing operations, we spent
$18.3 million for various Downstream Segment pipeline projects, $7.8 million
for the Midstream Segment and $6.6 million for Upstream Segment facilities. An
additional $15.0 million was spent on system upgrade projects among all of our
business segments.

We estimate that capital expenditures, excluding acquisitions, for 2004
will be approximately $144.0 million (which includes $4.0 million of
capitalized interest). We expect to spend approximately $112.0 million for
revenue generating projects and facility improvements. Capital spending on
revenue generating projects and facility improvements will include
approximately $49.0 million for the expansion of our Downstream Segment
facilities including pipelines extending from Seymour to Indianapolis, Indiana,
further expansions of our Northeast pipeline

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system and construction of a new truck loading terminal in Bossier City,
Louisiana. We expect to spend $21.2 million to expand our Upstream Segment
pipelines and facilities in South Texas and Oklahoma and approximately $41.8
million to expand our Midstream Segment assets. We expect to spend
approximately $28.0 million to sustain existing operations, including
life-cycle replacements for equipment at various facilities and pipeline and
tank replacements among all of our business segments. We continually review
and evaluate potential capital improvements and expansions that would be
complementary to our present business segments. These expenditures can vary
greatly depending on the magnitude of our transactions. We may finance capital
expenditures through internally generated funds, debt or the issuance of
additional equity.

Regulation

Our interstate common carrier pipeline operations are subject to rate
regulation by the FERC under the provisions of the Interstate Commerce Act, the
Energy Policy Act of 1992 and rules and orders promulgated thereunder.
FERC regulation requires that interstate petroleum products and crude oil
pipeline rates be posted publicly and that these rates be just and reasonable
and nondiscriminatory.

Rates of interstate petroleum products and crude oil pipeline companies,
like us, are currently regulated by the FERC primarily through an index
methodology, which allows a pipeline to change its rates based on the change
from year to year in the Producer Price Index for finished goods (PPI Index).
Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index
from PPI  1% to PPI. On April 22, 2003, several shippers filed a petition in
the United States Court of Appeals for the District of Columbia Circuit, Flying
J. Inc., Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and
Marketing Company vs. Federal Energy Regulatory Commission, Docket No. 03-1107,
seeking a review of whether the FERCs adoption of the PPI Index was reasonable
and supported by the evidence. Oral arguments are scheduled for early 2004.

As an alternative to using the PPI Index, interstate petroleum products
and crude 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 petroleum products and crude oil pipeline
companies that the rate is acceptable.

TE Products has been granted permission by the FERC to utilize
Market-Based Rates for all of its refined products movements other than the
Little Rock, Arkansas, Arcadia and Shreveport-Arcadia, Louisiana destination
markets, which are currently subject to the PPI Index. With respect to LPG
movements, TE Products uses the PPI Index. All interstate transportation
movements of crude oil by TCTM are subject to the PPI Index as is the NGL
interstate transportation movements on the Chaparral NGL system.

In a 1995 decision involving an unrelated 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
pipeline limited partnership, the FERC held that the pipeline limited
partnership may not claim an income tax allowance for income attributable to
non-corporate limited partners. These FERC decisions do not affect our current
rates and rate structure because we do not use the cost-of-service methodology
to support our rates. However, the FERC decisions might become relevant to us
should we (i) elect in the future to use the cost-of-service methodology or
(ii) be required to use such methodology to defend initial rates or our indexed
rates against a shipper protest alleging that an indexed rate increase
substantially exceeds actual cost increases. Should these circumstances arise,
there can be no assurance with respect to the effect of these precedents on our
rates in view of the uncertainties involved in this issue.

The natural gas gathering operations of the Jonah and Val Verde systems
are exempt from FERC regulation under the Natural Gas Act of 1938 since they
are intrastate gas gathering systems rather than interstate transmission
pipelines. However, FERC regulation still significantly affects the Midstream
Segment, directly or indirectly, by its influences on the parties that produce
the natural gas gathered on the Jonah and Val Verde systems. In addition, in
recent years, FERC has pursued pro-competition policies in its regulation of
interstate natural gas pipelines. If the FERC does not continue the
pro-competition policies as it considers pipeline rate case proposals,
revisions to rules and policies that affect shipper rights of access to
interstate natural gas transportation capacity or proposals by

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natural gas pipelines to allow natural gas pipelines to charge negotiated
rates without rate ceiling limits, such policy changes could have an adverse
effect on the gathering rates the Midstream Segment is able to charge in the
future.

Environmental Matters

Our operations are subject to federal, state and local laws and
regulations governing the discharge of materials into the environment. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, imposition of injunctions
delaying or prohibiting certain activities and the need to perform
investigatory and remedial activities. Although we believe our operations are
in material compliance with applicable environmental laws and regulations,
risks of significant costs and liabilities are inherent in pipeline operations,
and we cannot assure you 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 our
operations, could result in substantial costs and liabilities to us. We
believe that changes in environmental laws and regulations will not have a
material adverse effect on our financial position, results of operations or
cash flows in the near term.

Water

The Federal Water Pollution Control Act of 1972, as renamed and amended as
the Clean Water Act (CWA), and analogous state laws impose 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 petroleum or other hazardous substances. 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
navigable waters or into groundwater. Spill prevention control and
countermeasure requirements of federal laws require appropriate containment
berms and similar structures to help prevent a petroleum tank release from
impacting navigable waters.

Contamination resulting from spills or releases of petroleum products is
an inherent risk within the petroleum pipeline industry. To the extent that
groundwater contamination requiring remediation exists along our pipeline
systems as a result of past operations, we believe any such contamination could
be controlled or remedied without having a material adverse effect on our
financial position, but such costs are site specific, and we cannot assure you
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. OPA 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
federal 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 resource damages.

The EPA has adopted regulations that require us 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 we operate. These permits may
require us to monitor and sample the storm water run-off.

Air Emissions

Our operations are subject to the federal Clean Air Act (the Clean Air
Act) and comparable state laws. Amendments to the Clean Air Act, as well as
recent or soon to be adopted changes to state implementation plans for
controlling air emissions in regional, non-attainment areas, may require our
operations to incur future capital expenditures in connection with the addition
or modification of existing air emission control equipment and strategies. In
addition, some of our facilities are included within the categories of
hazardous air pollutant sources, which are subject to increasing regulation
under the Clean Air Act. The Clean Air Act requires federal operating permits
for major sources of air emissions. Under this program, a federal operating
permit (a Title V permit) may

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be issued. The permit acts as an umbrella that includes other federal,
state and local preconstruction and/or operating permit provisions, emission
standards, grandfathered rates and record keeping, reporting and monitoring
requirements in a single document. The federal operating permit is the tool
that the public and regulatory agencies use to review and enforce a sites
compliance with all aspects of clean air regulation at the federal, state and
local level. We have completed applications for the facilities for which these
regulations apply.

Risk Management Plans

We are subject to the EPAs Risk Management Plan (RMP) regulations at
certain locations. This regulation is intended to work with the Occupational
Safety and Health Act (OSHA) Process Safety Management regulation (see
Safety Matters below) to minimize the offsite consequences of catastrophic
releases. The regulation requires a regulated source, in excess of threshold
quantities, to develop and implement a risk management program that includes a
five-year accident history, an offsite consequence analysis, a prevention
program and an emergency response program. We believe the operating expenses of
the RMP regulations will not have a material adverse effect on our financial
position, results of operations or cash flows.

Solid Waste

We generate hazardous and non-hazardous solid wastes that are subject to
requirements of the federal Resource Conservation and Recovery Act (RCRA) and
comparable state statutes. We also utilize waste minimization and recycling
processes to reduce the volumes of our waste. Amendments to RCRA required 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. From time to time, the EPA considers
the adoption of stricter disposal standards for non-hazardous wastes, including
crude oil and gas wastes. The adoption of such stricter standards for
non-hazardous wastes, or any future re-designation of non-hazardous wastes as
hazardous wastes will likely increase our operating expenses as well as for the
industry in general.

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 where a release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at a facility. Under CERCLA, these persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health studies. CERCLA also
authorizes the EPA and, in some instances, third parties to take actions in
response to threats to the public health or the environment and to seek to
recover the costs they incur from the responsible classes of persons. It is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by hazardous
substances or other pollutants released into the environment. In the course of
our ordinary operations, our pipeline systems generate wastes that may fall
within CERCLAs definition of a hazardous substance. In the event a disposal
facility previously used by us requires clean up in the future, we may be
responsible under CERCLA for all or part of the costs required to clean up
sites at which such wastes have been disposed.

Other Environmental Proceedings

In 1994, the Louisiana Department of Environmental Quality (LDEQ) issued
a compliance order for environmental contamination at our Arcadia, Louisiana,
facility. This contamination may be attributable to our operations, as well as
to adjacent petroleum terminals operated by other companies. In 1999, our
Arcadia facility and adjacent terminals were directed by the Remediation
Services Division of the LDEQ to pursue remediation of this contamination. At
December 31, 2003, we have an accrued liability of $0.3 million for remediation
costs at our Arcadia facility. We do not expect that the completion of the
remediation program proposed to the LDEQ will have a future material adverse
effect on our financial position, results of operations or cash flows.

In December 1999, we were notified by the EPA of potential liability for
alleged waste disposal at Container Recycling, Inc., located in Kansas City,
Kansas. We were also asked to respond to an EPA Information

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Request. Our response to the information request has been filed with the
EPA Region VII office. Based on information we have received from the EPA, as
well as through our internal investigations, we are pursuing dismissal from
this matter.

In November 2002, we were notified by the EPA of a potential liability for
alleged waste disposal at Industrial Pollution Control located in Jackson,
Mississippi. Based on the pro-rata share of waste disposed of at the facility,
the potentially responsible parties were requested to file a tolling agreement.
We filed this agreement with the EPA in December 2002. Our contribution of
total waste disposed of at the facility was estimated to be less than 1%, and
we agreed in August 2003 to pay our pro-rata share of the remediation costs
which amounted to $12,000. This matter has been fully resolved with the EPA,
and no further action is expected.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel
from a storage tank at our Blue Island terminal located in Cook County,
Illinois. As a result of the release, we have entered into an Agreed Order
with the State of Illinois. The Agreed Order requires us, in part, to complete
a site investigation plan to delineate the scope of any potential contamination
resulting from the release and to remediate any contamination present above
regulatory standards. This site investigation plan has been completed and
submitted to the State of Illinois. The Agreed Order does not contain any
provision for any fines or penalties; however, it does not preclude the State
of Illinois from assessing these at a later date. We do not expect that the
completion of the remediation program will have a future material adverse
effect on our financial position, results of operations or cash flows.

At December 31, 2003, we have an accrued liability of $5.9 million related
to various TCTM sites requiring environmental remediation activities. Under
the terms of a 1998 agreement through which we acquired various crude oil
assets from DETTCO, we received a five year contractual indemnity obligation
for environmental liabilities not otherwise assumed by us that were
attributable to the operations of the assets prior to our acquisition. The
indemnity expired on November 30, 2003. Under the agreement, we were
responsible for the first $3.0 million in environmental liabilities covered by
DETTCOs indemnification obligation, and DETTCO was responsible for specified
environmental liabilities in excess of $3.0 million, up to a maximum amount of
$25.0 million. At December 31, 2002, we had a receivable balance from DETTCO
of $4.2 million, the majority of which related to remediation activities at the
Velma, Oklahoma crude oil site. On March 31, 2003, we received a $2.4 million
payment from DETTCO for environmental liabilities we incurred that were covered
under the indemnity obligation with DETTCO. The remaining $1.8 million due was
determined as not attributable to DETTCOs indemnity obligation as a result of
settlement discussions with DETTCO on this matter and was written off.
On December 1, 2003, concurrent with the expiration of the five year
contractual indemnity obligation, we entered into a Settlement Agreement and
Release with DETTCO regarding future obligations pertaining to various
environmental liabilities associated with the assets purchased from DETTCO in
1998. The agreement provided for a net payment of $1.3 million to us from
DETTCO, which consisted of a settlement of $2.0 million for remaining crude oil
sites, partially offset by the sharing of expenses of $1.0 million which were
incurred by DETTCO in remediation of a crude oil site in Stephens County,
Oklahoma. The agreement also provided for $0.3 million toward the purchase of
an environmental insurance policy for gathering systems located in Texas and
Oklahoma and the assumption of responsibility by DETTCO for environmental
liabilities associated with three sites located in Texas and Oklahoma. We do
not expect that the completion of remediation programs associated with TCTM
activities will have a future material adverse effect on our financial
position, results of operations or cash flows.

DOT Pipeline Compliance Matters

We are subject to regulation by the United States Department of
Transportation (DOT) under the Accountable Pipeline and Safety Partnership
Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act
(HLPSA), and comparable state statutes relating to the design, installation,
testing, construction, operation, replacement and management of our pipeline
facilities. The 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 file certain
reports and provide information as required by the Secretary of Transportation.
The HLPSA was reauthorized in 2002. We believe that we are in material
compliance with these HLPSA regulations.

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We are subject to the DOT regulation requiring qualification of pipeline
personnel. The regulation requires pipeline operators to develop and maintain
a written qualification program for individuals performing covered tasks on
pipeline facilities. The intent of this regulation is to ensure a qualified
work force and to reduce the probability and consequence of incidents caused by
human error. The regulation establishes qualification requirements for
individuals performing covered tasks, and amends certain training requirements
in existing regulations. A written qualification program was completed in
April 2001, and our employees performing a covered task were qualified by the
October 2002 deadline. We believe that we are in material compliance with
these DOT regulations.

We are also subject to the OPS Integrity Management regulations which
specify how companies with greater than 500 miles of pipeline should assess,
evaluate, validate and maintain the integrity of pipeline segments that, in the
event of a release, could impact High Consequence Areas (HCA). HCA are
defined as highly populated areas, unusually sensitive environmental areas and
commercially navigable waterways. The regulation requires the development and
implementation of an Integrity Management Program (IMP) that utilizes
internal pipeline inspection, pressure testing, or other equally effective
means to assess the integrity of HCA pipeline segments. The regulation also
requires periodic review of HCA pipeline segments to ensure adequate
preventative and mitigative measures exist and that companies take prompt
action to address integrity issues raised by the assessment and analysis. In
compliance with these OPS regulations, we identified our HCA pipeline segments
and developed an IMP by the March 31, 2002 deadline. The regulations require
that initial HCA baseline integrity assessments must be conducted within seven
years, with all subsequent assessments conducted on a five-year cycle. During
2003, we continued with the baseline evaluation efforts initiated in 2002 and
completed the evaluation and associated repair of approximately 1,300 miles of
our pipeline system.

Safety Matters

We are also subject to the requirements of the federal OSHA and comparable
state statutes. We believe we are 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 us to organize and
disclose information about the hazardous materials used in our operations.
Certain parts of this information must be reported to employees, state and
local governmental authorities and local citizens upon request. We are 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. We utilize certain covered processes and maintain 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. We
believe we are in material compliance with the OSHA regulations.

In general, we expect to increase our expenditures during the next decade
to comply with stricter industry and regulatory safety standards such as those
described above. While such expenditures cannot be accurately estimated at
this time, we do not believe that they will have a future material adverse
effect on our financial position, results of operations or cash flows.

Employees

The Partnership does not have any employees. However, for organizational
purposes, TEPPCO GP, TEPPCO NGL Pipelines, LLC and TEPPCO Crude GP, LLC have
officers and directors, who are employees of the General Partner. The General
Partner is responsible for the management of us and our subsidiaries. As of
December 31, 2003, the General Partner had 1,061 employees.

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Available Information

We file annual, quarterly and other reports and other information with the
Securities and Exchange Commission (SEC) under the Securities Exchange Act of
1934 (the Exchange Act). You may read and copy any materials that we file
with the SEC at the SECs Public Reference Room at 450 Fifth Street, NW,
Washington, DC 20549. You may obtain additional information about the Public
Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC
maintains an Internet site (http://www.sec.gov) that contains reports, proxy
and information statements, and other information regarding issuers that file
electronically with the SEC, including us.

We also make available free of charge on or through our Internet website
(http://www.teppco.com) or through our Investor Relations Department
(1-800-659-0059) our Annual Reports on Form 10-K, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K, and other information statements and, if
applicable, amendments to those reports filed or furnished pursuant to Section
13(a) of the Exchange Act as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the SEC.




Item 3.Legal Proceedings

In the fall of 1999 and on December 1, 2000, the General Partner and the
Partnership were named as defendants in two separate lawsuits in Jackson County
Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S.
McCleery, et al. v. Texas Eastern Corporation, et al.(including the General
Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas
Eastern Corporation, et al.(including the General Partner and Partnership).
In both cases, the plaintiffs contend, among other things, that we and other
defendants stored and disposed of toxic and hazardous substances and hazardous
wastes in a manner that caused the materials to be released into the air, soil
and water. They further contend that the release caused damages to the
plaintiffs. In their complaints, the plaintiffs allege strict liability for
both personal injury and property damage together with gross negligence,
continuing nuisance, trespass, criminal mischief and loss of consortium. The
plaintiffs are seeking compensatory, punitive and treble damages. We have
filed an answer to both complaints, denying the allegations, as well as various
other motions. These cases are not covered by insurance. Discovery is
ongoing, and we are defending ourselves vigorously against the lawsuits. The
plaintiffs have not stipulated the amount of damages that they are seeking in
the suits. We cannot estimate the loss, if any, associated with these pending
lawsuits.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in
the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L.
Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this
case, the plaintiffs contend that our pipeline, which crosses the plaintiffs
property, leaked toxic products onto their property and, consequently caused
damages to them. We have filed an answer to the plaintiffs petition denying
the allegations, and we are defending ourselves vigorously against the lawsuit.
The plaintiffs have not stipulated the amount of damages they are seeking in
the suit; however, this case is covered by insurance. We do not believe that
the outcome of this lawsuit will have a material adverse effect on our
financial position, results of operations or cash flows.

On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P.,
filed a declaratory judgment action in the U.S. District Court for the Western
District of Oklahoma against D.R.D. Environmental Services, Inc. (D.R.D.)
seeking resolution of billing and other contractual disputes regarding
potential overcharges for environmental remediation services provided by D.R.D.
On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in
the amount of $2,243,525, and for unspecified damages for alleged tortious
interference with D.R.D.s contractual relations with DEFS. On July 16, 2003,
the parties entered into a Settlement Agreement and Mutual Release, dismissing
all claims and counterclaims against each other. The terms of the Settlement
Agreement and Mutual Release did not have a material adverse effect on our
financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit
styled John R. James, et al. v. J Graves Insulation Company, et al.as filed in
the first Judicial District Court, Caddo Parish, Louisiana. There are numerous
plaintiffs identified in the action that are alleged to have suffered damages
as the result of alleged exposure to asbestos-containing products and
materials. According to the petition and as a result of a preliminary
investigation, the General Partner believes that the only claim asserted
against it results from one individual for the

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period from July 1971 through June 1972, who is alleged to have worked on
a facility owned by the General Partners predecessor. This period represents
a small portion of the total alleged exposure period from January 1964 through
December 2001 for this individual. The individuals claims involve numerous
employers and alleged job sites. Currently, the General Partner has been
unable to confirm involvement by the General Partner or its predecessors with
the alleged location, and it is currently uncertain whether this case is
covered by insurance. Discovery is planned, and the General Partner intends to
defend itself vigorously against this lawsuit. The plaintiffs have not
stipulated the amount of damages that they are seeking in this suit. We are
obligated to reimburse the General Partner for any costs it incurs related to
this lawsuit. We cannot estimate the loss, if any, associated with this
pending lawsuit. We do not believe that the outcome of this lawsuit will have
a material adverse effect on our financial position, results of operations or
cash flows.

On April 2, 2003, Centennial was served with a petition in a matter styled
Adams, et al. v. Centennial Pipeline Company LLC, et al. This
matter involves
approximately 2,000 plaintiffs who allege that over 200 defendants, including
Centennial, generated, transported, and/or disposed of hazardous and toxic
waste at two sites in Bayou Sorrell, Louisiana, an underground injection well
and a landfill. The plaintiffs allege personal injuries, allergies, birth
defects, cancer and death. The underground injection well has been in
operation since May 1976. Based upon current information, Centennial
appears to be a de minimis contributor, having used the
disposal site during the two month time period of December 2001 to
January 2002. Marathon has been handling this
matter for Centennial under its operating agreement with Centennial. TE
Products has a 50% ownership interest in Centennial. Based upon
Centennial's limited involvement with the disposal site, we do not
believe that the outcome of this
matter will have a material adverse effect on our financial position,
results of operations or cash flows.

On December 16, 2003, Centennial, the General Partner, the Partnership and
other Partnership entities were named as defendants in a lawsuit in the 128th
District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial
Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline
leaked toxic substances on their property, causing them property damage. We
have filed an answer to the plaintiffs petition, denying the allegations, and
we are defending ourselves vigorously against this lawsuit. This case is
covered by insurance. We do not believe that the outcome of this lawsuit will
have a material adverse effect on our financial position, results of operations
or cash flows.

In addition to the litigation discussed above, we have 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. We believe that the outcome of these lawsuits and other
proceedings will not individually or in the aggregate have a future material
adverse effect on our consolidated financial position, results of operations or
cash flows.

On
February 6, 2004, a lawsuit styled San Juan Citizens Alliance et
al. v. Norton et al. was filed against the United States
Department of Interior and the BLM in the U.S. District Court,
District of Columbia, challenging a recent decision by the BLM. In
that decision, the BLM adopted a Resource Management Plan, which
authorized the development of additional gas wells on public lands in
northwestern New Mexico. A substantial portion of the development
activity in the area that is the subject of the suit involves the
infill drilling in the Basin-Fruitland Coal Gas Pool which covers
most of the San Juan Basin. We believe the BLM followed the
requirements of the law and reached a balanced decision in adopting
the Resource Management Plan. However, an adverse decision could
impact infill drilling activities in the San Juan Basin.




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

Our Limited Partner Units are listed and traded on the New York Stock
Exchange under the symbol TPP. The high and low trading prices of our Units in
2003 and 2002, respectively, as reported in The New York Times, were as
follows:

|        |  |      |       |      |  |      |       |     |  |   |       |  |  |   |       | 
|------- |  | ---- | ----- | ---- |  | ---- | ----- | --- |  | - | ----- |  |  | - | ----- | 
|        |  | 2003 |       | 2002
|        |  |      |       |     
|Quarter |  | High |       | Low  |  | High |       | Low
|        |  |      |       |      |  |      |       |    
|First   |  | $    | 31.64 |      |  | $    | 28.05 |     |  | $ | 33.25 |  |  | $ | 27.30 | 
|Second  |  |      | 37.00 |      |  |      | 30.35 |     |  |   | 33.20 |  |  |   | 29.35 | 
|Third   |  |      | 37.69 |      |  |      | 34.00 |     |  |   | 32.19 |  |  |   | 23.90 | 
|Fourth  |  |      | 41.15 |      |  |      | 35.22 |     |  |   | 29.98 |  |  |   | 26.00 | 

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Based on the information received from our transfer agent and from brokers
and nominees, we estimate the number of beneficial holders of our Units as of
February 20, 2004, to be approximately 70,000.

The quarterly cash distributions for the years ended December 31, 2003 and
2002 were as follows:

|                 |  |                  |  |          |       | 
|---------------- |  | ---------------- |  | -------- | ----- | 
|                 |  |                  |  | Amount  
|Record Date      |  | Payment Date     |  | Per Unit
|                 |  |                  |  |         
|April 30, 2002   |  | May 8, 2002      |  | $        | 0.575 | 
|July 31, 2002    |  | August 8, 2002   |  |          | 0.600 | 
|October 31, 2002 |  | November 8, 2002 |  |          | 0.600 | 
|January 31, 2003 |  | February 7, 2003 |  |          | 0.600 | 
|April 30, 2003   |  | May 9, 2003      |  | $        | 0.625 | 
|July 31, 2003    |  | August 8, 2003   |  |          | 0.625 | 
|October 31, 2003 |  | November 7, 2003 |  |          | 0.650 | 
|January 30, 2004 |  | February 6, 2004 |  |          | 0.650 | 

We make quarterly cash distributions of all of our 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 when cash distributions exceed certain
target thresholds (see Note 12. Partners Capital and Distributions).

We are a publicly traded master limited partnership and are not subject to
federal income tax. Instead, unitholders are required to report their allocated
share of our income, gain, loss, deduction and credit, regardless of whether we
make distributions. We have made quarterly distribution payments since May
1990.

Distributions of cash paid by us 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 owned by the unitholder.

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Item 6.Selected Financial Data

The following tables set forth, for the periods and at the dates
indicated, our selected consolidated financial and operating data. The
financial data was derived from our consolidated financial statements and
should be read in conjunction with our audited consolidated financial
statements included in the Index to Financial Statements on page F-1 of this
Report. See also Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations.

|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |           |      | 
|---------------------- | ---------------------------------------------- | ---------------------------------------------- | ------------------------ | ---------------------------- | --------- | --------------------------------------- | ---- | --------- | --------- | --------- | ---- | --------- | --------- | --------- | ---- | --------- | --------- | --------- | ---- | --------- | --------- | --------- | ---- | 
|                       |                                                |                                                |                          |                              |           | Years Ended December 31,               
|                       |                                                |                                                |                          |                              |           |                                        
|                       |                                                |                                                |                          |                              |           | 2003                                    |      | 2002 (1)  |           | 2001 (2)  |      | 2000 (3)  |           | 1999     
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |          
|                       |                                                |                                                |                          |                              |           | (in thousands, except per Unit amounts)
|Income Statement Data: |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |          
|                       | Operating revenues:                            |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |          
|                       |                                                | Sales of petroleum products                    |                          | $                            | 3,766,651 |                                         |      | $         | 2,823,800 |           |      | $         | 3,219,816 |           |      | $         | 2,821,943 |           |      | $         | 1,692,767 |          
|                       |                                                | Transportation  Refined products              |                          |                              | 138,926   |                                         |      |           | 123,476   |           |      |           | 139,315   |           |      |           | 119,331   |           |      |           | 123,004   |          
|                       |                                                | Transportation  LPGs                          |                          |                              | 91,787    |                                         |      |           | 74,577    |           |      |           | 77,823    |           |      |           | 73,896    |           |      |           | 67,701    |          
|                       |                                                | Transportation  Crude oil                     |                          |                              | 29,057    |                                         |      |           | 27,414    |           |      |           | 24,223    |           |      |           | 17,524    |           |      |           | 11,846    |          
|                       |                                                | Transportation  NGLs                          |                          |                              | 39,837    |                                         |      |           | 38,870    |           |      |           | 20,702    |           |      |           | 7,009     |           |      |           |          |          
|                       |                                                | Gathering  Natural gas                        |                          |                              | 135,144   |                                         |      |           | 90,053    |           |      |           | 8,824     |           |      |           |          |           |      |           |          |          
|                       |                                                | Mont Belvieu operations                        |                          |                              |          |                                         |      |           | 15,238    |           |      |           | 14,116    |           |      |           | 13,334    |           |      |           | 12,849    |          
|                       |                                                | Other revenues                                 |                          |                              | 54,430    |                                         |      |           | 48,735    |           |      |           | 51,594    |           |      |           | 34,904    |           |      |           | 26,716    |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       |                                                |                                                | Total operating revenues |                              |           | 4,255,832                               |      |           |           | 3,242,163 |      |           |           | 3,556,413 |      |           |           | 3,087,941 |      |           |           | 1,934,883 |     
|                       | Purchases of petroleum products                |                                                |                          | 3,711,207                    |           |                                         |      | 2,772,328 |           |           |      | 3,172,805 |           |           |      | 2,793,643 |           |           |      | 1,666,042 |          
|                       | Operating expenses                             |                                                |                          | 255,437                      |           |                                         |      | 213,556   |           |           |      | 185,918   |           |           |      | 150,149   |           |           |      | 136,095   |          
|                       | Depreciation and amortization                  |                                                |                          | 100,728                      |           |                                         |      | 86,032    |           |           |      | 45,899    |           |           |      | 35,163    |           |           |      | 32,656    |          
|                       | Gain on sale of assets                         |                                                |                          | (3,948                       | )         |                                         |      |          |           |           |      |          |           |           |      |          |           |           |      |          |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       |                                                | Operating income                               |                          |                              | 192,408   |                                         |      |           | 170,247   |           |      |           | 151,791   |           |      |           | 108,986   |           |      |           | 100,090   |          
|                       | Interest expense  net                         |                                                |                          | (84,250                      | )         |                                         |      | (66,192   | )         |           |      | (62,057   | )         |           |      | (44,423   | )         |           |      | (29,430   | )        
|                       | Equity earnings                                |                                                |                          | 16,863                       |           |                                         |      | 11,980    |           |           |      | 17,398    |           |           |      | 12,214    |           |           |      |          |          
|                       | Other income  net                             |                                                |                          | 748                          |           |                                         |      | 1,827     |           |           |      | 1,999     |           |           |      | 599       |           |           |      | 1,460     |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       |                                                | Net income (as reported)                       |                          |                              | 125,769   |                                         |      |           | 117,862   |           |      |           | 109,131   |           |      |           | 77,376    |           |      |           | 72,120    |          
|                       | Amortization of goodwill and excess investment |                                                |                          |                             |           |                                         |      |          |           |           |      | 2,396     |           |           |      | 767       |           |           |      |          |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       |                                                | Adjusted net income                            |                          | $                            | 125,769   |                                         |      | $         | 117,862   |           |      | $         | 111,527   |           |      | $         | 78,143    |           |      | $         | 72,120    |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       | Basic and diluted income per Unit: (4)         |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |          
|                       | As reported                                    |                                                | $                        | 1.52                         |           |                                         | $    | 1.79      |           |           | $    | 2.18      |           |           | $    | 1.89      |           |           | $    | 1.91      |          
|                       |                                                | Amortization of goodwill and excess investment |                          |                              |          |                                         |      |           |          |           |      |           | 0.05      |           |      |           | 0.02      |           |      |           |          |          
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          
|                       |                                                |                                                |                          | Adjusted net income per Unit |           | $                                       | 1.52 |           |           | $         | 1.79 |           |           | $         | 2.23 |           |           | $         | 1.91 |           |           | $         | 1.91 | 
|                       |                                                |                                                |                          |                              |           |                                         |      |           |           |           |      |           |           |           |      |           |           |           |      |           |           |          

|                    |                                            |  |                |           |          |  |         |           |          |  |      |           |  |  |   |           |  |  |   |           | 
|------------------- | ------------------------------------------ |  | -------------- | --------- | -------- |  | ------- | --------- | -------- |  | ---- | --------- |  |  | - | --------- |  |  | - | --------- | 
|                    |                                            |  | December 31,  
|                    |                                            |  |               
|                    |                                            |  | 2003           |           | 2002 (1) |  | 2001(2) |           | 2000 (3) |  | 1999
|                    |                                            |  |                |           |          |  |         |           |          |  |     
|                    |                                            |  | (in thousands)
|Balance Sheet Data: |                                            |  |                |           |          |  |         |           |          |  |      |           |  |  |   |           |  |  |   |          
|                    | Property, plant and equipment  net        |  | $              | 1,619,163 |          |  | $       | 1,587,824 |          |  | $    | 1,180,461 |  |  | $ | 949,705   |  |  | $ | 720,919   | 
|                    | Total assets                               |  |                | 2,940,992 |          |  |         | 2,768,422 |          |  |      | 2,065,348 |  |  |   | 1,622,810 |  |  |   | 1,041,373 | 
|                    | Long-term debt (net of current maturities) |  |                | 1,339,650 |          |  |         | 1,377,692 |          |  |      | 715,842   |  |  |   | 835,784   |  |  |   | 455,753   | 
|                    | Total debt                                 |  |                | 1,339,650 |          |  |         | 1,377,692 |          |  |      | 1,075,842 |  |  |   | 835,784   |  |  |   | 455,753   | 
|                    | Class B Units held by related party        |  |                |          |          |  |         | 103,363   |          |  |      | 105,630   |  |  |   | 105,411   |  |  |   | 105,859   | 
|                    | Partners capital                          |  |                | 1,109,321 |          |  |         | 891,842   |          |  |      | 543,181   |  |  |   | 315,057   |  |  |   | 229,767   | 

|                |                                                     |  |                                         |          |          |  |         |          |          |  |      |          |   |  |   |         |   |  |   |         |  
|--------------- | --------------------------------------------------- |  | --------------------------------------- | -------- | -------- |  | ------- | -------- | -------- |  | ---- | -------- | - |  | - | ------- | - |  | - | ------- | -
|                |                                                     |  | Years Ended December 31,               
|                |                                                     |  |                                        
|                |                                                     |  | 2003                                    |          | 2002 (1) |  | 2001(2) |          | 2000 (3) |  | 1999
|                |                                                     |  |                                         |          |          |  |         |          |          |  |     
|                |                                                     |  | (in thousands, except per Unit amounts)
|Cash Flow Data: |                                                     |  |                                         |          |          |  |         |          |          |  |      |          |   |  |   |         |   |  |   |        
|                | Net cash provided by operating activities           |  | $                                       | 239,354  |          |  | $       | 234,917  |          |  | $    | 169,148  |   |  | $ | 108,045 |   |  | $ | 103,070 |  
|                | Capital expenditures to sustain existing
operations |  |                                         | (32,864  | )        |  |         | (21,978  | )        |  |      | (18,578  | ) |  |   | (21,859 | ) |  |   | (24,890 | )
|                | Distributions paid                                  |  |                                         | (202,498 | )        |  |         | (151,853 | )        |  |      | (104,412 | ) |  |   | (82,231 | ) |  |   | (69,259 | )
|                | Distributions paid per Unit (4)                     |  | $                                       | 2.50     |          |  | $       | 2.35     |          |  | $    | 2.15     |   |  | $ | 2.00    |   |  | $ | 1.85    |  

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---



|(1) |  | Data reflects the operations of the Chaparral and Val Verde assets
acquired on March 1, 2002 and June 30, 2002, respectively.                                                                                     
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Data reflects the operations of the Jonah assets acquired on September
30, 2001.                                                                                                                                  
|   
|(3) |  | Data reflects the operations of the ARCO assets acquired on July 20,
2000.                                                                                                                                        
|   
|(4) |  | Per Unit calculation includes 3,700,000 Units issued in 2000, 7,750,000
Units issued in 2001, 13,359,597 Units issued in 2002 and 9,188,957 Units
issued in 2003, net of retirement of Class B Units of 3,916,547.




Item 7.Managements Discussion and Analysis of Financial Condition and Results of Operations

The following information is provided to facilitate increased
understanding of our 2003, 2002 and 2001 consolidated financial statements and
our accompanying notes listed in the Index to Financial Statements on page F-1
of this Report. Accounting policies that are among the most critical to the
portrayal of our financial condition and results of operations are discussed
under -Critical Accounting Policies. 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 Considerations
addresses trends, future plans and contingencies that are reasonably likely to
materially affect future liquidity or earnings.

Overview

TEPPCO Partners, L.P., a Delaware limited partnership, is a publicly
traded master limited partnership formed in March 1990. We operate through TE
Products, TCTM and TEPPCO Midstream. Collectively, TE Products, TCTM and
TEPPCO Midstream are referred to as the Operating Partnerships. Texas
Eastern Products Pipeline Company, LLC, a Delaware limited liability company,
serves as our general partner and owns a 2% general partner interest in us.
The General Partner is a wholly owned subsidiary of DEFS, a joint venture
between Duke Energy and ConocoPhillips. Duke Energy holds an interest of
approximately 70% in DEFS, and ConocoPhillips holds the remaining 30%. The
Company, as general partner, performs all management and operating functions
required for us, except for the management and operations of certain of the
TEPPCO Midstream assets that are managed by DEFS on our behalf. We reimburse
the General Partner for all reasonable direct and indirect expenses incurred in
managing us. TEPPCO GP, our subsidiary, is the general partner of our
Operating Partnerships. We hold a 99.999% limited partner interest in the
Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.

We operate and report in three business segments. Our Upstream Segment
gathers, transports, markets and stores crude oil and distributes lubrication
oils and specialty chemicals in Oklahoma, Texas, New Mexico and in the Rocky
Mountain region. Our Midstream Segment gathers natural gas in the Green River
Basin in southwestern Wyoming and in the San Juan Basin in northwestern New
Mexico and southwestern Colorado; transports NGLs from southeastern New Mexico,
East Texas and West Texas to Mont Belvieu, Texas, and fractionates NGLs at two
facilities in Colorado. Our Downstream Segment owns, operates or has
investments in properties located in 14 states and transports, stores and
provides terminal facilities for petroleum products; transports LPGs in the
Mont Belvieu area; transports petrochemicals in southeast Texas; and provides
other ancillary services.

We earn revenues and income and generate cash by charging our customers a
fee for the transportation, storage, gathering, terminaling, fractionation and
other services we provide. In our Upstream Segment, we seek to maintain a
balanced marketing position until we make physical delivery of the crude oil,
thereby minimizing or eliminating our exposure to price fluctuations occurring
after the initial purchase.

We are subject to economic and other factors that affect our industry.
The demand for crude oil and petroleum products is dependent on the price of
crude oil and the products produced from the refining of crude oil; the price
of natural gas and locations in which natural gas is drilled; and the demand
for petrochemicals, which is dependent on prices for products produced from
petrochemicals. We are also subject to regulatory factors such as the amounts
we are allowed to charge our customers for the services we provide on our
regulated pipeline systems.

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We are focused on opportunities, challenges and risks that are inherent in
our business segments as discussed in this Report. These include the safe,
reliable and efficient operation of the pipelines and facilities that we own or
operate while meeting increased regulations that govern the operation of our
assets and the costs associated with such regulations. We are also focused on
our continued growth through expansion of the assets that we own and through
acquisition of assets that compliment the segments in which we operate.

In 2003, excellent operating performance across all of our business
segments contributed to a record year for volumes, net income and earnings
before interest, taxes, depreciation and amortization. Our 2003 results
illustrate the strength and diversity of our asset portfolio. Our net income
for the year ended December 31, 2003, was $125.8 million. We raised our
distribution to our unitholders by $0.20 per Unit to an annualized rate of
$2.60 per Unit at year end, continuing our eleven year track record of
distribution increases. Distributions have increased 35% over the past five
years.

Our Upstream Segment had strong gathering, marketing and transportation
results, including the benefits of a one-time gain of $3.9 million related to
the sale of certain portions of the Rancho Pipeline. Additionally, Seaways
performance was noticeably stronger, with record volumes in the second half of
the year. We also had higher throughput on our crude systems and a record year
for gallons delivered by LSI. The Downstream Segment had an excellent year, as
well, with record refined product and propane deliveries, made possible by the
additional capacity provided by our lease agreement with Centennial. We have
utilized Centennial capacity in a manner that has provided additional delivery
capability for our customers. The Midstream Segment continued its strong
performance, with continued volume growth on the Jonah system and full year
contribution of the Val Verde system, acquired in June 2002, providing a
positive impact on our overall profitability. Additional revenue generating
capital growth prospects make the outlook favorable for continued strong
performance in this segment.

Our operating costs were higher than expected, largely as a result of
pipeline integrity expenses in our Downstream Segment. The goal of our on-going
pipeline integrity program has always been to maintain the long-term
reliability and safety of our pipeline systems, while minimizing the impact to
our customers. We ended 2003 in a solid financial position. During the year,
we spent $162.0 million on acquisitions and revenue generating capital
projects, which we believe will provide earnings, cash flow and growth
opportunities. We raised approximately $171.0 million in equity capital during
the year to fund these revenue generating capital projects, reduce debt and for
general partnership purposes.

We continued building a base for long-term growth by enhancing existing
systems and pursuing new business opportunities. We increased throughput on our
pipeline systems, constructed new pipeline and gathering systems, and expanded
and upgraded our existing infrastructure. Among the highlights of 2003:



| |  |  | We acquired an additional interest in Centennial for $20.0 million,
bringing our ownership interest to 50%. Additionally, Centennial has
provided additional capacity through our lease agreement that has
enabled us to transport record refined product volumes in 2003.                                                                                                                                                                                              
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | In November, we purchased 150 miles of crude supply and
transportation assets along the upper Texas Gulf Coast from Genesis
Crude Oil, L.P. and Genesis Pipeline Texas, L.P. The $21.0 million
acquisition strengthened our existing South Texas market position and
improved our physical asset base.                                                                                                                                                                  
|
| |  |  | During the fourth quarter of 2003, we completed a $12.0 million
expansion project that was part of a system-wide effort to increase our
deliverability of LPGs to the Northeast markets.                                                                                                                                                                                                                                                                                
|
| |  |  | In the fourth quarter of 2003, the Phase III expansion of the Jonah
system became operational. During 2003, we spent approximately $44.6
million on the project with an additional $14.4 million expected to be
spent in 2004. The Phase III project expands both pipeline and
processing capacity on the Jonah system. The Phase III expansion
provides additional investment opportunities from the ongoing
development of the Jonah and Pinedale reserves in Wyoming.
|
| |  |  | We spent an additional $64.4 million on other revenue generating
projects, including the expansion of Downstream Segment terminal
storage and delivery capacity, additional well connections in the
Midstream Segment and expansions on the Upstream Segments South Texas
system.                                                                                                                                                                                      

We remain confident that our current strategy and focus will provide
continued growth in earnings and cash distributions. With respect to 2004,
these opportunities include:

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| |  |  | Construction of a new truck loading facility in Bossier City, Louisiana.                                 
| | - |  | ---------------------------------------------------------------------------------------------------------
|
| |  |  | Integration of the Genesis crude oil assets and increased utilization of Seaway.                         
|
| |  |  | Continued development of refined products and propane market opportunities.                              
|
| |  |  | Continued development of the Jonah and Pinedale fields.                                                  
|
| |  |  | Infill drilling of CBM and conventional gas in the San Juan Basin,
where our Val Verde system is located.

Acquisitions

We completed several acquisitions in 2003, 2002 and 2001 that have
impacted the results of operations and liquidity discussed in this Report. The
following acquisitions were accounted for, and the purchase price was
allocated, in accordance with the purchase method of accounting. We adopted
Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations, in 2001 and followed the provisions of that statement for all
business combinations initiated after June 30, 2001.

Jonah Gas Gathering Company

On September 30, 2001, we completed the purchase of Jonah from Alberta
Energy Company for $359.8 million, with an additional payment of $7.3 million
made on February 4, 2002, for final purchase adjustments related primarily to
construction projects in progress at the time of closing. The acquisition
served as our entry into the natural gas gathering industry. We funded the
acquisition through a borrowing under a $400.0 million credit facility with
SunTrust Bank (see Note 11. Debt). We allocated the purchase price, net of
liabilities assumed, primarily to property, plant and equipment and intangible
assets for gas gathering contracts. We also recognized goodwill on the
purchase of approximately $2.8 million (see Note 6. Acquisitions and
Dispositions). Accordingly, the results of operations of the acquisition have
been included in our consolidated financial statements from September 30, 2001.
Under a contractual agreement, DEFS manages and operates Jonah on our behalf.

The value assigned to intangible assets relates to contracts with
customers that are for either a fixed term or which dedicate total future lease
production. We are amortizing the value assigned to intangible assets on a
unit-of-production basis, based upon the actual throughput of the system over
the expected total throughput for the contracts (averaging approximately 25
years).

Since the acquisition, we have expanded both the pipeline capacity and
processing capacity of the Jonah system. In 2002, we completed the Phase I and
Phase II expansions of Jonah, which nearly doubled the capacity of the Jonah
system. The first expansion was completed in May 2002 at a cost of
approximately $25.0 million and increased system capacity by 62%, from
approximately 450 MMcf/day to approximately 730 MMcf/day. In October 2002, an
additional expansion project was completed at a cost of approximately $45.0
million, which increased the capacity of the Jonah system from 730 MMcf/day to
approximately 880 MMcf/day. In 2003, the Jonah system was again expanded to
include an 80-mile expansion on the system and the building of a new 250
MMcf/day gas processing plant near Opal, Wyoming. Phase III was substantially
completed during the fourth quarter of 2003, and the system was operational,
with system capacity increasing to 1,180 MMcf/day. The cost of the Phase III
expansion through December 31, 2003, was approximately $44.6 million. The
total cost of the Phase III expansion will be approximately $59.0 million, with
the remaining work to be completed in 2004.

Chaparral NGL System

On March 1, 2002, we completed the purchase of the Chaparral NGL system
for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P.,
including acquisition related costs of approximately $0.4 million. The
Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu.
The pipeline delivers NGLs to fractionators and to MB Storages existing
storage facilities in Mont Belvieu. We funded the purchase through borrowings
under our $500.0 million revolving credit facility (see Note 11. Debt). We
allocated the purchase price to property, plant and equipment. Accordingly,
the results of the acquisition have been included in our consolidated financial
statements from March 1, 2002. Under a contractual agreement, DEFS manages and
operates Chaparral on our behalf.

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Val Verde Gas Gathering Company

On June 30, 2002, we completed the purchase of Val Verde for $444.2
million from Burlington Resources Gathering Inc., a subsidiary of Burlington
Resources Inc., including acquisition related costs of approximately $1.2
million. The Val Verde system gathers CBM from the Fruitland Coal Formation of
the San Juan Basin in New Mexico and Colorado. The system is one of the
largest CBM gathering and treating facilities in the United States. We funded
the purchase through borrowings of $168.0 million under our $500.0 million
revolving credit facility, $72.0 million under our 364-day revolving credit
facility and $200.0 million under a six-month term loan with SunTrust Bank (see
Note 11. Debt). The remaining purchase price was funded through working
capital sources of cash. We allocated the purchase price, net of liabilities
assumed, primarily to property, plant and equipment and intangible assets for
gas gathering contracts (see Note 6. Acquisitions and Dispositions).
Accordingly, the results of the acquisition have been included in our
consolidated financial statements from June 30, 2002. Under a contractual
agreement, DEFS manages and operates Val Verde on our behalf.

The value assigned to intangible assets relates to fixed-term contracts
with customers. We are amortizing the value assigned to intangible assets on a
unit-of-production basis, based upon the actual throughput of the system over
the expected total throughput for the contracts (averaging approximately 20
years).

Rancho Pipeline

In connection with our acquisition of crude oil assets in 2000, we
acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline,
which was a crude oil pipeline system from West Texas to Houston. In March
2003, the Rancho Pipeline ceased operations, and segments of the pipeline were
sold to certain of the owners which previously held undivided interests in the
pipeline. We acquired approximately 230 miles of the pipeline in exchange for
cash of $5.5 million and our interests in other portions of the Rancho
Pipeline. We sold part of the segment we acquired to other entities for cash
and assets valued at approximately $8.5 million. We recorded a net gain of
$3.9 million on the transactions, which is included in the gain on sale of
assets in our consolidated statements of income.

Genesis Pipeline

On November 1, 2003, we completed the purchase of crude supply and
transportation assets along the upper Texas Gulf Coast for $21.0 million from
Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. The transaction was
funded with proceeds from our August 2003 equity offering (see Note 12.
Partners Capital and Distributions). We allocated the purchase price, net of
liabilities assumed, primarily to property, plant and equipment and intangible
assets (see Note 6. Acquisitions and Dispositions). The assets acquired
included approximately 150 miles of small diameter trunk lines, 26,000 barrels
per day of throughput and 12,000 barrels per day of lease marketing and supply
business. We have integrated these assets into our South Texas pipeline system
which has allowed us to consolidate gathering and marketing assets in key
operating areas in a cost effective manner and will provide future growth
opportunities. Accordingly, the results of the acquisition are included in the
consolidated financial statements from November 1, 2003.

General

We operate and report in three business segments:



| |  |  | Downstream Segment  transportation and storage of refined products, LPGs and petrochemicals;                                                     
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Upstream Segment  gathering, transportation, marketing and
storage of crude oil and distribution of lubrication oils and
specialty chemicals; and
|
| |  |  | Midstream Segment  gathering of natural gas, transportation
of NGLs and fractionation of NGLs.                                                   

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Our reportable segments offer different products and services and are
managed separately because each requires different business strategies. TEPPCO
GP, our wholly owned subsidiary, acts as managing general partner of our
Operating Partnerships, with a 0.001% general partner interest and manages our
subsidiaries.

Effective January 1, 2002, we realigned our three business segments to
reflect our entry into the natural gas gathering business and the expanded
scope of NGLs operations. We transferred the fractionation of NGLs, which was
previously reflected as part of the Downstream Segment, to the Midstream
Segment. The operation of the NGL pipelines, which was previously reflected as
part of the Upstream Segment, was also transferred to the Midstream Segment.
We have adjusted our period-to-period comparisons to conform with the current
presentation.

Our Downstream Segment revenues are earned from transportation and storage
of refined products and LPGs, intrastate transportation of petrochemicals, sale
of product inventory and other ancillary services. The two largest operating
expense items of the Downstream Segment are labor and electric power. We
generally realize higher revenues during the first and fourth quarters of each
year since our operations are somewhat seasonal. 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. Our Downstream
Segment also includes the results of operations of the northern portion of the
Dean Pipeline. Beginning in January 2003, the northern portion of the Dean
Pipeline was converted to transport RGP from Mont Belvieu to Point Comfort,
Texas. As a result, the revenues and expenses of the northern portion of the
Dean Pipeline are included in the Downstream Segment. Our Downstream Segment
also includes our equity investments in Centennial and MB Storage (see Note 7.
Equity Investments).

Our Upstream Segment revenues are earned from gathering, transportation,
marketing and storage of crude oil and distribution of lubrication oils and
specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky
Mountain region. Marketing operations consist primarily of aggregating
purchased crude oil along our pipeline systems, or from third party pipeline
systems, and arranging the necessary transportation logistics for the ultimate
sale of the crude oil to local refineries, marketers or other end users. Our
Upstream Segment also includes our equity investment in Seaway (see Note 7.
Equity Investments).

Our Midstream Segment revenues are earned from the fractionation of NGLs
in Colorado, transportation of NGLs from two trunkline NGL pipelines in South
Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from
West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the
Green River Basin in southwestern Wyoming, through Jonah, and the gathering of
CBM in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS
manages and operates the Val Verde, Jonah and Chaparral assets for us under
contractual agreements. The results of operations of the acquisitions are
included in our consolidated financial statements in periods subsequent to
their respective acquisition dates (see Note 6. Acquisitions and
Dispositions).

Critical Accounting Policies

The preparation of financial statements in accordance with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities as well as the disclosure of contingent assets and liabilities at
the date of the financial statements. Such estimates and assumptions also
affect the reported amounts of revenues and expenses during the reporting
period. Changes in these estimates could materially affect our financial
position, results of operations or cash flows. Although we believe that these
estimates are reasonable, actual results could differ from these estimates.
Key estimates used by our management include estimates used to record revenue
and expense accruals, environmental costs, depreciation and amortization, asset
impairment and fair values of assets acquired. Significant accounting policies
that we employ are presented in the notes to the consolidated financial
statements (see Note 2. Summary of Significant Accounting Policies).

Critical accounting policies are those that are most important to the
portrayal of our financial position and results of operations. These policies
require managements most difficult, subjective or complex judgments, often
employing the use of estimates about the effect of matters that are inherently
uncertain. Our most critical accounting

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policies pertain to revenue and expense accruals, environmental costs,
property, plant and equipment and goodwill and intangible assets.

Revenue and Expense Accruals

We routinely make accruals for both revenues and expenses due to the
timing of compiling billing information, receiving certain third party
information and reconciling our records with those of third parties. The
delayed information from third parties includes, among other things, actual
volumes of crude oil purchased, transported or sold, adjustments to inventory
and invoices for purchases and other operating expenses. We make accruals to
reflect estimates for these items based on our internal records and information
from third parties. Most of the estimated accruals are reversed in the
following month when actual information is received from third parties and our
internal records have been reconciled.

The most difficult accruals to estimate are power costs, property taxes
and crude oil margins. Power cost accruals generally involve a two to three
month estimate, and the amount varies primarily for actual power usage. Power
costs are dependent upon the actual volumes transported through our pipeline
systems and the various power rates charged by numerous power companies along
the pipeline system. Peak demand rates, which are difficult to predict, drive
the variability of the power costs. Property tax accruals involve significant
tax rate estimates among numerous jurisdictions. Actual property taxes are
often not known until the tax bill is settled in subsequent periods, and the
tax amount can vary for tax rate changes and changes in tax methods or
elections. Crude oil margin estimates are based upon an average of the past
twelve months of crude oil marketing volumes, factoring in current market
events, and prices of crude oil. We use an average of prices that were in
effect during the applicable month to determine the expected revenue amount,
and we determine the margin by evaluating the actual margins of the prior
twelve months. Each of these accruals requires managements subjective
judgments, requiring estimates regarding the effects of items that are
inherently uncertain.

Environmental Costs

At December 31, 2003, we have accrued a liability for our estimate of the
future payments we expect to pay for environmental costs to remediate existing
conditions attributable to 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 damages and other costs,
when estimable. We monitor the balance of accrued undiscounted environmental
liabilities on a regular basis. We record liabilities for environmental costs
at a specific site when our liability for such 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 our ultimate liabilities associated with
environmental costs are particularly difficult to make with certainty due to
the number of variables involved, including the early stage of investigation at
certain sites, the lengthy time frames required to complete remediation
alternatives available and the evolving nature of environmental laws and
regulations. For information concerning environmental regulation and
environmental costs and contingencies, see Items 1 and 2. Business and
Properties  Environmental Matters.

Property, Plant and Equipment

We record property, plant and equipment at its acquisition cost.
Additions to property, plant and equipment, including major replacements or
betterments, are recorded at cost. We charge replacements and renewals of
minor items of property that do not materially increase values or extend useful
lives to maintenance expense. The cost of property, plant and equipment, less
estimated salvage value, is generally depreciated on a straight-line basis
using rates based upon expected useful lives of various classes of assets
(ranging from 2% to 20% per year). Useful lives are based on historical
experience and are adjusted when changes in planned use, technological advances
or other factors show that a different life would be more appropriate. Changes
in useful lives that do not result in the impairment of an asset are recognized
prospectively.

We review long-lived assets for impairment in accordance with SFAS No.
144, Accounting for the Impairment or Disposal of Long-Lived Assets.
Long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Recoverability of

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the carrying amount of assets to be held and used is measured by a
comparison of the carrying amount of the asset to future net cash flows
expected to be generated by the asset. Estimates of future net cash flows
include anticipated future revenues, expected future operating costs and other
estimates. If such assets are considered to be impaired, the impairment to be
recognized is measured by the amount by which the carrying amount of the assets
exceeds the fair value of the assets. Assets to be disposed of are reported at
the lower of the carrying amount or fair value less costs to sell.

During the second quarter of 2001, Pennzoil-Quaker State Company
(Pennzoil) sold its Shreveport, Louisiana, refinery. Under its
transportation agreement with TE Products, Pennzoil had a throughput commitment
of 25,000 barrels per day. Pennzoil and TE Products negotiated a settlement of
$18.9 million to terminate the long-term transportation agreement from the
Shreveport origin point on the Products Pipeline System. The termination
payment was recorded as refined products transportation revenue in 2001. In
connection with the termination of the transportation agreement, we evaluated
its impact on the pipeline segment from Shreveport to El Dorado, Arkansas, in
accordance with SFAS 144. The evaluation did not result in an impairment of
the carrying value of the related transportation assets, which was $28.1
million at December 31, 2003. We are pursuing a plan to make system changes to
allow for bi-directional product flow and deliveries into the Shreveport market
area. We have completed feasibility studies, and we are in discussions with
potential customers regarding the transportation of volumes through this
pipeline. We have approved a project for construction of a new truck loading
terminal in Bossier City, Louisiana, and the reversal of the pipeline.
Engineering design work and property acquisition for the terminal site are
currently under way, and the project is scheduled to be completed by the end of
2004. If the successful completion of the plan is not realized on this
pipeline segment, an impairment may be recorded for the excess of the carrying
value over discounted future net cash flows.

Goodwill and Intangible Assets

Goodwill and intangible assets represent the excess of consideration paid
over the fair value of tangible net assets acquired. Certain assumptions and
estimates are employed in determining the fair value of assets acquired
including goodwill and other intangible assets as well as determining the
allocation of goodwill to the appropriate reporting unit. In addition, we
assess the recoverability of these intangibles by determining whether the
amortization of these intangibles over their remaining useful lives can be
recovered through undiscounted future net cash flows of the acquired
operations. The amount of impairment, if any, is measured by the amount by
which the carrying amounts exceed the projected discounted future operating
cash flows. During 2002, we adopted SFAS No. 142, Goodwill and Other
Intangible Assets, which discontinues the amortization of goodwill and
indefinite life intangibles and requires an annual test of impairment based on
a comparison of fair value to carrying values. The evaluation of impairment
under SFAS 142 requires the use of projections, estimates and assumptions as to
the future performance of the operations, including anticipated future
revenues, expected future operating costs and the discount factor used. Actual
results could differ from projections resulting in revisions to our assumptions
and, if required, recognizing an impairment loss. Based on our assessment, we
do not believe our goodwill is impaired and we have not recorded a charge from
the adoption of SFAS 142 (see Note 3. Goodwill and Other Intangible Assets).
At December 31, 2003, the recorded value of goodwill was $16.9 million.

At December 31, 2003, we have $400.3 million of intangible assets related
to natural gas transportation contracts which were recorded as part of our
acquisitions of Jonah on September 30, 2001, and Val Verde on June 30, 2002
(see Note 6. Acquisitions and Dispositions). The value assigned to the
natural gas transportation contracts required management to make estimates
regarding the fair value of the assets acquired. In connection with the
acquisition of Jonah, we assumed contracts that dedicate future production from
natural gas wells in the Green River Basin in Wyoming. We assigned $222.8
million of the purchase price to these production contracts based upon a fair
value appraisal at the time of closing. In connection with the acquisition of
Val Verde, we assumed fixed-term gas transportation contracts with customers in
the San Juan Basin in New Mexico and Colorado. We assigned $239.6 million of
the purchase price to these fixed term contracts based upon a fair value
appraisal at the time of the closing. The value assigned to intangible assets
is amortized on a unit-of-production basis, based upon the actual throughput of
the system over the expected total throughput for the lives of the contracts.
The amortization of the Jonah and Val Verde systems are expected to average
approximately 25 years and 20 years, respectively. On a quarterly basis, we
update throughput estimates and evaluate the remaining expected useful life of
the contract assets based upon the best available information. Changes in the
estimated remaining production will impact the timing of amortization expense
reported for future periods.

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Results of Operations

The following table summarizes financial data by business segment for the
years ended December 31, 2003, 2002 and 2001 (in thousands):

|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |           | 
|------------------------- | ------------------------- | ------------------------------ | ------- | ------------------------ | --------- | ---- | ------- | --------- | --------- |  | ------- | --------- | --------- | 
|                          |                           |                                |         | Years Ended December 31,
|                          |                           |                                |         |                         
|                          |                           |                                |         | 2003                     |           | 2002 |         | 2001     
|                          |                           |                                |         |                          |           |      |         |          
|Operating revenues:       |                           |                                |         |                          |           |      |         |           |           |  |         |          
|                          | Downstream Segment        |                                | $       | 266,427                  |           |      | $       | 243,538   |           |  | $       | 264,233   |          
|                          | Upstream Segment          |                                |         | 3,806,215                |           |      |         | 2,861,700 |           |  |         | 3,255,260 |          
|                          | Midstream Segment         |                                |         | 185,105                  |           |      |         | 138,922   |           |  |         | 37,242    |          
|                          | Intercompany eliminations |                                |         | (1,915                   | )         |      |         | (1,997    | )         |  |         | (322      | )        
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|                          |                           | Total operating revenues       |         |                          | 4,255,832 |      |         |           | 3,242,163 |  |         |           | 3,556,413 | 
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|Operating income:         |                           |                                |         |                          |           |      |         |           |           |  |         |          
|                          | Downstream Segment        |                                |         | 83,704                   |           |      |         | 83,098    |           |  |         | 117,676   |          
|                          | Upstream Segment          |                                |         | 28,416                   |           |      |         | 26,408    |           |  |         | 18,292    |          
|                          | Midstream Segment         |                                |         | 80,288                   |           |      |         | 60,741    |           |  |         | 15,823    |          
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|                          |                           | Total operating income         |         |                          | 192,408   |      |         |           | 170,247   |  |         |           | 151,791   | 
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|Earnings before interest: |                           |                                |         |                          |           |      |         |           |           |  |         |          
|                          | Downstream Segment        |                                |         | 79,844                   |           |      |         | 77,115    |           |  |         | 118,064   |          
|                          | Upstream Segment          |                                |         | 49,671                   |           |      |         | 46,735    |           |  |         | 38,027    |          
|                          | Midstream Segment         |                                |         | 80,577                   |           |      |         | 61,010    |           |  |         | 15,897    |          
|                          | Intercompany eliminations |                                |         | (73                      | )         |      |         | (806      | )         |  |         |          |          
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|                          |                           | Total earnings before interest |         |                          | 210,019   |      |         |           | 184,054   |  |         |           | 171,988   | 
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|Interest expense          |                           |                                | (89,540 | )                        |           |      | (70,537 | )         |           |  | (66,057 | )        
|Interest capitalized      |                           |                                | 5,290   |                          |           |      | 4,345   |           |           |  | 4,000   |          
|Minority interest         |                           |                                |        |                          |           |      |        |           |           |  | (800    | )        
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          
|                          |                           | Net income                     |         | $                        | 125,769   |      |         | $         | 117,862   |  |         | $         | 109,131   | 
|                          |                           |                                |         |                          |           |      |         |           |           |  |         |           |          

Below is a detailed analysis of the results of operations, including
reasons for changes in results, by each of our operating segments.

Downstream Segment

The following table presents volumes delivered in barrels and average
tariff per barrel for the years ended December 31, 2003, 2002 and 2001:

|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |    |    |   
|-------------------------- | ---------------- | -------------------------------- | - | ----------------------------------------- | ------- | ------------------- | - | ------- | ------- | ---- | - | ------- | ------- |  |  | ---------- | -- | - |  | -- | -- | --
|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  | Percentage
|                           |                  |                                  |   | Years Ended December 31,                  |         | Increase (Decrease)
|                           |                  |                                  |   |                                           |         |                    
|                           |                  |                                  |   | 2003                                      |         | 2002                |   | 2001    |         | 2003 |   | 2002   
|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |        
|                           |                  |                                  |   | (in thousands, except tariff information) |         |                     |   |         |         |      |   |        
|Volumes Delivered:         |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |   
|                           | Refined products |                                  |   | 154,061                                   |         |                     |   | 138,164 |         |      |   | 122,947 |         |  |  | 12         | %  |   |  | 12 | % 
|                           | LPGs             |                                  |   | 42,543                                    |         |                     |   | 40,490  |         |      |   | 39,957  |         |  |  | 5          | %  |   |  | 1  | % 
|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |    |   
|                           |                  | Total                            |   |                                           | 196,604 |                     |   |         | 178,654 |      |   |         | 162,904 |  |  |            | 10 | % |  |    | 10 | % 
|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |    |   
|Average Tariff per Barrel: |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |   
|                           | Refined products |                                  | $ | 0.90                                      |         |                     | $ | 0.89    |         |      | $ | 0.98    | (1)     |  |  | 1          | %  |   |  | (9 | %)
|                           | LPGs             |                                  |   | 2.16                                      |         |                     |   | 1.84    |         |      |   | 1.95    |         |  |  | 17         | %  |   |  | (6 | %)
|                           |                  | Average system tariff per barrel |   | $                                         | 1.17    |                     |   | $       | 1.11    |      |   | $       | 1.22    |  |  |            | 5  | % |  |    | (9 | %)
|                           |                  |                                  |   |                                           |         |                     |   |         |         |      |   |         |         |  |  |            |    |   |  |    |   

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---

|(1) |  | Excludes $18.9 million received from Pennzoil in 2001 for canceled
transportation agreement discussed below.
|--- |  | ------------------------------------------------------------------------------------------------------------

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Downstream Segment reported earnings before interest of $79.8 million
for the year ended December 31, 2003, compared with earnings before interest of
$77.1 million for the year ended December 31, 2002. Earnings before interest
increased $2.7 million primarily due to an increase of $22.9 million in
operating revenues and increased income of $2.7 million from equity
investments, partially offset by an increase of $22.3 million in costs and
expenses and a decrease of $0.6 million in other income  net. We discuss
factors influencing our operating performance below.

Revenues from refined products transportation increased $15.5 million for
the year ended December 31, 2003, compared with the year ended December 31,
2002, due to an overall increase of 12% in the refined products volumes
delivered. This increase was primarily due to deliveries of products received
into our pipeline from Centennial at Creal Springs, Illinois. Centennial,
which began operations in April 2002, has provided our system with additional
pipeline capacity for products originating in the U.S. Gulf Coast area. In
February 2003, we entered into a lease agreement with Centennial that increased
our capacity to deliver refined products to our market areas. Prior to the
lease agreement with Centennial, deliveries on our pipeline system were based
upon a proration policy, which limited customer transportation. During 2003,
with the expanded capacity through our lease agreement with Centennial, our
pipeline system was not prorated during portions of 2003 and was better able to
serve markets which increased transportation on our system. In addition, in
December 2002, we raised the operating pressure of our Chicago lateral pipeline
which resulted in an increase in capacity for deliveries into the Indianapolis
and Chicago markets. With this incremental pipeline capacity, our previously
constrained system has expanded deliveries in markets both south and north of
Creal Springs. Volume increases were due to increased demand and market share
for products supplied from the U.S. Gulf Coast into Midwest markets. The
refined products average rate per barrel increased 1% from the prior year
period primarily due higher market-based tariff rates which went into effect in
July 2003, partially offset by the impact of the Midwest origin point for
barrels received from Centennial, which resulted in an increase in short-haul
barrels transported on our system.

Revenues from LPGs transportation increased $17.2 million for the year
ended December 31, 2003, compared with the year ended December 31, 2002,
primarily due to increased deliveries of propane in the upper Midwest and
Northeast market areas attributable to colder than normal weather during the
first quarter of 2003 and due to low inventories at competing supply locations
during the second and third quarters of 2003. The U.S. Gulf Coast had higher
propane inventory during 2003 as compared to the previous year because of
higher than normal foreign propane imports at Mont Belvieu, which resulted in a
lower propane price in this market area. This lower price contributed to
increased transportation deliveries to the mid-continent market areas.
Additional pipeline capacity for expanded propane movements was available due
to a shift of refined product volumes to Centennial. Butane deliveries also
increased due to the increased demand by refineries for normal butane for use
in gasoline blending and increased isobutane deliveries to Chicago area
refineries. The LPGs average rate per barrel increased 17% from the prior year
period as a result of an increased percentage of long-haul deliveries during
the year ended December 31, 2003, and an increase in LPG tariff rates, which
went into effect in July 2003.

Effective January 1, 2003, TE Products 50% ownership interest in MB
Storage is accounted for as an equity investment. Revenues generated from Mont
Belvieu operations totaled $15.2 million for the year ended December 31, 2002.
As a result of the formation of MB Storage, revenues and expenses related to
Mont Belvieu operations are now recorded within equity earnings. See
discussion regarding changes in equity earnings/losses below.

Other operating revenues increased $5.4 million for the year ended
December 31, 2003, compared with the year ended December 31, 2002, primarily
due to the addition of the northern portion of the Dean Pipeline to the
Downstream Segment in January 2003, which increased other operating revenues by
$4.5 million as the pipeline began transporting RGP in January 2003. The
increase was also due to higher propane deliveries at our Providence, Rhode
Island import facility and higher refined product loading fees. These
increases were partially offset by lower

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revenues from product location exchanges which are used to position product in
the Midwest market area and lower volume of product inventory sales.

Costs and expenses increased $22.3 million for the year ended December 31,
2003, compared with the year ended December 31, 2002. The increase was made up
of a $23.4 million increase in operating, general and administrative expenses
and a $1.5 million increase in depreciation and amortization expense, partially
offset by a $2.4 million decrease in taxes  other than income taxes and a $0.2
million decrease in operating fuel and power. Operating, general and
administrative expenses increased primarily due to higher pipeline maintenance
expenses, due in part to pipeline rehabilitation expenses associated with our
integrity management program, increased consulting and contract services,
increased labor costs primarily due to an increase in the number of employees
between years, increased insurance expense, expense from the Centennial
pipeline capacity lease agreement that we entered into in 2003 and the
write-off of receivables of $0.8 million related to customer bankruptcies or
other customer non-payments. The addition of the northern portion of the Dean
Pipeline to the Downstream Segment increased operating, general and
administrative expense by $0.7 million. Depreciation and amortization expense
increased from the prior year period because of assets placed in service during
the year, which resulted in increased depreciation expense. In addition, we
wrote off assets taken out of service during the period to depreciation
expense, which also increased depreciation expense. These increases in
depreciation expense were partially offset by lower depreciation expense from
assets retired during the year, which reduced the asset base, and due to the
transfer of assets to MB Storage. Taxes  other than income taxes decreased as
a result of actual property taxes being lower than previously estimated and due
to the transfer of assets to MB Storage. Operating fuel and power expense
decreased as a result of lower power costs due to a slight decrease in the
price of natural gas, partially offset by increased mainline throughput.

Net losses from equity investments decreased $2.7 million for the year
ended December 31, 2003, compared with the year ended December 31, 2002. On
February 10, 2003, TE Products acquired an additional 16.7% interest in
Centennial, bringing its ownership interest to 50%. Centennial, which
commenced operations in April 2002, accounted for $11.4 million of the equity
losses for the year ended December 31, 2003, resulting in an increase of $4.7
million in equity losses as compared with the year ended December 31, 2002.
During the year ended December 31, 2003, we recognized increased equity losses
from our investment in Centennial due to the acquisition of the additional
16.7% ownership interest in February 2003. In April 2003, we
entered into a pipeline capacity lease with Centennial for a period of five
years in order to expand our capacity to deliver refined products to
our market areas. The losses from Centennial are partially offset by equity earnings of
$7.4 million from our equity ownership interest in MB Storage, which was formed
effective January 1, 2003. Amounts in the prior year period related to Mont
Belvieu operations which were recorded to revenues and costs and expenses are
now being recorded within equity earnings based upon our 50% ownership interest
in MB Storage, effective with its formation on January 1, 2003. If the 2002
revenues and costs and expenses from the Mont Belvieu operations had been
accounted for under the same method as in 2003, equity earnings from MB Storage
would have increased $0.2 million in 2003, compared with the prior year, due to
increased shuttle deliveries and increased storage revenue, partially offset by
increases in depreciation expense and rehabilitation expenses on MB Storage
assets.

Other income  net decreased $0.6 million for the year ended December 31,
2003, compared with the year ended December 31, 2002, primarily due to lower
interest income earned on cash investments.

The Downstream Segment is dependent in large part on the demand for
refined petroleum products in the markets served by its pipelines. Reductions
in that demand adversely affect the pipeline business of the Downstream
Segment. Market demand varies based upon the different end uses of the refined
products shipped in the Downstream Segment. Demand for gasoline, which in
recent years has accounted for approximately one-half of the Downstream
Segments refined products transportation revenues, depends upon price,
prevailing economic conditions and demographic changes in the markets served in
the Downstream Segment. Demand for distillates is affected by truck and
railroad freight, the price of natural gas used by utilities, which use
distillates as a substitute for natural gas when the price of natural gas is
high, and usage for agricultural operations, which is affected by weather
conditions, government policy and crop prices. Demand for jet fuel, which in
recent years has accounted for approximately one-quarter of the Downstream
Segments refined products revenues, depends on prevailing economic conditions
and military usage. Propane deliveries are generally sensitive to the weather
and meaningful year-to-year variances have occurred in the past and will likely
continue to occur in the future.

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Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Our Downstream Segment reported earnings before interest of $77.1 million
for the year ended December 31, 2002, compared with earnings before interest of
$118.1 million for the year ended December 31, 2001. Earnings before interest
decreased $41.0 million primarily due to a decrease of $20.7 million in
operating revenues, an increase of $13.9 million in costs and expenses,
additional losses of $5.7 million from equity investments and a decrease of
$0.7 million in other income  net. We discuss factors influencing our
operating performance below.

Revenues from refined products transportation decreased $15.8 million for
the year ended December 31, 2002, compared with the year ended December 31,
2001, primarily due to $18.9 million of revenue recognized in 2001 from a cash
settlement received from a canceled transportation agreement with Pennzoil and
the recognition of $1.7 million of previously deferred revenue related to the
approval of market-based rates during the second quarter of 2001. See further
discussion regarding these factors included in Other Considerations. These
decreases were partially offset by a 12% increase in refined products volumes
delivered during the year ended December 31, 2002, primarily due to barrels
received into our pipeline from Centennial at Creal Springs, Illinois.
Centennial commenced refined products deliveries to us beginning in April 2002.
The overall increase in refined products deliveries was partially offset by a
1.3 million barrel decrease in methyl tertiary butyl ether (MTBE) deliveries
as a result of the expiration of contract deliveries to our marine terminal
near Beaumont effective April 2001. As a result of the contract expiration, we
no longer transport MTBE through our Products Pipeline System. The refined
products average rate per barrel decreased 9% from the prior year due to the
impact of the Midwest origin point for volumes received from Centennial, which
was partially offset by decreased short-haul MTBE volumes delivered and higher
market-based tariff rates, which went into effect in July 2001.

Revenues from LPGs transportation decreased $3.2 million for the year
ended December 31, 2002, compared with the year ended December 31, 2001,
primarily due to decreased deliveries of propane in the upper Midwest and
Northeast market areas attributable to warmer than normal weather in the first
quarter of 2002. The decrease was also due to lower prices from competing
Canadian and mid-continent propane supply as compared to propane originating
from the Gulf Coast. Total LPGs volumes delivered increased 1% as a result of
increased short-haul deliveries to a petrochemical facility on the upper Texas
Gulf Coast. The LPGs average rate per barrel decreased 6% from the prior year
as a result of a decreased percentage of long-haul deliveries during the year
ended December 31, 2002.

Revenues generated from Mont Belvieu operations increased $1.1 million for
the year ended December 31, 2002, compared with the year ended December 31,
2001, as a result of increased storage revenue and receipt revenue. Mont
Belvieu shuttle volumes delivered increased 25% during the year ended December
31, 2002, compared with the year ended December 31, 2001, due to increased
petrochemical demand. The Mont Belvieu average rate per barrel decreased 17%
during the year ended December 31, 2002, as a result of increased contract
shuttle deliveries, which generally carry lower rates.

Other operating revenues decreased $2.8 million for the year ended
December 31, 2002, compared with the year ended December 31, 2001, primarily
due to lower propane deliveries from our Providence import facility, lower
refined products storage revenue, lower margins on product inventory sales and
lower revenues from product location exchanges which are used to position
product in the Midwest market area. These decreases were partially offset by
increased refined products and LPGs loading fees.

Costs and expenses increased $13.9 million for the year ended December 31,
2002, compared with the year ended December 31, 2001. The increase was
comprised of an $11.8 million increase in operating, general and administrative
expenses, a $3.4 million increase in depreciation and amortization expense and
a $3.1 million increase in taxes  other than income taxes. These increases
were partially offset by a $4.4 million decrease in operating fuel and power
expense. Operating, general and administrative expenses increased primarily
due to higher pipeline rehabilitation expenses associated with our integrity
management program, increased consulting and contract services, increased labor
costs and increased general and administrative supplies expense. Depreciation
expense increased from the prior year because of assets placed in service
during 2002. Taxes  other than income taxes increased as a result of a higher
property base in 2002. Operating fuel and power expense decreased as a result
of decreased long-haul volumes delivered related to Midwest volumes received
from Centennial and lower power costs.

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Net losses from equity investments increased $5.7 million for the year
ended December 31, 2002, compared with the year ended December 31, 2001. The
increase is primarily due to pre-operating expenses and start-up costs of
Centennial, which commenced operations in early April 2002.

Other income  net decreased $0.7 million for the year ended December 31,
2002, compared with the year ended December 31, 2001. The decrease was
primarily due to lower interest income earned on cash investments.

Upstream Segment

Information presented in the following table includes the margin of the
Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted
Accounting Principles) financial measure under the rules of the Securities and
Exchange Commission. We calculate the margin of the Upstream Segment as
revenues generated from the sale of crude oil and lubrication oil, and
transportation of crude oil, less the costs of purchases of crude oil and
lubrication oil. We believe that margin is a more meaningful measure of
financial performance than operating revenues and operating expenses due to the
significant fluctuations in revenues and expenses caused by variations in the
level of marketing activity and prices for products marketed. Margin and
volume information for the years ended December 31, 2003, 2002 and 2001 is
presented below (in thousands, except per barrel and per gallon amounts):

|                                       |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |     |    |  
|-------------------------------------- | ------------------------ | ------------ | ------ | ------------------------ | ------ | ------------------- | ----- | ------- | ------ | ---- | ----- | ------- | ------ |  | - | ---------- | -- | - | -- | --- | -- | -
|                                       |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   | Percentage
|                                       |                          |              |        | Years Ended December 31, |        | Increase (Decrease)
|                                       |                          |              |        |                          |        |                    
|                                       |                          |              |        | 2003                     |        | 2002                |       | 2001    |        | 2003 |       | 2002   
|                                       |                          |              |        |                          |        |                     |       |         |        |      |       |        
|Margins:                               |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |    
|                                       | Crude oil transportation |              | $      | 45,794                   |        |                     | $     | 39,025  |        |      | $     | 34,121  |        |  |   | 17         | %  |   |    | 14  | % 
|                                       | Crude oil marketing      |              |        | 22,017                   |        |                     |       | 22,914  |        |      |       | 22,502  |        |  |   | (4         | %) |   |    | 2   | % 
|                                       | Crude oil terminaling    |              |        | 9,403                    |        |                     |       | 10,124  |        |      |       | 10,163  |        |  |   | (7         | %) |   |    |    |   
|                                       | Lubrication oil sales    |              |        | 5,372                    |        |                     |       | 4,826   |        |      |       | 4,126   |        |  |   | 11         | %  |   |    | 17  | % 
|                                       |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |     |   
|                                       |                          | Total margin |        | $                        | 82,586 |                     |       | $       | 76,889 |      |       | $       | 70,912 |  |   |            | 7  | % |    |     | 8  | %
|                                       |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |     |   
|Total barrels:                         |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |    
|                                       | Crude oil transportation |              |        | 95,541                   |        |                     |       | 82,813  |        |      |       | 78,714  |        |  |   | 15         | %  |   |    | 5   | % 
|                                       | Crude oil marketing      |              |        | 159,710                  |        |                     |       | 139,182 |        |      |       | 159,477 |        |  |   | 15         | %  |   |    | (13 | %)
|                                       | Crude oil terminaling    |              |        | 115,076                  |        |                     |       | 127,376 |        |      |       | 121,932 |        |  |   | (10        | %) |   |    | 5   | % 
|Lubrication oil volume (total gallons) |                          |              | 10,449 |                          |        |                     | 9,648 |         |        |      | 8,769 |         |        |  | 8 | %          |    |   | 10 | %  
|Margin per barrel:                     |                          |              |        |                          |        |                     |       |         |        |      |       |         |        |  |   |            |    |   |    |    
|                                       | Crude oil transportation |              | $      | 0.479                    |        |                     | $     | 0.471   |        |      | $     | 0.434   |        |  |   | 2          | %  |   |    | 9   | % 
|                                       | Crude oil marketing      |              |        | 0.138                    |        |                     |       | 0.165   |        |      |       | 0.141   |        |  |   | (16        | %) |   |    | 17  | % 
|                                       | Crude oil terminaling    |              |        | 0.082                    |        |                     |       | 0.080   |        |      |       | 0.083   |        |  |   | 3          | %  |   |    | (4  | %)
|Lubrication oil margin (per gallon):   |                          | $            | 0.514  |                          |        | $                   | 0.500 |         |        | $    | 0.471 |         |        |  | 3 | %          |    |   | 6  | %  

The following table reconciles the Upstream Segment margin to the
consolidated statements of income using the information presented in the
consolidated statements of income and the statements of income in Note 18.
Segment Information (in thousands):

|                                      |              |   |                          |        |      |   |            |        |  |   |            |        | 
|------------------------------------- | ------------ | - | ------------------------ | ------ | ---- | - | ---------- | ------ |  | - | ---------- | ------ | 
|                                      |              |   | Years Ended December 31,
|                                      |              |   |                         
|                                      |              |   | 2003                     |        | 2002 |   | 2001      
|                                      |              |   |                          |        |      |   |           
|Sales of petroleum products           |              | $ | 3,766,651                |        |      | $ | 2,823,800  |        |  | $ | 3,219,816  |       
|Transportation  Crude oil            |              |   | 29,057                   |        |      |   | 27,414     |        |  |   | 24,223     |       
|Less: Purchases of petroleum products |              |   | (3,713,122               | )      |      |   | (2,774,325 | )      |  |   | (3,173,127 | )     
|                                      |              |   |                          |        |      |   |            |        |  |   |            |       
|                                      | Total margin |   | $                        | 82,586 |      |   | $          | 76,889 |  |   | $          | 70,912 | 
|                                      |              |   |                          |        |      |   |            |        |  |   |            |       

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Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Upstream Segment reported earnings before interest of $49.7 million
for the year ended December 31, 2003, compared with earnings before interest of
$46.7 million for the year ended December 31, 2002. Earnings before interest
increased $3.0 million primarily due to an increase of $5.7 million in margin,
an increase of $2.2 million in equity earnings of Seaway and a gain of $3.9
million from the sale of assets, partially offset by an increase of $7.6
million in costs and expenses (excluding purchases of crude oil and lubrication
oil) and a decrease of $1.2 million in other income  net. We discuss factors
influencing our operating performance below.

Our margin increased $5.7 million for the year ended December 31, 2003,
compared with the year ended December 31, 2002. Crude oil transportation margin
increased $6.8 million primarily due to increased revenues on our Red River,
Basin, South Texas and West Texas systems resulting from a 15% increase in
transportation volumes on these systems partially due to the acquisition of the
Genesis assets. During the fourth quarter of 2003, we completed the purchase
of crude supply and transportation assets (Genesis), which was integrated into
our South Texas system. The acquisition of the Genesis assets increased our
transportation and marketing margins by approximately $1.2 million and the
barrels transported and marketed by approximately 1.6 million barrels during
2003. Lubrication oil sales margin increased $0.5 million due to increased
sales of chemical volumes, higher margins on lubrication sales and increased
volumes related to the acquisition of a lubrication oil distributor in Abilene,
Texas, in December 2003. Crude oil marketing margin decreased $0.9 million
primarily due to an invoicing settlement on a marketing contract in the first
quarter of 2003, partially offset by increased volumes marketed, renegotiated
supply contracts, lower trucking expenses and more favorable crude oil price
differentials. Crude oil terminaling margin decreased $0.7 million as a result
of a 10% decrease in volumes at Midland, Texas, and Cushing, Oklahoma.

Costs and expenses (excluding expenses associated with purchases of crude
oil and lubrication oil) increased $7.6 million for the year ended December 31,
2003, compared with the year ended December 31, 2002. Operating, general and
administrative expenses increased $7.1 million from the prior year period. The
increase includes a $2.4 million increase in environmental assessment and
remediation costs in 2003, higher legal costs related to the litigation and
settlement with D.R.D. and other legal costs (see Note 17. Commitments and
Contingencies), $1.7 million of expense from the net settlement of crude oil
imbalances with customers, higher pipeline rehabilitation expenses associated
with our integrity management program and increased labor costs due to an
increase in the number of employees between periods, partially offset by lower
general and administrative supplies expenses during the period. In addition,
the acquisition of the Genesis assets and integration into our South Texas
system during the fourth quarter increased operating, general and
administrative expenses by approximately $0.5 million. Operating fuel and
power increased $0.3 million due to higher power costs and higher volumes in
2003. Depreciation and amortization expense increased $0.1 million due to
assets placed in service in 2002 and 2003 and due to asset retirements. Taxes
- other than income taxes increased $0.1 million due to slight increases in
property tax accruals.

Equity earnings from our investment in Seaway increased $2.2 million for
the year ended December 31, 2003, compared with the year ended December 31,
2002, due to a favorable crude oil imbalance settlement, a gain on the sale of
inventory, lower general and administrative expenses and higher long-haul
transportation volumes, partially offset by our portion of equity earnings
which decreased from 80% to 60% on a pro-rated basis in 2002 (averaging
approximately 67% for the year ended December 31, 2002), to 60% in 2003.

In June 2003, we recorded a net gain of $3.9 million, included in the gain
on sale of assets in our consolidated statements of income, on the sale of
certain of the assets of the Rancho Pipeline. In connection with our
acquisition of crude oil assets in 2000, we acquired an approximate 23.5%
undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline
system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased
operations, and segments of the pipeline were sold to certain of the current
owners of the Rancho Pipeline. We acquired approximately 230 miles of the
pipeline in exchange for cash of $5.5 million and our interests in other
portions of the Rancho Pipeline. We sold part of the segment we acquired to
other entities for cash and assets valued at approximately $8.5 million.

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Other income  net decreased $1.2 million for the year ended December 31,
2003, compared with the year ended December 31, 2002, primarily due to lower
interest income received on intercompany borrowings.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Our Upstream Segment reported earnings before interest of $46.7 million
for the year ended December 31, 2002, compared with earnings before interest of
$38.0 million for the year ended December 31, 2001. Earnings before interest
increased $8.7 million primarily due to an increase of $6.0 million in margin,
a decrease of $2.9 million in costs and expenses (excluding purchases of crude
oil and lubrication oil), an increase of $0.3 million in other income  net and
an increase of $0.2 million in equity earnings of Seaway. These increases were
partially offset by a decrease of $0.7 million in other operating revenues. We
discuss factors influencing our operating performance below.

Our margin increased $6.0 million for the year ended December 31, 2002,
compared with the year ended December 31, 2001. Crude oil transportation margin
increased $4.9 million primarily due to volumes transported on the pipeline
assets acquired from Valero in March 2001 and higher revenues on our Basin, Red
River and West Texas systems. Crude oil terminaling margin remained constant
between years as a result of higher volumes at Midland and our Red River
system, offset by lower volumes at Cushing and on our Basin system.
Lubrication oil sales margin increased $0.7 million due to increased volumes
related to the acquisition of a lubrication oil distributor in Amarillo, Texas,
in the fourth quarter of 2001. Crude oil marketing margin increased $0.4
million primarily due to increased volumes marketed, renegotiated supply
contracts and lower trucking expenses.

Other operating revenues of the Upstream Segment decreased $0.7 million
for the year ended December 31, 2002, compared with the year ended December 31,
2001, due to lower revenues from documentation and other services to support
customers trading activity at Midland and Cushing.

Costs and expenses (excluding expenses associated with purchases of crude
oil and lubrication oil) decreased $2.9 million for the year ended December 31,
2002, compared with the year ended December 31, 2001. Operating, general and
administrative expenses decreased $3.8 million from the prior year due to $4.4
million of environmental costs recognized in 2001 and decreased labor related
costs, partially offset by increased general and administrative supplies and
services expense and environmental costs recognized in 2002 (see Note 17.
Commitments and Contingencies). Depreciation and amortization expense
increased $1.9 million due to increased depreciation expense on the assets
acquired from Valero and from the acquisition of a lubrication oil distributor
in Amarillo, Texas, partially offset by lower amortization costs from the
adoption of SFAS 142 effective January 1, 2002, in which goodwill and excess
investment are no longer being amortized. Taxes  other than income taxes
decreased $1.6 million due to reductions in property tax accruals. These
decreases were partially offset by an increase of $0.6 million in operating
fuel and power costs attributed to higher transportation volumes.

Equity earnings from our investment in Seaway for the year ended December
31, 2002, increased $0.2 million from the year ended December 31, 2001, due to
higher third party transportation volumes. This increase was partially offset
by our portion of equity earnings being reduced from 80% to 60% on a pro rated
basis in 2002 (averaging approximately 67% for the year ended December 31,
2002). Equity earnings from our investment in Seaway were affected in 2002 as
a result of the reduction of the sharing percentages of TCTM under the Seaway
partnership agreement. Beginning in June 2002, our participation in Seaway
decreased from 80% of revenue and expense of Seaway to 60%. See Items 1 and 2.
Business and Properties, Upstream Segment  Gathering, Transportation,
Marketing and Storage of Crude Oil for a more detailed discussion.

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Midstream Segment

The following table presents volume and average rate information for the
years ended December 31, 2003, 2002 and 2001:

|                         |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  |            |     |    |  |  |     |   
|------------------------ | --------------------------------------- |  | ------------------------ | ------- | ------------------- |  | ---- | ------- | ---- |  | ---- | ------ |  |  | ---------- | --- | -- |  |  | --- | --
|                         |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  | Percentage
|                         |                                         |  | Years Ended December 31, |         | Increase (Decrease)
|                         |                                         |  |                          |         |                    
|                         |                                         |  | 2003                     |         | 2002                |  | 2001 |         | 2003 |  | 2002
|                         |                                         |  |                          |         |                     |  |      |         |      |  |     
|Gathering  Natural Gas: |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  |            |     |    |  |  |    
|                         | Million cubic feet                      |  |                          | 461,238 |                     |  |      | 340,697 |      |  |      | 45,496 |  |  |            | 35  | %  |  |  | 649 | % 
|                         | Million British thermal units
(MMBtu) |  |                          | 469,127 |                     |  |      | 353,663 |      |  |      | 50,650 |  |  |            | 33  | %  |  |  | 598 | % 
|                         | Average fee per MMBtu                   |  | $                        | 0.288   |                     |  | $    | 0.255   |      |  | $    | 0.174  |  |  |            | 13  | %  |  |  | 47  | % 
|Transportation  NGLs:   |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  |            |     |    |  |  |    
|                         | Thousand barrels                        |  |                          | 57,902  |                     |  |      | 53,980  |      |  |      | 21,538 |  |  |            | 7   | %  |  |  | 151 | % 
|                         | Average rate per barrel                 |  | $                        | 0.688   |                     |  | $    | 0.720   |      |  | $    | 0.961  |  |  |            | (4  | %) |  |  | (25 | %)
|Fractionation  NGLs:    |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  |            |     |    |  |  |    
|                         | Thousand barrels                        |  |                          | 4,131   |                     |  |      | 4,072   |      |  |      | 4,078  |  |  |            | 1   | %  |  |  |    |   
|                         | Average rate per barrel                 |  | $                        | 1.804   |                     |  | $    | 1.824   |      |  | $    | 1.813  |  |  |            | (1  | %) |  |  | 1   | % 
|Sales  Condensate:      |                                         |  |                          |         |                     |  |      |         |      |  |      |        |  |  |            |     |    |  |  |    
|                         | Thousand barrels                        |  |                          | 63.3    |                     |  |      | 80.0    |      |  |      | 16.2   |  |  |            | (21 | %) |  |  | 394 | % 
|                         | Average rate per barrel                 |  | $                        | 30.25   |                     |  | $    | 25.39   |      |  | $    | 19.91  |  |  |            | 19  | %  |  |  | 28  | % 

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Midstream Segment reported earnings before interest of $80.6 million
for the year ended December 31, 2003, compared with earnings before interest of
$61.0 million for the year ended December 31, 2002. Earnings before interest
increased $19.6 million due to an increase of $46.2 million in operating
revenues, partially offset by an increase of $26.6 million in costs and
expenses. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $45.1 million for the
year ended December 31, 2003, compared with the year ended December 31, 2002.
Natural gas gathering revenues from the Jonah system increased $14.6 million
and volumes delivered increased 54.6 Bcf for the year ended December 31, 2003,
due to the expansions of the Jonah system during 2002. The first expansion,
which was completed in May 2002, increased the capacity of the Jonah system by
62%, from approximately 450 MMcf/day to approximately 730 MMcf/day. In October
2002, additional expansion projects were completed, which increased the
capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day.
A Phase III expansion was substantially completed during the fourth quarter of
2003 and increased system capacity to 1,180 MMcf/day. The increase in Jonahs
revenues is also partially due to an increase in the average natural gas
gathering rate due to certain volume thresholds being exceeded. Natural gas
gathering revenues from the Val Verde system increased $30.5 million and
volumes delivered increased 65.9 Bcf for the year ended December 31, 2003,
primarily due to the acquisition of the Val Verde system on June 30, 2002.
Volumes delivered for the first half of 2003 were approximately 82.0 Bcf. As
Val Verde was acquired on June 30, 2002, there were no comparable volumes for
the first half of 2002. Volumes delivered during the second half of 2003 as
compared to the second half of 2002 declined approximately 16.0 Bcf. This
decrease in volumes during the second half of 2003 was due to the natural
decline of CBM production, which resulted in decreased revenues, partially
offset by an increase in the average natural gas gathering rate due to annual
fee escalations in gathering agreements and higher carbon dioxide treating fees
as a result of increasing carbon dioxide content in the natural gas.

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Revenues from the transportation of NGLs increased $1.0 million for the
year ended December 31, 2003, compared with the year ended December 31, 2002,
primarily due to an increase of $4.4 million related to the acquisition of
Chaparral on March 1, 2002, $0.7 million due to an increase in volumes
transported on Chaparral and $0.2 million due to an increase in volumes
transported on the Wilcox Pipeline. This increase was partially offset by a
decrease of $2.4 million due to lower transportation volumes on the Panola
Pipeline as a result of lower NGL volumes available from the connected NGL
plants and a decrease of $1.9 million on the southern portion of the Dean
Pipeline due to decreased transportation volumes. Lower transportation volumes
on the southern portion of the Dean Pipeline resulted from the conversion of
the northern portion of the pipeline to transport RGP and subsequent
classification as a part of the Downstream Segment, effective January 1, 2003.
The decrease in the NGL transportation average rate per barrel resulted from a
lower average rate per barrel on volumes transported on Chaparral.

Other operating revenues increased $0.1 million for the year ended
December 31, 2003, compared with the year ended December 31, 2002, due to an
increase in stabilizer overhead gas on the Jonah system, partially offset by a
decrease in condensate sales on Jonah.

Costs and expenses increased $26.6 million for the year ended December 31,
2003, compared with the year ended December 31, 2002, due to a $13.1 million
increase in depreciation and amortization expense, a $12.1 million increase in
operating, general and administrative expense and a $1.6 million increase in
operating fuel and power, partially offset by a $0.2 million decrease in taxes
- other than income taxes. Depreciation and amortization expense increased
$14.6 million due to the Chaparral and Val Verde assets acquired on March 1,
2002, and June 30, 2002, respectively, $0.3 million due to assets placed in
service in 2002 related primarily to the expansions of the Jonah system and
$2.0 million in amortization expense on Jonahs intangible assets under the
units-of-production method, as volumes gathered increased between periods.
These increases were partially offset by a decrease of $1.8 million in
amortization expense on Val Verdes intangible assets under the
units-of-production method as volumes gathered decreased between periods. In
addition, amortization expense on Jonah decreased $2.0 million related to its
intangible assets. In second quarter 2003, Jonahs estimated total throughput
of the system was adjusted, which resulted in an extension of the expected
amortization period from 16 years to 25 years (see Note 3. Goodwill and Other
Intangible Assets). Operating, general and administrative expense increased
$11.0 million from the assets acquired, and $1.1 million primarily due to
higher general and administrative labor and supplies expense and increased
consulting and contracting services. Operating fuel and power costs increased
$0.8 million due to the assets acquired and $0.8 million due to increased
volumes transported on Chaparral. Taxes  other than income taxes decreased
$0.2 million due to actual property taxes being lower than previously estimated
on Val Verde, Panola Pipeline and the southern portion of the Dean Pipeline.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Our Midstream Segment reported earnings before interest of $61.0 million
for the year ended December 31, 2002, compared with earnings before interest of
$15.9 million for the year ended December 31, 2001. Earnings before interest
increased $45.1 million due to an increase of $101.6 million in operating
revenues and an increase of $0.3 million in other income  net, partially
offset by an increase of $56.8 million in costs and expenses. We discuss
factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $81.2 million for the
year ended December 31, 2002, compared with the year ended December 31, 2001.
Natural gas gathering revenues from the Jonah system increased $41.3 million
and volumes delivered increased 202.9 Bcf for the year ended December 31, 2002,
due to a full years contribution to earnings from Jonah in 2002. The Jonah
system was acquired on September 30, 2001. Natural gas gathering revenues from
the Val Verde system, which was acquired on June 30, 2002, totaled $39.9
million and volumes delivered totaled 92.3 Bcf for the year ended December 31,
2002.

Revenues from the transportation of NGLs increased $18.2 million for the
year ended December 31, 2002, compared with the year ended December 31, 2001.
NGL transportation revenues increased $18.2 million, primarily due to the
acquisition of the Chaparral NGL system on March 1, 2002, partially offset by
lower revenues on a take-or-pay contract on the Dean Pipeline that was in
effect until the bankruptcy of Enron Corp. in December 2001. The decrease in
the NGL transportation average rate per barrel resulted from the cancellation
of the Enron Corp. take-or-pay contract and a lower average rate per barrel on
volumes transported on Chaparral.

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Other operating revenues increased $2.2 million for the year ended
December 31, 2002, compared with the year ended December 31, 2001, primarily
due to an increase in sales of gas condensate from the Jonah system.

Costs and expenses increased $56.8 million for the year ended December 31,
2002, compared with the year ended December 31, 2001, due to a $34.8 million
increase in depreciation and amortization expense, a $15.5 million increase in
operating, general and administrative expense, a $4.1 million increase in
operating fuel and power costs and a $2.4 million increase in taxes  other
than income taxes. Depreciation and amortization expense increased $34.6
million due to the acquisition of the Jonah, Chaparral and Val Verde assets on
September 30, 2001, March 1, 2002, and June 30, 2002, respectively. Operating,
general and administrative expense increased $15.5 million due to an increase
of $17.6 million from assets acquired and an increase of $2.2 million
attributable to higher general and administrative labor and supplies expense,
partially offset by decreased operating expenses. Operating, general and
administrative expenses for the year ended December 31, 2001, included a $4.3
million reserve for a doubtful receivable balance under a transportation
contract with an Enron Corp. subsidiary. Operating fuel and power costs and
taxes  other than income taxes increased $4.1 million and $2.4 million,
respectively, due to the assets acquired in 2001 and 2002.

Interest Expense and Capitalized Interest

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Interest expense increased $19.0 million for the year ended December 31,
2003, compared with the year ended December 31, 2002, primarily due to $12.3
million of additional expense related to changes in our fair value and cash
flow hedging activities, $16.1 million of additional expense related to the
issuance of our 6.125% Senior Notes in January 2003 and our 7.625% Senior Notes
in February 2002 and $1.3 million of debt issuance costs written off in June
2003 related to the refinancing of our revolving credit facility. These
increases were partially offset by a $10.7 million reduction in interest
expense related to decreased borrowings under our revolving credit facility.

Capitalized interest increased $0.9 million for the year ended December
31, 2003, compared with the year ended December 31, 2002, due to increased
construction work-in-progress balances during 2003, partially offset by
interest capitalized on our investment in Centennial during the first quarter
of 2002.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Interest expense increased $4.5 million for the year ended December 31,
2002, compared with the year ended December 31, 2001, primarily due to higher
outstanding debt balances used for capital expenditures and to finance the
acquisition of assets acquired in the Midstream Segment, partially offset by
lower LIBOR rates in effect during the year ended December 31, 2002.

Capitalized interest increased $0.3 million for the year ended December
31, 2002, compared with the year ended December 31, 2001, due to interest
capitalized on the investment during the construction of the Jonah expansion
and increased balances during 2002 on construction work-in-progress.

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Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity
offerings are our primary sources of liquidity. At December 31, 2003, and
2002, we had working capital deficits of $22.8 million and $6.2 million,
respectively. At December 31, 2003, we had $340.0 million in available
borrowing capacity under our revolving credit facility to cover any working
capital shortfalls. Cash flows for the years ended December 31, 2003, 2002 and
2001 were as follows (in millions):

|                            |                      |  |                          |        |      |  |      |        |   |  |   |        |  
|--------------------------- | -------------------- |  | ------------------------ | ------ | ---- |  | ---- | ------ | - |  | - | ------ | -
|                            |                      |  | Years Ended December 31,
|                            |                      |  |                         
|                            |                      |  | 2003                     |        | 2002 |  | 2001
|                            |                      |  |                          |        |      |  |     
|Cash provided by (used in): |                      |  |                          |        |      |  |      |        |   |  |   |       
|                            | Operating activities |  | $                        | 239.4  |      |  | $    | 234.9  |   |  | $ | 169.2  |  
|                            | Investing activities |  |                          | (185.3 | )    |  |      | (724.7 | ) |  |   | (557.9 | )
|                            | Financing activities |  |                          | (55.6  | )    |  |      | 495.3  |   |  |   | 387.1  |  

Operating Activities

Net cash from operating activities for the years ended December 31, 2003,
2002 and 2001, were comprised of the following (in millions):

|                                                     |  |                          |       |      |  |      |       |   |  |   |       |  
|---------------------------------------------------- |  | ------------------------ | ----- | ---- |  | ---- | ----- | - |  | - | ----- | -
|                                                     |  | Years Ended December 31,
|                                                     |  |                         
|                                                     |  | 2003                     |       | 2002 |  | 2001
|                                                     |  |                          |       |      |  |     
|Net income                                           |  | $                        | 125.8 |      |  | $    | 117.9 |   |  | $ | 109.1 |  
|Depreciation and amortization                        |  |                          | 100.7 |      |  |      | 86.0  |   |  |   | 45.9  |  
|Earnings in equity investments                       |  |                          | (16.9 | )    |  |      | (12.0 | ) |  |   | (26.4 | )
|Distributions from equity investments                |  |                          | 28.0  |      |  |      | 30.9  |   |  |   | 40.8  |  
|Gain on sale of assets                               |  |                          | (3.9  | )    |  |      |      |   |  |   |      |  
|Non-cash portion of interest expense                 |  |                          | 4.8   |      |  |      | 4.9   |   |  |   | 4.1   |  
|Cash provided by (used in) working capital and other |  |                          | 0.9   |      |  |      | 7.2   |   |  |   | (4.3  | )
|                                                     |  |                          |       |      |  |      |       |   |  |   |       |  
|Net cash from operating activities                   |  | $                        | 239.4 |      |  | $    | 234.9 |   |  | $ | 169.2 |  
|                                                     |  |                          |       |      |  |      |       |   |  |   |       |  

For a discussion of changes in earnings before interest, depreciation and
amortization, equity earnings and gain on sale of assets by segment and
consolidated interest expense  net, see Results of Operations for the
Downstream Segment, Upstream Segment and Midstream Segment in Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
Operations. Cash provided by operating activities increased for the year ended
December 31, 2003, compared with the years ended December 31, 2002, and 2001,
primarily due to our 2002 and 2001 acquisitions and changes in working capital
components resulting from the timing of cash receipts and cash disbursements.
Distributions from equity method investments decreased between periods,
primarily due to our sharing ratio in Seaway decreasing from 80% to 60% between
years, partially offset by a distribution from MB Storage in 2003 of $5.3
million.

We believe that we will continue to have adequate liquidity to fund future
recurring operating and investing activities. Our primary cash requirements
consist of normal operating expenses, capital expenditures to sustain existing
operations and revenue generating expenditures, interest payments on our Senior
Notes and revolving credit facility, distributions to our General Partner and
unitholders and acquisitions of new assets or businesses. Short-term cash
requirements, such as operating expenses, capital expenditures to sustain
existing operations and quarterly distributions to our General Partner and
unitholders, are expected to be funded through operating cash flows. Long-term
cash requirements for expansion projects and acquisitions are expected to be
funded by several sources, including cash flows from operating activities,
borrowings under credit facilities, and the issuance of additional equity and
debt securities. Our ability to complete future debt and equity offerings and
the timing of any such

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offerings will depend on various factors, including prevailing market
conditions, interest rates and our financial condition and our credit rating at
the time.

Net cash from operating activities for the years ended December 31, 2003,
2002 and 2001, included interest payments, net of amounts capitalized, of $79.9
million, $48.9 million and $61.5 million, respectively. Excluding the effects
of hedging activities and interest capitalized, during the year ended December
31, 2004, we expect interest payments on our fixed rate Senior Notes to be
approximately $78.0 million. We expect to pay our interest payments with cash
flows from operating activities.

Investing Activities

Cash flows used in investing activities totaled $185.3 million for the
year ended December 31, 2003, and were comprised of $140.6 million of capital
expenditures, $22.0 million for our acquisition of the Genesis assets and other
assets, $20.0 million for TE Products acquisition of an additional 16.7%
interest in Centennial, $4.0 million of cash contributions for TE Products
ownership interest in Centennial and $2.5 million of cash contributions for TE
Products ownership interest in MB Storage. These uses of cash were partially
offset by $3.0 million in net cash proceeds from the Rancho Pipeline
transactions and $0.8 million received on matured cash investments. Cash flows
used in investing activities totaled $724.7 million for the year ended December
31, 2002, and were comprised of $7.3 million for the final purchase price
adjustments on the acquisition of Jonah, $133.4 million of capital
expenditures, $10.9 million of cash contributions for TE Products ownership
interest in Centennial, $132.4 million for the purchase of the Chaparral NGL
system on March 1, 2002, and $444.2 million for the purchase of Val Verde on
June 30, 2002. These uses of cash were partially offset by $3.5 million in
cash proceeds from the sale of assets. Cash flows used in investing activities
totaled $557.9 million for the year ended December 31, 2001, and were comprised
of $359.8 million for the purchase of Jonah on September 30, 2001, $107.6
million of capital expenditures, $65.0 million of cash contributions for TE
Products ownership interest in Centennial, $20.0 million for the purchase of
assets from Valero on March 1, 2001, and $11.0 million paid in October 2001,
for the final purchase price settlement related to the previously acquired ARCO
assets. These uses of cash were partially offset by $1.3 million of cash
received from the sale of vehicles and $4.2 million received on matured cash
investments.

Financing Activities

Cash flows used in financing activities totaled $55.6 million for the year
ended December 31, 2003, and were comprised of $382.0 million in proceeds from
revolving credit facilities; $198.6 million from the issuance in January 2003
of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of
$3.4 million; and $287.5 million from the issuance of 9.2 million Units in
April and August 2003. These sources of cash for the year ended December 31,
2003, were partially offset by $604.0 million of repayments on our revolving
credit facilities, $113.8 million to repurchase and retire all of the 3.9
million outstanding Class B Units, and $202.5 million of distributions paid to
unitholders. Cash flows provided by financing activities totaled $495.3
million for the year ended December 31, 2002, and were comprised of $675.0
million in proceeds from revolving credit facilities; $497.8 million from the
issuance in February 2002 of our 7.625% Senior Notes due 2012, partially offset
by debt issuance costs of $7.0 million; $372.5 million from the issuance of
13.4 million Units during the year ended December 31, 2002, and $7.6 million of
General Partner contributions; and $44.9 million of proceeds from the
termination of our interest rate swaps on our 7.625% Senior Notes due 2012.
These sources of cash for the year ended December 31, 2002, were partially
offset by $943.7 million of repayments on our revolving credit facilities and
$151.8 million of distributions to unitholders. Cash flows provided by
financing activities totaled $387.1 million for the year ended December 31,
2001, and were comprised of $546.1 million of proceeds from term and revolving
credit facilities, partially offset by debt issuance costs of $2.6 million; and
$234.7 million from the issuance of 7.8 million Units during the year ended
December 31, 2001, and $4.8 million of General Partner contributions. These
sources of cash for the year ended December 31, 2001 were partially offset by
$291.5 million of repayments on our term and revolving credit facilities and
$104.4 million of distributions to unitholders.

Centennial entered into credit facilities totaling $150.0 million, and as
of December 31, 2003, $150.0 million was outstanding under those credit
facilities. The proceeds were used to fund construction and conversion costs
of its pipeline system. TE Products and Marathon have each guaranteed one-half
of Centennials debt, up to a maximum of $75.0 million each.

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Credit Facilities and Interest Rate Swap Agreements

On April 6, 2001, we entered into a $500.0 million revolving credit
facility including the issuance of letters of credit of up to $20.0 million
(Three Year Facility). The interest rate was based, at our option, on either
the lenders base rate plus a spread, or LIBOR plus a spread in effect at the
time of the borrowings. The credit agreement for the Three Year Facility
contained certain restrictive financial covenant ratios. During 2002,
borrowings under the Three Year Facility were used to finance the acquisitions
of Chaparral on March 1, 2002, and Val Verde on June 30, 2002, and for general
partnership purposes. During 2002, repayments were made on the Three Year
Facility with proceeds from the issuance of our 7.625% Senior Notes, proceeds
from the issuance of additional Units and proceeds from the termination of
interest rate swaps (see Note 4. Interest Rate Swaps). During the first
quarter of 2003, we repaid $182.0 million of the outstanding balance of the
Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes
on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under
the Three Year Facility with borrowings under a new credit facility, and
canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million revolving credit
facility with a three year term, including the issuance of letters of credit of
up to $20.0 million (Revolving Credit Facility). The interest rate is based,
at our option, on either the lenders base rate plus a spread, or LIBOR plus a
spread in effect at the time of the borrowings. The credit agreement for the
Revolving Credit Facility contains certain restrictive financial covenant
ratios. We borrowed $263.0 million under the Revolving Credit Facility and
repaid the outstanding balance of the Three Year Facility. On December 31,
2003, $210.0 million was outstanding under the Revolving Credit Facility at a
weighted average interest rate, before the effects of hedging activities, of
1.9%. At December 31, 2003, we were in compliance with the covenants in this
credit agreement.

On April 6, 2001, we entered into a 364-day, $200.0 million revolving
credit agreement (Short-term Revolver). The interest rate was based, at our
option, on either the lenders base rate plus a spread, or LIBOR plus a spread
in effect at the time of the borrowings. The credit agreement contained certain
restrictive financial covenant ratios. On March 28, 2002, the Short-term
Revolver was extended for an additional period of 364 days, ending in March
2003. During 2002, borrowings under the Short-term Revolver were used to
finance the acquisition of the Val Verde assets and for other purposes. During
2002, we repaid the existing amounts outstanding under the Short-term Revolver
with proceeds we received from the issuance of Units in 2002. The Short-term
Revolver expired on March 27, 2003.

On September 28, 2001, we entered into a $400.0 million credit facility
with SunTrust Bank (Bridge Facility) payable in June 2002. We borrowed
$360.0 million under the Bridge Facility to acquire the Jonah assets (see Note
6. Acquisitions and Dispositions). During the fourth quarter of 2001, we
repaid $160.0 million of the outstanding principal from proceeds received from
the issuance of Units in November 2001. On February 5, 2002, we borrowed an
additional $15.0 million under the Bridge Facility. On February 20, 2002, we
repaid the outstanding balance of the Bridge Facility of $215.0 million with
proceeds from the issuance of the 7.625% Senior Notes and canceled the
facility.

On February 20, 2002, we completed the issuance of $500.0 million
principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were
issued at a discount of $2.2 million and are being accreted to their face value
over the term of the notes. We used the proceeds from the offering to reduce a
portion of the outstanding balances of our credit facilities, including those
issued in connection with the acquisition of Jonah. The Senior Notes may be
redeemed at any time at our option with the payment of accrued interest and a
make-whole premium determined by discounting remaining interest and principal
payments using a discount rate equal to the rate of the United States Treasury
securities of comparable remaining maturity plus 35 basis points. The
indenture governing the 7.625% Senior Notes contains covenants, including, but
not limited to, covenants limiting the creation of liens securing indebtedness
and sale and leaseback transactions. However, the indenture does not limit our
ability to incur additional indebtedness. As of December 31, 2003, we were in
compliance with the covenants of these Senior Notes.

On June 27, 2002, we entered into a $200.0 million six-month term loan
with SunTrust Bank (Six-Month Term Loan) payable in December 2002. We
borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde
assets (see Note 6. Acquisitions and Dispositions). The interest rate was
based, at our option, on

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either the lenders base rate plus a spread, or LIBOR plus a spread in effect
at the time of the borrowings. The credit agreement contained certain
restrictive financial covenant ratios. On July 11, 2002, we repaid $90.0
million of the outstanding principal from proceeds primarily received from the
issuance of Units in July 2002. On September 10, 2002, we repaid the remaining
outstanding balance of $110.0 million with proceeds received from the issuance
of Units in September 2002, and canceled the facility.

On January 30, 2003, we completed the issuance of $200.0 million principal
amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at
a discount of $1.4 million and are being accreted to their face value over the
term of the notes. We used $182.0 million of the proceeds from the offering to
reduce the outstanding principal on the Three Year Facility to $250.0 million.
The balance of the net proceeds received was used for general partnership
purposes. The Senior Notes may be redeemed at any time at our option with the
payment of accrued interest and a make-whole premium determined by discounting
remaining interest and principal payments using a discount rate equal to the
rate of the United States Treasury securities of comparable remaining maturity
plus 35 basis points. The indenture governing our 6.125% Senior Notes contains
covenants, including, but not limited to, covenants limiting the creation of
liens securing indebtedness and sale and leaseback transactions. However, the
indenture does not limit our ability to incur additional indebtedness. As of
December 31, 2003, we were in compliance with the covenants of these Senior
Notes.

We have entered into interest rate swap agreements to hedge our exposure
to cash flows and fair value changes. These agreements are more fully
described in Item 7A. Quantitative and Qualitative Disclosures About Market
Risk.

The following table summarizes our credit facilities as of December 31,
2003 (in millions):

|                          |       |           |                         |          |           |      |           |       |  |               |  |  | 
|------------------------- | ----- | --------- | ----------------------- | -------- | --------- | ---- | --------- | ----- |  | ------------- |  |  | 
|                          |       |           | As of December 31, 2003
|                          |       |           |                        
|                          |       |           |                         |          |           |      | Available |       |  |               | 
|                          |       |           | Outstanding             |          | Borrowing |      | Maturity 
|Description:              |       | Principal |                         | Capacity |           | Date
|                          |       |           |                         |          |           |     
|Revolving Credit Facility |       | $         | 210.0                   |          |           | $    | 340.0     |       |  | June 2006    
|6.45% Senior Notes (1)    |       |           | 180.0                   |          |           |      |          |       |  | January 2008 
|7.625% Senior Notes (1)   |       |           | 500.0                   |          |           |      |          |       |  | February 2012
|6.125% Senior Notes (1)   |       |           | 200.0                   |          |           |      |          |       |  | February 2013
|7.51% Senior Notes (1)    |       |           | 210.0                   |          |           |      |          |       |  | January 2028 
|                          |       |           |                         |          |           |      |           |       |  |               |  | 
|                          | Total |           | $                       | 1,300.0  |           |      | $         | 340.0 |  |               |  |  | 
|                          |       |           |                         |          |           |      |           |       |  |               |  | 



---

|(1) |  | Our TE Products subsidiary entered into an interest rate swap
agreement to hedge its exposure to changes in the fair value of its
7.51% Senior Notes due 2028. At December 31, 2003, the 7.51% Senior
Notes include an adjustment to increase the fair value of the debt by
$2.3 million related to this interest rate swap agreement. We also
entered into interest rate swap agreements to hedge our exposure to
changes in the fair value of our 7.625% Senior Notes due 2012. At
December 31, 2003, the 7.625% Senior Notes include a deferred gain, net
of amortization, from previous interest rate swap terminations of $40.6
million. At December 31, 2003, our 6.45% Senior Notes, our 7.625%
Senior Notes and our 6.125% Senior Notes include $3.2 million of
unamortized debt discounts. The fair value adjustments, the deferred
gain adjustment and the unamortized debt discounts are excluded from
this table.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $202.5 million ($2.50 per Unit), $151.9
million ($2.35 per Unit) and $104.4 million ($2.15 per Unit), during each of
the years ended December 31, 2003, 2002 and 2001, respectively. Additionally,
on January 16, 2004, we declared a cash distribution of $0.65 per Unit for the
quarter ended December 31, 2003. The distribution of $57.1 million was paid on
February 6, 2004, to unitholders of record on January 30, 2004.

On March 22, 2002, we sold in an underwritten public offering 1.92 million
Units at $31.18 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $57.3 million and were used to

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repay $50.0 million of the outstanding balance on the Three Year Facility, with
the remaining amount being used for general partnership purposes.

On July 11, 2002, we sold in an underwritten public offering 3.0 million
Units at $30.15 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $86.6 million and were used to reduce
borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units
were sold upon exercise of the underwriters over-allotment option granted in
connection with the offering on July 11, 2002. Proceeds from that sale totaled
$5.1 million and were used for general partnership purposes.

On September 5, 2002, we sold in an underwritten public offering 3.8
million Units at $29.72 per Unit. The proceeds from the offering, net of
underwriting discount, totaled approximately $108.1 million and were used to
reduce borrowings under our Six-Month Term Loan. On September 19, 2002,
570,000 Units were sold upon exercise of the underwriters over-allotment
option granted in connection with the offering on September 5, 2002. Proceeds
from that sale totaled $16.2 million and were used to reduce borrowings under
our Short-term Revolver.

On November 7, 2002, we sold in an underwritten public offering 3.3
million Units at $26.83 per Unit. The proceeds from the offering, net of
underwriting discount, totaled approximately $84.8 million and were used to
reduce borrowings under our Short-term Revolver and Three Year Facility. On
December 4, 2002, 495,000 Units were sold upon exercise of the underwriters
over-allotment option granted in connection with the offering on November 7,
2002. Proceeds from that sale totaled $12.7 million and were used to reduce
borrowings under our Short-term Revolver and Three Year Facility.

On April 2, 2003, we sold in an underwritten public offering 3.9 million
Units at $30.35 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $114.5 million, of which approximately $113.8
million was used to repurchase and retire all of the 3.9 million previously
outstanding Class B Units held by DETTCO. We received approximately $0.7
million in proceeds from the offering in excess of the amount needed to
repurchase and retire the Class B Units.

On August 7, 2003, we sold in an underwritten public offering 5.0 million
Units at $34.68 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $166.0 million. On August 19, 2003, 162,900
Units were sold upon exercise of the underwriters over-allotment option
granted in connection with the offering on August 7, 2003. Proceeds from the
over-allotment sale, net of underwriting discount, totaled $5.4 million.
Approximately $53.0 million of the proceeds were used to repay indebtedness
under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 6. Acquisitions and
Dispositions). The remaining amount was used primarily to fund
revenue-generating and system upgrade capital expenditures and for general partnership purposes.

General Partner Interest

As of December 31, 2003, we had a deficit balance of $7.2 million in our
General Partners equity account. This negative balance does not represent an
asset to us and does not represent an obligation of the General Partner to
contribute cash or other property to us. The General Partners equity account
consists of its cumulative share of our net income and cash distributions that
we made and capital contributions that it has made to us (see our Consolidated
Statements of Partners Capital for a detail of the General Partners equity
account). For the year ended December 31, 2003, the General Partner was
allocated $34.8 million (representing 27.65%) of our net income and received
$54.7 million in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are
maintained for our General Partner and our limited partners. The Capital
Account provisions of our Partnership Agreement incorporate principles
established for U.S. Federal income tax purposes and are not comparable to the
equity accounts reflected under accounting principles generally accepted in the
United States in our financial statements. Under our Partnership Agreement,
the General Partner is only required to make additional capital contributions
to us upon the issuance of any additional limited partner units and only if
necessary to maintain a Capital Account balance equal to 1.999999% of the total
Capital Accounts of all partners. At December 31, 2003, the General Partners
Capital Account balance substantially exceeded this requirement.

Net income is allocated between the General Partner and the limited
partners in the same proportion as aggregate cash distributions made to the
General Partner and the limited partners during the period. This is generally
consistent with the manner of allocating net income under our Partnership
Agreement. Net income determined under our Partnership Agreement, however,
incorporates principles established for U.S. Federal income tax purposes and is
not comparable to net income reflected under accounting principles generally
accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income
for the period. We make quarterly cash distributions of all of our Available
Cash, generally defined as consolidated cash receipts less consolidated cash
disbursements and cash reserves established by the General Partner in its sole
discretion (see Note 12. Partners Capital and Distributions). Cash
distributions in excess of net income allocations and capital contributions
during the year ended December 31, 2003, resulted in a deficit in the General
Partners equity account at December 31, 2003. Future cash distributions which
exceed net income will result in an increase in the deficit balance in the
General Partners equity account.

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According to the Partnership Agreement, in the event of our dissolution,
after satisfying our liabilities, our remaining assets would be divided among
our limited partners and the General Partner generally in the same proportion
as Available Cash but calculated on a cumulative basis over the life of the
partnership. After all allocations are made between the partners, if a deficit
balance in its equity account still remains for the General Partner, the
General Partner would not be required to make whole any such deficit.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2004
will be approximately $144.0 million (which includes $4.0 million of
capitalized interest). We expect to spend approximately $112.0 million for
revenue generating projects and facility improvements. Capital spending on
revenue generating projects and facility improvements will include
approximately $49.0 million for the expansion of our Downstream Segment
facilities including pipelines extending from Seymour to Indianapolis, Indiana,
further expansions of our Northeast pipeline system and construction of a new
truck loading terminal in Bossier City, Louisiana. We expect to spend $21.2
million to expand our Upstream Segment pipelines and facilities in South Texas
and Oklahoma and approximately $41.8 million to expand our Midstream Segment
assets. We expect to spend approximately $28.0 million to sustain existing
operations, including life-cycle replacements for equipment at various
facilities and pipeline and tank replacements among all of our business
segments. We continually review and evaluate potential capital improvements
and expansions that would be complementary to our present business segments.
These expenditures can vary greatly depending on the magnitude of our
transactions. We may finance capital expenditures through internally generated
funds, debt or the issuance of additional equity.

Our debt repayment obligations consist of payments for principal and
interest on (i) outstanding principal amounts under the Revolving Credit
Facility due in June 2006 ($210.0 million outstanding at December 31, 2003),
(ii) the TE Products $180.0 million 6.45% Senior Notes due January 15, 2008,
(iii) our $500.0 million 7.625% Senior Notes due February 15, 2012, (iv) our
$200.0 million 6.125% Senior Notes due February 1, 2013, and (v) the TE
Products $210.0 million 7.51% Senior Notes due January 15, 2028.

TE Products is contingently liable as guarantor for the lesser of one-half
or $75.0 million principal amount (plus interest) of the borrowings of
Centennial. In January 2003, TE Products entered into a pipeline capacity
lease agreement with Centennial for a period of five years that contains a
minimum throughput requirement. During the year ended December 31, 2003, TE
Products exceeded the minimum throughput requirements on the lease agreement.
On February 10, 2003, TE Products acquired an additional 16.7% ownership
interest in Centennial, bringing its ownership percentage to 50%.

During the years ended December 31, 2003, 2002 and 2001, we contributed
$4.0 million, $10.9 million and $65.0 million, respectively, to Centennial to
cover operating shortfalls and capital expenditures. During the year ended
December 31, 2003, we contributed $2.5 million to MB Storage for capital
expenditures. During 2004, we may be required to contribute cash to both
Centennial and MB Storage to cover capital expenditures or other operating
shortfalls.

We do not rely on off-balance sheet borrowings to fund our acquisitions.
We have no off-balance sheet commitments for indebtedness other than the
limited guaranty of Centennial debt and leases covering assets utilized in
several areas of our operations.

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The following table summarizes our debt repayment obligations and material
contractual commitments as of December 31, 2003 (in millions):

|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   |           |       | 
|----------------------------------- | ------------- | - | ------------------------------------------ | ------- | ---------------- | - | --------- | ---- | --------- | - | ------- | ----- |  | - | ----- | ----- |  | - | --------- | ----- | 
|                                    |               |   | Amount of Commitment Expiration Per Period
|                                    |               |   |                                           
|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   | More than
|                                    |               |   | Total                                      |         | Less than 1 Year |   | 1-3 Years |      | 3-5 Years |   | 5 Years
|                                    |               |   |                                            |         |                  |   |           |      |           |   |        
|Revolving Credit Facility           |               | $ | 210.0                                      |         |                  | $ |          |      |           | $ | 210.0   |       |  | $ |      |       |  | $ |          |      
|6.45% Senior Notes due 2008 (1) (2) |               |   | 180.0                                      |         |                  |   |          |      |           |   |        |       |  |   | 180.0 |       |  |   |          |      
|7.625% Senior Notes due 2012 (2)    |               |   | 500.0                                      |         |                  |   |          |      |           |   |        |       |  |   |      |       |  |   | 500.0     |      
|6.125% Senior Notes due 2013 (2)    |               |   | 200.0                                      |         |                  |   |          |      |           |   |        |       |  |   |      |       |  |   | 200.0     |      
|7.51% Senior Notes due 2028 (1) (2) |               |   | 210.0                                      |         |                  |   |          |      |           |   |        |       |  |   |      |       |  |   | 210.0     |      
|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   |           |      
|                                    | Debt subtotal |   |                                            | 1,300.0 |                  |   |           |     |           |   |         | 210.0 |  |   |       | 180.0 |  |   |           | 910.0 | 
|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   |           |      
|Operating leases                    |               |   | 71.6                                       |         |                  |   | 16.5      |      |           |   | 27.9    |       |  |   | 15.3  |       |  |   | 11.9      |      
|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   |           |      
|                                    | Total         |   | $                                          | 1,371.6 |                  |   | $         | 16.5 |           |   | $       | 237.9 |  |   | $     | 195.3 |  |   | $         | 921.9 | 
|                                    |               |   |                                            |         |                  |   |           |      |           |   |         |       |  |   |       |       |  |   |           |      



---



|(1) |  | Obligations of TE Products.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Our TE Products subsidiary entered into an interest rate swap agreement
to hedge its exposure to changes in the fair value of its 7.51% Senior
Notes due 2028. At December 31, 2003, the 7.51% Senior Notes include an
adjustment to increase the fair value of the debt by $2.3 million related
to this interest rate swap agreement. We also entered into interest rate
swap agreements to hedge our exposure to changes in the fair value of our
7.625% Senior Notes due 2012. At December 31, 2003, the 7.625% Senior
Notes include a deferred gain, net of amortization, from previous interest
rate swap terminations of $40.6 million. At December 31, 2003, our 6.45%
Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include
$3.2 million of unamortized debt discounts. The fair value adjustments,
the deferred gain adjustment and the unamortized debt discounts are
excluded from this table.

We expect to repay the long-term, senior unsecured obligations and bank
debt through the issuance of additional long-term senior unsecured debt at the
time the 2008, 2012, 2013 and 2028 debt matures, issuance of additional equity,
with proceeds from dispositions of assets, cash flow from operations or any
combination of the above items.

Sources of Future Capital

Historically, we have funded our capital commitments from operating cash
flow and borrowings under bank credit facilities or bridge loans. We repaid
these loans in part by the issuance of long term debt in capital markets and
the public offering of Units. We expect future capital needs would be
similarly funded to the extent not otherwise available from cash flow from
operations.

As of December 31, 2003, we had $340.0 million in available borrowing
capacity under the Revolving Credit Facility. We expect that cash flows from
operating activities will be adequate to fund cash distributions and capital
additions necessary to sustain existing operations. However, future
expansionary capital projects and acquisitions may require funding through
proceeds from the sale of additional debt or equity offerings.

Our senior unsecured debt is rated BBB by Standard and Poors (S&P) and
Baa3 by Moodys Investors Service (Moodys). Both ratings are stable. A
rating reflects only the view of a rating agency and is not a recommendation to
buy, sell or hold any indebtedness. Any rating can be revised upward or
downward or withdrawn at any time by a rating agency if it determines that the
circumstances warrant such a change. The senior unsecured debt of our
subsidiary, TE Products, is also rated BBB by S&P and Baa3 by Moodys.

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Other Considerations

Credit Risks

Risks of non-payment and nonperformance by customers are a major
consideration in our businesses. Our credit procedures and policies do not
fully eliminate customer credit risk. During the years ended December 31,
2003, 2002 and 2001, some of our customers filed for bankruptcy protection.
During the years ended December 31, 2003 and 2002, we expensed approximately
$0.8 million and $0.9 million, respectively, of uncollectible receivables due
to customer bankruptcies and other customer non-payments. During the year
ended December 31, 2001, we expensed a receivable for transportation fees of
approximately $4.3 million, or approximately $0.09 per Unit because of the
bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001.

Terrorist Threats

On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale. Since the September 11 attacks, the United
States government has issued warnings that energy assets, specifically the
nations pipeline infrastructure, could be a future target of terrorist
organizations. These developments have subjected our operations to increased
risks. Any terrorist attack on our facilities, customers facilities and, in
some cases, those of other pipelines, could have a material adverse effect on
our business. We have increased security initiatives and are working with
various governmental agencies to minimize risks associated with additional
terrorist attacks.

Environmental

Our operations are subject to federal, state and local laws and
regulations governing the discharge of materials into the environment. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, imposition of injunctions
delaying or prohibiting certain activities and the need to perform
investigatory and remedial activities. Although we believe our operations are
in material compliance with applicable environmental laws and regulations,
risks of significant costs and liabilities are inherent in pipeline operations,
and we cannot assure you 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 our
operations, could result in substantial costs and liabilities to us. We
believe that changes in environmental laws and regulations will not have a
material adverse effect on our financial position, results of operations or
cash flows in the near term.

In 1994, the LDEQ issued a compliance order for environmental
contamination at our Arcadia, Louisiana, facility. This contamination may be
attributable to our operations, as well as to adjacent petroleum terminals
operated by other companies. In 1999, our Arcadia facility and adjacent
terminals were directed by the Remediation Services Division of the LDEQ to
pursue remediation of this contamination. At December 31, 2003, we have an
accrued liability of $0.3 million for remediation costs at our Arcadia
facility. We do not expect that the completion of the remediation program
proposed to the LDEQ will have a future material adverse effect on our
financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel
from a storage tank at our Blue Island terminal located in Cook County,
Illinois. As a result of the release, we have entered into an Agreed Order
with the State of Illinois. The Agreed Order requires us, in part, to complete
a site investigation plan to delineate the scope of any potential contamination
resulting from the release and to remediate any contamination present above
regulatory standards. This site investigation plan has been completed and
submitted to the State of Illinois. The Agreed Order does not contain any
provision for any fines or penalties; however, it does not preclude the State
of Illinois from assessing these at a later date. We do not expect that the
completion of the remediation program will have a future material adverse
effect on our financial position, results of operations or cash flows.

At December 31, 2003, we have an accrued liability of $5.9 million related
to various TCTM sites requiring environmental remediation activities. Under
the terms of a 1998 agreement through which we acquired various crude oil
assets from DETTCO, we received a five year contractual indemnity obligation
for environmental liabilities not otherwise assumed by us that were
attributable to the operations of the assets prior to our acquisition.

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The indemnity expired on November 30, 2003. Under the agreement, we were
responsible for the first $3.0 million in environmental liabilities covered by
DETTCOs indemnification obligation, and DETTCO was responsible for specified
environmental liabilities in excess of $3.0 million, up to a maximum amount of
$25.0 million. At December 31, 2002, we had a receivable balance from DETTCO
of $4.2 million, the majority of which related to remediation activities at the
Velma, Oklahoma crude oil site. On March 31, 2003, we received a $2.4 million
payment from DETTCO for environmental liabilities we incurred that were covered
under the indemnity obligation with DETTCO. The remaining $1.8 million due was
determined as not attributable to DETTCOs indemnity obligation as a result of
settlement discussions with DETTCO on this matter and was written off.
On December 1, 2003, concurrent with the expiration of the five year
contractual indemnity obligation, we entered into a Settlement Agreement and
Release with DETTCO regarding future obligations pertaining to various
environmental liabilities associated with the assets purchased from DETTCO in
1998. The agreement provided for a net payment of $1.3 million to us from
DETTCO, which consisted of a settlement of $2.0 million for remaining crude oil
sites, partially offset by the sharing of expenses of $1.0 million which were
incurred by DETTCO in remediation of a crude oil site in Stephens County,
Oklahoma. The agreement also provided for $0.3 million toward the purchase of
an environmental insurance policy for gathering systems located in Texas and
Oklahoma and the assumption of responsibility by DETTCO for environmental
liabilities associated with three sites located in Texas and Oklahoma. We do
not expect that the completion of remediation programs associated with TCTM
activities will have a future material adverse effect on our financial
position, results of operations or cash flows.

Market-Based Rates

On May 11, 1999, TE Products filed an application with the FERC requesting
permission to charge Market-Based Rates for substantially all refined products
transportation tariffs. On July 31, 2000, the FERC issued an order granting TE
Products Market-Based Rates in certain markets and set for hearing TE Products
application for Market-Based Rates in certain destination markets and origin
markets. After the matter was set for hearing, TE Products and the protesting
shippers entered into a settlement agreement resolving their respective
differences. On April 25, 2001, the FERC issued an order approving the offer
of settlement. As a result of the settlement, TE Products recognized
approximately $1.7 million of previously deferred transportation revenue in the
second quarter of 2001. As a part of the settlement, TE Products withdrew the
application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia
and Shreveport-Arcadia, Louisiana, destination markets, which are currently
subject to the PPI Index. As a result, we made refunds of approximately $1.0
million in the third quarter of 2001 for those destination markets.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2. Summary of
Significant Accounting Policies  New Accounting Pronouncements in the
accompanying consolidated financial statements.

Disclosures About Effects of Transactions with Related Parties

The Partnership does not have any employees, and we are managed by the
General Partner, a wholly owned subsidiary of DEFS. Duke Energy holds an
interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining
30%. See Item 10. Directors and Executive Officers of the Registrant and Item
13. Certain Relationships and Related Transactions for discussion regarding
transactions between us and DEFS, Duke Energy and ConocoPhillips.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We may be exposed to market risk through changes in crude oil commodity
prices and interest rates. We do not have foreign exchange risks. Our Risk
Management Committee has established policies to monitor and control these
market risks. The Risk Management Committee is comprised, in part, of senior
executives of the Company.

At December 31, 2003, we had $210.0 million outstanding under our variable
interest rate revolving credit agreement. The interest rate is based, at our
option, on either the lenders base rate plus a spread or LIBOR plus a spread
in effect at the time of the borrowings and is adjusted monthly, bimonthly,
quarterly or semiannually. Utilizing the balances of our variable interest
rate debt outstanding at December 31, 2003, including the effects of hedging
activities discussed below, and assuming market interest rates increase 100
basis points, the potential annual increase in interest expense would be less
than $0.1 million.

We have utilized and expect to continue to utilize interest rate swap
agreements to hedge a portion of our cash flow and fair value risks. Interest
rate swap agreements are used to manage the fixed and floating interest rate
mix of our total debt portfolio and overall cost of borrowing. The interest
rate swap related to our cash flow risk is intended to reduce our exposure to
increases in the benchmark interest rates underlying our variable rate
revolving credit facility. The interest rate swaps related to our fair value
risks are intended to reduce our exposure to changes in the fair value of the
fixed rate Senior Notes. The interest rate swap agreements involve the
periodic exchange of payments without the exchange of the notional amount upon
which the payments are based. The related amount payable to or receivable from
counterparties is included as an adjustment to accrued interest.

At December 31, 2003, TE Products had outstanding $180.0 million principal
amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of
7.51% Senior Notes due 2028 (collectively the TE Products Senior Notes). At
December 31, 2003, the estimated fair value of the TE Products Senior Notes was
approximately $432.8 million. At December 31, 2003, we had outstanding $500.0
million principal amount of 7.625% Senior Notes due 2012 and $200.0 million
principal amount of 6.125% Senior Notes due 2013. At December 31, 2003, the
estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0
million 6.125% Senior Notes was approximately $578.2 million and $206.7
million, respectively.

As of December 31, 2003, TE Products had an interest rate swap agreement
in place to hedge its exposure to changes in the fair value of its fixed rate
7.51% TE Products Senior Notes due 2028. We designated this swap agreement as
a fair value hedge. The swap agreement has a notional amount of $210.0 million
and matures in January 2028 to match the principal and maturity of the TE
Products Senior Notes. Under the swap agreement, TE Products pays a floating
rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread,
and receives a fixed rate of interest of 7.51%. During the years ended
December 31, 2003, and 2002, we recognized reductions in interest expense of
$10.0 million and $8.6 million, respectively, related to the difference between
the fixed rate and the floating rate of interest on the interest rate swap.
During the year ended December 31, 2003, we measured the hedge effectiveness of
this interest rate swap and noted that no gain or loss from ineffectiveness was
required to be recognized. The fair value of this interest rate swap agreement
was a gain of approximately $2.3 million and $13.6 million at December 31,
2003, and 2002, respectively. Utilizing the balance of the 7.51% TE Products
Senior Notes outstanding at December 31, 2003, and including the effects of
hedging activities, assuming market interest rates increase 100 basis points,
the potential annual increase in interest expense is $2.1 million.

We have entered into an interest rate swap agreement to hedge our exposure
to increases in the benchmark interest rate underlying our variable rate
revolving credit facility. This interest rate swap matures on April 6, 2004.
We designated this swap agreement, which hedges exposure to variability in
expected future cash flows attributed to changes in interest rates, as a cash
flow hedge. The swap agreement is based on a notional amount of $250.0 million.
Under the swap agreement, we pay a fixed rate of interest of 6.955% and
receive a floating rate based on a three-month U.S. Dollar LIBOR rate. Since
this swap is designated as a cash flow hedge, the changes in fair value, to the
extent the swap is effective, are recognized in other comprehensive income
until the hedged interest costs are recognized in earnings. On June 27, 2003,
we repaid the amounts outstanding under the revolving credit facility with
borrowings under a new three year revolving credit facility and canceled the
old facility (see Note 11. Debt). We redesignated this interest rate swap as
a hedge of our exposure to increases in the benchmark interest rate underlying
the new variable rate revolving credit facility. During the years ended
December 31, 2003, and 2002, we

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recognized increases in interest expense of $14.4 million and $12.9
million, respectively, related to the difference between the fixed rate and the
floating rate of interest on the interest rate swap.

During the year ended December 31, 2003, we determined that we would repay
a portion of the amount outstanding under the revolving credit facility,
established June 27, 2003, with proceeds from our Unit offering in August 2003
(see Note 12. Partners Capital and Distributions) resulting in a reduction of
probable future interest payments under the credit facility. As a result, we
measured and reclassified amounts previously accumulated in other comprehensive
income related to the discontinued portion of the hedge and recognized a loss
of $1.0 million, which has been included in interest expense. The total fair
value of the interest rate swap was a loss of approximately $3.9 million and
$20.1 million at December 31, 2003, and 2002, respectively. Losses recognized
in other comprehensive income of approximately $2.9 million related to the
portion of the interest rate swap hedging probable future interest payments
will be transferred into earnings over the remaining term of the interest rate
swap. Changes in the fair value of the portion of the interest rate swap
related to the discontinued hedge will be recorded in earnings over the
remaining term of the interest rate swap.

On February 20, 2002, we entered into interest rate swap agreements,
designated as fair value hedges, to hedge our exposure to changes in the fair
value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had
a combined notional amount of $500.0 million and matured in 2012 to match the
principal and maturity of the Senior Notes. Under the swap agreements, we paid
a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread,
and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap
agreements were terminated resulting in a gain of approximately $18.0 million.
Concurrent with the swap terminations, we entered into new interest rate swap
agreements, with identical terms as the previous swap agreements; however, the
floating rate of interest was based upon a spread of an additional 50 basis
points. In December 2002, the swap agreements entered into on July 16, 2002,
were terminated, resulting in a gain of approximately $26.9 million. The gains
realized from the July 2002 and December 2002 swap terminations have been
deferred as adjustments to the carrying value of the Senior Notes and are being
amortized using the effective interest method as reductions to future interest
expense over the remaining term of the Senior Notes. At December 31, 2003, the
unamortized balance of the deferred gains was $40.6 million. In the event of
early extinguishment of the Senior Notes, any remaining unamortized gains would
be recognized in the consolidated statement of income at the time of
extinguishment.




Item 8.Financial Statements and Supplementary Data

Our consolidated financial statements, together with the independent
auditors report 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.




Item 9A. Controls and Procedures

The principal executive officer and principal financial officer of our
General Partner, after evaluating the effectiveness of our disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of
December 31, 2003, have concluded that, as of such date, our disclosure
controls and procedures are adequate and effective to ensure that material
information relating to us and our consolidated subsidiaries would be made
known to them by others within those entities.

During the fourth quarter of 2003, there have been no changes in our
internal control over financial reporting that have materially affected, or are
reasonably likely to materially affect, those internal controls subsequent to
the date of the evaluation. As a result, no corrective actions were required
or undertaken.

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PART III




Item 10.Directors and Executive Officers of the Registrant

Partnership Management

We do not directly have directors or officers, as is commonly the case
with publicly traded partnerships. Our operations and activities are managed by
the General Partner, which employs our management and operational personnel.
The officers and directors of the General Partner are responsible for managing
us. All directors of the General Partner are elected annually by DEFS. All
officers serve at the discretion of the directors. None of the officers of the
General Partner serve as officers or employees of DEFS or any other
parent-affiliated company.

Because we are a limited partnership, the listing standards of the New
York Stock Exchange do not require that we or our General Partner have a
majority of independent directors or a nominating or compensation committee of
the General Partners board of directors.

Committees of the Board of Directors

Audit Committee

Our General Partner has an audit committee (the Audit Committee)
comprised of three board members who are independent as that term is defined
in Rule 10A-3 of the Exchange Act and as that term is used in applicable
listing standards of the New York Stock Exchange. The members of the Audit
Committee are R. A. Walker (Chairman), John P. DesBarres and Milton Carroll.
The members of the Audit Committee are non-employee directors of the General
Partner and are not officers, directors or otherwise affiliated with DEFS or
its parent companies, ConocoPhillips or Duke Energy. No member of the Audit
Committee of our General Partner serves on the audit committees of more than
three public companies. Our Board of Directors has also determined that no
Audit Committee member has a material relationship with the Company. Our Board
of Directors has also determined that Mr. Walker qualifies as an audit
committee financial expert as defined in Item 401(h) of Regulation S-K.

The Audit Committee provides independent oversight with respect to our
internal controls, accounting policies, financial reporting, internal audit
function and the independent auditors. The Audit Committee also reviews the
scope and quality, including the independence and objectivity of the
independent and internal auditors. The Audit Committee has sole authority as
to the retention, evaluation, compensation and oversight of the work of the
independent auditors. The independent auditors report directly to the Audit
Committee. The Audit Committee also has sole authority to approve all audit
and non-audit services provided by the independent auditors and shall assure
that the independent auditors are not engaged to perform specific non-audit
services prohibited by law or regulation. The charter of the Audit Committee
is filed as an exhibit to this Annual Report on Form 10-K and is available on
our website at www.teppco.com.

Our Audit Committee has established procedures for the receipt, retention
and treatment of complaints we receive regarding accounting, internal
accounting controls or auditing matters and the confidential, anonymous
submission by our employees of concerns regarding questionable accounting or
auditing matters. Persons wishing to communicate with our Audit Committee may
do so by calling 1-800-799-4607.

Special Committee

The Special Committee is a standing committee of the Board of Directors of
the General Partner and is composed of three independent directors, John P.
DesBarres (Chairman), Milton Carroll and R. A. Walker. The members of the
Special Committee are non-employee directors of the General Partner and are not
officers, directors or otherwise affiliated with DEFS or its parent companies,
ConocoPhillips or Duke Energy. The Special Committee is responsible for the
independent evaluation of the fairness and reasonableness of affiliate
transactions and the approval or rejection of those transactions that would
ordinarily require board approval involving the General

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Partner, DEFS or an affiliate of either, and us. Such transactions
include related party asset sales and operating agreements. The Special
Committee is also responsible for the evaluation of the fairness and approval
or rejection of the issuance and pricing of additional Units and debt.

Compensation Committee

The Compensation Committee is a standing committee of the Board of
Directors of the General Partner and is composed of five directors, Jim W. Mogg
(Chairman), Milton Carroll, Derrill Cody, John P. DesBarres and R. A. Walker.
The Compensation Committee establishes and maintains competitive and equitable
compensation and employment policies to retain the management required to carry
out our business, to stimulate their useful and profitable efforts on our
behalf and to attract necessary additions to management with appropriate
qualifications. The Compensation Committee also recommends to the Board of
Directors the election of officers and reviews the management succession plans
for senior officer positions.

Code of Ethics, Corporate Governance Guidelines and Charter of the Audit
Committee

We have adopted a Code of Ethics applicable to all employees, including
the principal executive officer, principal financial officer and directors of
the General Partner. A copy of the Code of Ethics is available on our website
at www.teppco.com under Corporate Governance. We intend to post on our website
any amendments to, or waivers from, our Code of Ethics applicable to our senior
officers.

Corporate governance guidelines are currently under consideration by our
Board of Directors, and will address director qualification standards; director
access to management, and as necessary and appropriate, independent advisors;
director compensation; director orientation and continuing education;
management succession and annual performance evaluation of the board.
The Charter of our Audit Committee is currently available on our website at
www.teppco.com under Corporate Governance. Our Corporate Governance Guidelines
will be available on our website when adopted, and will be in place before the
date required by the listing standards of the New York Stock
Exchange. Additionally, the Code of Ethics and the Charter of the Audit
Committee are available in print to any person who requests the
information. Persons wishing to obtain this printed material should submit
a request in care of Secretary, TEPPCO Partners, L.P., 2929 Allen Parkway, P.O.
Box 2521, Houston, Texas 77252-2521.

Executive Sessions of Non-Management Directors

Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P.
DesBarres, Jim W. Mogg, William H. Easter III and R. A. Walker, who are
non-management directors of our General Partner, meet at regularly scheduled
executive sessions without management. Mr. Mogg serves as the presiding
director at those executive sessions. Persons wishing to communicate with the
Companys non-management directors may do so by calling 1-800-799-4607.

Milton Carroll, John P. DesBarres and R. A. Walker, who are independent
non-management directors of our General Partner, meet at regularly scheduled
executive sessions without management and the other directors. The chairs of
the Audit Committee and the Special Committee of the Board of Directors rotate
on an annual basis as the chair of the independent non-management directors.
The chair for 2004 is John P. DesBarres. Persons wishing to communicate with
the Companys independent non-management directors may do so by calling
1-800-799-4607.

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Directors and Executive Officers

The following table sets forth certain information with respect to the
directors and executive officers of the General Partner.

|                      |  |     |    |                                   |  |                                                                          
|--------------------- |  | --- | -- | --------------------------------- |  | -------------------------------------------------------------------------
|Name                  |  | Age |    | Position with Our General Partner
|                      |  |     |    |                                  
|Jim W. Mogg           |  |     | 55 |                                   |  | Chairman of the Board, Member of the Compensation* Committee and
Director
|Mark A. Borer         |  |     | 49 |                                   |  | Director                                                                 
|Michael J. Bradley    |  |     | 49 |                                   |  | Director                                                                 
|Milton Carroll        |  |     | 53 |                                   |  | Director and Member of the Compensation, Special and Audit Committees    
|Derrill Cody          |  |     | 65 |                                   |  | Director and Member of the Compensation Committee                        
|John P. DesBarres     |  |     | 64 |                                   |  | Director and Member of the Compensation, Special* and Audit Committees   
|William H. Easter III |  |     | 54 |                                   |  | Director                                                                 
|R. A. Walker          |  |     | 46 |                                   |  | Director and Member of the Compensation, Special and Audit* Committees   
|Barry R. Pearl+       |  |     | 54 |                                   |  | President, Chief Executive Officer and Director                          
|Charles H. Leonard+   |  |     | 55 |                                   |  | Senior Vice President and Chief Financial Officer                        
|James C. Ruth+        |  |     | 56 |                                   |  | Senior Vice President, General Counsel and Secretary                     
|Thomas R. Harper+     |  |     | 63 |                                   |  | Senior Vice President of Commercial Downstream                           
|J. Michael Cockrell+  |  |     | 57 |                                   |  | Senior Vice President of Commercial Upstream                             
|Leonard W. Mallett+   |  |     | 47 |                                   |  | Vice President of Operations                                             
|Stephen W. Russell+   |  |     | 52 |                                   |  | Vice President of Support Services                                       
|David E. Owen+        |  |     | 54 |                                   |  | Vice President of Human Resources                                        
|John N. Goodpasture+  |  |     | 55 |                                   |  | Vice President of Corporate Development                                  
|Barbara A. Carroll+   |  |     | 49 |                                   |  | Vice President of Environmental, Health and Safety                       



---

|* |  | Indicates Chairman of committee                                                                                                       
|- |  | --------------------------------------------------------------------------------------------------------------------------------------
| 
|+ |  | Indicates employment contract with the General Partner (see Executive
Employment Contracts and Termination of
Employment Arrangements)

Jim W. Moggwas elected a director of the General Partner in October 1997,
Chairman of the Compensation Committee in April 2000 and Chairman of the Board
in May 2002. Mr. Mogg succeeded William L. Thacker as Chairman of the Board in
May 2002, when Mr. Thacker retired as Chairman. Prior to being elected
Chairman of the Board in 2002, Mr. Mogg served as Vice Chairman of the Board
from April 2000 to April 2002. Mr. Mogg was named group vice president and
chief development officer of Duke Energy, effective January 1, 2004. He served
as chairman, president and chief executive officer of DEFS from December 1999
to December 2003. Mr. Mogg was previously president of Centana Energy
Corporation, a subsidiary of a predecessor of Duke Energy, from 1992 to 1999.
He joined Duke Energy in 1973 in the gas supply department of Panhandle Eastern
Pipe Line Company.

Mark A. Borerwas elected a director of the General Partner in April 2000.
Mr. Borer is executive vice president of marketing and corporate development
of DEFS, having been elected in April 2002. He previously served as senior
vice president, Southern Division, having been elected to that position in 1999
when Union Pacific Fuels, Inc. was acquired by DEFS. Before joining DEFS, he
was vice president of natural gas marketing for Union Pacific Fuels, Inc. from
1992 until 1999.

Michael J. Bradleywas elected a director of the General Partner in
February 2003. Mr. Bradley is executive vice president, gathering and
processing of DEFS, having been elected to that position in April 2002. He
previously served as senior vice president, Northern Division, for DEFS, having
been elected to that position in 1999. Mr. Bradley joined DEFS in 1979 and
served in a variety of positions in marketing, business development and
operations.

Milton Carrollwas elected a director of the General Partner in November
1997 and is a member of the Compensation Committee, Special Committee and the
Audit Committee. He served as Chairman of the Audit Committee from April 2000
until January 16, 2003. Mr. Carroll is the chairman of CenterPoint Energy,
Inc., having

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been elected in September 2002. Mr. Carroll is the founder and chairman
of Instrument Products, Inc., a manufacturer of oil field equipment since 1977.
Mr. Carroll is a director of Devon Energy Corporation, Eagle Global Logistics
and Chairman of the Board of Health Care Service Corporation.

Derrill Codywas elected a director of the General Partner in 1989. He is
a member of the Compensation Committee and was Chairman of the Audit Committee
from April 1990 until April 2000. Mr. Cody is currently of counsel to McKinney
and Stringer, P. C., which represents Duke Energy, DEFS and us in certain
matters. He is also an advisor to DEFS pursuant to a personal contract. Mr.
Cody served as chief executive officer of Texas Eastern Gas Pipeline Company
from 1987 to 1990. Prior to that, he was executive vice president of Kerr
McGee Corporation. Mr. Cody is a director of CenterPoint Energy, Inc.

John P. DesBarreswas elected a director of the General Partner in May
1995. He is a member of the Compensation and Audit Committees and serves as
Chairman of the Special Committee. Mr. DesBarres was formerly chairman,
president and chief executive officer of Transco Energy Company from 1992 to
1995. He joined Transco in 1991 as president and chief executive officer.
Prior to joining Transco, Mr. DesBarres served as chairman, president and chief
executive officer for Santa Fe Pacific Pipelines, Inc. from 1988 to 1991. Mr.
DesBarres is a director of American Electric Power and Penn Virginia G.P., LLC,
an indirect wholly owned subsidiary of Penn Virginia Corporation, which is the
general partner of Penn Virginia Resource Partners, L.P.

William H. Easter IIIwas elected a director of the General Partner in
February 2004. Mr. Easter is chairman, president and chief executive officer
of DEFS, having been elected to that position in January 2004. He was
previously vice president of state government affairs for ConocoPhillips from
2002 until December 2003. Mr. Easter joined ConocoPhillips (formerly Conoco
Inc.) in 1971 and served in a variety of positions, most recently as general
manager of Gulf Coast businesses unit in Lake Charles, Louisiana, from 1998
until 2002.

R. A. Walkerwas elected director of the General Partner in July 2002, and
is a member of the Compensation, Audit and Special Committees. He was elected
Chairman of the Audit Committee on January 16, 2003. Mr. Walker was president,
chief financial officer and director of 3TEC Energy Corporation, a publicly
held independent oil and gas company from 2000 to 2003. 3TEC Energy was
acquired by Plains Exploration and Production Company in 2003. Prior to
joining 3TEC Energy Corporation in 2000, Mr. Walker was senior managing
director and co-head of Prudential Capital Group, an asset management firm of
The Prudential Insurance Company of America from 1997 to 2000. Previously, he
was managing director of Prudential Capitals Dallas office from 1990 to 1997,
where he was responsible for its worldwide energy investing.

Barry R. Pearlwas elected President of the General Partner in February
2001 and Chief Executive Officer and director in May 2002. He succeeded
William L. Thacker as Chief Executive Officer in May 2002, when Mr. Thacker
retired as Chief Executive Officer. Mr. Pearl was previously Chief Operating
Officer from February 2001 until May 2002. Prior to joining the Company, Mr.
Pearl was vice president  finance and administration, treasurer, secretary and
chief financial officer of Maverick Tube Corporation from June 1998. Mr. Pearl
was senior vice president and chief financial officer of Santa Fe Pacific
Pipeline Partners, L.P. from 1995 until 1998, and senior vice president,
business development from 1992 to 1995.

Charles H. Leonardis Senior Vice President and Chief Financial Officer 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 was
Treasurer from October 1996 until May 2002.

James C. Ruthis Senior Vice President, General Counsel and Secretary of
the General Partner, having been elected in February 2001. Mr. Ruth was
previously Vice President and General Counsel and Secretary from 1998 until
February 2001, and Vice President, General Counsel from 1991 until 1998. Mr.
Ruth joined the Company in 1970.

Thomas R. Harperis Senior Vice President, Commercial Downstream of the
General Partner, having been elected in February 2003. Mr. Harper was
previously Vice President, Commercial Downstream from September 2000 until
February 2003 and Vice President, Product Transportation and Refined Products
Marketing from 1988 until September 2000. Mr. Harper joined the Company in 1987
as Director of Product Transportation.

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J. Michael Cockrellis Senior Vice President, Commercial Upstream of the
General Partner, having been elected in February 2003. Mr. Cockrell was
previously Vice President, Commercial Upstream from September 2000 until
February 2003. He was elected Vice President of the General Partner in January
1999 and also serves as President of TEPPCO Crude GP, LLC. He joined PanEnergy
in 1987 and served in a variety of positions in supply and development,
including president of DETTCO.

Leonard W. Mallettis Vice President, Operations of the General Partner,
having been elected in September 2000. Mr. Mallett was previously Region
Manager of the Southwest Region of the Company from 1994 until 1999 and
Director of Engineering, from 1992 until 1994. Mr. Mallett joined the Company
in 1979 as an engineer.

Stephen W. Russellis Vice President, Support Services of the General
Partner, having been elected in September 2000. Mr. Russell was previously
Region Manager of the Southwest Region from July 1999 until September 2000, and
Technical Operations Superintendent of the Southwest Region from 1994 until
1999. Mr. Russell joined the Company in 1988 as Project Manager in
Engineering.

David E. Owenis Vice President, Human Resources of the General Partner,
having joined the Company in February 2001. He was previously Northern
Division human resources manager of DEFS from May 2000 until he joined the
Company. Prior to DEFS, Mr. Owen held various positions with ARCO
International Oil and Gas Company from October 1996 until January 2000.

John N. Goodpastureis Vice President, Corporate Development of the
General Partner, having joined the Company in November 2001. Mr. Goodpasture
was previously Vice President of Business Development for Enron Transportation
Services from June 1999 until he joined the Company. Prior to his employment at
Enron Transportation Services, Mr. Goodpasture spent 19 years in various
executive positions at Seagull Energy Corporation (now Devon Energy
Corporation), a large independent oil and gas company. At Seagull Energy, Mr.
Goodpasture had most recently served for over ten years as Senior Vice
President, Pipelines and Marketing.

Barbara A. Carrollis Vice President, Environmental, Health and Safety,
having been elected in February 2002. Ms. Carroll joined ExxonMobil in 1990
and served in a variety of management positions, including Procurement Services
Manager, Materials and Service Manager and Baytown Area Public Affairs Manager
until she joined the Company in February 2002. Prior to ExxonMobil, Ms.
Carroll was General Manager, Corporate Environmental Protection and Compliance
with Panhandle Eastern Corporation. Ms. Carroll is not related to Milton
Carroll.

In addition to our Executive Officers, Mark G. Stockard serves as
Treasurer, having been elected in May 2002. Mr. Stockard was Assistant
Treasurer of the General Partner from July 2001 until May 2002. He was
previously Controller from October 1996 until May 2002. Mr. Stockard joined
the Company in October 1990.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors,
officers and persons who beneficially own more than ten percent of a registered
class of our equity securities to file with the SEC and the New York Stock
Exchange initial reports of ownership and reports of changes in ownership of
such equity securities. 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, 2003, except for reports
covering certain transactions that were filed late by Mr. Mallett.




Item 11.Executive Compensation

Summary Compensation Table

The officers of the General Partner manage and operate our business. We
do not directly employ any of the persons responsible for managing or operating
our operations, but instead reimburse the General Partner for the

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services of these persons (See Note 8. Related Party Transactions). The
following table reflects cash compensation paid or accrued by the General
Partner for the years ended December 31, 2003, 2002 and 2001, with respect to
its Chief Executive Officer and the four other most highly compensated
executive officers in 2003 (collectively, the Named Executive Officers).

SUMMARY COMPENSATION TABLE

|                    |                     |                           |      |                     |      |         |         |              |         |           |         |              |         |         |        |              |        |  |         |   |         |  |        |        |        | 
|------------------- | ------------------- | ------------------------- | ---- | ------------------- | ---- | ------- | ------- | ------------ | ------- | --------- | ------- | ------------ | ------- | ------- | ------ | ------------ | ------ |  | ------- | - | ------- |  | ------ | ------ | ------ | 
|                    |                     |                           |      | Annual Compensation |      | Other   |         | Long Term    |         |           |         |             
|                    |                     |                           |      |                     |      | Annual  |         | Compensation |         | All Other
|Name and            |                     |                           |      |                     |      |         |         |              |         | Bonus     |         | Compensation |         | Payouts |        | Compensation
|Principal Position  |                     | Year                      |      | Salary ($)          |      | ($) (2) |         | ($) (3)      |         | ($)(4)    |         | ($) (5)     
|                    |                     |                           |      |                     |      |         |         |              |         |           |         |             
|Barry R. Pearl (1)  |                     |                           | 2003 |                     |      |         | 283,500 |              |         |           | 196,465 |              |         |         | 52,000 |              |        |  |        |   |         |  | 26,683 |       
|                    | President and Chief |                           |      | 2002                |      |         |         | 252,308      |         |           |         | 142,000      |         |         |        | 24,160       |        |  |         |  |         |  |        | 16,163 |       
|                    | Executive Officer   |                           |      | 2001                |      |         |         | 190,385      |         |           |         | 131,900      |         |         |        | 7,800        |        |  |         |  |         |  |        | 78,423 |       
|J. Michael Cockrell |                     |                           | 2003 |                     |      |         | 202,846 |              |         |           | 114,364 |              |         |         | 7,250  |              |        |  | 108,225 |   |         |  | 18,716 |       
|                    |                     | Senior Vice President,    |      |                     | 2002 |         |         |              | 195,462 |           |         |              | 86,600  |         |        |              | 21,750 |  |         |   | 358,200 |  |        |        | 13,369 | 
|                    |                     | Commercial Upstream       |      |                     | 2001 |         |         |              | 189,504 |           |         |              | 100,500 |         |        |              | 32,250 |  |         |   |        |  |        |        | 10,722 | 
|Charles H. Leonard  |                     |                           | 2003 |                     |      |         | 195,654 |              |         |           | 108,800 |              |         |         | 20,250 |              |        |  | 271,523 |   |         |  | 16,112 |       
|                    |                     | Senior Vice President and |      |                     | 2002 |         |         |              | 182,342 |           |         |              | 88,200  |         |        |              | 18,095 |  |         |   | 32,062  |  |        |        | 11,241 | 
|                    |                     | Chief Financial Officer   |      |                     | 2001 |         |         |              | 170,404 |           |         |              | 106,700 |         |        |              | 11,395 |  |         |   | 46,581  |  |        |        | 8,347  | 
|James C. Ruth       |                     |                           | 2003 |                     |      |         | 195,654 |              |         |           | 108,333 |              |         |         | 20,250 |              |        |  | 456,084 |   |         |  | 13,439 |       
|                    |                     | Senior Vice President and |      |                     | 2002 |         |         |              | 182,342 |           |         |              | 86,300  |         |        |              | 18,095 |  |         |   | 55,368  |  |        |        | 11,346 | 
|                    |                     | General Counsel           |      |                     | 2001 |         |         |              | 169,942 |           |         |              | 103,300 |         |        |              | 11,395 |  |         |   | 23,411  |  |        |        | 6,156  | 
|John N. Goodpasture |                     |                           | 2003 |                     |      |         | 189,846 |              |         |           | 104,263 |              |         |         | 13,250 |              |        |  |        |   |         |  | 17,996 |       
|                    |                     | Vice President,           |      |                     | 2002 |         |         |              | 182,885 |           |         |              | 91,000  |         |        |              | 5,875  |  |         |   |        |  |        |        | 7,226  | 
|                    |                     | Corporate Development     |      |                     | 2001 |         |         |              | 27,692  |           |         |              |        |         |        |              |       |  |         |   |        |  |        |        |       | 



---

|(1) |  | Mr. Pearl was elected as President in February 2001, and Chief
Executive Officer and director effective May 1, 2002.                                                                                                                                                                                                                                                                    
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Amounts represent bonuses accrued during the year under the
Management Incentive Compensation Plan (MICP). Payments under the
MICP are made in the subsequent year. Annual compensation does not
include awards under long-term incentive plans, which are described in
the 2000 LTIP awards table under -Compensation Pursuant to General
Partner Plans.                           
|   
|(3) |  | Amounts represent quarterly distribution equivalents under the
terms of the Companys 2000 Long Term Incentive Plan (2000 LTIP) and
Retention Incentive Compensation Plan (RICP).                                                                                                                                                                                                   
|   
|(4) |  | Amounts represent credits earned to Performance Unit accounts and
options exercised under the terms of 1994 LTIP, payouts under the RICP
and payouts under the 2000 LTIP.                                                                                                                                                                                                               
|   
|(5) |  | Includes (i) Company matching contributions under funded,
qualified, defined contribution retirement plans; (ii) Company matching
contribution credits under unfunded, non qualified plans; and (iii) the
imputed value of premiums paid by the Company for insurance on the
Named Executive Officers lives. Amount for Mr. Pearl in 2001 also
includes $74,302 of relocation expenses.

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Executive Employment Contracts and Termination of Employment Arrangements

On February 12, 2001, Barry R. Pearl and the Company entered into an
employment agreement, which set a minimum base salary of $220,000 per year. The
Company may terminate the employment agreement for cause, death or disability.
In addition, the Company or Mr. Pearl may terminate the agreement upon written
notice. Mr. Pearl participates in other Company sponsored benefit plans on the
same basis as other senior executives of the Company. In the event Mr. Pearl
is terminated due to death or disability or by the Company for cause, Mr. Pearl
is entitled only to base salary earned through the date of termination. In the
event of termination for any other reason, Mr. Pearl is entitled to base salary
earned through the date of termination plus a lump sum severance payment equal
to two times his base annual salary and two times the current target bonus
approved under the MICP by the Compensation Committee. In the event Mr. Pearl
is involuntarily terminated following a change in control, he is entitled to a
lump sum severance payment equal to two times his base annual salary plus two
times his current target bonus.

The Company has entered into employment agreements with its executive
officers identified in Item 10. Directors and Executive Officers of the
Registrant. 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, the executive is entitled only to base salary earned through the date of
termination. In the event of termination for any other reason, the 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, the 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 Committee Interlocks and Insider Participation

During 2003, Jim W. Mogg, a director of the General Partner and chairman,
president and chief executive officer of DEFS, was chairman of the Compensation
Committee of the General Partner and participated in deliberations concerning
the General Partners executive officer compensation. The other four members
of the Compensation Committee of the General Partner, Milton Carroll, R. A.
Walker, Derrill Cody and John P. DesBarres, are non-employee directors of the
General Partner and are not officers or directors of DEFS or its parent
companies, ConocoPhillips or Duke Energy.

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 objectives and personal objectives are met each year. The
Compensation Committee of the Board of Directors of the General Partner
determines at the beginning of each year which employees are eligible to become
participants in the MICP. Additional participants may be added to the plan
during the year by the Chief Executive Officer. Each participant is assigned a
target award, determined as a percentage of total annual eligible earnings for
the plan year less any incentive compensation payments during the plan year, by
the Compensation Committee. Such target award determines the additional
compensation to be paid if certain performance objectives and personal
objectives are met. The amount of the target awards may range from 10% to 55%
of a participants base salary. Maximum payout under the MICP is 144% of a
participants target award. Awards are paid as soon as practicable following
approval by the Compensation Committee after the close of a year.

1994 Long Term Incentive Plan

The 1994 LTIP authorized incentive awards to key employees whereby a
participant was granted an option to purchase Units together with a stipulated
number of Performance Units, which provided for cash credits to participants
accounts when annual earnings exceeded specified levels. No awards have been
made under the 1994 LTIP since 1999, and none are expected to be made in the
future.

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The following table provides information concerning the Unit options
exercised under the 1994 LTIP by each of the Named Executive Officers during
2003. There were no unexercised outstanding Unit options under the 1994 LTIP
to the Named Executive Officers as of December 31, 2003.

AGGREGATED OPTIONS EXERCISES IN YEAR ENDED DECEMBER 31, 2003

|            |  |             |        |          |  |                        |         |                      |  |              |   |  |  |             |   | 
|----------- |  | ----------- | ------ | -------- |  | ---------------------- | ------- | -------------------- |  | ------------ | - |  |  | ----------- | - | 
|            |  |             |        |          |  |                        |         |                      |  |              |   |  |  | Value of   
|            |  |             |        |          |  |                        |         |                      |  |              |   |  |  | Unexercised
|            |  | Shares      |        |          |  |                        |         | Number of Securities |  | In-the-Money
|            |  | Acquired on |        | Value    |  | Underlying Unexercised |         | Options             
|Name        |  | Exercise    |        | Realized |  | Options at FY-end (1)  |         | at FY-end (1)       
|            |  |             |        |          |  |                        |         |                     
|Mr. Leonard |  |             | 17,328 |          |  |                        | 196,123 |                      |  |              |  |  |  |             |  | 
|Mr. Ruth    |  |             | 32,547 |          |  |                        | 356,109 |                      |  |              |  |  |  |             |  | 



---

|(1) |  | All remaining outstanding options were exercised during the year
ended December 31, 2003.
|--- |  | -----------------------------------------------------------------------------------------

2000 Long Term Incentive Plan

Effective January 1, 2000, the General Partner established the Texas
Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (2000
LTIP) to provide key employees incentives to achieve improvements in our
financial performance. Generally, upon the close of a three-year performance
period, if the participant is then still an employee of the General Partner,
the participant will receive a cash payment in an amount equal to (1) the
applicable performance percentage specified in the award multiplied by (2) the
number of phantom Units granted under the award multiplied by (3) the average
of the closing prices of a Unit over the ten consecutive trading days
immediately preceding the last day of the performance period. Generally, a
participants performance percentage is based upon the improvement of our
Economic Value Added (as defined below) during a three-year performance period
over the Economic Value Added during the three-year period immediately
preceding the performance period. If a participant incurs a separation from
service during the performance period due to death, disability or retirement
(as such terms are defined in the 2000 LTIP), the participant will be entitled
to receive a cash payment in an amount equal to the amount computed as
described above multiplied by a fraction, the numerator of which is the number
of days that have elapsed during the performance period prior to the
participants separation from service and the denominator of which is the
number of days in the performance period.

The performance period applicable to awards granted in 2003 is the
three-year period that commenced on January 1, 2003, and ends on December 31,
2005. Each participants performance percentage is the result of [(A) minus
(B)] divided by [(C) minus (B)] where (A) is the actual Economic Value Added
for the performance period, (B) is $60.1 million (which represents the actual
Economic Value Added for the three-year period immediately preceding the
performance period) and (C) is $82.0 million (which represents the Target
Economic Value Added during the three-year performance period). No amounts
will be payable under the awards granted in 2003 for the 2000 LTIP unless
Economic Value Added for the three year performance period exceeds $60.1
million. The performance percentage may not exceed 150%.

Economic Value Added means our average annual EBITDA for the performance
period minus the product of our average asset base and our cost of capital for
the performance period. For purposes of the 2000 LTIP for plan years 2000
through 2002, EBITDA means our earnings before net interest expense,
depreciation and amortization and our proportional interest in EBITDA of our
joint ventures as presented in our consolidated financial statements prepared
in accordance with generally accepted accounting principles, except that in its
discretion the Compensation Committee of the General Partner may exclude gains
or losses from extraordinary, unusual or non-recurring items. For the year
ended December 31, 2003, EBITDA means, in addition to the above, earnings
before other income  net. Average asset base means the quarterly average,
during the performance period, of our gross value of property, plant and
equipment, plusproducts and crude oil operating oil supply and the gross value
of intangibles and equity investments. Our cost of capital is approved by the
Compensation Committee at the date of award grant.

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In addition to the payment described above, during the performance period,
the General Partner will pay to the participant the amount of cash
distributions that we would have paid to our unitholders had the participant
been the owner of the number of Units equal to the number of phantom Units
granted to the participant under this award.

The following table provides information concerning awards under the 2000
LTIP to each of the Named Executive Officers during 2003.

|                |  |         |       |             |  |           |  |                              |   |         |  |  |        |  |  |  |        |  |  | 
|--------------- |  | ------- | ----- | ----------- |  | --------- |  | ---------------------------- | - | ------- |  |  | ------ |  |  |  | ------ |  |  | 
|                |  | Number  |       |             |  |           |  | Estimated Future Payouts (1)
|                |  | of      |       |             |  |           |  |                             
|                |  | Phantom |       | Performance |  | Threshold |  | Target                       |   | Maximum
|Name            |  | Units   |       | Period      |  | (#) (2)   |  | (#) (3)                      |   | (#) (4)
|                |  |         |       |             |  |           |  |                              |   |        
|Mr. Pearl       |  |         | 9,100 |             |  | 3 years   |  |                              |  |         |  |  | 13,650 |  |  |  | 13,650 | 
|Mr. Leonard     |  |         | 2,900 |             |  | 3 years   |  |                              |  |         |  |  | 4,350  |  |  |  | 4,350  | 
|Mr. Ruth        |  |         | 2,900 |             |  | 3 years   |  |                              |  |         |  |  | 4,350  |  |  |  | 4,350  | 
|Mr. Goodpasture |  |         | 2,800 |             |  | 3 years   |  |                              |  |         |  |  | 4,200  |  |  |  | 4,200  | 



---

|(1) |  | Phantom units will be settled in cash based upon the then
market price of the Units at the end of the performance period as
described above.                                                                                                                                                                                                                                                             
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | No amounts will be payable for awards granted in 2003 unless
Economic Value Added for the three year performance period exceeds
$60.1 million.                                                                                                                                                                                                                                                           
|   
|(3) |  | In number of phantom units. Pursuant to Instruction 5 to
Regulation 402(e) of the Securities and Exchange Commission, these
amounts assume that the 37% increase in Economic Value Added for
2003 as compared with 2002 is maintained for each of the three years
in the performance period. There can be no assurance that any
specific amount of Economic Value Added will be attained for such
period.
|   
|(4) |  | The maximum potential payout under the 2000 LTIP is 150% of
phantom units awarded.                                                                                                                                                                                                                                                                                                                       

Pension Plan

Prior to the transfer of the General Partner interest from Duke Energy to
DEFS on April 1, 2000, the Companys employees participated in the Duke Energy
Retirement Cash Balance Plan, which is a noncontributory, trustee-administered
pension plan. Effective January 1, 1999, the benefit formula for all eligible
employees was a cash balance formula. Under a cash balance formula, a plan
participant accumulated a retirement benefit based upon pay credits and current
interest credits. The pay credits were based on a participants salary, age,
and service. In addition, the Named Executive Officers participated in the Duke
Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified,
defined benefit retirement plan. The Duke Energy Executive Cash Balance Plan
was established to restore benefit reductions caused by the maximum benefit
limitations that apply to qualified plans.

Benefits under the Duke Energy Retirement Cash Balance Plan and the Duke
Energy Executive Cash Balance Plan were based on eligible pay, generally
consisting of base pay, short term incentive pay, and lump-sum merit increases.
The Duke Energy Retirement Cash Balance Plan excludes deferred compensation,
other than deferrals pursuant to Sections 401(k) and 125 of the Internal
Revenue Code. As part of the change in ownership on March 31, 2000, the
Company is no longer responsible for the funding of the liabilities associated
with the Duke Energy Retirement Cash Balance Plan or the Duke Energy Executive
Cash Balance Plan.

Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash
Balance Plan (TEPPCO RCBP) and the TEPPCO Supplemental Benefit Plan (TEPPCO
SBP). The benefits and provisions of these plans are substantially identical
to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive
Cash Balance Plan previously in effect prior to April 1, 2000.

Under the cash balance benefit accrual formula that applies in determining
benefits under the TEPPCO RCBP, 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

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employees monthly eligible pay. The percentage depends on age added to
completed years of services at the beginning of the year, as shown below:

|                 |  |             |   |  
|---------------- |  | ----------- | - | -
|                 |  | Monthly Pay
|                 |  | Credit     
|Age plus Service |  | Percentage 
|                 |  |            
|34 or less       |  |             | 4 | %
|35 to 49         |  |             | 5 | %
|50 to 64         |  |             | 6 | %
|65 or more       |  |             | 7 | %

The above monthly pay credit is increased by an additional 4% of any
portion of eligible pay above the Social Security taxable wage base ($87,000
for 2003). Employee accounts also receive monthly interest credits on their
balances. The rate of the interest credit is adjusted quarterly and is derived
from the average annual yield on 30-year U.S. Treasury Bonds during the third
week of the last month of the previous quarter, subject to a minimum rate of 4%
per year and a maximum rate of 9% per year.

Assuming that the Named Executive Officers continue in their present
positions at their present salaries until retirement at age 65, their estimated
annual pensions in a single life annuity form under the applicable pension
plan(s) (including the Duke Energy Retirement Cash Balance Plan, the Duke
Energy Executive Cash Balance Plan, the TEPPCO RCBP and the TEPPCO SBP)
attributable to such salaries would be as follows: Barry R. Pearl, $66,977; J.
Michael Cockrell, $43,259; Charles H. Leonard, $98,261; James C. Ruth,
$165,721; and John N. Goodpasture, $34,545. Such estimates were calculated
assuming interest credits at a rate of 6% per annum and using a future Social
Security taxable wage base equal to $87,900.

Compensation of Directors

Directors of the General Partner who are neither officers nor employees of
either the Company or DEFS receive a stipend, effective January 1, 2004, of
$35,000 per annum, $1,000 for attendance at each meeting of the Board of
Directors, $1,000 for attendance at each meeting of a committee of the Board of
Directors, except for attendance of the Audit Committee, for which the amount is
$2,000 for each meeting, 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 $5,000
per annum, except for the chairman of the Audit Committee, who receives an
additional stipend of $20,000 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 Units.

Effective April 1, 2002, 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 then current market value of 100 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 in
cash to the director according to the distribution schedule chosen by such
director.

Messrs. Mogg, Pearl, Borer, Bradley and Easter are not compensated for
their services as directors, and it is not anticipated that any compensation
for service as a director will be paid in the future to directors who are
either officers or full-time employees of Duke Energy, DEFS, the General
Partner or any of their affiliates.

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Item 12.Security Ownership of Certain Beneficial Owners and Management

Equity Compensation Plan Information

The following table provides information about our Equity Compensation
Plans.

|                                                           |  |                  |   |                |  |                 |   |           |  |  |   | 
|---------------------------------------------------------- |  | ---------------- | - | -------------- |  | --------------- | - | --------- |  |  | - | 
|                                                           |  | Number of        |   |                |  |                 |   |           |  | 
|                                                           |  | securities to be |   |                |  |                 |   | Number of
|                                                           |  | issued upon      |   | Weighted       |  | securities     
|                                                           |  | exercise of      |   | average price  |  | remaining      
|                                                           |  | outstanding      |   | of outstanding |  | available for  
|Plan Category                                              |  | options          |   | options        |  | future issuance
|                                                           |  |                  |   |                |  |                
|Equity compensation plans approved by
Security holders     |  |                  |  |                |  |                 |  |           |  |  |  | 
|Equity compensation plans not approved by
Security holders |  |                  |  |                |  |                 |  |           |  |  |  | 
|                                                           |  |                  |   |                |  |                 |   |           |  |  |   | 
|Total                                                      |  |                  |  |                |  |                 |  |           |  |  |  | 
|                                                           |  |                  |   |                |  |                 |   |           |  |  |   | 

During the year ended December 31, 2003, all of the remaining outstanding
Unit options under the 1994 LTIP were exercised (see Compensation Pursuant to
General Partner Plans). We have no other compensation plans that would result
in the issuance of equity.

Security Ownership of Certain Beneficial Owners

As of February 20, 2004, Duke Energy, through its ownership of the Company
and other subsidiaries, owns 2,500,000 Units, representing 4.0% of the 63.0
million Units outstanding. The following table sets forth information of each
person other than Duke Energy known to us to be the beneficial owner of more
than 5% of our voting shares as of February 20, 2004:

|                                     |                                 |           |                   |       |            |  |     |   | 
|------------------------------------ | ------------------------------- | --------- | ----------------- | ----- | ---------- |  | --- | - | 
|                                     |                                 |           | Amount and Nature |       |            |  |    
|                                     |                                 |           | of Beneficial     |       | Percentage
|Name and Address of Beneficial Owner |                                 | Ownership |                   | Owned
|                                     |                                 |           |                   |      
|Goldman, Sachs & Co.                 |                                 |           | 3,714,182         | (1)   |            |  | 5.9 | %
|                                     | 85
Broad St.
New York, NY 10004 |           |                   |       |            |  |     |   | 



---

|(1) |  | Goldman, Sachs & Co. reported shared voting and dispositive power in its
most recent report on Schedule 13G/A filed February 12, 2004. Goldman,
Sachs & Co. is registered investment adviser whose clients have the right
to receive distributions from, and the proceeds from the sale of, such
shares.
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

No other person is known by us to own more than 5% of our outstanding
Units.

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##### Table of Contents



Security Ownership of Management

The following table sets forth certain information, as of February 20,
2004, concerning the beneficial ownership of 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. This information is based on data furnished by
the persons named. Based on information furnished to the General Partner by
these persons, no director or officer of the General Partner owned
beneficially, as of February 20, 2004, more than 1% of the 63.0 million Units
outstanding at that date.

|                                                                                  |  |           |        | 
|--------------------------------------------------------------------------------- |  | --------- | ------ | 
|                                                                                  |  | Number of
|Name                                                                              |  | Units (1)
|                                                                                  |  |          
|Mark A. Borer                                                                     |  |           | 1,000  | 
|Michael J. Bradley                                                                |  |           | 1,150  | 
|J. Michael Cockrell                                                               |  |           | 5,000  | 
|Derrill Cody                                                                      |  |           | 13,000 | 
|John P. DesBarres                                                                 |  |           | 20,000 | 
|Charles H. Leonard                                                                |  |           | 1,124  | 
|Jim W. Mogg (2)                                                                   |  |           | 4,427  | 
|Barry R. Pearl                                                                    |  |           | 10,000 | 
|James C. Ruth                                                                     |  |           | 5,000  | 
|All directors and officers (consisting of 18 people, including those named above) |  |           | 72,438 | 



---

|(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 2,227 Units owned by daughters.                                                                                                                                                        




Item 13.Certain Relationships and Related Transactions

Our Management

We have no employees and are managed by the Company, a wholly owned
subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in
DEFS, and ConocoPhillips holds the remaining 30%. According to the
Partnership Agreements, the Company is entitled to reimbursement of all direct
and indirect expenses related to our business activities (see Note 1.
Partnership Organization).

For the years ended December 31, 2003, 2002, and 2001, we incurred direct
expenses of $74.5 million, $66.7 million and $65.2 million, respectively, which
were charged to us by DEFS. Substantially all of these costs were related to
payroll and payroll related expenses. For the years ended December 31, 2003,
2002, and 2001, expenses for administrative services and overhead allocated to
us by Duke Energy and its affiliates were $1.1 million, $0.8 million and $0.6
million, respectively.

Transactions with DEFS

LSI sells lubrication oils and specialty chemicals to DEFS. For the years
ended December 31, 2003, 2002, and 2001, revenues recognized by LSI included
$15.2 million, $14.6 million and $12.3 million, respectively, for the sale of
lubrication oils and specialty chemicals to DEFS.

Effective with the purchase of the fractionation facilities on March 31,
1998, TEPPCO Colorado and DEFS entered into a 20-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 $7.4 million for each of the years ended December 31, 2003,
2002 and 2001. TEPPCO Colorado and DEFS also entered into an 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.

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##### Table of Contents



Expenses related to the Operation and Maintenance Agreement totaled $0.9
million for each of the years ended December 31, 2003, 2002 and 2001.

The Dean Pipeline and the Wilcox Pipeline were included with the crude oil
assets purchased from DEFS effective November 1, 1998. The Dean Pipeline
originates in South Texas and transports NGLs for DEFS into its pipeline in
Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation
totaled $1.0 million, $2.9 million and $0.1 million for the years ended
December 31, 2003, 2002 and 2001, respectively. The Wilcox Pipeline, which is
located along the Texas Gulf Coast, transports NGLs for DEFS from two of its
processing plants and is currently supported by a throughput agreement with
DEFS through 2005. The fees paid to us by DEFS under the agreement
were $1.5 million, $1.2 million and $1.2 million for the years ended December 31, 2003, 2002
and 2001, respectively.

The Panola Pipeline and San Jacinto Pipeline were purchased on December
31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS East
Texas Plant Complex in Panola County, Texas. For the years ended December 31,
2003, 2002 and 2001, revenues recognized included $9.2 million, $12.0 million
and $13.9 million, respectively, from an affiliate of DEFS for NGL
transportation fees on the Panola and San Jacinto Pipelines.

Effective May 2001, we entered into an agreement with an affiliate of DEFS
to commit sole utilization of our Providence terminal to an affiliate of DEFS.
We operate the terminal and provide propane loading services to an affiliate of
DEFS. The agreement terminates in May 2004, and we are currently renegotiating
the agreement. During the years ended December 31, 2003, 2002 and 2001,
revenues of $3.2 million, $2.3 million and $1.5 million from an affiliate of
DEFS, respectively, were recognized pursuant to this agreement.

On September 30, 2001, we completed the acquisition of Jonah (see Note 6.
Acquisitions and Dispositions). The Jonah assets are managed and operated by
employees of DEFS under a contractual agreement under which DEFS is reimbursed
for its actual costs. During the years ended December 31, 2003, 2002 and 2001,
we recognized $3.7 million, $3.3 million and $0.6 million, respectively, of
expense related to the operation and management of the Jonah assets by DEFS.

On March 1, 2002, we completed the acquisition of the Chaparral NGL system
(see Note 6. Acquisitions and Dispositions). The Chaparral assets are managed
and operated by employees of DEFS under a contractual agreement under which
DEFS is reimbursed for its actual costs. During the years ended December 31,
2003, and 2002, we recognized $2.1 million and $1.7 million, respectively, of
expenses related to the operation and management of the Chaparral assets by
DEFS. An affiliate of DEFS transports NGLs on the Chaparral NGL system. The
fees paid to us by an affiliate of DEFS for NGL transportation on Chaparral
totaled $5.5 million and $4.5 million for the years ended December 31, 2003 and
2002, respectively.

On June 30, 2002, we completed the acquisition of Val Verde (see Note 6.
Acquisitions and Dispositions). The Val Verde assets are managed and operated
by employees of DEFS under a contractual agreement under which DEFS is
reimbursed for its actual costs. During the years ended December 31, 2003, and
2002, we recognized $3.0 million and $1.2 million, respectively, of expenses
related to the operation and management of the Val Verde assets by DEFS.

At December 31, 2003 and 2002, we had a receivable from DEFS of $1.8
million and $6.9 million, respectively, related to sales and transportation
services provided to DEFS. Included in the receivable balance at December 31,
2002, was an amount related to environmental remediation activities. At
December 31, 2003 and 2002, we had a payable to DEFS of $9.7 million and $6.7
million, respectively, related to direct payroll, payroll related costs and
management fees for Jonah, Chaparral, and Val Verde as described above.
Included in this payable balance to DEFS at December 31, 2003 and 2002, is an
imbalance payable to DEFS by TEPPCO Midstream of $1.5 million and $0.9 million,
respectively.

On April 2, 2003, we sold in an underwritten public offering 3.9 million
Units at $30.35 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $114.5 million, of which approximately $113.8
million was used to repurchase and retire all of the 3.9 million previously
outstanding Class B Units held by DETTCO (see Note 12. Partners Capital and
Distributions).

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We contract with Bison Insurance Company Limited (Bison), a wholly owned
subsidiary of Duke Energy, for a majority of our insurance coverage, including
property, liability, auto and directors and officers insurance coverage. For
the years ended December 31, 2003 and 2002, we paid insurance premiums to Bison
of $6.4 million and $4.5 million, respectively. At December 31, 2003 and 2002,
we had insurance reimbursement receivables due from Bison of $1.9 million and
$1.3 million, respectively.

At December 31, 2003, we had a loan of propane outstanding to DEFS with a
total value of $1.4 million. We will earn a nominal rental fee of $0.1 million
on this transaction. This propane will be returned to us in February 2004. We
regularly loan inventory for a fee to third parties and affiliates as part of
our inventory management practice.

Interest of the General Partner in the Partnership

We make quarterly cash distributions of all of our Available Cash,
generally defined as consolidated cash receipts less consolidated cash
disbursements and cash reserves established by the General Partner in its sole
discretion. According to the Partnership Agreement, the Company receives
incremental incentive cash distributions when cash distributions exceed certain
target thresholds as follows:

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

During the year ended December 31, 2003, distributions paid to the General
Partner totaled $54.7 million, including incentive distributions of $51.7
million.

Interests of Duke Energy in the Partnership

In connection with our formation, 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 in a
manner identical to Units and are treated as Units for purposes of this Report.
These Units were assigned to Duke Energy when ownership of the Company was
transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership
Agreement, we have registered the resale by Duke Energy of these Units with the
Securities and Exchange Commission. As of December 31, 2003, none of these
Units had been sold by Duke Energy.

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Item 14.Principal Accounting Fees and Services

The following table describes fees for professional audit services
rendered by KPMG, our principal accountant, for the audit of our financial
statements for the years ended December 31, 2003 and 2002, and for fees billed
for other services rendered by KPMG during those periods.

|                       |       |      |                          |       |  |   |     |       | 
|---------------------- | ----- | ---- | ------------------------ | ----- |  | - | --- | ----- | 
|                       |       |      | Years Ended December 31,
|                       |       |      |                         
|Type of Fee            |       | 2003 |                          | 2002 
|                       |       |      |                          |      
|                       |       |      | (in thousands)          
|Audit Fees             |       | $    | 953                      |       |  | $ | 915 |      
|Audit Related Fees (1) |       |      | 58                       |       |  |   | 15  |      
|Tax Fees (2)           |       |      | 183                      |       |  |   | 17  |      
|All Other Fees (3)     |       |      | 656                      |       |  |   | 106 |      
|                       |       |      |                          |       |  |   |     |      
|                       | Total |      | $                        | 1,850 |  |   | $   | 1,053 | 
|                       |       |      |                          |       |  |   |     |      



---

|(1) |  | Audit related fees consist principally of fees for audits of financial
statements of certain employee benefit plans and certain internal control
documentation assistance.                                                                                                                                                                                                                
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Tax Fees consist of fees for sales and use tax consultation and tax
compliance services.                                                                                                                                                                                                                                                                                                  
|   
|(3) |  | All Other Fees include the aggregate fees we paid during the years ended
December 31, 2003 and 2002, for products and services provided by KPMG,
other than the services reported above. The majority of the other fees
are fees for litigation support services related to the D.R.D. legal
proceedings which were settled on July 16, 2003 (see Note 17. Commitments
and Contingencies).

Procedures For Audit Committee Pre-Approval of Audit and Permissible Non-Audit
Services of Independent Auditor

Pursuant to its charter, the Audit Committee of our Board of Directors is
responsible for reviewing and approving, in advance, any audit and any
permissible non-audit engagement or relationship between us and our independent
auditors. KPMGs engagement to conduct our audit was approved by the Audit
Committee on April 28, 2003. Additionally, all permissible non-audit
engagements with KPMG have been reviewed and approved by
the Audit Committee, pursuant to pre-approval policies and procedures
established by the Audit Committee.




PART IV




Item 15.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.                                                                                                                                

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| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| | ------- | ----- | ----------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Exhibit |       |            
| | Number  |       | Description
| |         |       |            
| |         | 3.1   |             | Certificate of Limited Partnership of TEPPCO Partners, L.P.
(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   |             | Third Amended and Restated Agreement of Limited Partnership
of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit
3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 2001 and incorporated
herein by reference).                                                                                                                                                                                                                                                                                                                           
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.1   |             | Form of Certificate representing Limited Partner Units (Filed
as Exhibit 4.1 to the Registration Statement of TEPPCO Partners,
L.P. (Commission File No. 33-32203) and incorporated herein by
reference).                                                                                                                                                                                                                                                                                                                                                                                                          
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.2   |             | Form of Indenture between TE Products Pipeline Company,
Limited Partnership and The Bank of New York, as Trustee, dated as
of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline
Company, Limited Partnerships Registration Statement on Form S-3
(Commission File No. 333-38473) and incorporated herein by
reference).                                                                                                                                                                                                                                                                              
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.3   |             | Form of Certificate representing Class B Units (Filed as
Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the year ended December 31, 1998 and incorporated
herein by reference).                                                                                                                                                                                                                                                                                                                                                                                               
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.4   |             | Form of Indenture between TEPPCO Partners, L.P., as issuer,
TE Products Pipeline Company, Limited Partnership, TCTM, L.P.,
TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as
subsidiary guarantors, and First Union National Bank, NA, as
trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to
Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
dated as of February 20, 2002 and incorporated herein by reference).                                                                                                                                                 
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.5   |             | First Supplemental Indenture between TEPPCO Partners, L.P.,
as issuer, TE Products Pipeline Company, Limited Partnership, TCTM,
L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering
Company, as subsidiary guarantors, and First Union National Bank,
NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3
to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
dated as of February 20, 2002 and incorporated herein by reference).                                                                                                                                      
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.6   |             | Second Supplemental Indenture, dated as of June 27, 2002,
among TEPPCO Partners, L.P., as issuer, TE Products Pipeline
Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream
Companies, L.P., and Jonah Gas Gathering Company, as Initial
Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as
New Subsidiary Guarantor, and Wachovia Bank, National Association,
formerly known as First Union National Bank, as trustee (Filed as
Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the quarter ended June 30, 2002 and incorporated
herein by reference).
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 4.7   |             | Third Supplemental Indenture among TEPPCO Partners, L.P. as
issuer, TE Products Pipeline Company, Limited Partnership, TCTM,
L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company
and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors,
and Wachovia Bank, National Association, as trustee, dated as of
January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year ended
December 31, 2002 and incorporated herein by reference).                                                                                       
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.1+ |             | Duke Energy Corporation Executive Savings Plan (Filed as
Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the year ended December 31, 1999 and incorporated
herein by reference).                                                                                                                                                                                                                                                                                                                                                                                              
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.2+ |             | Duke Energy Corporation Executive Cash Balance Plan (Filed
as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the year ended December 31, 1999 and
incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                                         
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.3+ |             | Duke Energy Corporation Retirement Benefit Equalization Plan
(Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31, 1999
and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                               

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| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| | ------- | ------ | ----------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Exhibit |        |            
| | Number  |        | Description
| |         |        |            
| |         | 10.4+  |             | 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).                                                                                                                             
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.5+  |             | 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).                                                                                                              
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.6+  |             | Form of Employment Agreement between the Company and Thomas
R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture,
Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara
A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended December 31,
1998 and incorporated herein by reference).               
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.7   |             | 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).
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.8   |             | 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).                                                                                                                                                                              
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.9+  |             | 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).                                                                                                                   
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.10+ |             | Form of Employment and Non-Compete Agreement between the Company
and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit
10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 1999 and incorporated
herein by reference).                                                                                                     
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.11+ |             | 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).                                                                                                         
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.12+ |             | 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).                                                                                                  
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.13+ |             | 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).                                                                                                                         
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.14+ |             | Texas Eastern Products Pipeline Company, LLC 2000 Long Term
Incentive Plan, Amendment and Restatement, effective January 1, 2000
(Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31, 2000
and incorporated herein by reference).                                                                                           
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.15+ |             | TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed
as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the year ended December 31, 2000 and
incorporated herein by reference).                                                                                                                                                                  
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.16+ |             | Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30
to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the quarter ended March 31, 2001 and incorporated herein by
reference).                                                                                                                                                                                   
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                    
| |         | 10.17  |             | Amended and Restated Credit Agreement among TEPPCO Partners,
L.P. as Borrower, SunTrust Bank as Administrative Agent and LC
Issuing Bank, and Certain Lenders, dated as of April 6, 2001
($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended March 31, 2001 and incorporated herein by reference). 

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| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| | ------- | ----- | ----------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Exhibit |       |            
| | Number  |       | Description
| |         |       |            
| |         | 10.18 |             | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent, and Certain Lenders, dated as
of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit
10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended March 31, 2001 and incorporated
herein by reference).                                                                                                                 
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.19 |             | Amendment 1, dated as of September 28, 2001, to the Amended
and Restated Credit Agreement among TEPPCO Partners, L.P. as
Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank,
and Certain Lenders, dated as of April 6, 2001 ($500,000,000
Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the quarter ended
September 30, 2001 and incorporated herein by reference).                
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.20 |             | Amendment 1, dated as of September 28, 2001, to the Credit
Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as
Administrative Agent, and Certain Lenders, dated as of April 6, 2001
($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended September 30, 2001 and incorporated herein by
reference).                                                         
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.21 |             | Amendment and Restatement, dated as of November 13, 2001, to
the Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent, and Certain Lenders, dated as
of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit
10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No.
1-10403) for the year ended December 31, 2001 and incorporated
herein by reference).                                                 
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.22 |             | Second Amendment and Restatement, dated as of November 13,
2001, to the Amended and Restated Credit Agreement amount TEPPCO
Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent
and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001
($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form
10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the
year ended December 31, 2001 and incorporated herein by reference).
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.23 |             | Second Amended and Restated Agreement of Limited Partnership
of TE Products Pipeline Company, Limited Partnership, dated
September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the quarter ended
September 30, 2001 and incorporated herein by reference).                                                                                                                                                     
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.24 |             | Amended and Restated Agreement of Limited Partnership of
TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended September 30, 2001 and incorporated herein by
reference).                                                                                                                                                                                                   
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.25 |             | Contribution, Assignment and Amendment Agreement among
TEPPCO Partners, L.P., TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company,
LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6
to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the quarter ended June 30, 2001 and incorporated herein by
reference).                                                                  
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.26 |             | 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).                                                                                                                                                                                                                                                    
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.27 |             | Agreement of Limited Partnership of TEPPCO Midstream
Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for
the quarter ended September 30, 2001 and incorporated herein by
reference).                                                                                                                                                                                                 
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.28 |             | Agreement of Partnership of Jonah Gas Gathering Company
dated June 20, 1996 as amended by that certain Assignment of
Partnership Interests dated September 28, 2001 (Filed as Exhibit
10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the year ended December 31, 2001 and incorporated
herein by reference).                                                                                                                               
| |         |       |             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |         | 10.29 |             | Unanimous Written Consent of the Board of Directors of
TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to
Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for
the year ended December 31, 2001 and incorporated herein by
reference).                                                                                                                                                                                                    

72



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| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| | ------- | ------ | ----------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Exhibit |        |            
| | Number  |        | Description
| |         |        |            
| |         | 10.30  |             | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent and Certain Lenders, as
Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit
Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the three months ended March
31, 2002 and incorporated herein by reference).                                      
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.31  |             | Amended and Restated Credit Agreement among TEPPCO Partners,
L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC
Issuing Bank and Certain Lenders, as Lenders dated as of March 28,
2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for
the three months ended March 31, 2002 and incorporated herein by
reference).   
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.32  |             | Purchase and Sale Agreement between Burlington Resources
Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated
May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and
incorporated herein by reference).                                                                                                                   
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.33  |             | Credit Agreement among TEPPCO Partners, L.P., as Borrower,
SunTrust Bank, as Administrative Agent and Certain Lenders, as
Lenders dated as of June 27, 2002 ($200,000,000 Term Facility)
(Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) dated as of July 2, 2002 and
incorporated herein by reference).                                                                    
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.34  |             | Amendment, dated as of June 27, 2002 to the Amended and
Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower,
SunTrust Bank, as Administrative Agent, and Certain Lenders, dated
as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed
as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) dated as of July 2, 2002 and incorporated herein
by reference).
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.35  |             | Amendment 1, dated as of June 27, 2002 to the Credit
Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank,
as Administrative Agent and Certain Lenders, dated as of March 28,
2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4
to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
dated as of July 2, 2002 and incorporated herein by reference).                    
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.36  |             | Agreement of Limited Partnership of Val Verde Gas Gathering
Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended June 30, 2002 and incorporated herein by reference).                                                                                                                                                  
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.37+ |             | Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit
Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for
the quarter ended June 30, 2002 and incorporated herein by
reference).                                                                                                                                          
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.38+ |             | Amended and Restated TEPPCO Supplemental Benefit Plan, effective
November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year ended
December 31, 2002 and incorporated herein by reference).                                                                                                                                                             
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.39+ |             | Texas Eastern Products Pipeline Company, LLC 2000 Long Term
Incentive Plan, Second Amendment and Restatement, effective January
1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended December 31,
2002 and incorporated herein by reference).                                                                                                       
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.40+ |             | Amended and Restated Texas Eastern Products Pipeline Company, LLC
Management Incentive Compensation Plan, effective January 1, 2003
(Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31, 2002
and incorporated herein by reference).                                                                                                           
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.41+ |             | Amended and Restated TEPPCO Retirement Cash Balance Plan,
effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of
TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 2002 and incorporated herein by reference).                                                                                                                                                           
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                       
| |         | 10.42  |             | Formation Agreement between Panhandle Eastern Pipe Line
Company and Marathon Ashland Petroleum LLC and TE Products Pipeline
Company, Limited Partnership, dated as of August 10, 2000 (Filed as
Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P.                                                                                                                                                                   

73



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| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| | ------- | ------ | ----------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Exhibit |        |            
| | Number  |        | Description
| |         |        |            
| |         |        |             | (Commission File No. 1-10403) for the year ended December 31,
2002 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                      
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.43  |             | Amended and Restated Limited Liability Company Agreement of
Centennial Pipeline LLC dated as of August 10, 2000 (Filed as
Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the year ended December 31, 2002 and incorporated
herein by reference).                                                                                                                        
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.44  |             | Guaranty Agreement, dated as of September 27, 2002, between
TE Products Pipeline Company, Limited Partnership and Marathon
Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC
(Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31, 2002
and incorporated herein by reference).                                        
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.45  |             | LLC Membership Interest Purchase Agreement By and Between
CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland
Petroleum LLC and TE Products Pipeline Company, Limited Partnership,
Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51
to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the year ended December 31, 2002 and incorporated herein by
reference).
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.46  |             | Joint Development Agreement between TE Products Pipeline
Company, Limited Partnership and Louis Dreyfus Plastics Corporation
dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of
TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter
ended March 31, 2003 and incorporated herein by reference).                                                                                   
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.47  |             | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent and LC Issuing Bank and The
Lenders Party Hereto, as Lenders, dated as of June 27, 2003
($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended June 30, 2003 and incorporated herein by reference).               
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.48  |             | Agreement of Limited Partnership of Mont Belvieu Storage
Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit
10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 2003 and incorporated
herein by reference).                                                                                                                           
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 10.49  |             | Letter of Agreement Clarifying Rights and Obligations of the
Parties Under the Mont Belvieu Storage Partners, L.P., Partnership
Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated
October 13, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the quarter ended
September 30, 2003 and incorporated herein by reference).                 
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 12.1*  |             | Statement of Computation of Ratio of Earnings to Fixed
Charges.                                                                                                                                                                                                                                                                                                                                                
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 21     |             | Subsidiaries of the Partnership (Filed as Exhibit 21 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended June 30, 2002 and incorporated herein by reference).                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 23*    |             | Consent of KPMG LLP.                                                                                                                                                                                                                                                                                                                                                                                           
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 24*    |             | Powers of Attorney.                                                                                                                                                                                                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 31.1*  |             | Certification of Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 31.2*  |             | Certification of Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 32.1** |             | Certification of Chief Executive Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 32.2** |             | Certification of Chief Financial Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
| |         |        |             |                                                                                                                                                                                                                                                                                                                                                                                                                
| |         | 99.1*  |             | Charter of the Audit Committee of the Board of Directors of
the General Partner.                                                                                                                                                                                                                                                                                                                               



---

|*  |  | Filed herewith.                                                   
|-- |  | ------------------------------------------------------------------
|  
|** |  | Furnished herewith pursuant to Item 601(b)-(32) of
Regulation S-K.
|  
|+  |  | A management contract or compensation plan or arrangement.        

74



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##### Table of Contents



|(b) |  | Reports on Form 8-K filed with or furnished to the Securities
and Exchange Commission during the quarter ended December 31, 2003:
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | A current report on Form 8-K was furnished on October 28,
2003, in connection with disclosure of third quarter
estimates and earnings guidance.
| |  |  | -----------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | A current report on Form 8-K was filed on November 3, 2003,
in connection with a presentation to analysts and investors.                       
|
| |  |  | A current report on Form 8-K was filed on December 9, 2003,
in connection with a presentation at an industry conference.                       




SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this Report to be signed
on its behalf by the undersigned, thereunto duly authorized.

| |  |                                          
| |  | -----------------------------------------
| |  | TEPPCO Partners, L.P.                    
| |  |                                          
| |  | (Registrant)                             
| |  | (A Delaware Limited Partnership)         
| |  |                                          
| |  | By: Texas Eastern Products Pipeline      
| |  | Company, LLC, as General Partner         
| |  |                                          
| |  | By: /s/ BARRY R. PEARL                   
| |  |                                          
| |  | Barry R. Pearl,                          
| |  | President and Chief Executive Officer    
| |  |                                          
| |  | By: /s/ CHARLES H. LEONARD               
| |  |                                          
| |  | Charles H. Leonard,                      
| |  | Senior Vice President and Chief Financial
| |  | Officer                                  

Dated: February 23, 2004

75



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##### Table of Contents



Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

|                                             |  |                                                                                                                                                |  |                  
|-------------------------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------- |  | -----------------
|Signature                                    |  | Title                                                                                                                                          |  | Date             
|                                             |  |                                                                                                                                                |  |                  
|BARRY R. PEARL*
Barry R. Pearl               |  | President and Chief Executive Officer
of Texas Eastern Products Pipeline Company, LLC                                                          |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|CHARLES H. LEONARD
Charles H. Leonard        |  | Senior Vice President and Chief Financial Officer
of Texas Eastern Products Pipeline Company, LLC
(Principal Accounting and Financial Officer) |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|JIM W. MOGG*
Jim W. Mogg                     |  | Chairman of the Board of Texas
Eastern Products Pipeline Company, LLC                                                                          |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|MARK A. BORER *
Mark A. Borer                |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|MILTON CARROLL*
Milton Carroll               |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|R.A. WALKER*
R.A. Walker                     |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|DERRILL CODY*
Derrill Cody                   |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|JOHN P. DESBARRES*
John P. DesBarres         |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|MICHAEL J. BRADLEY*
Michael J. Bradley       |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004
|                                             |  |                                                                                                                                                |  |                  
|WILLIAM H. EASTER III*
William H. Easter III |  | Director of Texas Eastern
Products Pipeline Company, LLC                                                                                       |  | February 23, 2004

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

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

76



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##### Table of Contents



CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.

INDEX TO FINANCIAL STATEMENTS

|                      |                                                                                                   |  |      |     | 
|--------------------- | ------------------------------------------------------------------------------------------------- |  | ---- | --- | 
|                      |                                                                                                   |  | Page
|                      |                                                                                                   |  |     
|Financial Statements: |                                                                                                   |  |      |    
|                      | Independent Auditors Report                                                                      |  |      | F-2 | 
|                      | Consolidated Balance Sheets as of December 31, 2003 and 2002                                      |  |      | F-3 | 
|                      | Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001            |  |      | F-4 | 
|                      | Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and
2001        |  |      | F-5 | 
|                      | Consolidated Statements of Partners Capital for the years ended December 31, 2003,
2002 and 2001 |  |      | F-6 | 
|                      | Notes to Consolidated Financial Statements                                                        |  |      | F-7 | 

F-1



---



##### Table of Contents



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, 2003 and 2002, 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, 2003. These consolidated financial
statements are the responsibility of the Partnerships management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of TEPPCO
Partners, L.P. as of December 31, 2003 and 2002, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2003, in conformity with accounting principles generally
accepted in the United States of America.

As described in Note 2 to the consolidated financial statements, as of
January 1, 2001, the Partnership changed its method of accounting for
derivative instruments and hedging activities and, effective January 1, 2002,
adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets.



| | KPMG LLP
| | --------

Houston, Texas
February 12, 2004

F-2



---



##### Table of Contents



TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)

|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |         |           |  |  | 
|------------------------------------------------------------------------------------------------------------------ | ---------------------------------------------------------------------------------------- | --------------------------------------- | --------------------------------- | --------- | --------- | ------------ | --------- | ------- | --------- |  |  | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           | December 31,
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |             
|                                                                                                                   |                                                                                          |                                         |                                   |           |           | 2003         |           | 2002   
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   |                                                                                          |                                         |                                   | ASSETS    |           |              |           |         |           |  |  | 
|Current assets:                                                                                                    |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   | Cash and cash equivalents                                                                |                                         | $                                 | 29,469    |           |              | $         | 30,968  |          
|                                                                                                                   | Accounts receivable, trade (net of allowance for doubtful accounts of
$4,700 and $4,608) |                                         |                                   | 371,938   |           |              |           | 271,854 |          
|                                                                                                                   | Accounts receivable, related parties                                                     |                                         |                                   | 3,143     |           |              |           | 8,751   |          
|                                                                                                                   | Inventories                                                                              |                                         |                                   | 16,060    |           |              |           | 15,104  |          
|                                                                                                                   | Other                                                                                    |                                         |                                   | 32,208    |           |              |           | 31,670  |          
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |         |          
|                                                                                                                   |                                                                                          | Total current assets                    |                                   |           | 452,818   |              |           |         | 358,347   | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|Property, plant and equipment, at cost (net of accumulated
depreciation and amortization of $345,357 and $338,746) |                                                                                          |                                         | 1,619,163                         |           |           |              | 1,587,824 |        
|Equity investments                                                                                                 |                                                                                          |                                         | 365,286                           |           |           |              | 284,705   |        
|Intangible assets                                                                                                  |                                                                                          |                                         | 438,565                           |           |           |              | 465,374   |        
|Goodwill                                                                                                           |                                                                                          |                                         | 16,944                            |           |           |              | 16,944    |        
|Other assets                                                                                                       |                                                                                          |                                         | 48,216                            |           |           |              | 55,228    |        
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |         |          
|                                                                                                                   |                                                                                          | Total assets                            |                                   | $         | 2,940,992 |              |           | $       | 2,768,422 | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   |                                                                                          |                                         | LIABILITIES AND PARTNERS CAPITAL |           |           |              |           |         |           |  | 
|Current liabilities:                                                                                               |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   | Accounts payable and accrued liabilities                                                 |                                         | $                                 | 359,660   |           |              | $         | 265,844 |          
|                                                                                                                   | Accounts payable, related parties                                                        |                                         |                                   | 16,269    |           |              |           | 8,888   |          
|                                                                                                                   | Accrued interest                                                                         |                                         |                                   | 35,111    |           |              |           | 29,726  |          
|                                                                                                                   | Other accrued taxes                                                                      |                                         |                                   | 9,941     |           |              |           | 11,260  |          
|                                                                                                                   | Other                                                                                    |                                         |                                   | 54,610    |           |              |           | 48,845  |          
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |         |          
|                                                                                                                   |                                                                                          | Total current liabilities               |                                   |           | 475,591   |              |           |         | 364,563   | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|Senior Notes                                                                                                       |                                                                                          |                                         | 1,129,650                         |           |           |              | 945,692   |        
|Other long-term debt                                                                                               |                                                                                          |                                         | 210,000                           |           |           |              | 432,000   |        
|Other liabilities and deferred credits                                                                             |                                                                                          |                                         | 16,430                            |           |           |              | 30,962    |        
|Redeemable Class B Units held by related party                                                                     |                                                                                          |                                         |                                  |           |           |              | 103,363   |        
|Commitments and contingencies                                                                                      |                                                                                          |                                         |                                   |           |           |              |           |        
|Partners capital:                                                                                                 |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   | Accumulated other comprehensive loss                                                     |                                         |                                   | (2,902    | )         |              |           | (20,055 | )        
|                                                                                                                   | General partners interest                                                               |                                         |                                   | (7,181    | )         |              |           | 12,770  |          
|                                                                                                                   | Limited partners interests                                                              |                                         |                                   | 1,119,404 |           |              |           | 899,127 |          
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   |                                                                                          | Total partners capital                 |                                   |           | 1,109,321 |              |           |         | 891,842   | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        
|                                                                                                                   |                                                                                          | Total liabilities and partners capital |                                   | $         | 2,940,992 |              |           | $       | 2,768,422 | 
|                                                                                                                   |                                                                                          |                                         |                                   |           |           |              |           |        

See accompanying Notes to Consolidated Financial Statements.

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##### Table of Contents



TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per Unit amounts)

|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |           |           | 
|----------------------------------------------------------------- | ------------------------------------- | ------------------------------- | ------- | ------------------------ | --------- | ---- | ------- | --------- | --------- | - | ------- | --------- | --------- | 
|                                                                  |                                       |                                 |         | Years Ended December 31,
|                                                                  |                                       |                                 |         |                         
|                                                                  |                                       |                                 |         | 2003                     |           | 2002 |         | 2001     
|                                                                  |                                       |                                 |         |                          |           |      |         |          
|Operating revenues:                                               |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|                                                                  | Sales of petroleum products           |                                 | $       | 3,766,651                |           |      | $       | 2,823,800 |           |   | $       | 3,219,816 |          
|                                                                  | Transportation  Refined products     |                                 |         | 138,926                  |           |      |         | 123,476   |           |   |         | 139,315   |          
|                                                                  | Transportation  LPGs                 |                                 |         | 91,787                   |           |      |         | 74,577    |           |   |         | 77,823    |          
|                                                                  | Transportation  Crude oil            |                                 |         | 29,057                   |           |      |         | 27,414    |           |   |         | 24,223    |          
|                                                                  | Transportation  NGLs                 |                                 |         | 39,837                   |           |      |         | 38,870    |           |   |         | 20,702    |          
|                                                                  | Gathering  Natural gas               |                                 |         | 135,144                  |           |      |         | 90,053    |           |   |         | 8,824     |          
|                                                                  | Mont Belvieu operations               |                                 |         |                         |           |      |         | 15,238    |           |   |         | 14,116    |          
|                                                                  | Other                                 |                                 |         | 54,430                   |           |      |         | 48,735    |           |   |         | 51,594    |          
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |           |          
|                                                                  |                                       | Total operating revenues        |         |                          | 4,255,832 |      |         |           | 3,242,163 |   |         |           | 3,556,413 | 
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|Costs and expenses:                                               |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|                                                                  | Purchases of petroleum products       |                                 |         | 3,711,207                |           |      |         | 2,772,328 |           |   |         | 3,172,805 |          
|                                                                  | Operating, general and administrative |                                 |         | 201,329                  |           |      |         | 158,753   |           |   |         | 135,253   |          
|                                                                  | Operating fuel and power              |                                 |         | 38,511                   |           |      |         | 36,814    |           |   |         | 36,575    |          
|                                                                  | Depreciation and amortization         |                                 |         | 100,728                  |           |      |         | 86,032    |           |   |         | 45,899    |          
|                                                                  | Taxes  other than income taxes       |                                 |         | 15,597                   |           |      |         | 17,989    |           |   |         | 14,090    |          
|                                                                  | Gain on sale of assets                |                                 |         | (3,948                   | )         |      |         |          |           |   |         |          |          
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |           |          
|                                                                  |                                       | Total costs and expenses        |         |                          | 4,063,424 |      |         |           | 3,071,916 |   |         |           | 3,404,622 | 
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|                                                                  |                                       | Operating income                |         |                          | 192,408   |      |         |           | 170,247   |   |         |           | 151,791   | 
|Interest expense  net                                            |                                       |                                 | (84,250 | )                        |           |      | (66,192 | )         |           |   | (62,057 | )        
|Equity earnings                                                   |                                       |                                 | 16,863  |                          |           |      | 11,980  |           |           |   | 17,398  |          
|Other income  net                                                |                                       |                                 | 748     |                          |           |      | 1,827   |           |           |   | 2,799   |          
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|                                                                  |                                       | Income before minority interest |         |                          | 125,769   |      |         |           | 117,862   |   |         |           | 109,931   | 
|Minority interest                                                 |                                       |                                 |        |                          |           |      |        |           |           |   | (800    | )        
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |           |          
|                                                                  |                                       | Net income                      |         | $                        | 125,769   |      |         | $         | 117,862   |   |         | $         | 109,131   | 
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|Net Income Allocation:                                            |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|Limited Partner Unitholders                                       |                                       | $                               | 89,191  |                          |           | $    | 81,238  |           |           | $ | 76,986  |          
|Class B Unitholder                                                |                                       |                                 | 1,806   |                          |           |      | 6,943   |           |           |   | 8,642   |          
|General Partner                                                   |                                       |                                 | 34,772  |                          |           |      | 29,681  |           |           |   | 23,503  |          
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |           |          
|                                                                  |                                       | Total net income allocated      |         | $                        | 125,769   |      |         | $         | 117,862   |   |         | $         | 109,131   | 
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|Basic and diluted net income per Limited
Partner and Class B Unit |                                       | $                               | 1.52    |                          |           | $    | 1.79    |           |           | $ | 2.18    |          
|                                                                  |                                       |                                 |         |                          |           |      |         |           |           |   |         |          
|Weighted average Limited Partner and Class B
Units outstanding    |                                       |                                 | 59,765  |                          |           |      | 49,202  |           |           |   | 39,258  |          

See accompanying Notes to Consolidated Financial Statements.

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##### Table of Contents



TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |          |         |          |  
|---------------------------------------------------- | ----------------------------------------------------------------------------- | ------------------------------------------------------------ | --------------------------------------------------- | -------- | ------------------------ | -------- | ------ | -------- | ------- | -------- | ------ | -------- | ------- | -------- | -
|                                                     |                                                                               |                                                              |                                                     |          | Years Ended December 31,
|                                                     |                                                                               |                                                              |                                                     |          |                         
|                                                     |                                                                               |                                                              |                                                     |          | 2003                     |          | 2002   |          | 2001   
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |        
|Cash flows from operating activities:                |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     | Net income                                                                    |                                                              | $                                                   | 125,769  |                          |          | $      | 117,862  |         |          | $      | 109,131  |        
|                                                     | Adjustments to reconcile net income to cash provided by
operating activities: |                                                              |                                                     |          |                          |          |        |          |         |          |        |          |        
|                                                     |                                                                               | Depreciation and amortization                                |                                                     |          | 100,728                  |          |        |          | 86,032  |          |        |          | 45,899  |         
|                                                     |                                                                               | Earnings in equity investments, net of distributions         |                                                     |          | 11,140                   |          |        |          | 18,401  |          |        |          | 14,377  |         
|                                                     |                                                                               | Gain on sale of assets                                       |                                                     |          | (3,948                   | )        |        |          |        |          |        |          |        |         
|                                                     |                                                                               | Non-cash portion of interest expense                         |                                                     |          | 4,793                    |          |        |          | 4,916   |          |        |          | 4,053   |         
|                                                     |                                                                               | Decrease (increase) in accounts receivable                   |                                                     |          | (100,085                 | )        |        |          | (50,313 | )        |        |          | 81,190  |         
|                                                     |                                                                               | Decrease (increase) in inventories                           |                                                     |          | (956                     | )        |        |          | 2,139   |          |        |          | 7,541   |         
|                                                     |                                                                               | Increase in other current assets                             |                                                     |          | (953                     | )        |        |          | (16,263 | )        |        |          | (8,082  | )       
|                                                     |                                                                               | Increase (decrease) in accounts payable and accrued expenses |                                                     |          | 100,757                  |          |        |          | 68,805  |          |        |          | (71,757 | )       
|                                                     |                                                                               | Other                                                        |                                                     |          | 2,109                    |          |        |          | 3,338   |          |        |          | (13,204 | )       
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |          |        
|                                                     |                                                                               |                                                              | Net cash provided by operating activities           |          |                          | 239,354  |        |          |         | 234,917  |        |          |         | 169,148  |  
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Cash flows from investing activities:                |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     | Proceeds from the sale of assets                                              |                                                              |                                                     | 8,531    |                          |          |        | 3,380    |         |          |        | 1,300    |        
|                                                     | Proceeds from cash investments                                                |                                                              |                                                     | 750      |                          |          |        |         |         |          |        | 4,236    |        
|                                                     | Purchase of crude oil assets                                                  |                                                              |                                                     | (27,469  | )                        |          |        |         |         |          |        | (31,000  | )      
|                                                     | Purchase of Val Verde Gathering System                                        |                                                              |                                                     |         |                          |          |        | (444,150 | )       |          |        |         |        
|                                                     | Purchase of Jonah Gas Gathering Company                                       |                                                              |                                                     |         |                          |          |        | (7,319   | )       |          |        | (359,834 | )      
|                                                     | Purchase of Chaparral NGL System                                              |                                                              |                                                     |         |                          |          |        | (132,372 | )       |          |        |         |        
|                                                     | Investment in Mont Belvieu Storage Partners, L.P.                             |                                                              |                                                     | (2,533   | )                        |          |        |         |         |          |        |         |        
|                                                     | Investment in Centennial Pipeline LLC                                         |                                                              |                                                     | (4,000   | )                        |          |        | (10,882  | )       |          |        | (64,953  | )      
|                                                     | Acquisition of additional interest in Centennial Pipeline LLC                 |                                                              |                                                     | (20,000  | )                        |          |        |         |         |          |        |         |        
|                                                     | Capital expenditures                                                          |                                                              |                                                     | (140,517 | )                        |          |        | (133,372 | )       |          |        | (107,614 | )      
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     |                                                                               |                                                              | Net cash used in investing activities               |          |                          | (185,238 | )      |          |         | (724,715 | )      |          |         | (557,865 | )
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Cash flows from financing activities:                |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     | Proceeds from revolving credit facilities                                     |                                                              |                                                     | 382,000  |                          |          |        | 675,000  |         |          |        | 546,148  |        
|                                                     | Issuance of Limited Partner Units, net                                        |                                                              |                                                     | 287,506  |                          |          |        | 372,506  |         |          |        | 234,660  |        
|                                                     | Issuance of Senior Notes                                                      |                                                              |                                                     | 198,570  |                          |          |        | 497,805  |         |          |        |         |        
|                                                     | Proceeds from termination of interest rate swaps                              |                                                              |                                                     |         |                          |          |        | 44,896   |         |          |        |         |        
|                                                     | Repayments on revolving credit facilities                                     |                                                              |                                                     | (604,000 | )                        |          |        | (943,659 | )       |          |        | (291,490 | )      
|                                                     | Repurchase and retirement of Class B Units                                    |                                                              |                                                     | (113,814 | )                        |          |        |         |         |          |        |         |        
|                                                     | Debt issuance costs                                                           |                                                              |                                                     | (3,381   | )                        |          |        | (7,025   | )       |          |        | (2,601   | )      
|                                                     | General Partners contributions                                               |                                                              |                                                     | 2        |                          |          |        | 7,617    |         |          |        | 4,795    |        
|                                                     | Distributions paid                                                            |                                                              |                                                     | (202,498 | )                        |          |        | (151,853 | )       |          |        | (104,412 | )      
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     |                                                                               |                                                              | Net cash (used in) provided by financing activities |          |                          | (55,615  | )      |          |         | 495,287  |        |          |         | 387,100  |  
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Net increase (decrease) in cash and cash equivalents |                                                                               |                                                              | (1,499                                              | )        |                          |          | 5,489  |          |         |          | (1,617 | )       
|Cash and cash equivalents at beginning of period     |                                                                               |                                                              | 30,968                                              |          |                          |          | 25,479 |          |         |          | 27,096 |         
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Cash and cash equivalents at end of period           |                                                                               | $                                                            | 29,469                                              |          |                          | $        | 30,968 |          |         | $        | 25,479 |         
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Non-cash investing activities:                       |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     | Net assets transferred to Mont Belvieu Storage Partners, L.P.                 |                                                              | $                                                   | 61,408   |                          |          | $      |         |         |          | $      |         |        
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|Supplemental disclosure of cash flows:               |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         
|                                                     | Cash paid for interest (net of amounts capitalized)                           |                                                              | $                                                   | 79,930   |                          |          | $      | 48,908   |         |          | $      | 61,458   |        
|                                                     |                                                                               |                                                              |                                                     |          |                          |          |        |          |         |          |        |         

See accompanying Notes to Consolidated Financial Statements.

F-5



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##### Table of Contents



TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(in thousands, except Unit amounts)

|                                       |                                                                 |  |             |            |           |   |           |         |               |   |           |          |             |   |         |         |   |   |           |          |  
|-------------------------------------- | --------------------------------------------------------------- |  | ----------- | ---------- | --------- | - | --------- | ------- | ------------- | - | --------- | -------- | ----------- | - | ------- | ------- | - | - | --------- | -------- | -
|                                       |                                                                 |  | Outstanding |            |           |   |           |         |               |   |           |          | Accumulated |   |         |         |  
|                                       |                                                                 |  | Limited     |            | General   |   | Limited   |         | Other         |   |           |          |            
|                                       |                                                                 |  | Partner     |            | Partners |   | Partners |         | Comprehensive |   |           |          |            
|                                       |                                                                 |  | Units       |            | Interest  |   | Interests |         | Loss          |   | Total    
|                                       |                                                                 |  |             |            |           |   |           |         |               |   |          
|Partners capital at December 31, 2000 |                                                                 |  | 32,700,000  |            |           | $ | 1,824     |         |               | $ | 313,233   |          |             | $ |        |         |   | $ | 315,057   |         
|                                       | Capital contributions                                           |  |             |           |           |   |           | 4,795   |               |   |           |         |             |   |         |        |   |   |           | 4,795    |  
|                                       | Issuance of Limited Partner Units, net                          |  |             | 7,750,000  |           |   |           |        |               |   |           | 234,660  |             |   |         |        |   |   |           | 234,660  |  
|                                       | Minority interest restructured                                  |  |             |           |           |   |           | 4,598   |               |   |           |         |             |   |         |        |   |   |           | 4,598    |  
|                                       | Cumulative effect of accounting change                          |  |             |           |           |   |           |        |               |   |           |         |             |   |         | (10,103 | ) |   |           | (10,103  | )
|                                       | Net loss on cash flow hedge                                     |  |             |           |           |   |           |        |               |   |           |         |             |   |         | (10,221 | ) |   |           | (10,221  | )
|                                       | 2001 net income allocation                                      |  |             |           |           |   |           | 23,503  |               |   |           | 76,986   |             |   |         |        |   |   |           | 100,489  |  
|                                       | 2001 cash distributions                                         |  |             |           |           |   |           | (21,530 | )             |   |           | (73,961  | )           |   |         |        |   |   |           | (95,491  | )
|                                       | Option exercises, net of Unit
repurchases                       |  |             |           |           |   |           |        |               |   |           | (603     | )           |   |         |        |   |   |           | (603     | )
|                                       |                                                                 |  |             |            |           |   |           |         |               |   |           |          |             |   |         |         |   |   |           |         
|Partners capital at December 31, 2001 |                                                                 |  | 40,450,000  |            |           |   | 13,190    |         |               |   | 550,315   |          |             |   | (20,324 | )       |   |   | 543,181   |         
|                                       | Capital contributions                                           |  |             |           |           |   |           | 7,568   |               |   |           |         |             |   |         |        |   |   |           | 7,568    |  
|                                       | Issuance of Limited Partner Units, net                          |  |             | 13,260,000 |           |   |           |        |               |   |           | 370,108  |             |   |         |        |   |   |           | 370,108  |  
|                                       | Net gain on cash flow hedge                                     |  |             |           |           |   |           |        |               |   |           |         |             |   |         | 269     |   |   |           | 269      |  
|                                       | 2002 net income allocation                                      |  |             |           |           |   |           | 29,681  |               |   |           | 81,238   |             |   |         |        |   |   |           | 110,919  |  
|                                       | 2002 cash distributions                                         |  |             |           |           |   |           | (37,718 | )             |   |           | (104,932 | )           |   |         |        |   |   |           | (142,650 | )
|                                       | Issuance of Limited Partner Units
upon exercise of options      |  |             | 99,597     |           |   |           | 49      |               |   |           | 2,398    |             |   |         |        |   |   |           | 2,447    |  
|                                       |                                                                 |  |             |            |           |   |           |         |               |   |           |          |             |   |         |         |   |   |           |         
|Partners capital at December 31, 2002 |                                                                 |  | 53,809,597  |            |           |   | 12,770    |         |               |   | 899,127   |          |             |   | (20,055 | )       |   |   | 891,842   |         
|                                       | Issuance of Limited Partner Units, net                          |  |             | 9,101,650  |           |   |           |        |               |   |           | 285,461  |             |   |         |        |   |   |           | 285,461  |  
|                                       | Retirement of Class B Units                                     |  |             |           |           |   |           |        |               |   |           | (10,993  | )           |   |         |        |   |   |           | (10,993  | )
|                                       | Net gain on cash flow hedge                                     |  |             |           |           |   |           |        |               |   |           |         |             |   |         | 16,164  |   |   |           | 16,164   |  
|                                       | Reclassification due to discontinued
portion of cash flow hedge |  |             |           |           |   |           |        |               |   |           |         |             |   |         | 989     |   |   |           | 989      |  
|                                       | 2003 net income allocation                                      |  |             |           |           |   |           | 34,772  |               |   |           | 89,191   |             |   |         |        |   |   |           | 123,963  |  
|                                       | 2003 cash distributions                                         |  |             |           |           |   |           | (54,725 | )             |   |           | (145,427 | )           |   |         |        |   |   |           | (200,152 | )
|                                       | Issuance of Limited Partner Units upon
exercise of options      |  |             | 87,307     |           |   |           | 2       |               |   |           | 2,045    |             |   |         |        |   |   |           | 2,047    |  
|                                       |                                                                 |  |             |            |           |   |           |         |               |   |           |          |             |   |         |         |   |   |           |         
|Partners capital at December 31, 2003 |                                                                 |  | 62,998,554  |            |           | $ | (7,181    | )       |               | $ | 1,119,404 |          |             | $ | (2,902  | )       |   | $ | 1,109,321 |         
|                                       |                                                                 |  |             |            |           |   |           |         |               |   |           |          |             |   |         |         |   |   |           |         

See accompanying Notes to Consolidated Financial Statements.

F-6



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##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

TEPPCO Partners, L.P. (the Partnership), a Delaware limited partnership,
is a master limited partnership formed in March 1990. We operate through TE
Products Pipeline Company, Limited Partnership (TE Products), TCTM, L.P.
(TCTM) and TEPPCO Midstream Companies, L.P. (TEPPCO Midstream).
Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the
Operating Partnerships. Texas Eastern Products Pipeline Company, LLC (the
Company or General Partner), a Delaware limited liability company, serves
as our general partner and owns a 2% general partner interest in us. The
General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC
(DEFS), a joint venture between Duke Energy Corporation (Duke Energy) and
ConocoPhillips. Duke Energy holds an interest of approximately 70% in DEFS,
and ConocoPhillips holds the remaining 30%. The Company, as general partner,
performs all management and operating functions required for us, except for the
management and operations of certain of the TEPPCO Midstream assets that are
managed by DEFS on our behalf. We reimburse the General Partner for all
reasonable direct and indirect expenses incurred in managing us.

As used in this Report, we, us, our, and the Partnership means
TEPPCO Partners, L.P. and, where the context requires, includes our
subsidiaries.

On July 26, 2001, the Company restructured its general partner ownership
of the Operating Partnerships to cause them to be indirectly wholly owned by
us. TEPPCO GP, Inc. (TEPPCO GP), our subsidiary, succeeded the Company as
general partner of the Operating Partnerships. All remaining partner interests
in the Operating Partnerships not already owned by us were transferred to us.
In exchange for this contribution, the Companys interest as our general
partner was increased to 2%. The increased percentage is the economic
equivalent of the aggregate interest that the Company had prior to the
restructuring through its combined interests in us and the Operating
Partnerships. As a result, we hold a 99.999% limited partner interest in the
Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.
This reorganization was undertaken to simplify required financial reporting by
the Operating Partnerships when the Operating Partnerships issue guarantees of
our debt.

At formation in 1990, we completed an initial public offering of
26,500,000 Units representing Limited Partner Interests (Limited Partner
Units) at $10.00 per Unit. In connection with our formation, 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 in a manner identical to Limited Partner Units and are
treated as Limited Partner Units for purposes of this Report. These Limited
Partner Units were assigned to Duke Energy when ownership of the Company was
transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership
Agreement, we have registered the resale by Duke Energy of such Limited Partner
Units with the Securities and Exchange Commission. As of December 31, 2003,
none of these Limited Partner Units had been sold by Duke Energy.

At December 31, 2003 and 2002, we had outstanding 62,998,554 and
53,809,597 Limited Partner Units, respectively. At December 31, 2002, we had
outstanding 3,916,547 Class B Limited Partner Units (Class B Units). All of
the Class B Units were issued to Duke Energy Transport and Trading Company, LLC
(DETTCO) in connection with an acquisition of assets initially acquired in
the Upstream Segment in 1998. The Class B Units shared in income and
distributions on the same basis as the Limited Partner Units, but they were not
listed on the New York Stock Exchange. The Class B Units were not included in
partners capital at December 31, 2002, as the Class B Units could have been
converted into Limited Partner Units upon approval by the unitholders. We had
the option to seek approval for the conversion of the Class B Units into
Limited Partner Units; however, if the conversion was denied, DETTCO, as holder
of the Class B Units, would have had the right to sell them to us at 95.5% of
the 20-day average market closing price of the Limited Partner Units, as
determined under our Partnership Agreement. On April 2, 2003, we repurchased
and retired all of the 3,916,547 previously outstanding Class B Units with
proceeds from the issuance of additional Limited Partner Units (see Note 12.
Partners Capital and Distributions). Collectively, the Limited Partner Units
and Class B Units are referred to as Units.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We adhere to the following significant accounting policies in the
preparation of our consolidated financial statements.

Basis of Presentation and Principles of Consolidation

The financial statements include our accounts on a consolidated basis. The
Companys 1% general partner interest in the Operating Partnerships, prior to
July 26, 2001, is accounted for as a minority interest. We have eliminated all
significant intercompany items in consolidation. We have reclassified certain
amounts from prior periods to conform with the current presentation.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires our 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.

Business Segments

We operate and report in three business segments: transportation and
storage of refined products, liquefied petroleum gases (LPGs) and
petrochemicals (Downstream Segment); gathering, transportation, marketing and
storage of crude oil and distribution of lubrication oils and specialty
chemicals (Upstream Segment); and gathering of natural gas, fractionation of
natural gas liquids (NGLs) and transportation of NGLs (Midstream Segment).
Our reportable segments offer different products and services and are managed
separately because each requires different business strategies.

Effective January 1, 2002, we realigned our three business segments to
reflect our entry into the natural gas gathering business and the expanded
scope of our NGLs operations. We transferred the fractionation of NGLs, which
was previously reflected as part of the Downstream Segment, to the Midstream
Segment. The operation of the NGL pipelines, which was previously reflected as
part of the Upstream Segment, was also transferred to the Midstream Segment.
We have adjusted our period-to-period comparisons to conform with the current
presentation.

Our interstate transportation operations, including rates charged to
customers, are subject to regulations prescribed by the Federal Energy
Regulatory Commission (FERC). We refer to refined products, LPGs,
petrochemicals, crude oil, NGLs and natural gas in this Report, collectively,
as petroleum products or products.

Revenue Recognition

Our Downstream Segment revenues are earned from transportation and storage
of refined products and LPGs, intrastate transportation of petrochemicals, sale
of product inventory and other ancillary services. Transportation revenues are
recognized as products are delivered to customers. Storage revenues are
recognized upon receipt of products into storage and upon performance of
storage services. Terminaling revenues are recognized as products are
out-loaded. Revenues from the sale of product inventory are recognized when
the products are sold.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Our Upstream Segment revenues are earned from gathering, transportation,
marketing and storage of crude oil, and distribution of lubrication oils and
specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky
Mountain region. Revenues are also generated from trade documentation and
pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas.
Revenues are accrued at the time title to the product sold transfers to the
purchaser, which typically occurs upon receipt of the product by the purchaser,
and purchases are accrued at the time title to the product purchased transfers
to our crude oil marketing company, TEPPCO Crude Oil, L.P., which typically
occurs upon our receipt of the product. Revenues related to trade
documentation and pumpover fees are recognized as services are completed.

Except for crude oil purchased from time to time as inventory, our policy
is to purchase only crude oil for which we have a market to sell and to
structure sales contracts so that crude oil price fluctuations do not
materially affect the margin received. As we purchase crude oil, we establish
a margin by selling crude oil for physical delivery to third party users or by
entering into a future delivery obligation. Through these transactions, we
seek 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.

Our Midstream Segment revenues are earned from the gathering of natural
gas, fractionation of NGLs and transportation of NGLs. Gathering and
transportation revenues are recognized as natural gas or NGLs are delivered to
customers. Revenues are also earned from the sale of condensate liquid
extracted from the natural gas stream to an Upstream Segment marketing
affiliate. Fractionation revenues are recognized ratably over the contract
year as products are delivered to DEFS. We generally do not take title to the
natural gas gathered, NGLs transported or NGLs fractionated, with the exception
of inventory imbalances discussed in Natural Gas Imbalances. Therefore, the
results of our Midstream Segment are not directly affected by changes in the
prices of natural gas or NGLs.

Cash and Cash Equivalents

Cash equivalents are defined as all highly marketable securities with
maturities of three months or less when purchased. The carrying value of cash
and cash equivalents approximate fair value because of the short term nature of
these investments.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine
that we will not collect all or part of the outstanding balance.
Collectibility is reviewed regularly and an allowance is established or
adjusted, as necessary, using the specific identification method. The
following table presents the activity of our allowance for doubtful accounts
for the years ended December 31, 2003, 2002 and 2001 (in thousands):

|                               |                          |   |                          |       |      |   |       |       |  |   |       |       | 
|------------------------------ | ------------------------ | - | ------------------------ | ----- | ---- | - | ----- | ----- |  | - | ----- | ----- | 
|                               |                          |   | Years Ended December 31,
|                               |                          |   |                         
|                               |                          |   | 2003                     |       | 2002 |   | 2001 
|                               |                          |   |                          |       |      |   |      
|Balance at beginning of period |                          | $ | 4,608                    |       |      | $ | 4,422 |       |  | $ |      |      
|Charges to expense             |                          |   | 793                      |       |      |   | 325   |       |  |   | 4,422 |      
|Deductions and other           |                          |   | (701                     | )     |      |   | (139  | )     |  |   |      |      
|                               |                          |   |                          |       |      |   |       |       |  |   |       |      
|                               | Balance at end of period |   | $                        | 4,700 |      |   | $     | 4,608 |  |   | $     | 4,422 | 
|                               |                          |   |                          |       |      |   |       |       |  |   |       |      

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Inventories

Inventories consist primarily of petroleum products and crude oil which
are valued at the lower of cost (weighted average cost method) or market. Our
Downstream Segment acquires and disposes of various products under exchange
agreements. Receivables and payables arising from these transactions are
usually satisfied with products rather than cash. The net balances of exchange
receivables and payables are valued at weighted average cost and included in
inventories. Inventories of materials and supplies, used for ongoing
replacements and expansions, are carried at the lower of fair value or cost.

Property, Plant and Equipment

We record property, plant and equipment at its acquisition cost.
Additions to property, plant and equipment, including major replacements or
betterments, are recorded at cost. We charge replacements and renewals of
minor items of property that do not materially increase values or extend useful
lives 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).

We evaluate impairment of long-lived assets in accordance with Statement
of Financial Accounting Standards (SFAS) No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Recoverability of the
carrying amount of assets to be held and used is measured by a comparison of
the carrying amount of the asset to future net cash flows expected to be
generated by the asset. If such assets are considered to be impaired, the
impairment to be recognized is measured by the amount by which the carrying
amount of the assets exceeds the fair value of the assets. Assets to be
disposed of are reported at the lower of the carrying amount or fair value less
costs to sell.

Capitalization of Interest

We capitalize interest on borrowed funds related to capital projects only
for periods that activities are in progress to bring these projects to their
intended use. The weighted average rate used to capitalize interest on borrowed
funds was 4.84%, 5.11% and 6.46% for the years ended December 31, 2003, 2002
and 2001, respectively. During the years ended December 31, 2003, 2002 and
2001, the amount of interest capitalized was $5.3 million, $4.3 million and
$4.0 million, respectively.

Intangible Assets

Intangible assets at December 31, 2003, consist primarily of gathering
contracts assumed in the acquisition of Jonah Gas Gathering System (Jonah) on
September 30, 2001, and the acquisition of Val Verde Gathering System (Val
Verde) on June 30, 2002, the fractionation agreement with DEFS and other
intangible assets (see Note 3. Goodwill and Other Intangible Assets).

In connection with the acquisitions of Jonah and Val Verde, we assumed
contracts that dedicate future production from natural gas wells in the Green
River Basin in Wyoming, and we assumed fixed-term contracts with customers that
gather coal bed methane (CBM) from the San Juan Basin in New Mexico and
Colorado, respectively (see Note 6. Acquisitions and Dispositions). The value
assigned to our intangible assets relates to contracts with customers that are
for either a fixed term or which dedicate total future lease production to the
gathering system. The value assigned to intangible assets is amortized on a
unit-of-production basis, based upon the actual throughput of the system over
the expected total throughput for the lives of the contracts. Due to our
recent expansions on the gathering systems at Jonah and because of certain
limited production forecasts obtained from producers on the Jonah system
related to the expansions, in the second quarter of 2003, we increased our
estimate of

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

future throughput on the Jonah system. This increase in the estimate of
future throughput extends the expected amortization period of Jonahs natural
gas gathering contracts from 16 years to approximately 25 years. The
amortization of the contracts related to the Val Verde system is expected to
average approximately 20 years. Further revisions to these estimates may occur
as additional production information is made available to us.

In connection with the purchase of the fractionation facilities in 1998,
we entered into a fractionation agreement with DEFS. The fractionation
agreement is being amortized over a period of 20 years, which is the term of
the agreement with DEFS (see Note 8. Related Party Transactions).

In connection with the acquisition of crude supply and transportation
assets in November 2003, we acquired intangible customer contracts for $8.5
million, which are amortized on a unit-of-production basis (see Note 6.
Acquisitions and Dispositions).

Goodwill

Goodwill represents the excess of purchase price over fair value of net
assets acquired and is presented on the consolidated balance sheets net of
accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill
and Other Intangible Assetswhich was issued by the Financial Accounting
Standards Board (FASB) in July 2001 (see Note 3. Goodwill and Other
Intangible Assets). SFAS 142 prohibits amortization of goodwill and intangible
assets with indefinite useful lives, but instead requires testing for
impairment at least annually. SFAS 142 requires that intangible assets with
definite useful lives be amortized over their respective estimated useful
lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we
no longer record amortization expense related to goodwill or amortization
expense related to the excess investment on our equity investment (equity
method goodwill).

Environmental Expenditures

We accrue 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 damages and other costs, when estimable. We
monitor the balance of accrued undiscounted environmental liabilities on a
regular basis. We record liabilities for environmental costs at a specific
site when our liability for such 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 our ultimate liabilities associated with environmental costs are
particularly difficult to make with certainty due to the number of variables
involved, including the early stage of investigation at certain sites, the
lengthy time frames required to complete remediation alternatives available and
the evolving nature of environmental laws and regulations.

The following table presents the activity of our environmental reserve for
the years ended December 31, 2003, 2002 and 2001 (in thousands):

|                                  |                          |   |                          |       |      |   |        |       |  |   |        |       | 
|--------------------------------- | ------------------------ | - | ------------------------ | ----- | ---- | - | ------ | ----- |  | - | ------ | ----- | 
|                                  |                          |   | Years Ended December 31,
|                                  |                          |   |                         
|                                  |                          |   | 2003                     |       | 2002 |   | 2001  
|                                  |                          |   |                          |       |      |   |       
|Balance at beginning of period    |                          | $ | 7,693                    |       |      | $ | 6,434  |       |  | $ | 3,648  |      
|Additions related to acquisitions |                          |   |                         |       |      |   |       |       |  |   | 300    |      
|Charges to expense                |                          |   | 6,824                    |       |      |   | 5,785  |       |  |   | 8,691  |      
|Deductions and other              |                          |   | (6,878                   | )     |      |   | (4,526 | )     |  |   | (6,205 | )    
|                                  |                          |   |                          |       |      |   |        |       |  |   |        |      
|                                  | Balance at end of period |   | $                        | 7,639 |      |   | $      | 7,693 |  |   | $      | 6,434 | 
|                                  |                          |   |                          |       |      |   |        |       |  |   |        |      

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Natural Gas Imbalances

Gas imbalances occur when gas producers (customers) deliver more or less
actual natural gas gathering volumes to our gathering systems than they
originally nominated. Actual deliveries are different from nominated volumes
due to fluctuations in gas production at the wellhead. If the customers supply
more natural gas gathering volumes than they nominated, Val Verde and Jonah
record a payable for the amount due to customers and also record a receivable
for the same amount due from connecting pipeline transporters or shippers. If
the customers supply less natural gas gathering volumes than they nominated,
the Val Verde and the Jonah systems record a receivable reflecting the amount
due from customers and a payable for the same amount due to connecting pipeline
transporters or shippers. We record natural gas imbalances using a
mark-to-market approach.

Income Taxes

We are a limited partnership. As such, we are not a taxable entity for
federal and state income tax purposes and do not directly pay federal and state
income tax. Our taxable income or loss, which may vary substantially from the
net income or net loss we report in our consolidated statements of income, is
includable in the federal and state income tax returns of each unitholder.
Accordingly, no recognition has been given to federal income taxes for our
operations. The aggregate difference in the basis of our net assets for
financial and tax reporting purposes cannot be readily determined as we do not
have access to information about each unitholders tax attributes in the
Partnership.

Use of Derivatives

We account for derivative financial instruments in accordance with SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities,and SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of FASB Statement No. 133.These statements establish
accounting and reporting standards requiring that derivative instruments
(including certain derivative instruments embedded in other contracts) be
recorded on the balance sheet at fair value as either assets or liabilities.
The accounting for changes in the fair value of a derivative instrument depends
on the intended use of the derivative and the resulting designation, which is
established at the inception of a derivative.

We adopted SFAS 133 at January 1, 2001, which resulted in the recognition
of approximately $10.1 million of derivative liabilities, $4.1 million of which
were current liabilities and $6.0 million of which were noncurrent liabilities,
and $10.1 million of hedging losses included in accumulated other comprehensive
income, a component of partners capital, as the cumulative effect of the
change in accounting. The hedging losses included in accumulated other
comprehensive loss are transferred to earnings as the forecasted transactions
actually occur. Amounts determined as of January 1, 2001, were based on the
market quote of our interest swap agreement in place at the time of adoption.

Our derivative instruments consist primarily of interest rate swaps and
contracts for the purchase and sale of petroleum products in connection with
our crude oil marketing activities. Substantially all derivative instruments
related to our crude oil marketing activities meet the normal purchases and
sales criteria of SFAS 133, as amended, and as such, changes in the fair value
of petroleum product purchase and sales agreements are reported on the accrual
basis of accounting. SFAS 133 describes normal purchases and sales as
contracts that provide for the purchase or sale of something other than a
financial instrument or derivative instrument that will be delivered in
quantities expected to be used or sold by the reporting entity over a
reasonable period in the normal course of business.

For all hedging relationships, we formally document at inception the
hedging relationship and its risk-management objective and strategy for
undertaking the hedge, the hedging instrument, the item, the nature of the risk
being hedged, how the hedging instruments effectiveness in offsetting the
hedged risk will be assessed and a

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

description of the method of measuring ineffectiveness. This process
includes linking all derivatives that are designated as fair value or cash flow
to specific assets and liabilities on the balance sheet or to specific firm
commitments or forecasted transactions. We also formally assess, both at the
hedges inception and on an ongoing basis, whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in fair
values or cash flows of hedged items. If it is determined that a derivative is
not highly effective as a hedge or that it has ceased to be a highly effective
hedge, we discontinue hedge accounting prospectively.

For derivative instruments designated as fair value hedges, gains and
losses on the derivative instrument are offset against related results on the
hedged item in the statement of income. Changes in the fair value of a
derivative that is highly effective and that is designated and qualifies as a
fair value hedge, along with the loss or gain on the hedged asset or liability
or unrecognized firm commitment of the hedged item that is attributable to the
hedged risk, are recorded in earnings. Changes in the fair value of a
derivative that is highly effective and that is designated and qualifies as a
cash flow hedge are recorded in other comprehensive income to the extent that
the derivative is effective as a hedge, until earnings are affected by the
variability in cash flows of the designated hedged item. Hedge effectiveness is
measured at least quarterly based on the relative cumulative changes in fair
value between the derivative contract and the hedged item over time. The
ineffective portion of the change in fair value of a derivative instrument that
qualifies as either a fair value hedge or a cash flow hedge is reported
immediately in earnings.

According to SFAS 133, as amended, we are required to discontinue hedge
accounting prospectively when it is determined that the derivative is no longer
effective in offsetting changes in the fair value or cash flows of the hedged
item, the derivative expires or is sold, terminated, or exercised, the
derivative is dedesignated as a hedging instrument, because it is unlikely that
a forecasted transaction will occur, a hedged firm commitment no longer meets
the definition of a firm commitment, or management determines that designation
of the derivative as a hedging instrument is no longer appropriate.

When hedge accounting is discontinued because it is determined that the
derivative no longer qualifies as an effective fair value hedge, we continue to
carry the derivative on the balance sheet at its fair value and no longer
adjust the hedged asset or liability for changes in fair value. The adjustment
of the carrying amount of the hedged asset or liability is accounted for in the
same manner as other components of the carrying amount of that asset or
liability. When hedge accounting is discontinued because the hedged item no
longer meets the definition of a firm commitment, we continue to carry the
derivative on the balance sheet at its fair value, remove any asset or
liability that was recorded pursuant to recognition of the firm commitment from
the balance sheet, and recognize any gain or loss in earnings. When hedge
accounting is discontinued because it is probable that a forecasted transaction
will not occur, we continue to carry the derivative on the balance sheet at its
fair value with subsequent changes in fair value included in earnings, and
gains and losses that were accumulated in other comprehensive income are
recognized immediately in earnings. In all other situations in which hedge
accounting is discontinued, we continue to carry the derivative at its fair
value on the balance sheet and recognize any subsequent changes in its fair
value in earnings.

Net Income Per Unit

Basic net income per Unit is computed by dividing net income, after
deduction of the General Partners interest, by the weighted average number of
Limited Partner and Class B Units outstanding (a total of 59.8 million Units,
49.2 million Units and 39.3 million Units for the years ended December 31,
2003, 2002 and 2001, respectively). The General Partners percentage interest
in our net income is based on its percentage of cash distributions from
Available Cash for each year (see Note 12. Partners Capital and
Distributions). The General Partner was allocated $34.8 million (representing
27.65%) of net income for the year ended December 31, 2003, $29.7 million
(representing 25.18%) of net income for the year ended December 31, 2002, and
$23.5 million (representing 21.54%) of net income for the year ended December
31, 2001. The General Partners percentage interest in our net income
increases as cash distributions paid per Unit increase, according to our
Partnership Agreement.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Diluted net income per Unit is similar to the computation of basic net
income per Unit, except that the denominator is increased to include the
dilutive effect of outstanding Unit options by application of the treasury
stock method. For the years ended December 31, 2003, 2002 and 2001, the
denominator was increased by 11,878 Units, 32,053 Units and 41,864 Units,
respectively. During the third quarter of 2003, all remaining outstanding Unit
options were exercised (see Note 14. Unit-Based Compensation).

Unit Option Plan

We have not granted options for any periods presented. For options
outstanding under the 1994 Long Term Incentive Plan (see Note 14. Unit-Based
Compensation), we followed the intrinsic value method of accounting for
recognizing stock-based compensation expense. Under this method, we record no
compensation expense for Unit options granted when the exercise price of the
options granted is equal to, or greater than, the market price of our Units on
the date of the grant. During the year ended December 31, 2003, all remaining
outstanding Unit options were exercised.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation 
Transition and Disclosurewas issued. SFAS 148 amends SFAS No. 123, Accounting
for Stock-Based Compensation, and provides alternative methods of transition
for a voluntary change to the fair value based method of accounting for
stock-based employee compensation. In addition, SFAS 148 amends the disclosure
requirements of SFAS 123 to require prominent disclosure in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results.
Certain of the disclosure modifications are required for fiscal years ending
after December 15, 2002, and are included in Note 14. Unit-Based Compensation.

Assuming we had used the fair value method of accounting for our Unit
option plan, pro forma net income for the years ended December 31, 2002 and
2001, would be lower than reported net income by an immaterial amount. Pro
forma net income would equal reported net income for the year ended December
31, 2003. Pro forma net income per Unit would equal reported net income per
Unit for the periods presented. The adoption of SFAS 148 did not have an
effect on our financial position, results of operations or cash flows.

New Accounting Pronouncements

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation
of Variable Interest Entities, an interpretation of ARB No. 51(FIN 46). FIN
46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. We are required
to apply FIN 46 to all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, we were required to apply FIN 46 on July 1, 2003. In
connection with the adoption of FIN 46, we evaluated our investments in
Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage
Partners, L.P. and determined that these entities are not variable interest
entities as defined by FIN 46, and thus we have accounted for them as equity
method investments (see Note 7. Equity Investments). The adoption of FIN 46
did not have an effect on our financial position, results of operations or cash
flows.

In December 2003, the FASB revised FIN 46. The revised statement, FASB
Interpretation No. 46(R), Consolidation of Variable Interest Entities, an
interpretation of ARB No. 51(FIN 46(R)) clarifies some of the requirements
of FIN 46, eases some implementation problems that companies experienced
implementing FIN 46, adds new scope exceptions and makes the probability more
likely for many companies that potential variable interest entities will be
identified and consolidated. We are required to apply the new requirements
detailed in FIN 46(R) as of March 31, 2004. We are evaluating our investments
in Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu
Storage Partners, L.P. to determine the impact, if any, of the adoption of FIN

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

46(R). We do not believe the adoption of FIN 46(R) will have a material effect
on our financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. SFAS 149 amends SFAS 133 to
conform and incorporate derivative implementation issues and subsequently
issued accounting guidance. SFAS 149 clarifies under what circumstances a
contract with an initial net investment meets the characteristics of a
derivative, clarifies when a derivative contains a financing component, amends
the definition of an underlying to conform it to language used in FASB
Interpretation No. 45, Guarantors Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Othersand amends
certain other existing pronouncements. SFAS 149 is effective for contracts
entered into or modified after June 30, 2003, and should be applied
prospectively. However, certain SFAS 133 implementation issues that were
effective for all fiscal quarters prior to June 15, 2003, should continue to be
applied in accordance with their respective effective dates. We adopted SFAS
149 effective July 1, 2003. The adoption of SFAS 149 did not have an effect on
our financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
SFAS 150 establishes standards for how an issuer classifies and measures
certain freestanding financial instruments with characteristics of both
liabilities and equity. SFAS 150 requires that an issuer classify a financial
instrument that is within its scope as a liability (or asset in some
circumstances). We adopted SFAS 150 effective July 1, 2003. The adoption of
SFAS 150 did not have an effect on our financial position, results of
operations or cash flows.

In May 2003, the EITF reached consensus in EITF 01-08, Determining Whether
an Arrangement Contains a Lease, to clarify the requirements of identifying
whether an arrangement should be accounted for as a lease at its inception.
The guidance in the consensus is designed to mandate reporting revenue as
rental or leasing income that otherwise would be reported as part of product
sales or service revenue. EITF 01-08 requires both parties in an arrangement
to determine whether a service contract or similar arrangement is or includes a
lease within the scope of SFAS No. 13, Accounting For Leases. We have
historically leased storage capacity to outside parties and entered into
pipeline capacity lease agreements both as the lessee and as the lessor. The
accounting requirements under the consensus affect the timing of revenue and
expense recognition, and revenues reported as transportation and storage
services might have to be reported as rental or leasing income. Should
capital-lease treatment be necessary, purchasers of transportation and storage
services in the arrangements would have to recognize new assets on their
balance sheets. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning after May 28, 2003. Previous arrangements that would be leases or
would contain a lease according to the consensus will continue to be accounted
for as transportation and storage purchases or sales arrangements. As we enter
into new arrangements, we will assess the impact of EITF 01-08 on the
arrangement. The adoption of EITF 01-08 did not have a material effect on our
financial position, results of operations or cash flows.

In July 2003, the EITF reached consensus in EITF 03-11, Reporting Gains
and Losses on Derivative Instruments That Are Subject to FASB Statement No.
133, Accounting for Derivative Instruments and Hedging Activities, and Not Held
for Trading Purposes. In a 2002 Issue, the EITF reached a consensus that all
gains and losses (realized and unrealized) on derivative instruments within the
scope of SFAS 133 should be shown net in the income statement, whether or not
settled physically, if the derivative instruments are held for trading
purposes. However, the EITF recognized that there may be contracts within the
scope of SFAS 133 considered not held for trading purposes that warrant further
consideration as to the appropriate income statement classification of the
gains and losses. In EITF 03-11, the EITF clarified certain criteria to use in
determining whether gains and losses related to non-trading derivative
instruments should be shown net in the income statement. The adoption of EITF
03-11 did not have a material effect on our financial position, results of
operations or cash flows.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

On December 8, 2003, President Bush signed into a law a bill that expands
Medicare, primarily adding a prescription drug benefit for Medicare-eligible
retirees starting in 2006. We anticipate that the benefits we pay after 2006
could be lower as a result of the new Medicare provisions; however, at this
time the retiree medical obligations and costs reported do not reflect any
changes as a result of this legislation. Deferring the recognition of the new
Medicare provisions impact is permitted by FASB Staff Position 106-1,
Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003,due to open questions about
some of the new Medicare provisions and a lack of authoritative accounting
guidance about certain matters. The final accounting guidance could require
changes to previously reported information. We do not believe that this
regulation will have a material adverse effect on our financial position,
results of operations or cash flows.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of purchase price over fair value of net
assets acquired and is presented on the consolidated balance sheets net of
accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill
and Other Intangible Assets,which was issued by the FASB in July 2001. SFAS
142 prohibits amortization of goodwill and intangible assets with indefinite
useful lives, but instead requires testing for impairment at least annually.

Beginning January 1, 2002, effective with the adoption of SFAS 142, we no
longer record amortization expense related to goodwill or amortization expense
related to the excess investment on our equity investment in Seaway Crude
Pipeline Company (see Note 7. Equity Investments). The following table
presents our results on a comparable basis, as if we had not recorded
amortization expense of goodwill or amortization expense of our excess
investment in Seaway Crude Pipeline Company for the years ended December 31,
2003, 2002 and 2001 (in thousands, except per Unit amounts):

|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |         |         | 
|------------------------------------------------------------------ | ---------------------------------------------- | ---------------------------- | - | ------------------------ | ------- | ---- | - | ------- | ------- |  | - | ------- | ------- | 
|                                                                   |                                                |                              |   | Years Ended December 31,
|                                                                   |                                                |                              |   |                         
|                                                                   |                                                |                              |   | 2003                     |         | 2002 |   | 2001   
|                                                                   |                                                |                              |   |                          |         |      |   |        
|Net income:                                                        |                                                |                              |   |                          |         |      |   |         |         |  |   |        
|                                                                   | Reported net income                            |                              | $ | 125,769                  |         |      | $ | 117,862 |         |  | $ | 109,131 |        
|                                                                   | Amortization of goodwill and excess investment |                              |   |                         |         |      |   |        |         |  |   | 2,396   |        
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |         |        
|                                                                   |                                                | Adjusted net income          |   | $                        | 125,769 |      |   | $       | 117,862 |  |   | $       | 111,527 | 
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |        
|Net income allocation:                                             |                                                |                              |   |                          |         |      |   |         |         |  |   |        
|                                                                   | Limited Partner Unitholders                    |                              | $ | 89,191                   |         |      | $ | 81,238  |         |  | $ | 78,676  |        
|                                                                   | Class B Unitholder                             |                              |   | 1,806                    |         |      |   | 6,943   |         |  |   | 8,832   |        
|                                                                   | General Partner                                |                              |   | 34,772                   |         |      |   | 29,681  |         |  |   | 24,019  |        
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |         |        
|                                                                   |                                                | Total net income allocated   |   | $                        | 125,769 |      |   | $       | 117,862 |  |   | $       | 111,527 | 
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |        
|Basic and diluted net income per Limited
Partner and Class B Unit: |                                                |                              |   |                          |         |      |   |         |         |  |   |        
|                                                                   | As reported                                    |                              | $ | 1.52                     |         |      | $ | 1.79    |         |  | $ | 2.18    |        
|                                                                   | Amortization of goodwill and excess investment |                              |   |                         |         |      |   |        |         |  |   | 0.05    |        
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |         |        
|                                                                   |                                                | Adjusted net income per Unit |   | $                        | 1.52    |      |   | $       | 1.79    |  |   | $       | 2.23    | 
|                                                                   |                                                |                              |   |                          |         |      |   |         |         |  |   |        

In connection with the transitional goodwill impairment evaluation
required by SFAS 142, we were required to perform an assessment of whether
there was an indication that goodwill was impaired as of the date of adoption.
We accomplished this by identifying our reporting units and determining the
carrying value of each

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

reporting unit by assigning the assets and liabilities, including the
existing goodwill and intangible assets, to those reporting units as of the
date of adoption. We then determined the fair value of each reporting unit and
compared it to the carrying value of the reporting unit. We completed this
analysis during the second quarter of 2002, resulting in no transitional
impairment loss. We will continue to compare the fair value of each reporting
unit to the carrying value on an annual basis to determine if an impairment
loss has occurred.

At December 31, 2003, we had $16.9 million of unamortized goodwill and
$25.5 million of excess investment in our equity investment in Seaway Crude
Pipeline Company (equity method goodwill). We completed an impairment analysis
of the excess investment in our equity investment during the year ended
December 31, 2003, and we noted no indication of impairment. The excess
investment is included in our equity investments account at December 31, 2003.
The following table presents the carrying amount of goodwill and equity method
goodwill at December 31, 2003, by business segment (in thousands):

|                       |  |            |   |           |  |          |       |          |  |   |        |  |  |   |        | 
|---------------------- |  | ---------- | - | --------- |  | -------- | ----- | -------- |  | - | ------ |  |  | - | ------ | 
|                       |  | Downstream |   | Midstream |  | Upstream |       | Segments
|                       |  | Segment    |   | Segment   |  | Segment  |       | Total   
|                       |  |            |   |           |  |          |       |         
|Goodwill               |  | $          |  |           |  | $        | 2,777 |          |  | $ | 14,167 |  |  | $ | 16,944 | 
|Equity method goodwill |  |            |  |           |  |          |      |          |  |   | 25,502 |  |  |   | 25,502 | 

Other Intangible Assets

The following table reflects the components of amortized intangible assets
at December 31, 2003 and 2002 (in thousands):

|                             |                                         |       |   |                   |         |                   |   |                |         |              |   |         |         |  |   |         |         |  
|---------------------------- | --------------------------------------- | ----- | - | ----------------- | ------- | ----------------- | - | -------------- | ------- | ------------ | - | ------- | ------- |  | - | ------- | ------- | -
|                             |                                         |       |   | December 31, 2003 |         | December 31, 2002
|                             |                                         |       |   |                   |         |                  
|                             |                                         |       |   | Gross Carrying    |         | Accumulated       |   | Gross Carrying |         | Accumulated 
|                             |                                         |       |   | Amount            |         | Amortization      |   | Amount         |         | Amortization
|                             |                                         |       |   |                   |         |                   |   |                |         |             
|Amortized intangible assets: |                                         |       |   |                   |         |                   |   |                |         |              |   |         |         |  |   |        
|                             | Gathering and transportation agreements |       | $ | 464,337           |         |                   | $ | (62,436        | )       |              | $ | 463,449 |         |  | $ | (28,818 | )      
|                             | Fractionation agreement                 |       |   | 38,000            |         |                   |   | (10,925        | )       |              |   | 38,000  |         |  |   | (9,025  | )      
|                             | Other                                   |       |   | 11,270            |         |                   |   | (1,681         | )       |              |   | 2,745   |         |  |   | (977    | )      
|                             |                                         |       |   |                   |         |                   |   |                |         |              |   |         |         |  |   |         |        
|                             |                                         | Total |   | $                 | 513,607 |                   |   | $              | (75,042 | )            |   | $       | 504,194 |  |   | $       | (38,820 | )
|                             |                                         |       |   |                   |         |                   |   |                |         |              |   |         |         |  |   |        

At December 31, 2003, we had $33.4 million of excess investment in our
equity investment in Centennial Pipeline LLC, which was created upon formation
of the company (see Note 7. Equity Investments). The excess investment is
included in our equity investments account at December 31, 2003. This excess
investment is accounted for as an intangible asset with an indefinite life. We
completed an impairment analysis of the excess investment in Centennial
Pipeline LLC during the year ended December 31, 2003, and we noted no
indication of impairment. We will assess the intangible asset for impairment
on an annual basis.

Upon the adoption of SFAS 142, we were required to reassess the useful
lives and residual values of all intangible assets acquired, and make necessary
amortization period adjustments by the end of the first interim period after
adoption. We completed this analysis during the year ended December 31, 2002,
resulting in no change to the amortization period for our intangible assets.
We will continue to reassess the useful lives and residual values of all
intangible assets on an annual basis.

SFAS 142 requires that intangible assets with finite useful lives be
amortized over their respective estimated useful lives. If an intangible asset
has a finite useful life, but the precise length of that life is not known,
that intangible asset shall be amortized over the best estimate of its useful
life. At a minimum, we will assess the useful lives and residual values of all
intangible assets on an annual basis to determine if adjustments are required.
With respect to our natural gas gathering contracts, we update throughput
estimates and evaluate the remaining

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

expected useful life of the contract assets on a quarterly basis based on the
best available information. Amortization expense on intangible assets was
$36.2 million, $27.9 million and $5.5 million for the years ended December 31,
2003, 2002 and 2001, respectively.

The value assigned to our intangible assets for natural gas gathering
contracts is amortized on a unit-of-production basis, based upon the actual
throughput of the system over the expected total throughput for the lives of
the contracts. Due to our recent expansions on the gathering systems at Jonah
and because of certain limited production forecasts obtained from producers on
the Jonah system related to the expansions, in the second quarter of 2003, we
increased our best estimate of future throughput on the Jonah system. This
increase in the estimate of future throughput extends the amortization period
of Jonahs natural gas gathering contracts by an estimated 9 years, increasing
from approximately 16 years to 25 years. Further revisions to this estimate
may occur as additional production information is made available to us.

The following table sets forth the estimated amortization expense on
intangible assets for the years ending December 31 (in thousands):

|     |  |   |       
|---- |  | - | ------
|2004 |  | $ | 35,146
|2005 |  |   | 40,614
|2006 |  |   | 37,882
|2007 |  |   | 35,005
|2008 |  |   | 32,688

NOTE 4. INTEREST RATE SWAPS

We have utilized and expect to continue to utilize interest rate swap
agreements to hedge a portion of our cash flow and fair value risks. Interest
rate swap agreements are used to manage the fixed and floating interest rate
mix of our total debt portfolio and overall cost of borrowing. The interest
rate swap related to our cash flow risk is intended to reduce our exposure to
increases in the benchmark interest rates underlying our variable rate
revolving credit facility. The interest rate swap related to our fair value
risk is intended to reduce our exposure to changes in the fair value of our
fixed rate Senior Notes. The interest rate swap agreements involve the
periodic exchange of payments without the exchange of the notional amount upon
which the payments are based. The related amount payable to or receivable from
counterparties is included as an adjustment to accrued interest.

By using interest rate swap agreements to hedge exposures to changes in
interest rates and the fair value of fixed rate Senior Notes, we are exposed to
credit risk and market risk. Credit risk is the failure of the counterparty to
perform under the terms of the derivative contract. When the fair value of a
derivative contract is positive, the counterparty owes us, which creates credit
risk for us. When the fair value of a derivative contract is negative, we owe
the counterparty and, therefore, we do not possess credit risk. We minimize
the credit risk in derivative instruments by entering into transactions with
major financial institutions. Market risk is the adverse effect on the value
of a financial instrument that results from a change in interest rates. We
manage market risk associated with interest rate contracts by establishing and
monitoring parameters that limit the type and degree of market risk that may be
undertaken.

We have entered into an interest rate swap agreement to hedge our exposure
to increases in the benchmark interest rate underlying our variable rate
revolving credit facility. This interest rate swap matures on April 6, 2004.
We designated this swap agreement, which hedges exposure to variability in
expected future cash flows attributed to changes in interest rates, as a cash
flow hedge. The swap agreement is based on a notional amount of $250.0 million.
Under the swap agreement, we pay a fixed rate of interest of 6.955% and
receive a floating rate based on a three-month U.S. Dollar LIBOR rate. Since
this swap is designated as a cash flow hedge, the changes in fair value, to the

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

extent the swap is effective, are recognized in other comprehensive income
until the hedged interest costs are recognized in earnings. On June 27, 2003,
we repaid the amounts outstanding under the revolving credit facility with
borrowings under a new three year revolving credit facility and canceled the
old facility (see Note 11. Debt). We redesignated this interest rate swap as
a hedge of our exposure to increases in the benchmark interest rate underlying
the new variable rate revolving credit facility. During the years ended
December 31, 2003, and 2002, we recognized increases in interest expense of
$14.4 million and $12.9 million, respectively, related to the difference
between the fixed rate and the floating rate of interest on the interest rate
swap.

During the year ended December 31, 2003, we determined that we would repay
a portion of the amount outstanding under the revolving credit facility,
established June 27, 2003, with proceeds from our Unit offering in August 2003
(see Note 12. Partners Capital and Distributions) resulting in a reduction of
probable future interest payments under the credit facility. As a result, we
measured and reclassified amounts previously accumulated in other comprehensive
income related to the discontinued portion of the hedge and recognized a loss
of $1.0 million, which has been included in interest expense. The total fair
value of the interest rate swap was a loss of approximately $3.9 million and
$20.1 million at December 31, 2003, and 2002, respectively. Losses recognized
in other comprehensive income of approximately $2.9 million related to the
portion of the interest rate swap hedging probable future interest payments
will be transferred into earnings over the remaining term of the interest rate
swap agreement. Changes in the fair value of the portion of the interest rate
swap related to the discontinued hedge will be recorded in earnings over the
remaining term of the interest rate swap.

On October 4, 2001, TE Products entered into an interest rate swap
agreement to hedge its exposure to changes in the fair value of its fixed rate
7.51% Senior Notes due 2028. We designated this swap agreement as a fair value
hedge. The swap agreement has a notional amount of $210.0 million and matures
in January 2028 to match the principal and maturity of the TE Products Senior
Notes. Under the swap agreement, TE Products pays a floating rate of interest
based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a
fixed rate of interest of 7.51%. During the years ended December 31, 2003, and
2002, we recognized reductions in interest expense of $10.0 million and $8.6
million, respectively, related to the difference between the fixed rate and the
floating rate of interest on the interest rate swap. During the quarter ended
December 31, 2003, we measured the hedge effectiveness of this interest rate
swap and noted that no gain or loss from ineffectiveness was required to be
recognized. The fair value of this interest rate swap was a gain of
approximately $2.3 million and $13.6 million at December 31, 2003, and 2002,
respectively.

On February 20, 2002, we entered into interest rate swap agreements,
designated as fair value hedges, to hedge our exposure to changes in the fair
value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had
a combined notional amount of $500.0 million and matured in 2012 to match the
principal and maturity of the Senior Notes. Under the swap agreements, we paid
a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread,
and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap
agreements were terminated resulting in a gain of approximately $18.0 million.
Concurrent with the swap terminations, we entered into new interest rate swap
agreements, with identical terms as the previous swap agreements; however, the
floating rate of interest was based upon a spread of an additional 50 basis
points. In December 2002, the swap agreements entered into on July 16, 2002,
were terminated, resulting in a gain of approximately $26.9 million. The gains
realized from the July 2002 and December 2002 swap terminations have been
deferred as adjustments to the carrying value of the Senior Notes and are being
amortized using the effective interest method as reductions to future interest
expense over the remaining term of the Senior Notes. At December 31, 2003, the
unamortized balance of the deferred gains was $40.6 million. In the event of
early extinguishment of the Senior Notes, any remaining unamortized gains would
be recognized in the consolidated statement of income at the time of
extinguishment.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

NOTE 5. ASSET RETIREMENT OBLIGATIONS

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS 143 requires us to record the fair value of an
asset retirement obligation as a liability in the period in which we incur a
legal obligation for the retirement of tangible long-lived assets. A
corresponding asset is also recorded and depreciated over the life of the
asset. After the initial measurement of the asset retirement obligation, the
liability will be adjusted at the end of each reporting period to reflect
changes in the estimated future cash flows underlying the obligation.
Determination of any amounts recognized upon adoption is based upon numerous
estimates and assumptions, including future retirement costs, future inflation
rates and the credit-adjusted risk-free interest rates.

The Downstream Segment assets consist primarily of an interstate trunk
pipeline system and a series of storage facilities that originate along the
upper Texas Gulf Coast and extend through the Midwest and northeastern United
States. We transport refined products, LPGs and petrochemicals through the
pipeline system. These products are primarily received in the south end of the
system and stored and/or transported to various points along the system per
customer nominations. The Upstream Segments operations include purchasing
crude oil from producers at the wellhead and providing delivery, storage and
other services to its customers. The properties in the Upstream Segment
consist of interstate trunk pipelines, pump stations, trucking facilities,
storage tanks and various gathering systems primarily in Texas and Oklahoma.
The Midstream Segment gathers natural gas from wells owned by producers and
transports natural gas and NGLs on its pipeline systems, primarily in Texas,
Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates
two NGL fractionator facilities in Colorado.

We have completed our assessment of SFAS 143, and we have determined that
we are obligated by contractual or regulatory requirements to remove facilities
or perform other remediation upon retirement of our assets. However, we are
not able to reasonably determine the fair value of the asset retirement
obligations for our trunk, interstate and gathering pipelines and our surface
facilities, since future dismantlement and removal dates are indeterminate.

In order to determine a removal date for our gathering lines and related
surface assets, reserve information regarding the production life of the
specific field is required. As a transporter and gatherer of crude oil and
natural gas, we are not a producer of the field reserves, and we therefore do
not have access to adequate forecasts that predict the timing of expected
production for existing reserves on those fields in which we gather crude oil
and natural gas. In the absence of such information, we are not able to make a
reasonable estimate of when future dismantlement and removal dates of our
gathering assets will occur. With regard to our trunk and interstate pipelines
and their related surface assets, it is impossible to predict when demand for
transportation of the related products will cease. Our right-of-way agreements
allow us to maintain the right-of-way rather than remove the pipe. In
addition, we can evaluate our trunk pipelines for alternative uses, which can
be and have been found.

We will record such asset retirement obligations in the period in which
more information becomes available for us to reasonably estimate the settlement
dates of the retirement obligations. The adoption of SFAS 143 did not have an
effect on our financial position, results of operations or cash flows.

NOTE 6. ACQUISITIONS AND DISPOSITIONS

Jonah Gas Gathering Company

On September 30, 2001, we completed the purchase of Jonah from Alberta
Energy Company for $359.8 million, with an additional payment of $7.3 million
made on February 4, 2002, for final purchase adjustments related primarily to
construction projects in progress at the time of closing. The acquisition
served as our entry into the natural gas gathering industry. We funded the
acquisition through a borrowing under a $400.0 million credit

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

facility with SunTrust Bank (see Note 11. Debt). We allocated the
purchase price, net of liabilities assumed, primarily to property, plant and
equipment and intangible assets for gas gathering contracts. We also
recognized goodwill on the purchase of approximately $2.8 million. We
accounted for the acquisition under the purchase method of accounting.
Accordingly, the results of operations of the acquisition have been included in
our consolidated financial statements from September 30, 2001. Under a
contractual agreement, DEFS manages and operates Jonah on our behalf.

The following table allocates the estimated fair value of Jonah assets
acquired on September 30, 2001, and includes the additional purchase adjustment
paid on February 4, 2002 (in thousands):

|                                                      |                     |   |         |         | 
|----------------------------------------------------- | ------------------- | - | ------- | ------- | 
|Property, plant and equipment                         |                     | $ | 141,835 |        
|Intangible assets (primarily gas gathering contracts) |                     |   | 222,800 |        
|Goodwill                                              |                     |   | 2,777   |        
|Other                                                 |                     |   | 147     |        
|                                                      |                     |   |         |        
|                                                      | Total assets        |   |         | 367,559 | 
|                                                      |                     |   |         |        
|Total liabilities assumed                             |                     |   | (489    | )      
|                                                      |                     |   |         |        
|                                                      | Net assets acquired |   | $       | 367,070 | 
|                                                      |                     |   |         |        

The value assigned to intangible assets relates to contracts with
customers that are for either a fixed term or which dedicate total future lease
production. We are amortizing the value assigned to intangible assets on a
unit-of-production basis, based upon the actual throughput of the system over
the expected total throughput for the contracts (averaging approximately 25
years) (see Note 3. Goodwill and Other Intangible Assets).

Chaparral NGL System

On March 1, 2002, we completed the purchase of the Chaparral NGL system
(Chaparral) for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch
III, L.P., including acquisition related costs of approximately $0.4 million.
The Chaparral NGL system extends from West Texas and New Mexico to Mont
Belvieu. The pipeline delivers NGLs to fractionators and to our existing
storage facilities in Mont Belvieu. We funded the purchase through borrowings
under our $500.0 million revolving credit facility (see Note 11. Debt). We
allocated the purchase price to property, plant and equipment. We accounted
for the acquisition of these assets under the purchase method of accounting.
Accordingly, the results of the acquisition have been included in our
consolidated financial statements from March 1, 2002. Under a contractual
agreement, DEFS manages and operates Chaparral on our behalf.

Val Verde Gas Gathering Company

On June 30, 2002, we completed the purchase of Val Verde for $444.2
million from Burlington Resources Gathering Inc., a subsidiary of Burlington
Resources Inc., including acquisition related costs of approximately $1.2
million. The Val Verde system gathers CBM from the Fruitland Coal Formation of
the San Juan Basin in New Mexico and Colorado. The system is one of the
largest CBM gathering and treating facilities in the United States. We funded
the purchase through borrowings of $168.0 million under our $500.0 million
revolving credit facility, $72.0 million under our 364-day revolving credit
facility, and $200.0 million under a six-month term loan with SunTrust Bank
(see Note 11. Debt). The remaining purchase price was funded through working
capital sources of cash. We allocated the purchase price, net of liabilities
assumed, primarily to property, plant and equipment and intangible assets for
gas gathering contracts. We accounted for the acquisition of these assets
under the purchase method of accounting. Accordingly, the results of the
acquisition have been included in our consolidated financial

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

statements from June 30, 2002. Under a contractual agreement, DEFS
manages and operates Val Verde on our behalf.

The following table allocates the estimated fair value of the Val Verde
assets acquired on June 30, 2002 (in thousands):

|                                                      |                     |   |         |         | 
|----------------------------------------------------- | ------------------- | - | ------- | ------- | 
|Property, plant and equipment                         |                     | $ | 205,146 |        
|Intangible assets (primarily gas gathering contracts) |                     |   | 239,649 |        
|                                                      |                     |   |         |        
|                                                      | Total assets        |   |         | 444,795 | 
|                                                      |                     |   |         |        
|Total liabilities assumed                             |                     |   | (645    | )      
|                                                      |                     |   |         |        
|                                                      | Net assets acquired |   | $       | 444,150 | 
|                                                      |                     |   |         |        

The value assigned to intangible assets relates to fixed-term contracts
with customers. We are amortizing the value assigned to intangible assets on a
unit-of-production basis, based upon the actual throughput of the system over
the expected total throughput for the contracts. The period of amortization is
expected to be approximately 20 years from the date of acquisition.

The following table presents our unaudited pro forma results as though the
acquisitions of Jonah and Val Verde occurred at the beginning of 2002 and 2001
(in thousands, except per Unit amounts). The unaudited pro forma results give
effect to certain pro forma adjustments including depreciation and amortization
expense adjustments of property, plant and equipment and intangible assets
based upon the purchase price allocations, interest expense related to
financing the acquisition, amortization expense of debt issue costs and the
removal of income tax effects in historical results of operations. The pro
forma results do not include operating efficiencies or revenue growth from
historical results.

|                                      |  |              |           |      |  |   |           | 
|------------------------------------- |  | ------------ | --------- | ---- |  | - | --------- | 
|                                      |  | Year Ended  
|                                      |  | December 31,
|                                      |  |             
|                                      |  | 2002         |           | 2001
|                                      |  |              |           |     
|Revenues                              |  | $            | 3,279,948 |      |  | $ | 3,659,496 | 
|Operating income                      |  |              | 181,717   |      |  |   | 179,600   | 
|Net income                            |  |              | 130,335   |      |  |   | 119,286   | 
|Basic and diluted net income per Unit |  | $            | 1.70      |      |  | $ | 2.00      | 

The summarized pro forma information has been prepared for comparative
purposes only. It is not intended to be indicative of the actual operating
results that would have occurred had the acquisitions been consummated at the
beginning of 2002 or 2001, or the results which may be attained in the future.

Rancho Pipeline

In connection with our acquisition of crude oil assets in 2000, we
acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline,
which was a crude oil pipeline system from West Texas to Houston, Texas. In
March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline
were sold to certain of the owners which previously held undivided interests in
the pipeline. We acquired approximately 230 miles of the pipeline in exchange
for cash of $5.5 million and our interests in other portions of the Rancho
Pipeline. We sold part of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million.
We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our
consolidated statements of income.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

Genesis Pipeline

On November 1, 2003, we completed the purchase of crude supply and
transportation assets along the upper Texas Gulf Coast for $21.0 million from
Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P (Genesis). The
transaction was funded with proceeds from our August 2003 equity offering (see
Note 12. Partners Capital and Distributions). We allocated the purchase
price, net of liabilities assumed, primarily to property, plant and equipment
and intangible assets. The assets acquired included approximately 150 miles of
small diameter trunk lines, 26,000 barrels per day of throughput and 12,000
barrels per day of lease marketing and supply business. We have integrated
these assets into our South Texas pipeline system which has allowed us to
consolidate gathering and marketing assets in key operating areas in a cost
effective manner and will provide future growth opportunities. Accordingly,
the results of the acquisition are included in the consolidated financial
statements from November 1, 2003.

The following table allocates the estimated fair value of the Genesis
assets acquired on November 1, 2003 (in thousands):

|                              |                     |   |        |        | 
|----------------------------- | ------------------- | - | ------ | ------ | 
|Property, plant and equipment |                     | $ | 13,053 |       
|Intangible assets             |                     |   | 8,500  |       
|Other                         |                     |   | 144    |       
|                              |                     |   |        |       
|                              | Total assets        |   |        | 21,697 | 
|                              |                     |   |        |       
|Total liabilities assumed     |                     |   | (687   | )     
|                              |                     |   |        |       
|                              | Net assets acquired |   | $      | 21,010 | 
|                              |                     |   |        |       

NOTE 7. EQUITY INVESTMENTS

Through one of our indirect wholly owned subsidiaries, we own a 50%
ownership interest in Seaway Crude Pipeline Company (Seaway). The remaining
50% interest is owned by ConocoPhillips. Seaway owns a pipeline that carries
mostly imported crude oil from a marine terminal at Freeport, Texas, to
Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to
refineries in the Texas City and Houston, Texas, areas. The Seaway Crude
Pipeline Company Partnership Agreement provides for varying participation
ratios throughout the life of the Seaway partnership. From July 20, 2000,
through May 2002, we received 80% of revenue and expense of Seaway. From June
2002 through May 2006, we receive 60% of revenue and expense of Seaway.
Thereafter, the sharing ratio becomes 40% of revenue and expense to us. For
the year ended December 31, 2002, our portion of equity earnings on a pro-rated
basis averaged approximately 67%.

In August 2000, TE Products entered into agreements with Panhandle Eastern
Pipeline Company (PEPL), a former subsidiary of CMS Energy Corporation, and
Marathon Ashland Petroleum LLC (Marathon) to form Centennial Pipeline LLC
(Centennial). Centennial owns an interstate refined petroleum products
pipeline extending from the upper Texas Gulf Coast to central Illinois.
Through February 9, 2003, each participant owned a one-third interest in
Centennial. On February 10, 2003, TE Products and Marathon each acquired an
additional interest in Centennial from PEPL for $20.0 million each, increasing
their percentage ownerships in Centennial to 50% each. During the year ended
December 31, 2003, including the amount paid for the acquisition of the
additional ownership interest, TE Products has invested $24.0 million in
Centennial, which is included in the equity investment balance at December 31,
2003.

As of January 1, 2003, TE Products and Louis Dreyfus Energy Services, L.P.
(Louis Dreyfus) formed Mont Belvieu Storage Partners, L.P. (MB Storage).
TE Products and Louis Dreyfus each own a 50% ownership

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

interest in MB Storage. The purpose of MB Storage is to expand services to the
upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and
the mix of products handled through the existing system and establishing new
receipt and delivery connections. MB Storage is a service-oriented, fee-based
venture with no commodity trading activity. TE Products continues to operate
the facilities for MB Storage. Effective January 1, 2003, TE Products
contributed property and equipment with a net book value of $67.4 million to MB
Storage. Additionally, as of the contribution date, Louis Dreyfus had invested
$6.1 million for expansion projects for MB Storage that TE Products was
required to reimburse if the original joint development and marketing agreement
was terminated by either party. This deferred liability was also contributed
and converted to the capital account of Louis Dreyfus in MB Storage.

TE Products receives the first $1.8 million per quarter (or $7.15 million
on an annual basis) of MB Storages gross income less mandatory capital
expenditures plus capital contributions, as defined in the operating agreement.
Any amount of MB Storages gross income in excess of the $7.15 million is
allocated evenly between TE Products and Louis Dreyfus, except for depreciation
expense. Each partner is allocated depreciation expense based upon assets each
originally contributed to MB Storage. Depreciation expense on assets
constructed or acquired by MB Storage is allocated evenly between TE Products
and Louis Dreyfus. For the year ended December 31, 2003, TE Products sharing
ratio in the earnings of MB Storage was approximately 70.4%. During the year
ended December 21, 2003, excluding the contribution of property, plant and
equipment, TE Products contributed $2.5 million to MB Storage. In December
2003, we received a distribution of $5.3 million from MB Storage.

We use the equity method of accounting to account for our investments in
Seaway, Centennial and MB Storage. Summarized combined financial information
for Seaway, Centennial and MB Storage for the year ended December 31, 2003, and
for Seaway and Centennial for the year ended December 31, 2002, is presented
below (in thousands):

|           |  |              |         |      |  |   |        | 
|---------- |  | ------------ | ------- | ---- |  | - | ------ | 
|           |  | Years Ended 
|           |  | December 31,
|           |  |             
|           |  | 2003         |         | 2002
|           |  |              |         |     
|Revenues   |  | $            | 125,521 |      |  | $ | 83,237 | 
|Net income |  |              | 30,034  |      |  |   | 5,389  | 

Summarized combined balance sheet data for Seaway, Centennial and MB
Storage as of December 31, 2003, and for Seaway and Centennial as of December
31, 2002, is presented below (in thousands):

|                       |  |              |         |      |  |   |         | 
|---------------------- |  | ------------ | ------- | ---- |  | - | ------- | 
|                       |  | December 31,
|                       |  |             
|                       |  | 2003         |         | 2002
|                       |  |              |         |     
|Current assets         |  | $            | 56,243  |      |  | $ | 32,528  | 
|Noncurrent assets      |  |              | 609,215 |      |  |   | 551,324 | 
|Current liabilities    |  |              | 43,177  |      |  |   | 28,681  | 
|Long-term debt         |  |              | 140,000 |      |  |   | 140,000 | 
|Noncurrent liabilities |  |              | 13,182  |      |  |   | 14,875  | 
|Partners capital      |  |              | 469,099 |      |  |   | 400,296 | 

Our investments in Seaway and Centennial include excess net investment
amounts of $25.5 million and $33.4 million, respectively. Excess investment is
the amount by which our investment balance exceeds our proportionate share of
the net assets of the investment. Prior to January 1, 2002, and the adoption
of SFAS 142, we were amortizing the excess investment in Seaway using the
straight-line method over 20 years.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 8. RELATED PARTY TRANSACTIONS

Duke Energy, DEFS and Affiliates

We have no employees and are managed by the Company, a wholly owned
subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in
DEFS, and ConocoPhillips holds the remaining 30%. According to the
Partnership Agreements, the Company is entitled to reimbursement of all direct
and indirect expenses related to our business activities (see Note 1.
Partnership Organization).

For the years ended December 31, 2003, 2002, and 2001, we incurred direct
expenses of $74.5 million, $66.7 million and $65.2 million, respectively, which
were charged to us by DEFS. Substantially all of these costs were related to
payroll and payroll related expenses. For the years ended December 31, 2003,
2002, and 2001, expenses for administrative services and overhead allocated to
us by Duke Energy and its affiliates were $1.1 million, $0.8 million and $0.6
million, respectively.

Lubrication Services, L.P. (LSI) sells lubrication oils and specialty
chemicals to DEFS. For the years ended December 31, 2003, 2002, and 2001,
revenues recognized by LSI included $15.2 million, $14.6 million and $12.3
million, respectively, for the sale of lubrication oils and specialty chemicals
to DEFS.

Effective with the purchase of the fractionation facilities on March 31,
1998, TEPPCO Colorado, LLC (TEPPCO Colorado) and DEFS entered into a 20-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 $7.4 million for each of the years ended
December 31, 2003, 2002 and 2001. TEPPCO Colorado and DEFS also entered into
an Operation and Maintenance Agreement, whereby DEFS operates and maintains the
fractionation facilities. For these services, TEPPCO Colorado pays DEFS a set
volumetric rate for all fractionated volumes delivered to DEFS. Expenses
related to the Operation and Maintenance Agreement totaled $0.9 million for
each of the years ended December 31, 2003, 2002 and 2001.

The Dean Pipeline and the Wilcox Pipeline were included with the crude oil
assets purchased from DEFS effective November 1, 1998. The Dean Pipeline
originates in South Texas and transports NGLs for DEFS into its pipeline in
Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation
totaled $1.0 million, $2.9 million and $0.1 million for the years ended
December 31, 2003, 2002 and 2001, respectively. The Wilcox Pipeline, which is
located along the Texas Gulf Coast, transports NGLs for DEFS from two of its
processing plants and is currently supported by a throughput agreement with
DEFS through 2005. The fees paid to us by DEFS under the agreement
were $1.5 million, $1.2 million and $1.2 million for the years ended December 31, 2003, 2002
and 2001, respectively.

The Panola Pipeline and San Jacinto Pipeline were purchased on December
31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS East
Texas Plant Complex in Panola County, Texas. For the years ended December 31,
2003, 2002 and 2001, revenues recognized included $9.2 million, $12.0 million
and $13.9 million, respectively, from an affiliate of DEFS for NGL
transportation fees on the Panola and San Jacinto Pipelines.

Effective May 2001, we entered into an agreement with an affiliate of DEFS
to commit sole utilization of our Providence terminal to an affiliate of DEFS.
We operate the terminal and provide propane loading services to
an affiliate of DEFS. During the years ended December 31, 2003, 2002 and
2001, revenues of $3.2 million, $2.3 million and $1.5 million from an affiliate
of DEFS, respectively, were recognized pursuant to this agreement.

On September 30, 2001, we completed the acquisition of Jonah (see Note 6.
Acquisitions and Dispositions). The Jonah assets are managed and operated by
employees of DEFS under a contractual agreement under which DEFS is reimbursed
for its actual costs. During the years ended December 31, 2003, 2002 and 2001,
we recognized $3.7 million, $3.3 million and $0.6 million, respectively, of
expense related to the operation and management of the Jonah assets by DEFS.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

On March 1, 2002, we completed the acquisition of the Chaparral NGL system
(see Note 6. Acquisitions and Dispositions). The Chaparral assets are managed
and operated by employees of DEFS under a contractual agreement under which
DEFS is reimbursed for its actual costs. During the years ended December 31,
2003, and 2002, we recognized $2.1 million and $1.7 million, respectively, of
expenses related to the operations and management of the Chaparral assets by
DEFS. An affiliate of DEFS transports NGLs on the Chaparral NGL system. The
fees paid to us by an affiliate of DEFS for NGL transportation on Chaparral
totaled $5.5 million and $4.5 million for the years ended December 31, 2003 and
2002, respectively.

On June 30, 2002, we completed the acquisition of Val Verde (see Note 6.
Acquisitions and Dispositions). The Val Verde assets are managed and operated
by employees of DEFS under a contractual agreement under which DEFS is
reimbursed for its actual costs. During the years ended December 31, 2003, and
2002, we recognized $3.0 million and $1.2 million, respectively, of expenses
related to the operation and management of the Val Verde assets by DEFS.

At December 31, 2003 and 2002, we had a receivable from DEFS of $1.8
million and $6.9 million, respectively, related to sales and transportation
services provided to DEFS. Included in the receivable balance at December 31,
2002, was an amount related to environmental remediation activities. At
December 31, 2003 and 2002, we had a payable to DEFS of $9.7 million and $6.7
million, respectively, related to direct payroll, payroll related costs and
management fees for Jonah, Chaparral, and Val Verde as described above.
Included in this payable balance to DEFS at December 31, 2003 and 2002, is an
imbalance payable to DEFS by TEPPCO Midstream of $1.5 million and $0.9 million,
respectively.

On April 2, 2003, we sold in an underwritten public offering 3.9 million
Units at $30.35 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $114.5 million, of which approximately $113.8
million was used to repurchase and retire all of the 3.9 million previously
outstanding Class B Units held by DETTCO (see Note 12. Partners Capital and
Distributions).

We contract with Bison Insurance Company Limited (Bison), a wholly owned
subsidiary of Duke Energy, for a majority of our insurance coverage, including
property, liability, auto and directors and officers insurance coverage. For
the years ended December 31, 2003 and 2002, we paid insurance premiums to Bison
of $6.4 million and $4.5 million, respectively. At December 31, 2003 and 2002,
we had insurance reimbursement receivables due from Bison of $1.9 million and
$1.3 million, respectively.

At December 31, 2003, we had a loan of propane outstanding to DEFS with a
total value of $1.4 million. We will earn a nominal rental fee of $0.1 million
on this transaction. This propane will be returned to us in February 2004. We
regularly loan inventory for a fee to third parties and affiliates as part of
our inventory management practice.

Seaway

On July 20, 2000, we acquired a 50% ownership interest in Seaway.
ConocoPhillips owns the remaining 50% interest in Seaway. We are the operator
of Seaway. During the years ended December 31, 2003, 2002 and 2001, we billed
Seaway $7.2 million, $7.1 million and $7.0 million, respectively, for direct
payroll and payroll related expenses for operating Seaway. Additionally, for
each of the years ended December 31, 2003, 2002 and 2001, we billed Seaway $2.1
million for indirect management fees for operating Seaway. At December 31,
2003 and 2002, we had a payable balance to Seaway of $4.0 million and $1.1
million, respectively, for advances Seaway paid to us as operator for operating
costs, including payroll and related expenses and management fees.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

Centennial

In August 2000, TE Products entered into agreements with PEPL and Marathon
to form Centennial (see Note 7. Equity Investments). At December 31, 2003, TE
Products had a 50% ownership interest in Centennial. TE Products has entered
into a management agreement with Centennial to operate Centennials terminal at
Creal Springs and pipeline connection in Beaumont, Texas. For each of the
years ended December 31, 2003, and 2002, we recognized management fees of $0.2
million from Centennial, and actual operating expenses billed to Centennial
were $4.4 million and $4.0 million, respectively.

TE Products also has a joint tariff with Centennial to deliver products at
TE Products locations using Centennials pipeline as part of the delivery
route to connecting carriers. TE Products, as the delivering pipeline,
invoices the shippers for the entire delivery rate, records only the net rate
attributable to it as transportation revenues and records a liability for the
amounts due to Centennial for its share of the tariff. At December 31, 2003
and 2002, we had a payable balance of $2.3 million and $1.0 million,
respectively, to Centennial for its share of the joint tariff deliveries. In
addition, TE Products performs ongoing construction services for Centennial and
bills Centennial for labor and other costs to perform the construction. At
December 31, 2003 and 2002, TE Products had a receivable balance of $1.3
million and $1.9 million, respectively, due from Centennial for reimbursement
of construction services provided to Centennial.

In January 2003, TE Products entered into a pipeline capacity lease
agreement with Centennial for a period of five years that contains a minimum
throughput requirement. For the year ended December 31, 2003, TE Products
incurred $3.8 million of rental charges related to the lease of pipeline
capacity on Centennial.

MB Storage

Effective January 1, 2003, TE Products entered into agreements with Louis
Dreyfus to form MB Storage (see Note 7. Equity Investments). TE Products
operates the facilities for MB Storage. TE Products and MB Storage have
entered into a pipeline capacity lease agreement, and for the year ended
December 31, 2003, TE Products recognized $0.1 million in rental revenue
related to this lease agreement. TE Products also billed MB Storage $2.3
million for direct payroll and payroll related expenses for operating MB
Storage during the year ended December 31, 2003. At December 31, 2003, TE
Products had a payable balance to MB Storage of $0.2 million for advances MB
Storage paid for operating costs, including payroll and related expenses.

NOTE 9. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average
cost method) or market. The costs of inventories did not exceed market values
at December 31, 2003 and 2002. The major components of inventories were as
follows (in thousands):

|                                         |       |   |              |        |      |   |       |        | 
|---------------------------------------- | ----- | - | ------------ | ------ | ---- | - | ----- | ------ | 
|                                         |       |   | December 31,
|                                         |       |   |             
|                                         |       |   | 2003         |        | 2002
|                                         |       |   |              |        |     
|Crude oil                                |       | $ | 1,303        |        |      | $ |      |       
|Refined products                         |       |   | 6,632        |        |      |   | 5,164 |       
|LPGs                                     |       |   | 517          |        |      |   | 1,991 |       
|Lubrication oils and specialty chemicals |       |   | 3,080        |        |      |   | 3,836 |       
|Materials and supplies                   |       |   | 4,528        |        |      |   | 4,113 |       
|                                         |       |   |              |        |      |   |       |       
|                                         | Total |   | $            | 16,060 |      |   | $     | 15,104 | 
|                                         |       |   |              |        |      |   |       |       

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment were as follows (in thousands):

|                              |                                                |                                   |           |              |           |      |           |           |           | 
|----------------------------- | ---------------------------------------------- | --------------------------------- | --------- | ------------ | --------- | ---- | --------- | --------- | --------- | 
|                              |                                                |                                   |           | December 31,
|                              |                                                |                                   |           |             
|                              |                                                |                                   |           | 2003         |           | 2002
|                              |                                                |                                   |           |              |           |     
|Land and right of way         |                                                | $                                 | 130,775   |              |           | $    | 132,132   |          
|Line pipe and fittings        |                                                |                                   | 1,256,393 |              |           |      | 1,158,071 |          
|Storage tanks                 |                                                |                                   | 135,938   |              |           |      | 147,650   |          
|Buildings and improvements    |                                                |                                   | 35,648    |              |           |      | 16,425    |          
|Machinery and equipment       |                                                |                                   | 292,949   |              |           |      | 370,046   |          
|Construction work in progress |                                                |                                   | 112,817   |              |           |      | 102,246   |          
|                              |                                                |                                   |           |              |           |      |           |          
|                              | Total property, plant and equipment            |                                   | $         | 1,964,520    |           |      | $         | 1,926,570 |          
|                              | Less accumulated depreciation and amortization |                                   |           | 345,357      |           |      |           | 338,746   |          
|                              |                                                |                                   |           |              |           |      |           |          
|                              |                                                | Net property, plant and equipment |           | $            | 1,619,163 |      |           | $         | 1,587,824 | 
|                              |                                                |                                   |           |              |           |      |           |          

Depreciation expense on property, plant and equipment was $64.5 million,
$56.0 million and $39.5 million for the years ended December 31, 2003, 2002 and
2001, respectively.

NOTE 11. DEBT

Senior Notes

On January 27, 1998, TE Products completed the issuance of $180.0 million
principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal
amount of 7.51% Senior Notes due 2028 (collectively the TE Products Senior
Notes). The 6.45% TE Products Senior Notes were issued at a discount of $0.3
million and are being accreted to their face value over the term of the notes.
The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior
to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at
par, may be redeemed at any time after January 15, 2008, at the option of TE
Products, in whole or in part, at a premium.

The TE Products Senior Notes do not have sinking fund requirements.
Interest on the TE Products Senior Notes is payable semiannually in arrears on
January 15 and July 15 of each year. The TE Products Senior Notes are
unsecured obligations of TE Products and rank on a parity with all other
unsecured and unsubordinated indebtedness of TE Products. The indenture
governing the TE Products Senior Notes contains covenants, including, but not
limited to, covenants limiting the creation of liens securing indebtedness and
sale and leaseback transactions. However, the indenture does not limit our
ability to incur additional indebtedness. As of December 31, 2003, TE Products
was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million
principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were
issued at a discount of $2.2 million and are being accreted to their face value
over the term of the notes. We used the proceeds from the offering to reduce a
portion of the outstanding balances of our credit facilities, including those
issued in connection with the acquisition of Jonah. The Senior Notes may be
redeemed at any time at our option with the payment of accrued interest and a
make-whole premium
determined by discounting remaining interest and principal payments using
a discount rate equal to the rate of the United States Treasury securities of
comparable remaining maturity plus 35 basis points. The indenture governing
our 7.625% Senior Notes contains covenants, including, but not limited to,
covenants limiting the creation of liens securing indebtedness and sale and
leaseback transactions. However, the indenture does not limit our ability to
incur

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##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

additional indebtedness. As of December 31, 2003, we were in compliance with
the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal
amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at
a discount of $1.4 million and are being accreted to their face value over the
term of the notes. We used $182.0 million of the proceeds from the offering to
reduce the outstanding principal on our $500.0 million revolving credit
facility to $250.0 million. The balance of the net proceeds received was used
for general partnership purposes. The Senior Notes may be redeemed at any time
at our option with the payment of accrued interest and a make-whole premium
determined by discounting remaining interest and principal payments using a
discount rate equal to the rate of the United States Treasury securities of
comparable remaining maturity plus 35 basis points. The indenture governing
our 6.125% Senior Notes contains covenants, including, but not limited to,
covenants limiting the creation of liens securing indebtedness and sale and
leaseback transactions. However, the indenture does not limit our ability to
incur additional indebtedness. As of December 31, 2003, we were in compliance
with the covenants of these Senior Notes.

The following table summarizes the estimated fair values of the Senior
Notes as of December 31, 2003 and 2002 (in millions):

|                                                 |  |       |       |      |  |              |       |  |  |   |       | 
|------------------------------------------------ |  | ----- | ----- | ---- |  | ------------ | ----- |  |  | - | ----- | 
|                                                 |  |       |       |      |  | December 31,
|                                                 |  | Face  |       |     
|                                                 |  | Value |       | 2003 |  | 2002        
|                                                 |  |       |       |      |  |             
|6.45% TE Products Senior Notes, due January 2008 |  | $     | 180.0 |      |  | $            | 204.8 |  |  | $ | 184.6 | 
|7.625% Senior Notes, due February 2012           |  |       | 500.0 |      |  |              | 578.2 |  |  |   | 529.1 | 
|6.125% Senior Notes, due February 2013           |  |       | 200.0 |      |  |              | 206.7 |  |  |   |      | 
|7.51% TE Products Senior Notes, due January 2028 |  |       | 210.0 |      |  |              | 228.0 |  |  |   | 201.2 | 

We have entered into interest rate swap agreements to hedge our exposure
to changes in the fair value on a portion of the Senior Notes discussed above.
See Note 4. Interest Rate Swaps.

Other Long Term Debt and Credit Facilities

On April 6, 2001, we entered into a $500.0 million revolving credit
facility including the issuance of letters of credit of up to $20.0 million
(Three Year Facility). The interest rate was based, at our option, on either
the lenders base rate plus a spread, or LIBOR plus a spread in effect at the
time of the borrowings. The credit agreement for the Three Year Facility
contained certain restrictive financial covenant ratios. During 2002,
borrowings under the Three Year Facility were used to finance the acquisitions
of Chaparral on March 1, 2002, and Val Verde on June 30, 2002, and for general
partnership purposes. During 2002, repayments were made on the Three Year
Facility with proceeds from the issuance of our 7.625% Senior Notes, proceeds
from the issuance of additional Units and proceeds from the termination of
interest rate swaps (see Note 4. Interest Rate Swaps). During the first
quarter of 2003, we repaid $182.0 million of the outstanding balance of the
Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes
on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under
the Three Year Facility with borrowings under a new credit facility, and
canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million revolving credit
facility with a three year term, including the issuance of letters of credit of
up to $20.0 million (Revolving Credit Facility). The interest rate is based,
at our option, on either the lenders base rate plus a spread, or LIBOR plus a
spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility
contains certain restrictive financial covenant ratios. We borrowed $263.0
million under the Revolving Credit Facility and repaid the outstanding balance
of the Three Year Facility. On December 31, 2003, $210.0 million was
outstanding under the Revolving Credit Facility at a weighted average interest
rate, before the effects of hedging activities, of 1.9%. At December 31, 2003,
we were in compliance with the covenants of this credit agreement.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

We have entered into an interest rate swap agreement to hedge our exposure
to increases in interest rates on a portion of the credit facilities discussed
above. See Note 4. Interest Rate Swaps.

Short Term Credit Facilities

On April 6, 2001, we entered into a 364-day, $200.0 million revolving
credit agreement (Short-term Revolver). The interest rate was based, at our
option, on either the lenders base rate plus a spread, or LIBOR plus a spread
in effect at the time of the borrowings. The credit agreement contained certain
restrictive financial covenant ratios. On March 28, 2002, the Short-term
Revolver was extended for an additional period of 364 days, ending in March
2003. During 2002, borrowings under the Short-term Revolver were used to
finance the acquisition of the Val Verde assets and for other purposes. During
2002, we repaid the existing amounts outstanding under the Short-term Revolver
with proceeds we received from the issuance of Units in 2002. The Short-term
Revolver expired on March 27, 2003.

On September 28, 2001, we entered into a $400.0 million credit facility
with SunTrust Bank (Bridge Facility) payable in June 2002. We borrowed
$360.0 million under the Bridge Facility to acquire the Jonah assets (see Note
6. Acquisitions and Dispositions). During the fourth quarter of 2001, we
repaid $160.0 million of the outstanding principal from proceeds received from
the issuance of Units in November 2001. On February 5, 2002, we borrowed an
additional $15.0 million under the Bridge Facility. On February 20, 2002, we
repaid the outstanding balance of the Bridge Facility of $215.0 million with
proceeds from the issuance of the 7.625% Senior Notes and canceled the
facility.

On June 27, 2002, we entered into a $200.0 million six-month term loan
with SunTrust Bank (Six-Month Term Loan) payable in December 2002. We
borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde
assets (see Note 6. Acquisitions and Dispositions). The interest rate was
based, at our option, on either the lenders base rate plus a spread, or LIBOR
plus a spread in effect at the time of the borrowings. The credit agreement
contained certain restrictive financial covenant ratios. On July 11, 2002, we
repaid $90.0 million of the outstanding principal from proceeds primarily
received from the issuance of Units in July 2002. On September 10, 2002, we
repaid the remaining outstanding balance of $110.0 million with proceeds
received from the issuance of Units in September 2002, and canceled the
facility.

The following table summarizes the principal amounts outstanding under our
credit facilities as of December 31, 2003 and 2002 (in thousands):

|                   |                                                                   |                         |   |              |           |      |   |         |           | 
|------------------ | ----------------------------------------------------------------- | ----------------------- | - | ------------ | --------- | ---- | - | ------- | --------- | 
|                   |                                                                   |                         |   | December 31,
|                   |                                                                   |                         |   |             
|                   |                                                                   |                         |   | 2003         |           | 2002
|                   |                                                                   |                         |   |              |           |     
|Credit Facilities: |                                                                   |                         |   |              |           |      |   |        
|                   | Three Year Facility, due April 2004                               |                         | $ |             |           |      | $ | 432,000 |          
|                   | Revolving Credit Facility, due June 2006                          |                         |   | 210,000      |           |      |   |        |          
|                   | 6.45% TE Products Senior Notes, due January 2008                  |                         |   | 179,876      |           |      |   | 179,845 |          
|                   | 7.625% Senior Notes, due February 2012                            |                         |   | 498,216      |           |      |   | 497,995 |          
|                   | 6.125% Senior Notes, due February 2013                            |                         |   | 198,702      |           |      |   |        |          
|                   | 7.51% TE Products Senior Notes, due January 2028                  |                         |   | 210,000      |           |      |   | 210,000 |          
|                   |                                                                   |                         |   |              |           |      |   |        
|                   |                                                                   | Total borrowings        |   |              | 1,296,794 |      |   |         | 1,319,840 | 
|                   | Adjustment to carrying value associated with
hedges of fair value |                         |   | 42,856       |           |      |   | 57,852  |          
|                   |                                                                   |                         |   |              |           |      |   |        
|                   |                                                                   | Total Credit Facilities |   | $            | 1,339,650 |      |   | $       | 1,377,692 | 
|                   |                                                                   |                         |   |              |           |      |   |        

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 12. PARTNERS CAPITAL AND DISTRIBUTIONS

Equity Offerings

On March 22, 2002, we sold in an underwritten public offering 1.92 million
Units at $31.18 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $57.3 million and were used to repay $50.0
million of the outstanding balance on the Three Year Facility, with the
remaining amount being used for general partnership purposes.

On July 11, 2002, we sold in an underwritten public offering 3.0 million
Units at $30.15 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $86.6 million and were used to reduce
borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units
were sold upon exercise of the underwriters over-allotment option granted in
connection with the offering on July 11, 2002. Proceeds from that sale totaled
$5.1 million and were used for general partnership purposes.

On September 5, 2002, we sold in an underwritten public offering 3.8
million Units at $29.72 per Unit. The proceeds from the offering, net of
underwriting discount, totaled approximately $108.1 million and were used to
reduce borrowings under our Six-Month Term Loan. On September 19, 2002,
570,000 Units were sold upon exercise of the underwriters over-allotment
option granted in connection with the offering on September 5, 2002. Proceeds
from that sale totaled $16.2 million and were used to reduce borrowings under
our Short-term Revolver.

On November 7, 2002, we sold in an underwritten public offering 3.3
million Units at $26.83 per Unit. The proceeds from the offering, net of
underwriting discount, totaled approximately $84.8 million and were used to
reduce borrowings under our Short-term Revolver and Three Year Facility. On
December 4, 2002, 495,000 Units were sold upon exercise of the underwriters
over-allotment option granted in connection with the offering on November 7,
2002. Proceeds from that sale totaled $12.7 million and were used to reduce
borrowings under our Short-term Revolver and Three Year Facility.

On April 2, 2003, we sold in an underwritten public offering 3.9 million
Units at $30.35 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $114.5 million, of which approximately $113.8
million was used to repurchase and retire all of the 3.9 million previously
outstanding Class B Units held by DETTCO. We received approximately $0.7
million in proceeds from the offering in excess of the amount needed to
repurchase and retire the Class B Units.

On August 7, 2003, we sold in an underwritten public offering 5.0 million
Units at $34.68 per Unit. The proceeds from the offering, net of underwriting
discount, totaled approximately $166.0 million. On August 19, 2003, 162,900
Units were sold upon exercise of the underwriters over-allotment option
granted in connection with the offering on August 7, 2003. Proceeds from the
over-allotment sale, net of underwriting discount, totaled $5.4 million.
Approximately $53.0 million of the proceeds were used to repay indebtedness
under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 6. Acquisitions and
Dispositions). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.

Quarterly Distributions of Available Cash

We make quarterly cash distributions of all of our 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 when cash distributions exceed certain
target thresholds as follows:

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TEPPCO PARTNERS, L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

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

The following table reflects the allocation of total distributions paid
during the years ended December 31, 2003, 2002 and 2001 (in thousands, except
per Unit amounts):

|                                       |                                            |   |                          |         |      |   |         |         |  |   |        |         | 
|-------------------------------------- | ------------------------------------------ | - | ------------------------ | ------- | ---- | - | ------- | ------- |  | - | ------ | ------- | 
|                                       |                                            |   | Years Ended December 31,
|                                       |                                            |   |                         
|                                       |                                            |   | 2003                     |         | 2002 |   | 2001   
|                                       |                                            |   |                          |         |      |   |        
|Limited Partner Units                  |                                            | $ | 145,427                  |         |      | $ | 104,932 |         |  | $ | 73,961 |        
|General Partner Ownership Interest     |                                            |   | 3,016                    |         |      |   | 2,329   |         |  |   | 1,273  |        
|General Partner Incentive              |                                            |   | 51,709                   |         |      |   | 35,389  |         |  |   | 20,257 |        
|                                       |                                            |   |                          |         |      |   |         |         |  |   |        |        
|                                       | Total Partners Capital Cash Distributions |   |                          | 200,152 |      |   |         | 142,650 |  |   |        | 95,491  | 
|Class B Units                          |                                            |   | 2,346                    |         |      |   | 9,203   |         |  |   | 8,421  |        
|Minority Interest                      |                                            |   |                         |         |      |   |        |         |  |   | 500    |        
|                                       |                                            |   |                          |         |      |   |         |         |  |   |        |        
|                                       | Total Cash Distributions Paid              |   | $                        | 202,498 |      |   | $       | 151,853 |  |   | $      | 104,412 | 
|                                       |                                            |   |                          |         |      |   |         |         |  |   |        |        
|Total Cash Distributions Paid Per Unit |                                            | $ | 2.50                     |         |      | $ | 2.35    |         |  | $ | 2.15   |        
|                                       |                                            |   |                          |         |      |   |         |         |  |   |        |        

On February 6, 2004, we paid a cash distribution of $0.65 per Unit for the
quarter ended December 31, 2003. The fourth quarter 2003 cash distribution
totaled $57.1 million.

General Partner Interest

As of December 31, 2003, we had a deficit balance of $7.2 million in our
General Partners equity account. This negative balance does not represent an
asset to us and does not represent an obligation of the General Partner to
contribute cash or other property to us. The General Partners equity account
consists of its cumulative share of our net income and cash distributions that
we made and capital contributions that it has made to us (see our Consolidated
Statements of Partners Capital for a detail of the General Partners equity
account). For the year ended December 31, 2003, the General Partner was
allocated $34.8 million (representing 27.65%) of our net income and received
$54.7 million in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are
maintained for our General Partner and our limited partners. The Capital
Account provisions of our Partnership Agreement incorporate principles
established for U.S. Federal income tax purposes and are not comparable to the
equity accounts reflected under accounting principles generally accepted in the
United States in our financial statements. Under our Partnership Agreement,
the General Partner is only required to make additional capital contributions
to us upon the issuance of any additional limited partner units and only if
necessary to maintain a Capital Account balance equal to 1.999999% of the total
Capital Accounts of all partners. At December 31, 2003, the General Partners
Capital Account balance substantially exceeded this requirement.

Net income is allocated between the General Partner and the limited
partners in the same proportion as aggregate cash distributions made to the
General Partner and the limited partners during the period. This is generally
consistent with the manner of allocating net income under our Partnership
Agreement. Net income determined under our Partnership Agreement, however,
incorporates principles established for U.S. Federal income tax purposes and is
not comparable to net income reflected under accounting principles generally
accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income
for the period. We make quarterly cash distributions of all of our Available
Cash, generally defined as consolidated cash receipts less consolidated cash
disbursements and cash reserves established by the General Partner in its sole
discretion (see Note 12. Partners Capital and Distributions). Cash
distributions in excess of net income allocations and capital contributions
during the year ended December 31, 2003, resulted in a deficit in the General
Partners equity account at December 31, 2003. Future cash distributions which
exceed net income will result in an increase in the deficit balance in the
General Partners equity account.

According to the Partnership Agreement, in the event of our dissolution,
after satisfying our liabilities, our remaining assets would be divided among
our limited partners and the General Partner generally in the same proportion
as Available Cash but calculated on a cumulative basis over the life of the
partnership. After all allocations are made between the partners, if a deficit
balance in its equity account still remains for the General Partner, the
General Partner would not be required to make whole any such deficit.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 13. CONCENTRATIONS OF CREDIT RISK

Our primary market areas are located in the Northeast, Midwest and
Southwest regions of the United States. We have 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 our overall credit risk in that the customers may be
similarly affected by changes in economic, regulatory or other factors. We
thoroughly analyze our customers historical and future credit positions prior
to extending credit. We manage our 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.

For the years ended December 31, 2003, 2002 and 2001, we had one customer
from the Upstream Segment, Valero Energy Corp., which accounted for 16%, 16%
and 14%, respectively, of our total consolidated revenues. No other single
customer accounted for 10% or more of our total consolidated revenues for the
years ended December 31, 2003, 2002 and 2001.

The carrying amount of cash and cash equivalents, accounts receivable,
inventories, other current assets, accounts payable and accrued liabilities and
other current liabilities approximates their fair value due to their short-term
nature.

NOTE 14. UNIT-BASED COMPENSATION

1994 Long Term Incentive Plan

During 1994, the Company adopted the Texas Eastern Products Pipeline
Company 1994 Long Term Incentive Plan (1994 LTIP). The 1994 LTIP provides
certain key employees with an incentive award whereby a participant is granted
an option to purchase Units. These same employees are also granted a
stipulated number of Performance Units, the cash value of which may be used to
pay for the exercise of the respective Unit options awarded. Under the
provisions of the 1994 LTIP, no more than one million options and two million
Performance Units may be granted.

When our calendar year earnings per unit (exclusive of certain special
items) exceeds a stated threshold, each participant receives a credit to their
respective Performance Unit account equal to the earnings per unit excess
multiplied by the number of Performance Units awarded. The balance in the
Performance Unit account may be used to offset the cost of exercising 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. Any unused balance previously credited is forfeited upon
termination. We accrue compensation expense for the Performance Units awarded
annually based upon the terms of the plan discussed above.

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. At December 31, 2003, 42,000 Performance Units granted in 1995
with an earnings threshold of $1.25 remain outstanding. The Performance Units
expire in 2005.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

A summary of Unit options granted under the terms of the 1994 LTIP is
presented below:

|              |                                  |                    |  |             |         |             |  |          |         |   |   |              |              | 
|------------- | -------------------------------- | ------------------ |  | ----------- | ------- | ----------- |  | -------- | ------- | - | - | ------------ | ------------ | 
|              |                                  |                    |  | Options     |         | Options     |  | Exercise
|              |                                  |                    |  | Outstanding |         | Exercisable |  | Range   
|              |                                  |                    |  |             |         |             |  |         
|Unit Options: |                                  |                    |  |             |         |             |  |          |         |   |   |             
|              | Outstanding at December 31, 2000 |                    |  | 290,864     |         |             |  | 160,529  |         |   | $ | 13.81-$25.69 |             
|              |                                  | Forfeited          |  |             | (2,800  | )           |  |          |        |   |   | $            | 25.25        | 
|              |                                  | Became exercisable |  |             |        |             |  |          | 81,669  |   |   | $            | 25.25-$25.69 | 
|              |                                  | Exercised          |  |             | (98,376 | )           |  |          | (98,376 | ) |   | $            | 13.81-$25.69 | 
|              |                                  |                    |  |             |         |             |  |          |         |   |   |             
|              | Outstanding at December 31, 2001 |                    |  | 189,688     |         |             |  | 143,822  |         |   | $ | 13.81-$25.69 |             
|              |                                  | Became exercisable |  |             |        |             |  |          | 45,866  |   |   | $            | 25.25        | 
|              |                                  | Exercised          |  |             | (99,597 | )           |  |          | (99,597 | ) |   | $            | 13.81-$25.69 | 
|              |                                  |                    |  |             |         |             |  |          |         |   |   |             
|              | Outstanding at December 31, 2002 |                    |  | 90,091      |         |             |  | 90,091   |         |   | $ | 13.81-$25.69 |             
|              |                                  | Exercised          |  |             | (90,091 | )           |  |          | (90,091 | ) |   | $            | 13.81-$25.69 | 
|              |                                  |                    |  |             |         |             |  |          |         |   |   |             
|              | Outstanding at December 31, 2003 |                    |  |            |         |             |  |         |         |   |   |              |             
|              |                                  |                    |  |             |         |             |  |          |         |   |   |             

We have not granted options for any periods presented. During the year
ended December 31, 2003, all remaining outstanding Unit options were exercised.
For options previously outstanding, we followed the intrinsic value method for
recognizing stock-based compensation expense. The exercise price of all
options awarded under the 1994 LTIP equaled the market price of our Units on
the date of grant. Accordingly, we recognized no compensation expense 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 been immaterial for the years ended December 31,
2002 and 2001, and no compensation expense would have been recognized for the
year ended December 31, 2003.

1999 and 2002 Phantom Unit Plans

Effective September 1, 1999, the Company adopted the Texas Eastern
Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (1999 PURP).
Effective June 1, 2002 the Company adopted the Texas Eastern Products Pipeline
Company, LLC 2002 Phantom Unit Retention Plan (2002 PURP). The 1999 PURP and
the 2002 PURP provide key employees with incentive awards whereby a participant
is granted phantom units. These phantom units are automatically redeemed for
cash based on the vested portion of the fair market value of the phantom units
at stated redemption dates. The fair market value of each phantom unit is
equal to the closing price of a Unit as reported on the New York Stock Exchange
on the redemption date.

Under the agreement for the phantom units, each participant will vest 10%
of the number of phantom units initially granted under his or her award at the
end of each of the first four years and will vest the final 60% at the end of
the fifth year. Each participant is required to redeem their units as they
vest. They are also entitled to quarterly cash distributions equal to the
product of the number of phantom units outstanding for the participant and the
amount of the cash distribution that we paid per Unit to unitholders. A total
of 26,040 phantom units granted under the 1999 PURP remain outstanding at
December 31, 2003. A total of 67,230 phantom units granted under the 2002 PURP
remain outstanding at December 31, 2003. We accrue compensation expense
annually based upon the terms of the 1999 PURP and 2002 PURP discussed above.
At December 31, 2003 and 2002, we had an accrued liability balance of $2.1
million and $1.0 million, respectively, for compensation related to the 1999
PURP and 2002 PURP.

2000 Long Term Incentive Plan

Effective January 1, 2000, the General Partner established the Texas
Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (2000
LTIP) to provide key employees incentives to achieve improvements

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

in our financial performance. Generally, upon the close of a three-year
performance period, if the participant is then still an employee of the General
Partner, the participant will receive a cash payment in an amount equal to (1)
the applicable performance percentage specified in the award multiplied by (2)
the number of phantom Units granted under the award multiplied by (3) the
average of the closing prices of a Unit over the ten consecutive trading days
immediately preceding the last day of the performance period. Generally, a
participants performance percentage is based upon the improvement of our
Economic Value Added during a three-year performance period over the Economic
Value Added during the three-year period immediately preceding the performance
period. If a participant incurs a separation from service during the
performance period due to death, disability or retirement (as such terms are
defined in the 2000 LTIP), the participant will be entitled to receive a cash
payment in an amount equal to the amount computed as described above multiplied
by a fraction, the numerator of which is the number of days that have elapsed
during the performance period prior to the participants separation from
service and the denominator of which is the number of days in the performance
period. At December 31, 2003, phantom Units outstanding were 31,800, 22,300
and 24,013 for awards granted for the years ended December 31, 2003, 2002 and
2001, respectively.

Economic Value Added means our average annual EBITDA for the performance
period minus the product of our average asset base and our cost of capital for
the performance period. For purposes of the 2000 LTIP for plan years 2000
through 2002, EBITDA means our earnings before net interest expense,
depreciation and amortization and our proportional interest in EBITDA of our
joint ventures as presented in our consolidated financial statements prepared
in accordance with generally accepted accounting principles, except that in its
discretion the Compensation Committee of the General Partner may exclude gains
or losses from extraordinary, unusual or non-recurring items. For the year
ended December 31, 2003, EBITDA means, in addition to the above, earnings
before other income  net. Average asset base means the quarterly average,
during the performance period, of our gross value of property, plant and
equipment, plusproducts and crude oil operating oil supply and the gross value
of intangibles and equity investments. Our cost of capital is approved by the
Compensation Committee at the date of award grant.

In addition to the payment described above, during the performance period,
the General Partner will pay to the participant the amount of cash
distributions that we would have paid to our unitholders had the participant
been the owner of the number of Units equal to the number of phantom Units
granted to the participant under this award. We accrue compensation expense
annually based upon the terms of the 2000 LTIP discussed above. At December
31, 2003 and 2002, we had an accrued liability balance of $2.9 million and $1.8
million, respectively, for compensation related to the 2000 LTIP.

NOTE 15. OPERATING LEASES

We use leased assets in several areas of our operations. Total rental
expense for the years ended December 31, 2003, 2002 and 2001 was $21.9 million,
$14.2 million and $10.8 million, respectively. The following table sets forth
our minimum rental payments under our various operating leases for the years
ending December 31 (in thousands):

|           |  |   |        | 
|---------- |  | - | ------ | 
|2004       |  | $ | 16,444 | 
|2005       |  |   | 15,307 | 
|2006       |  |   | 12,620 | 
|2007       |  |   | 9,556  | 
|2008       |  |   | 5,771  | 
|Thereafter |  |   | 11,891 | 
|           |  |   |        | 
|           |  | $ | 71,589 | 
|           |  |   |        | 

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 16. EMPLOYEE BENEFITS

Retirement Plans

We have adopted the TEPPCO Retirement Cash Balance Plan (TEPPCO RCBP),
which is a noncontributory, trustee-administered pension plan. In addition,
certain executive officers participate in the TEPPCO Supplemental Benefit Plan
(TEPPCO SBP), which is a noncontributory, nonqualified, defined benefit
retirement plan. The TEPPCO SBP was established to restore benefit reductions
caused by the maximum benefit limitations that apply to qualified plans. The
benefit formula for all eligible employees is a cash balance formula. Under a
cash balance formula, a plan participant accumulates a retirement benefit based
upon pay credits and current interest credits. The pay credits are based on a
participants salary, age and service. We use a December 31 measurement date
for these plans.

The components of net pension benefits costs for the TEPPCO RCBP and the
TEPPCO SBP for the years ended December 31, 2003, 2002 and 2001, were as
follows (in thousands):

|                                              |                            |   |       |       |      |   |       |       |  |   |       |       | 
|--------------------------------------------- | -------------------------- | - | ----- | ----- | ---- | - | ----- | ----- |  | - | ----- | ----- | 
|                                              |                            |   | 2003  |       | 2002 |   | 2001 
|                                              |                            |   |       |       |      |   |      
|Service cost benefit earned during the year   |                            | $ | 3,179 |       |      | $ | 2,925 |       |  | $ | 2,419 |      
|Interest cost on projected benefit obligation |                            |   | 504   |       |      |   | 315   |       |  |   | 129   |      
|Expected return on plan assets                |                            |   | (604  | )     |      |   | (390  | )     |  |   | (166  | )    
|Amortization of prior service cost            |                            |   | 7     |       |      |   | 7     |       |  |   | 8     |      
|Recognized net actuarial loss                 |                            |   | 24    |       |      |   | 12    |       |  |   |      |      
|                                              |                            |   |       |       |      |   |       |       |  |   |       |      
|                                              | Net pension benefits costs |   | $     | 3,110 |      |   | $     | 2,869 |  |   | $     | 2,390 | 
|                                              |                            |   |       |       |      |   |       |       |  |   |       |      

Other Postretirement Benefits

Effective January 1, 2001, we provide employees with certain health care
and life insurance benefits for retired employees on a contributory and
non-contributory basis (TEPPCO OPB). Employees become eligible for these
benefits if they meet certain age and service requirements at retirement, as
defined in the plans. We provide a fixed dollar contribution, which does not
increase from year to year, towards retired employee medical costs. The
retiree pays all health care cost increases due to medical inflation. We use a
December 31 measurement date for this plan.

The components of net postretirement benefits cost for the TEPPCO OPB for
the years ended December 31, 2003, 2002 and 2001, were as follows (in
thousands):

|                                                               |                                   |   |      |     |      |   |      |     |  |   |     |     | 
|-------------------------------------------------------------- | --------------------------------- | - | ---- | --- | ---- | - | ---- | --- |  | - | --- | --- | 
|                                                               |                                   |   | 2003 |     | 2002 |   | 2001
|                                                               |                                   |   |      |     |      |   |     
|Service cost benefit earned during the year                    |                                   | $ | 137  |     |      | $ | 115  |     |  | $ | 99  |    
|Interest cost on accumulated postretirement benefit obligation |                                   |   | 137  |     |      |   | 119  |     |  |   | 113 |    
|Amortization of prior service cost                             |                                   |   | 126  |     |      |   | 126  |     |  |   | 126 |    
|                                                               |                                   |   |      |     |      |   |      |     |  |   |     |    
|                                                               | Net postretirement benefits costs |   | $    | 400 |      |   | $    | 360 |  |   | $   | 338 | 
|                                                               |                                   |   |      |     |      |   |      |     |  |   |     |    

We employ a building block approach in determining the long-term rate of
return for plan assets. Historical markets are studied and long-term
historical relationships between equities and fixed-income are preserved
consistent with a widely accepted capital market principle that assets with
higher volatility generate a
greater return over the long run. Current market factors such as
inflation and interest rates are evaluated before long-term capital market
assumptions are determined. The long-term portfolio return is established via
a building block approach with proper consideration of diversification and
rebalancing. Peer data and historical returns are reviewed to check for
reasonability and appropriateness.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

The weighted average assumptions used to determine benefit obligations for
the retirement plans and other postretirement benefit plans at December 31,
2003 and 2002, were as follows:

|                                                 |  |                  |      |          |  |      |      |      |  |                      |      |   |  |  |      |  
|------------------------------------------------ |  | ---------------- | ---- | -------- |  | ---- | ---- | ---- |  | -------------------- | ---- | - |  |  | ---- | -
|                                                 |  |                  |      |          |  |      |      |      |  | Other Postretirement
|                                                 |  | Pension Benefits |      | Benefits
|                                                 |  |                  |      |         
|                                                 |  | 2003             |      | 2002     |  | 2003 |      | 2002
|                                                 |  |                  |      |          |  |      |      |     
|Discount rate                                    |  |                  | 6.25 | %        |  |      | 6.75 | %    |  |                      | 6.25 | % |  |  | 6.75 | %
|Increase in compensation levels                  |  |                  | 5.00 | %        |  |      | 5.00 | %    |  |                      |     |   |  |  |     |  
|Expected long-term rate of return on plan assets |  |                  | 8.00 | %        |  |      | 9.00 | %    |  |                      |     |   |  |  |     |  

The weighted average assumptions used to determine net periodic benefit
cost for the retirement plans and other postretirement benefit plans for the
years ended December 31, 2003 and 2002, were as follows:

|                                                 |  |                  |      |          |  |      |      |      |  |                      |      |   |  |  |      |  
|------------------------------------------------ |  | ---------------- | ---- | -------- |  | ---- | ---- | ---- |  | -------------------- | ---- | - |  |  | ---- | -
|                                                 |  |                  |      |          |  |      |      |      |  | Other Postretirement
|                                                 |  | Pension Benefits |      | Benefits
|                                                 |  |                  |      |         
|                                                 |  | 2003             |      | 2002     |  | 2003 |      | 2002
|                                                 |  |                  |      |          |  |      |      |     
|Discount rate                                    |  |                  | 6.75 | %        |  |      | 7.25 | %    |  |                      | 6.75 | % |  |  | 7.25 | %
|Increase in compensation levels                  |  |                  | 5.00 | %        |  |      | 5.00 | %    |  |                      |     |   |  |  |     |  
|Expected long-term rate of return on plan assets |  |                  | 9.00 | %        |  |      | 9.00 | %    |  |                      |     |   |  |  |     |  

The following table sets forth our pension and other postretirement
benefits changes in benefit obligation, fair value of plan assets and funded
status as of December 31, 2003 and 2002 (in thousands):

|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |        |  
|------------------------------- | ---------------------------------------------- |  | ---------------- | ------ | -------- |  | ---- | ----- | ---- |  | -------------------- | ------ | - |  | - | ------ | -
|                                |                                                |  |                  |        |          |  |      |       |      |  | Other Postretirement
|                                |                                                |  | Pension Benefits |        | Benefits
|                                |                                                |  |                  |        |         
|                                |                                                |  | 2003             |        | 2002     |  | 2003 |       | 2002
|                                |                                                |  |                  |        |          |  |      |       |     
|Change in benefit obligation    |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       
|                                | Benefit obligation at beginning of year        |  | $                | 7,578  |          |  | $    | 3,786 |      |  | $                    | 2,001  |   |  | $ | 1,781  |  
|                                | Service cost                                   |  |                  | 3,179  |          |  |      | 2,925 |      |  |                      | 137    |   |  |   | 115    |  
|                                | Interest cost                                  |  |                  | 504    |          |  |      | 315   |      |  |                      | 137    |   |  |   | 118    |  
|                                | Actuarial (gain)/loss                          |  |                  | 236    |          |  |      | 711   |      |  |                      | 209    |   |  |   | 1      |  
|                                | Retiree contributions                          |  |                  |       |          |  |      |      |      |  |                      | 54     |   |  |   | 29     |  
|                                | Benefits paid                                  |  |                  | (241   | )        |  |      | (159  | )    |  |                      | (71    | ) |  |   | (43    | )
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |        |  
|                                | Benefit obligation at end of year              |  | $                | 11,256 |          |  | $    | 7,578 |      |  | $                    | 2,467  |   |  | $ | 2,001  |  
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       
|Change in plan assets           |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       
|                                | Fair value of plan assets at beginning of year |  | $                | 6,820  |          |  | $    | 3,959 |      |  | $                    |       |   |  | $ |       |  
|                                | Actual return on plan assets                   |  |                  | 650    |          |  |      | (99   | )    |  |                      |       |   |  |   |       |  
|                                | Retiree contributions                          |  |                  |       |          |  |      |      |      |  |                      | 54     |   |  |   | 29     |  
|                                | Employer contributions                         |  |                  | 3,692  |          |  |      | 3,119 |      |  |                      | 17     |   |  |   | 14     |  
|                                | Benefits paid                                  |  |                  | (241   | )        |  |      | (159  | )    |  |                      | (71    | ) |  |   | (43    | )
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |        |  
|                                | Fair value of plan assets at end of year       |  | $                | 10,921 |          |  | $    | 6,820 |      |  | $                    |       |   |  | $ |       |  
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       
|Reconciliation of funded status |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       
|                                | Funded status                                  |  | $                | (335   | )        |  | $    | (758  | )    |  | $                    | (2,467 | ) |  | $ | (2,001 | )
|                                | Unrecognized prior service cost                |  |                  | 40     |          |  |      | 47    |      |  |                      | 1,129  |   |  |   | 1,255  |  
|                                | Unrecognized actuarial loss                    |  |                  | 1,421  |          |  |      | 1,255 |      |  |                      | 267    |   |  |   | 58     |  
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |        |  
|                                | Net amount recognized                          |  | $                | 1,126  |          |  | $    | 544   |      |  | $                    | (1,071 | ) |  | $ | (688   | )
|                                |                                                |  |                  |        |          |  |      |       |      |  |                      |        |   |  |   |       

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

Plan Assets

We employ a total return investment approach whereby a mix of equities and
fixed income investments are used to maximize the long-term return of plan
assets for a prudent level of risk. Risk tolerance is established through
careful consideration of plan liabilities, plan funded status and corporate
financial condition. The investment portfolio contains a diversified blend of
equity and fixed-income investments. Furthermore, equity investments are
diversified across U.S. and non-U.S. stocks, both growth and value equity
style, and small, mid and large capitalizations. Investment risk and return
parameters are reviewed and evaluated periodically to ensure compliance with
stated investment objectives and guidelines. This comprehensive review
incorporates investment portfolio performance, annual liability measurements
and periodic asset/liability studies.

The following table sets forth the weighted average asset allocations for
the retirement plans and other postretirement benefit plans as of December 31,
2003 and 2002, by asset category (in thousands):

|                              |       |      |              |      |   |  |    |     |  
|----------------------------- | ----- | ---- | ------------ | ---- | - |  | -- | --- | -
|                              |       |      | December 31,
|                              |       |      |             
|Asset Category                |       | 2003 |              | 2002
|                              |       |      |              |     
|Equity securities             |       |      | 47           | %    |   |  | 21 | %  
|Debt securities               |       |      | 30           | %    |   |  | 56 | %  
|Other (money market and cash) |       |      | 23           | %    |   |  | 23 | %  
|                              |       |      |              |      |   |  |    |    
|                              | Total |      |              | 100  | % |  |    | 100 | %
|                              |       |      |              |      |   |  |    |    

We expect to contribute approximately $3.0 million to our retirement plans
and other postretirement benefit plans in 2004.

Other Plans

DEFS also sponsors an employee savings plan, which covers substantially
all employees. Plan contributions on behalf of the Company of $3.2 million,
$2.8 million and $3.1 million were recognized during the years ended December
31, 2003, 2002 and 2001, respectively.

NOTE 17. COMMITMENTS AND CONTINGENCIES

In the fall of 1999 and on December 1, 2000, the General Partner and the
Partnership were named as defendants in two separate lawsuits in Jackson County
Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S.
McCleery, et al. v. Texas Eastern Corporation, et al.(including the General
Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas
Eastern Corporation, et al.(including the General Partner and Partnership).
In both cases, the plaintiffs contend, among other things, that we and other
defendants stored and disposed of toxic and hazardous substances and hazardous
wastes in a manner that caused the materials to be released into the air, soil
and water. They further contend that the release caused damages to the
plaintiffs. In their complaints, the plaintiffs allege strict liability for
both personal injury and property damage together with gross negligence,
continuing nuisance, trespass, criminal mischief and loss of consortium. The
plaintiffs are seeking
compensatory, punitive and treble damages. We have filed an answer to
both complaints, denying the allegations, as well as various other motions.
These cases are not covered by insurance. Discovery is ongoing, and we are
defending ourselves vigorously against the lawsuits. The plaintiffs have not
stipulated the amount of damages that they are seeking in the suits. We cannot
estimate the loss, if any, associated with these pending lawsuits.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in
the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L.
Grisham et al. v. TE Products Pipeline Company, Limited

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

Partnership. In this case, the plaintiffs contend that our pipeline, which
crosses the plaintiffs property, leaked toxic products onto their property
and, consequently caused damages to them. We have filed an answer to the
plaintiffs petition denying the allegations, and we are defending ourselves
vigorously against the lawsuit. The plaintiffs have not stipulated the amount
of damages they are seeking in the suit; however, this case is covered by
insurance. We do not believe that the outcome of this lawsuit will have a
material adverse effect on our financial position, results of operations or
cash flows.

On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P.,
filed a declaratory judgment action in the U.S. District Court for the Western
District of Oklahoma against D.R.D. Environmental Services, Inc. (D.R.D.)
seeking resolution of billing and other contractual disputes regarding
potential overcharges for environmental remediation services provided by D.R.D.
On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in
the amount of $2,243,525, and for unspecified damages for alleged tortious
interference with D.R.D.s contractual relations with DEFS. On July 16, 2003,
the parties entered into a Settlement Agreement and Mutual Release, dismissing
all claims and counterclaims against each other. The terms of the Settlement
Agreement and Mutual Release did not have a material adverse effect on our
financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit
styled John R. James, et al. v. J Graves Insulation Company, et al.as filed in
the first Judicial District Court, Caddo Parish, Louisiana. There are numerous
plaintiffs identified in the action that are alleged to have suffered damages
as the result of alleged exposure to asbestos-containing products and
materials. According to the petition and as a result of a preliminary
investigation, the General Partner believes that the only claim asserted
against it results from one individual for the period from July 1971 through
June 1972, who is alleged to have worked on a facility owned by the General
Partners predecessor. This period represents a small portion of the total
alleged exposure period from January 1964 through December 2001 for this
individual. The individuals claims involve numerous employers and alleged job
sites. Currently, the General Partner has been unable to confirm involvement
by the General Partner or its predecessors with the alleged location, and it is
currently uncertain whether this case is covered by insurance. Discovery is
planned, and the General Partner intends to defend itself vigorously against
this lawsuit. The plaintiffs have not stipulated the amount of damages that
they are seeking in this suit. We are obligated to reimburse the General
Partner for any costs it incurs related to this lawsuit. We cannot estimate
the loss, if any, associated with this pending lawsuit. We do not believe that
the outcome of this lawsuit will have a material adverse effect on our
financial position, results of operations or cash flows.

On April 2, 2003, Centennial was served with a petition in a matter styled
Adams, et al. v. Centennial Pipeline Company LLC, et al. This
matter involves
approximately 2,000 plaintiffs who allege that over 200 defendants, including
Centennial, generated, transported, and/or disposed of hazardous and toxic
waste at two sites in Bayou Sorrell, Louisiana, an underground injection well
and a landfill. The plaintiffs allege personal injuries, allergies, birth
defects, cancer and death. The underground injection well has been in
operation since May 1976. Based upon current information, Centennial
appears to be a de minimis contributor, having used the disposal
site during the two month time period of December 2001 to January
2002. Marathon has been handling this
matter for Centennial under its operating agreement with Centennial. TE
Products has a 50% ownership interest in Centennial. Based upon
Centennial's limited involvement with the disposal site, we do not
believe that the outcome of this
matter will have a material adverse effect on our financial position,
results of operations or cash flows.

On December 16, 2003, Centennial, the General Partner, the Partnership and
other Partnership entities were named as defendants in a lawsuit in the 128th
District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial
Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline
leaked toxic substances on their
property, causing them property damage. We have filed an answer to the
plaintiffs petition, denying the allegations, and we are defending ourselves
vigorously against this lawsuit. This case is covered by insurance. We do not
believe that the outcome of this lawsuit will have a material adverse effect on
our financial position, results of operations or cash flows.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

In addition to the litigation discussed above, we have 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. We believe that the outcome of these lawsuits and other
proceedings will not individually or in the aggregate have a material adverse
effect on our consolidated financial position, results of operations or cash
flows.

Our operations are subject to federal, state and local laws and
regulations governing the discharge of materials into the environment. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, imposition of injunctions
delaying or prohibiting certain activities and the need to perform
investigatory and remedial activities. Although we believe our operations are
in material compliance with applicable environmental laws and regulations,
risks of significant costs and liabilities are inherent in pipeline operations,
and we cannot assure you 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 our
operations, could result in substantial costs and liabilities to us. We
believe that changes in environmental laws and regulations will not have a

material adverse effect on our financial position, results of operations or
cash flows in the near term.

On
February 6, 2004, a lawsuit styled San Juan Citizens Alliance et
al. v. Nortan et al. was filed against the United States Department
of Interior and the Bureau of Land Management (BLM) in
the U.S. District Court, District of Columbia, challenging a recent
decision by the BLM. In that decision, the BLM adopted a Resource
Management Plan, which authorized the development of additional gas
wells on public lands in northwestern New Mexico. A substantial
portion of the development activity in the area that is the subject
of the suit involves the infill drilling in the Basin-Fruitland Coal
Gas Pool which covers most of the San Juan Basin. We believe the BLM
followed the requirements of the law and reached a balanced decision
in adopting the Resource Management Plan. However, an adverse
decision could impact infill drilling activities in the San Juan
Basin.

In 1994, the Louisiana Department of Environmental Quality (LDEQ) issued
a compliance order for environmental contamination at our Arcadia, Louisiana,
facility. This contamination may be attributable to our operations, as well as
to adjacent petroleum terminals operated by other companies. In 1999, our
Arcadia facility and adjacent terminals were directed by the Remediation
Services Division of the LDEQ to pursue remediation of this contamination. At
December 31, 2003, we have an accrued liability of $0.3 million for remediation
costs at our Arcadia facility. We do not expect that the completion of the
remediation program proposed to the LDEQ will have a future material adverse
effect on our financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel
from a storage tank at our Blue Island terminal located in Cook County,
Illinois. As a result of the release, we have entered into an Agreed Order
with the State of Illinois. The Agreed Order requires us, in part, to complete
a site investigation plan to delineate the scope of any potential contamination
resulting from the release and to remediate any contamination present above
regulatory standards. This site investigation plan has been completed and
submitted to the State of Illinois. The Agreed Order does not contain any
provision for any fines or penalties; however, it does not preclude the State
of Illinois from assessing these at a later date. We do not expect that the
completion of the remediation program will have a future material adverse
effect on our financial position, results of operations or cash flows.

At December 31, 2003, we have an accrued liability of $5.9 million related
to various TCTM sites requiring environmental remediation activities. Under
the terms of a 1998 agreement through which we acquired various crude oil
assets from DETTCO, we received a five year contractual indemnity obligation
for environmental liabilities not otherwise assumed by us that were
attributable to the operations of the assets prior to our acquisition. The
indemnity expired on November 30, 2003. Under the agreement, we were
responsible for the first $3.0 million in environmental liabilities covered by
DETTCOs indemnification obligation, and DETTCO was responsible for specified
environmental liabilities in excess of $3.0 million, up to a maximum amount of
$25.0 million. At December 31, 2002, we had a receivable balance from DETTCO
of $4.2 million, the majority of which related to remediation activities at the
Velma, Oklahoma crude oil site. On March 31, 2003, we received a $2.4 million
payment from DETTCO for environmental liabilities we incurred that were covered
under the indemnity obligation with DETTCO. The remaining $1.8 million due was
determined as not attributable to DETTCOs indemnity obligation as a result of
settlement discussions with DETTCO on this matter and was written off. On
December 1, 2003, concurrent with the expiration of the five year contractual
indemnity obligation, we entered into a Settlement
Agreement and Release with DETTCO regarding future obligations pertaining
to various environmental liabilities associated with the assets purchased from
DETTCO in 1998. The agreement provided for a net payment of $1.3 million to us
from DETTCO, which consisted of a settlement of $2.0 million for remaining
crude oil sites, partially offset by the sharing of expenses of $1.0 million
which were incurred by DETTCO in remediation of a crude oil site in Stephens
County, Oklahoma. The agreement also provided for $0.3 million toward the
purchase of an

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

environmental insurance policy for gathering systems located in Texas and
Oklahoma and the assumption of responsibility by DETTCO for environmental
liabilities associated with three sites located in Texas and Oklahoma. We do
not expect that the completion of remediation programs associated with TCTM
activities will have a future material adverse effect on our financial
position, results of operations or cash flows.

Centennial entered into credit facilities totaling $150.0 million, and as
of December 31, 2003, $150.0 million was outstanding under those credit
facilities. The proceeds were used to fund construction and conversion costs
of its pipeline system. TE Products and Marathon have each guaranteed one-half
of Centennials debt, up to a maximum amount of $75.0 million each.

Rates of interstate petroleum products and crude oil pipeline companies,
like us, are currently regulated by the FERC primarily through an index
methodology, which allows a pipeline to change its rates based on the change
from year to year in the Producer Price Index for finished goods (PPI Index).
Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index
from PPI  1% to PPI. On April 22, 2003, several shippers filed a petition in
the United States Court of Appeals for the District of Columbia Circuit, Flying
J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and
Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107,
seeking a review of whether the FERCs adoption of the PPI Index was reasonable
and supported by the evidence. Oral arguments are scheduled for early 2004.

As an alternative to using the PPI Index, interstate petroleum products
and crude 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 petroleum products and crude oil pipeline
companies that the rate is acceptable.

Substantially all of the petroleum products that we transport and store
are owned by our customers. At December 31, 2003, TCTM and TE Products had
approximately 3.2 million barrels and 17.3 million barrels, respectively, of
products in their custody that was owned by customers. We are obligated for
the transportation, storage and delivery of such products on behalf of our
customers. We maintain insurance adequate to cover product losses through
circumstances beyond our control.

We carry insurance coverage consistent with companies engaged in similar
operations with similar type properties. Our insurance coverage includes (1)
commercial general public liability insurance for liabilities to third
parties for bodily injury and property damage resulting from our operations;
(2) workers compensation liability coverage to required statutory limits; (3)
automobile liability insurance for all owned, non-owned and hired vehicles
covering liabilities to third parties for bodily injury and property damage,
and (4) property insurance covering the replacement value of all real and
personal property damage, including damages arising from earthquake, flood
damage and business interruption/extra expense. For select assets, we also
carry pollution liability insurance that provides coverage for historical and
gradual pollution events. All coverages are subject to certain deductibles,
terms and conditions common for companies with similar types of operations.

We also maintain excess liability insurance coverage above the established
primary limits for commercial general liability and automobile liability
insurance. Limits, terms, conditions and deductibles are comparable to those
carried by other energy companies of similar size. The cost of our general
insurance coverages continued to fluctuate over the past year reflecting the
changing conditions of the insurance markets. These insurance policies, except
for the pollution liability policies, are with Bison Insurance Company Limited,
an insurance company that is wholly owned by Duke Energy (see Note 8. Related
Parties).

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

NOTE 18. SEGMENT INFORMATION

We have three reporting segments: transportation and storage of refined
products, LPGs and petrochemicals, which operates as the Downstream Segment;
gathering, transportation, marketing and storage of crude oil and distribution
of lubrication oils and specialty chemicals, which operates as the Upstream
Segment; and gathering of natural gas, fractionation of NGLs and transportation
of NGLs, which operates as the Midstream Segment. The amounts indicated below
as Partnership and Other relate primarily to intersegment eliminations and
assets that we hold that have not been allocated to any of our reporting
segments.

Our Downstream Segment revenues are earned from transportation and storage
of refined products and LPGs, intrastate transportation of petrochemicals, sale
of product inventory and other ancillary services. The two largest operating
expense items of the Downstream Segment are labor and electric power. We
generally realize higher revenues during the first and fourth quarters of each
year since our operations are somewhat seasonal. 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. Our Downstream
Segment also includes the results of operations of the northern portion of the
Dean Pipeline. Beginning in January 2003, the northern portion of the Dean
Pipeline was converted to transport refinery grade propylene (RGP) from Mont
Belvieu to Point Comfort, Texas. As a result, the revenues and expenses of the
northern portion of the Dean Pipeline are included in the Downstream Segment.
Our Downstream Segment also includes our equity investments in Centennial and
MB Storage (see Note 7. Equity Investments).

Our Upstream Segment revenues are earned from gathering, transportation,
marketing and storage of crude oil and distribution of lubrication oils and
specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky
Mountain region. Marketing operations consist primarily of aggregating
purchased crude oil along our pipeline systems, or from third party pipeline
systems, and arranging the necessary transportation logistics for the ultimate
sale of the crude oil to local refineries, marketers or other end users. Our
Upstream Segment also includes our equity investment in Seaway. Seaway
consists of large diameter pipelines that transport crude oil from Seaways
marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil
distribution point for the central United States, and to refineries in the
Texas City and Houston areas.

Our Midstream Segment revenues are earned from the fractionation of NGLs
in Colorado, transportation of NGLs from two trunkline NGL pipelines in South
Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from
West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the
Green River Basin in southwestern Wyoming, through Jonah and the gathering of
CBM in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS
manages and operates the Val Verde, Jonah and Chaparral assets for us under
contractual agreements. The results of operations of the Chaparral and Val
Verde acquisitions are included in periods subsequent to their respective
acquisition dates (see Note 6. Acquisitions and Dispositions).

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

The tables below include financial information by reporting segment for
the years ended December 31, 2003, 2002 and 2001 (in thousands):

|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |     |   |   |           |         | 
|------------------------------------- | ------------------------ | - | ---------------------------- | ------ | -------- | - | --------- | ------ | -------- | - | ----------- | ------ | ------------ | - | --------- | ------- |  | - | ------ | --- | - | - | --------- | ------- | 
|                                      |                          |   | Year Ended December 31, 2003
|                                      |                          |   |                             
|                                      |                          |   | Downstream                   |        | Upstream |   | Midstream |        | Segments |   | Partnership |        |              |   |          
|                                      |                          |   | Segment                      |        | Segment  |   | Segment   |        | Total    |   | and Other   |        | Consolidated
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |             
|Revenues                              |                          | $ | 266,427                      |        |          | $ | 3,806,215 |        |          | $ | 185,105     |        |              | $ | 4,257,747 |         |  | $ | (1,915 | )   |   | $ | 4,255,832 |        
|Purchases of petroleum
products       |                          |   |                             |        |          |   | 3,713,122 |        |          |   |            |        |              |   | 3,713,122 |         |  |   | (1,915 | )   |   |   | 3,711,207 |        
|Operating expenses,
including power   |                          |   | 151,103                      |        |          |   | 57,314    |        |          |   | 47,020      |        |              |   | 255,437   |         |  |   |       |     |   |   | 255,437   |        
|Depreciation and
amortization expense |                          |   | 31,620                       |        |          |   | 11,311    |        |          |   | 57,797      |        |              |   | 100,728   |         |  |   |       |     |   |   | 100,728   |        
|Gain on sale of assets                |                          |   |                             |        |          |   | (3,948    | )      |          |   |            |        |              |   | (3,948    | )       |  |   |       |     |   |   | (3,948    | )      
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |     |   |   |           |        
|                                      | Operating income         |   |                              | 83,704 |          |   |           | 28,416 |          |   |             | 80,288 |              |   |           | 192,408 |  |   |        |    |   |   |           | 192,408 | 
|Equity earnings (losses)              |                          |   | (4,086                       | )      |          |   | 20,949    |        |          |   |            |        |              |   | 16,863    |         |  |   |       |     |   |   | 16,863    |        
|Other income, net                     |                          |   | 226                          |        |          |   | 306       |        |          |   | 289         |        |              |   | 821       |         |  |   | (73    | )   |   |   | 748       |        
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |     |   |   |           |        
|                                      | Earnings before interest |   | $                            | 79,844 |          |   | $         | 49,671 |          |   | $           | 80,577 |              |   | $         | 210,092 |  |   | $      | (73 | ) |   | $         | 210,019 | 
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |     |   |   |           |        

|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |      |   |   |           |         | 
|------------------------------------- | ------------------------ | - | ---------------------------- | ------ | -------- | - | --------- | ------ | -------- | - | ----------- | ------ | ------------ | - | --------- | ------- |  | - | ------ | ---- | - | - | --------- | ------- | 
|                                      |                          |   | Year Ended December 31, 2002
|                                      |                          |   |                             
|                                      |                          |   | Downstream                   |        | Upstream |   | Midstream |        | Segments |   | Partnership |        |              |   |          
|                                      |                          |   | Segment                      |        | Segment  |   | Segment   |        | Total    |   | and Other   |        | Consolidated
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |             
|Revenues                              |                          | $ | 243,538                      |        |          | $ | 2,861,700 |        |          | $ | 138,922     |        |              | $ | 3,244,160 |         |  | $ | (1,997 | )    |   | $ | 3,242,163 |        
|Purchases of petroleum
products       |                          |   |                             |        |          |   | 2,774,325 |        |          |   |            |        |              |   | 2,774,325 |         |  |   | (1,997 | )    |   |   | 2,772,328 |        
|Operating expenses,
including power   |                          |   | 130,324                      |        |          |   | 49,781    |        |          |   | 33,451      |        |              |   | 213,556   |         |  |   |       |      |   |   | 213,556   |        
|Depreciation and
amortization expense |                          |   | 30,116                       |        |          |   | 11,186    |        |          |   | 44,730      |        |              |   | 86,032    |         |  |   |       |      |   |   | 86,032    |        
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |      |   |   |           |        
|                                      | Operating income         |   |                              | 83,098 |          |   |           | 26,408 |          |   |             | 60,741 |              |   |           | 170,247 |  |   |        |     |   |   |           | 170,247 | 
|Equity earnings (losses)              |                          |   | (6,815                       | )      |          |   | 18,795    |        |          |   |            |        |              |   | 11,980    |         |  |   |       |      |   |   | 11,980    |        
|Other income, net                     |                          |   | 832                          |        |          |   | 1,532     |        |          |   | 269         |        |              |   | 2,633     |         |  |   | (806   | )    |   |   | 1,827     |        
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |      |   |   |           |        
|                                      | Earnings before interest |   | $                            | 77,115 |          |   | $         | 46,735 |          |   | $           | 61,010 |              |   | $         | 184,860 |  |   | $      | (806 | ) |   | $         | 184,054 | 
|                                      |                          |   |                              |        |          |   |           |        |          |   |             |        |              |   |           |         |  |   |        |      |   |   |           |        

|                                      |                          |   |                              |         |          |   |           |        |          |   |             |        |              |   |           |         |  |   |      |   |  |   |           |         | 
|------------------------------------- | ------------------------ | - | ---------------------------- | ------- | -------- | - | --------- | ------ | -------- | - | ----------- | ------ | ------------ | - | --------- | ------- |  | - | ---- | - |  | - | --------- | ------- | 
|                                      |                          |   | Year Ended December 31, 2001
|                                      |                          |   |                             
|                                      |                          |   | Downstream                   |         | Upstream |   | Midstream |        | Segments |   | Partnership |        |              |   |          
|                                      |                          |   | Segment                      |         | Segment  |   | Segment   |        | Total    |   | and Other   |        | Consolidated
|                                      |                          |   |                              |         |          |   |           |        |          |   |             |        |             
|Revenues                              |                          | $ | 264,233                      |         |          | $ | 3,255,260 |        |          | $ | 37,242      |        |              | $ | 3,556,735 |         |  | $ | (322 | ) |  | $ | 3,556,413 |        
|Purchases of petroleum
products       |                          |   |                             |         |          |   | 3,173,127 |        |          |   |            |        |              |   | 3,173,127 |         |  |   | (322 | ) |  |   | 3,172,805 |        
|Operating expenses,
including power   |                          |   | 119,858                      |         |          |   | 54,578    |        |          |   | 11,482      |        |              |   | 185,918   |         |  |   |     |   |  |   | 185,918   |        
|Depreciation and
amortization expense |                          |   | 26,699                       |         |          |   | 9,263     |        |          |   | 9,937       |        |              |   | 45,899    |         |  |   |     |   |  |   | 45,899    |        
|                                      |                          |   |                              |         |          |   |           |        |          |   |             |        |              |   |           |         |  |   |      |   |  |   |           |        
|                                      | Operating income         |   |                              | 117,676 |          |   |           | 18,292 |          |   |             | 15,823 |              |   |           | 151,791 |  |   |      |  |  |   |           | 151,791 | 
|Equity earnings (losses)              |                          |   | (1,149                       | )       |          |   | 18,547    |        |          |   |            |        |              |   | 17,398    |         |  |   |     |   |  |   | 17,398    |        
|Other income, net                     |                          |   | 1,537                        |         |          |   | 1,188     |        |          |   | 74          |        |              |   | 2,799     |         |  |   |     |   |  |   | 2,799     |        
|                                      |                          |   |                              |         |          |   |           |        |          |   |             |        |              |   |           |         |  |   |      |   |  |   |           |        
|                                      | Earnings before interest |   | $                            | 118,064 |          |   | $         | 38,027 |          |   | $           | 15,897 |              |   | $         | 171,988 |  |   | $    |  |  |   | $         | 171,988 | 
|                                      |                          |   |                              |         |          |   |           |        |          |   |             |        |              |   |           |         |  |   |      |   |  |   |           |        

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##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

The following table provides the total assets, capital expenditures and
significant non-cash investing activities for each segment as of and for the
years ended December 31, 2003, 2002 and 2001 (in thousands):

|                   |                               |  |            |         |          |  |           |         |          |  |             |           |              |  |   |           |  |  |   |         |   |  |   |           | 
|------------------ | ----------------------------- |  | ---------- | ------- | -------- |  | --------- | ------- | -------- |  | ----------- | --------- | ------------ |  | - | --------- |  |  | - | ------- | - |  | - | --------- | 
|                   |                               |  | Downstream |         | Upstream |  | Midstream |         | Segments |  | Partnership |           |              |  |  
|                   |                               |  | Segment    |         | Segment  |  | Segment   |         | Total    |  | and Other   |           | Consolidated
|                   |                               |  |            |         |          |  |           |         |          |  |             |           |             
|December 31, 2003: |                               |  |            |         |          |  |           |         |          |  |             |           |              |  |   |           |  |  |   |         |   |  |   |          
|                   | Total assets                  |  | $          | 916,917 |          |  | $         | 834,502 |          |  | $           | 1,194,844 |              |  | $ | 2,946,263 |  |  | $ | (5,271  | ) |  | $ | 2,940,992 | 
|                   | Capital expenditures          |  |            | 59,061  |          |  |           | 13,427  |          |  |             | 67,882    |              |  |   | 140,370   |  |  |   | 147     |   |  |   | 140,517   | 
|                   | Non-cash investing activities |  |            | 61,408  |          |  |           |        |          |  |             |          |              |  |   | 61,408    |  |  |   |        |   |  |   | 61,408    | 
|December 31, 2002: |                               |  |            |         |          |  |           |         |          |  |             |           |              |  |   |           |  |  |   |         |   |  |   |          
|                   | Total assets                  |  | $          | 881,101 |          |  | $         | 724,860 |          |  | $           | 1,174,139 |              |  | $ | 2,780,100 |  |  | $ | (11,678 | ) |  | $ | 2,768,422 | 
|                   | Capital expenditures          |  |            | 60,900  |          |  |           | 10,212  |          |  |             | 62,260    |              |  |   | 133,372   |  |  |   |        |   |  |   | 133,372   | 
|December 31, 2001: |                               |  |            |         |          |  |           |         |          |  |             |           |              |  |   |           |  |  |   |         |   |  |   |          
|                   | Total assets                  |  | $          | 844,036 |          |  | $         | 694,934 |          |  | $           | 541,195   |              |  | $ | 2,080,165 |  |  | $ | (14,817 | ) |  | $ | 2,065,348 | 
|                   | Capital expenditures          |  |            | 81,410  |          |  |           | 13,987  |          |  |             | 12,217    |              |  |   | 107,614   |  |  |   |        |   |  |   | 107,614   | 

The following table reconciles the segments total earnings before interest
to consolidated net income for the three years ended December 31, 2003, 2003
and 2001 (in thousands):

|                         |            |   |                          |         |      |   |         |         |  |   |         |         | 
|------------------------ | ---------- | - | ------------------------ | ------- | ---- | - | ------- | ------- |  | - | ------- | ------- | 
|                         |            |   | Years Ended December 31,
|                         |            |   |                         
|                         |            |   | 2003                     |         | 2002 |   | 2001   
|                         |            |   |                          |         |      |   |        
|Earnings before interest |            | $ | 210,019                  |         |      | $ | 184,054 |         |  | $ | 171,988 |        
|Interest expense  net   |            |   | (84,250                  | )       |      |   | (66,192 | )       |  |   | (62,057 | )      
|Minority interest        |            |   |                         |         |      |   |        |         |  |   | (800    | )      
|                         |            |   |                          |         |      |   |         |         |  |   |         |        
|                         | Net income |   | $                        | 125,769 |      |   | $       | 117,862 |  |   | $       | 109,131 | 
|                         |            |   |                          |         |      |   |         |         |  |   |         |        

NOTE 19. COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Incomerequires certain items such
as foreign currency translation adjustments, minimum pension liability
adjustments and unrealized gains and losses on certain investments to be
reported in a financial statement. As of and for the years ended December 31,
2003, 2002 and 2001, the components of comprehensive income were due to the
interest rate swap related to our variable rate revolving credit facility,
which is designated as a cash flow hedge. Changes in the fair value of the
cash flow hedge, to the extent the hedge is effective, are recognized in other
comprehensive income until the hedge interest costs are recognized in earnings.
The table below reconciles reported net income to total comprehensive income
for the years ended December 31, 2003, 2002 and 2001 (in thousands).

|                                                       |                            |   |                          |         |      |   |         |         |  |   |         |        | 
|------------------------------------------------------ | -------------------------- | - | ------------------------ | ------- | ---- | - | ------- | ------- |  | - | ------- | ------ | 
|                                                       |                            |   | Years Ended December 31,
|                                                       |                            |   |                         
|                                                       |                            |   | 2003                     |         | 2002 |   | 2001   
|                                                       |                            |   |                          |         |      |   |        
|Net income                                             |                            | $ | 125,769                  |         |      | $ | 117,862 |         |  | $ | 109,131 |       
|Cumulative effect attributable to adoption of SFAS 133 |                            |   |                         |         |      |   |        |         |  |   | (10,103 | )     
|Net income (loss) on cash flow hedge                   |                            |   | 16,164                   |         |      |   | 269     |         |  |   | (10,221 | )     
|                                                       |                            |   |                          |         |      |   |         |         |  |   |         |       
|                                                       | Total comprehensive income |   | $                        | 141,933 |      |   | $       | 118,131 |  |   | $       | 88,807 | 
|                                                       |                            |   |                          |         |      |   |         |         |  |   |         |       

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##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

The accumulated balance of other comprehensive loss related to our cash
flow hedge is as follows (in thousands):

|                             |                                                                 |   |         |         |  
|---------------------------- | --------------------------------------------------------------- | - | ------- | ------- | -
|Balance at December 31, 2000 |                                                                 | $ |        |        
|                             | Cumulative effect of accounting change                          |   |         | (10,103 | )
|                             | Transferred to earnings                                         |   |         | 6,790   |  
|                             | Change in fair value of cash flow hedge                         |   |         | (17,011 | )
|                             |                                                                 |   |         |        
|Balance at December 31, 2001 |                                                                 | $ | (20,324 | )      
|                             | Transferred to earnings                                         |   |         | 12,883  |  
|                             | Change in fair value of cash flow hedge                         |   |         | (12,614 | )
|                             |                                                                 |   |         |        
|Balance at December 31, 2002 |                                                                 | $ | (20,055 | )      
|                             | Reclassification due to discontinued portion of cash flow hedge |   |         | 989     |  
|                             | Transferred to earnings                                         |   |         | 14,417  |  
|                             | Change in fair value of cash flow hedge                         |   |         | 1,747   |  
|                             |                                                                 |   |         |        
|Balance at December 31, 2003 |                                                                 | $ | (2,902  | )      
|                             |                                                                 |   |         |        

NOTE 20. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our significant operating subsidiaries, TE Products Pipeline Company,
Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas
Gathering Company and Val Verde Gas Gathering Company, L.P., have issued
unconditional guarantees of our debt securities. The guarantees are full,
unconditional, and joint and several. TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering
Company and Val Verde Gas Gathering Company, L.P. are collectively referred to
as the Guarantor Subsidiaries.

The following supplemental condensed consolidating financial information
reflects our separate accounts, the combined accounts of the Guarantor
Subsidiaries, the combined accounts of our other non-guarantor subsidiaries,
the combined consolidating adjustments and eliminations and our consolidated
accounts for the dates and periods indicated. For purposes of the following
consolidating information, our investments in our subsidiaries and the
Guarantor Subsidiaries investments in their subsidiaries are accounted for
under the equity method of accounting.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |           | 
|--------------------------------- | ----------------------------------- | --------------------------------------- | - | ----------------- | --------- | ------------ | - | ------------- | --------- | ------------- | - | -------------- | --------- |  | - | ---------- | ---------- | - | - | --------- | --------- | 
|                                  |                                     |                                         |   | December 31, 2003
|                                  |                                     |                                         |   |                  
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   | TEPPCO   
|                                  |                                     |                                         |   | TEPPCO            |           | Guarantor    |   | Non-Guarantor |           | Consolidating |   | Partners, L.P.
|                                  |                                     |                                         |   | Partners, L.P.    |           | Subsidiaries |   | Subsidiaries  |           | Adjustments   |   | Consolidated  
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |               
|                                  |                                     |                                         |   | (in thousands)   
|Assets                            |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|                                  | Current assets                      |                                         | $ | 38,281            |           |              | $ | 92,817        |           |               | $ | 360,564        |           |  | $ | (38,844    | )          |   | $ | 452,818   |          
|                                  | Property, plant and equipment  net |                                         |   |                  |           |              |   | 1,146,455     |           |               |   | 472,708        |           |  |   |           |            |   |   | 1,619,163 |          
|                                  | Equity investments                  |                                         |   | 1,112,252         |           |              |   | 404,886       |           |               |   | 209,438        |           |  |   | (1,361,290 | )          |   |   | 365,286   |          
|                                  | Intercompany notes receivable       |                                         |   | 943,447           |           |              |   |              |           |               |   |               |           |  |   | (943,447   | )          |   |   |          |          
|                                  | Intangible assets                   |                                         |   |                  |           |              |   | 401,404       |           |               |   | 37,161         |           |  |   |           |            |   |   | 438,565   |          
|                                  | Other assets                        |                                         |   | 6,157             |           |              |   | 21,444        |           |               |   | 37,559         |           |  |   |           |            |   |   | 65,160    |          
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |          
|                                  |                                     | Total assets                            |   | $                 | 2,100,137 |              |   | $             | 2,067,006 |               |   | $              | 1,117,430 |  |   | $          | (2,343,581 | ) |   | $         | 2,940,992 | 
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|Liabilities and partners capital |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|                                  | Current liabilities                 |                                         | $ | 41,895            |           |              | $ | 105,285       |           |               | $ | 367,260        |           |  | $ | (38,849    | )          |   | $ | 475,591   |          
|                                  | Long-term debt                      |                                         |   | 947,486           |           |              |   | 392,164       |           |               |   |               |           |  |   |           |            |   |   | 1,339,650 |          
|                                  | Intercompany notes payable          |                                         |   |                  |           |              |   | 557,842       |           |               |   | 385,604        |           |  |   | (943,446   | )          |   |   |          |          
|                                  | Other long term liabilities         |                                         |   | 1,435             |           |              |   | 14,995        |           |               |   |               |           |  |   |           |            |   |   | 16,430    |          
|                                  | Total partners capital             |                                         |   | 1,109,321         |           |              |   | 996,720       |           |               |   | 364,566        |           |  |   | (1,361,286 | )          |   |   | 1,109,321 |          
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |          
|                                  |                                     | Total liabilities and partners
capital |   | $                 | 2,100,137 |              |   | $             | 2,067,006 |               |   | $              | 1,117,430 |  |   | $          | (2,343,581 | ) |   | $         | 2,940,992 | 
|                                  |                                     |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          

|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |           | 
|--------------------------------- | ---------------------------------------------- | --------------------------------------- | - | ----------------- | --------- | ------------ | - | ------------- | --------- | ------------- | - | -------------- | --------- |  | - | ---------- | ---------- | - | - | --------- | --------- | 
|                                  |                                                |                                         |   | December 31, 2002
|                                  |                                                |                                         |   |                  
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   | TEPPCO   
|                                  |                                                |                                         |   | TEPPCO            |           | Guarantor    |   | Non-Guarantor |           | Consolidating |   | Partners, L.P.
|                                  |                                                |                                         |   | Partners, L.P.    |           | Subsidiaries |   | Subsidiaries  |           | Adjustments   |   | Consolidated  
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |               
|                                  |                                                |                                         |   | (in thousands)   
|Assets                            |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|                                  | Current assets                                 |                                         | $ | 241               |           |              | $ | 90,578        |           |               | $ | 286,379        |           |  | $ | (18,851    | )          |   | $ | 358,347   |          
|                                  | Property, plant and equipment  net            |                                         |   |                  |           |              |   | 1,128,803     |           |               |   | 459,021        |           |  |   |           |            |   |   | 1,587,824 |          
|                                  | Equity investments                             |                                         |   | 1,011,935         |           |              |   | 846,991       |           |               |   | 211,229        |           |  |   | (1,785,450 | )          |   |   | 284,705   |          
|                                  | Intercompany notes receivable                  |                                         |   | 986,852           |           |              |   |              |           |               |   |               |           |  |   | (986,852   | )          |   |   |          |          
|                                  | Intangible assets                              |                                         |   |                  |           |              |   | 434,941       |           |               |   | 30,433         |           |  |   |           |            |   |   | 465,374   |          
|                                  | Other assets                                   |                                         |   | 6,200             |           |              |   | 31,135        |           |               |   | 34,837         |           |  |   |           |            |   |   | 72,172    |          
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |          
|                                  |                                                | Total assets                            |   | $                 | 2,005,228 |              |   | $             | 2,532,448 |               |   | $              | 1,021,899 |  |   | $          | (2,791,153 | ) |   | $         | 2,768,422 | 
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|Liabilities and partners capital |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          
|                                  | Current liabilities                            |                                         | $ | 30,715            |           |              | $ | 120,949       |           |               | $ | 272,538        |           |  | $ | (59,639    | )          |   | $ | 364,563   |          
|                                  | Long-term debt                                 |                                         |   | 974,264           |           |              |   | 403,428       |           |               |   |               |           |  |   |           |            |   |   | 1,377,692 |          
|                                  | Intercompany notes payable                     |                                         |   |                  |           |              |   | 508,652       |           |               |   | 437,411        |           |  |   | (946,063   | )          |   |   |          |          
|                                  | Other long term liabilities                    |                                         |   | 6,523             |           |              |   | 24,230        |           |               |   | 209            |           |  |   |           |            |   |   | 30,962    |          
|                                  | Redeemable Class B Units held by
related party |                                         |   | 103,363           |           |              |   |              |           |               |   |               |           |  |   |           |            |   |   | 103,363   |          
|                                  | Total partners capital                        |                                         |   | 890,363           |           |              |   | 1,475,189     |           |               |   | 311,741        |           |  |   | (1,785,451 | )          |   |   | 891,842   |          
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |           |          
|                                  |                                                | Total liabilities and partners
capital |   | $                 | 2,005,228 |              |   | $             | 2,532,448 |               |   | $              | 1,021,899 |  |   | $          | (2,791,153 | ) |   | $         | 2,768,422 | 
|                                  |                                                |                                         |   |                   |           |              |   |               |           |               |   |                |           |  |   |            |            |   |   |          

F-46



---



##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |         | 
|---------------------- | ---------------- | - | ---------------------------- | ------- | ------------ | - | ------------- | ------- | ------------- | - | -------------- | ------ |  | - | -------- | -------- | - | - | --------- | ------- | 
|                       |                  |   | Year Ended December 31, 2003
|                       |                  |   |                             
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   | TEPPCO   
|                       |                  |   | TEPPCO                       |         | Guarantor    |   | Non-Guarantor |         | Consolidating |   | Partners, L.P.
|                       |                  |   | Partners, L.P.               |         | Subsidiaries |   | Subsidiaries  |         | Adjustments   |   | Consolidated  
|                       |                  |   |                              |         |              |   |               |         |               |   |               
|                       |                  |   | (in thousands)              
|Operating revenues     |                  | $ |                             |         |              | $ | 399,504       |         |               | $ | 3,858,243      |        |  | $ | (1,915   | )        |   | $ | 4,255,832 |        
|Costs and expenses     |                  |   |                             |         |              |   | 262,971       |         |               |   | 3,806,316      |        |  |   | (1,915   | )        |   |   | 4,067,372 |        
|Gain on sale of assets |                  |   |                             |         |              |   |              |         |               |   | (3,948         | )      |  |   |         |          |   |   | (3,948    | )      
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Operating income |   |                              |        |              |   |               | 136,533 |               |   |                | 55,875 |  |   |          |         |   |   |           | 192,408 | 
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|Interest expense  net |                  |   | (36,416                      | )       |              |   | (52,903       | )       |               |   | (31,420        | )      |  |   | 36,489   |          |   |   | (84,250   | )      
|Equity earnings        |                  |   | 125,769                      |         |              |   | 41,678        |         |               |   | 20,949         |        |  |   | (171,533 | )        |   |   | 16,863    |        
|Other income  net     |                  |   | 36,416                       |         |              |   | 461           |         |               |   | 360            |        |  |   | (36,489  | )        |   |   | 748       |        
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Net income       |   | $                            | 125,769 |              |   | $             | 125,769 |               |   | $              | 45,764 |  |   | $        | (171,533 | ) |   | $         | 125,769 | 
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        

|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |         | 
|---------------------- | ---------------- | - | ---------------------------- | ------- | ------------ | - | ------------- | ------- | ------------- | - | -------------- | ------ |  | - | -------- | -------- | - | - | --------- | ------- | 
|                       |                  |   | Year Ended December 31, 2002
|                       |                  |   |                             
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   | TEPPCO   
|                       |                  |   | TEPPCO                       |         | Guarantor    |   | Non-Guarantor |         | Consolidating |   | Partners, L.P.
|                       |                  |   | Partners, L.P.               |         | Subsidiaries |   | Subsidiaries  |         | Adjustments   |   | Consolidated  
|                       |                  |   |                              |         |              |   |               |         |               |   |               
|                       |                  |   | (in thousands)              
|Operating revenues     |                  | $ |                             |         |              | $ | 336,045       |         |               | $ | 2,908,115      |        |  | $ | (1,997   | )        |   | $ | 3,242,163 |        
|Costs and expenses     |                  |   |                             |         |              |   | 216,552       |         |               |   | 2,857,361      |        |  |   | (1,997   | )        |   |   | 3,071,916 |        
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Operating income |   |                              |        |              |   |               | 119,493 |               |   |                | 50,754 |  |   |          |         |   |   |           | 170,247 | 
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|Interest expense  net |                  |   | (51,947                      | )       |              |   | (40,651       | )       |               |   | (26,347        | )      |  |   | 52,753   |          |   |   | (66,192   | )      
|Equity earnings        |                  |   | 117,862                      |         |              |   | 38,053        |         |               |   | 18,795         |        |  |   | (162,730 | )        |   |   | 11,980    |        
|Other income  net     |                  |   | 51,947                       |         |              |   | 967           |         |               |   | 1,666          |        |  |   | (52,753  | )        |   |   | 1,827     |        
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Net income       |   | $                            | 117,862 |              |   | $             | 117,862 |               |   | $              | 44,868 |  |   | $        | (162,730 | ) |   | $         | 117,862 | 
|                       |                  |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        

|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |         | 
|---------------------- | ------------------------------- | - | ---------------------------- | ------- | ------------ | - | ------------- | ------- | ------------- | - | -------------- | ------ |  | - | -------- | -------- | - | - | --------- | ------- | 
|                       |                                 |   | Year Ended December 31, 2001
|                       |                                 |   |                             
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   | TEPPCO   
|                       |                                 |   | TEPPCO                       |         | Guarantor    |   | Non-Guarantor |         | Consolidating |   | Partners, L.P.
|                       |                                 |   | Partners, L.P.               |         | Subsidiaries |   | Subsidiaries  |         | Adjustments   |   | Consolidated  
|                       |                                 |   |                              |         |              |   |               |         |               |   |               
|                       |                                 |   | (in thousands)              
|Operating revenues     |                                 | $ |                             |         |              | $ | 273,379       |         |               | $ | 3,283,356      |        |  | $ | (322     | )        |   | $ | 3,556,413 |        
|Costs and expenses     |                                 |   |                             |         |              |   | 152,558       |         |               |   | 3,252,386      |        |  |   | (322     | )        |   |   | 3,404,622 |        
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Operating income                |   |                              |        |              |   |               | 120,821 |               |   |                | 30,970 |  |   |          |         |   |   |           | 151,791 | 
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|Interest expense  net |                                 |   | (40,143                      | )       |              |   | (30,605       | )       |               |   | (31,452        | )      |  |   | 40,143   |          |   |   | (62,057   | )      
|Equity earnings        |                                 |   | 109,131                      |         |              |   | 18,178        |         |               |   | 18,547         |        |  |   | (128,458 | )        |   |   | 17,398    |        
|Other income  net     |                                 |   | 40,143                       |         |              |   | 1,537         |         |               |   | 1,262          |        |  |   | (40,143  | )        |   |   | 2,799     |        
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Income before minority
interest |   |                              | 109,131 |              |   |               | 109,931 |               |   |                | 19,327 |  |   |          | (128,458 | ) |   |           | 109,931 | 
|Minority interest      |                                 |   |                             |         |              |   |              |         |               |   |               |        |  |   | (800     | )        |   |   | (800      | )      
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        
|                       | Net income                      |   | $                            | 109,131 |              |   | $             | 109,931 |               |   | $              | 19,327 |  |   | $        | (129,258 | ) |   | $         | 109,131 | 
|                       |                                 |   |                              |         |              |   |               |         |               |   |                |        |  |   |          |          |   |   |           |        

F-47



---



##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |         |        |         | 
|---------------------------------------------------- | ---------- | --------------------------------------------------------------------------------- | ---------------------------------------------------- | ------- | ---------------------------- | ------ | ------------ | ------- | ------------- | ------ | ------------- | ------ | --------------- | ------ | -------- | -------- | - | ------- | -------- | ------- | ------ | ------- | 
|                                                     |            |                                                                                   |                                                      |         | Year Ended December 31, 2003
|                                                     |            |                                                                                   |                                                      |         |                             
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |         | TEPPCO
|                                                     |            |                                                                                   |                                                      |         | TEPPCO                       |        | Guarantor    |         | Non-Guarantor |        | Consolidating |        | Partners, L .P.
|                                                     |            |                                                                                   |                                                      |         | Partners, L .P.              |        | Subsidiaries |         | Subsidiaries  |        | Adjustments   |        | Consolidated   
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                
|                                                     |            |                                                                                   |                                                      |         | (in thousands)              
|Cash flows from operating activities                 |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |        
|                                                     | Net income |                                                                                   | $                                                    | 125,769 |                              |        | $            | 125,769 |               |        | $             | 45,764 |                 |        | $        | (171,533 | ) |         | $        | 125,769 |       
|                                                     |            | Adjustments to reconcile net
income to net cash provided by
operating activities: |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |         |        |        
|                                                     |            |                                                                                   | Depreciation and amortization                        |         |                              |       |              |         |               | 80,114 |               |        |                 | 20,614 |          |          |   |        |          |         |        | 100,728 | 
|                                                     |            |                                                                                   | Earnings in equity
investments, net of
distributions |         |                              | 76,729 |              |         |               | 3,559  |               |        |                 | 1,791  |          |          |   | (70,939 | )        |         |        | 11,140  | 
|                                                     |            |                                                                                   | Changes in assets and
liabilities and other          |         |                              | 48,432 |              |         |               | 5,576  |               |        |                 | (5,943 | )        |          |   | (46,348 | )        |         |        | 1,717   | 
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |        
|Net cash provided by operating activities            |            |                                                                                   | 250,930                                              |         |                              |        | 215,018      |         |               |        | 62,226        |        |                 |        | (288,820 | )        |   |         | 239,354  |        
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |        
|Cash flows from investing activities                 |            |                                                                                   | (175,568                                             | )       |                              |        | (178,682     | )       |               |        | (34,519       | )      |                 |        | 203,531  |          |   |         | (185,238 | )      
|Cash flows from financing activities                 |            |                                                                                   | (55,618                                              | )       |                              |        | (25,340      | )       |               |        | (44,758       | )      |                 |        | 70,101   |          |   |         | (55,615  | )      
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |        
|Net increase (decrease) in cash and cash
equivalents |            |                                                                                   | 19,744                                               |         |                              |        | 10,996       |         |               |        | (17,051       | )      |                 |        | (15,188  | )        |   |         | (1,499   | )      
|Cash and cash equivalents at beginning of
period     |            |                                                                                   |                                                     |         |                              |        | 8,247        |         |               |        | 22,721        |        |                 |        |         |          |   |         | 30,968   |        
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |         |       
|Cash and cash equivalents at end of period           |            | $                                                                                 | 19,744                                               |         |                              | $      | 19,243       |         |               | $      | 5,670         |        |                 | $      | (15,188  | )        |   | $       | 29,469   |        
|                                                     |            |                                                                                   |                                                      |         |                              |        |              |         |               |        |               |        |                 |        |          |          |   |         |          |        

|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |         |        | 
|--------------------------------------------------- | ------------------------------------------------------------------------------------------- | ---------------------------------------------------- | -------- | ---------------------------- | -------- | ------------ | ---------- | ------------- | ------ | ------------- | -------- | --------------- | ------ | - | ---------- | -------- | ------- | - | -------- | ------- | ------ | 
|                                                    |                                                                                             |                                                      |          | Year Ended December 31, 2002
|                                                    |                                                                                             |                                                      |          |                             
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          | TEPPCO 
|                                                    |                                                                                             |                                                      |          | TEPPCO                       |          | Guarantor    |            | Non-Guarantor |        | Consolidating |          | Partners, L .P.
|                                                    |                                                                                             |                                                      |          | Partners, L .P.              |          | Subsidiaries |            | Subsidiaries  |        | Adjustments   |          | Consolidated   
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                
|                                                    |                                                                                             |                                                      |          | (in thousands)              
|Cash flows from operating activities                |                                                                                            
|                                                    | Net income                                                                                  |                                                      | $        | 117,862                      |          |              | $          | 117,862       |        |               | $        | 44,868          |        |   | $          | (162,730 | )       |   | $        | 117,862 |       
|                                                    | Adjustments to reconcile net
income to net cash provided by
(used in) operating activities: |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |         |       
|                                                    |                                                                                             | Depreciation and amortization                        |          |                              |         |              |            |               | 66,175 |               |          |                 | 19,857 |   |            |          |        |   |          |         | 86,032 | 
|                                                    |                                                                                             | Earnings in equity
investments, net of
distributions |          |                              | 33,994   |              |            |               | 18,879 |               |          |                 | 11,586 |   |            |          | (46,058 | ) |          |         | 18,401 | 
|                                                    |                                                                                             | Changes in assets and
liabilities and other          |          |                              | (269,102 | )            |            |               | 48,638 |               |          |                 | 40,254 |   |            |          | 192,832 |   |          |         | 12,622 | 
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |        
|Net cash provided by (used in)
operating activities |                                                                                             |                                                      | (117,246 | )                            |          |              | 251,554    |               |        |               | 116,565  |                 |        |   | (15,956    | )        |         |   | 234,917  |        
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |        
|Cash flows from investing activities                |                                                                                             |                                                      | (378,039 | )                            |          |              | (1,150,967 | )             |        |               | (253,879 | )               |        |   | 1,058,170  |          |         |   | (724,715 | )      
|Cash flows from financing activities                |                                                                                             |                                                      | 495,285  |                              |          |              | 904,006    |               |        |               | 138,210  |                 |        |   | (1,042,214 | )        |         |   | 495,287  |        
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |        
|Net increase in cash and cash equivalents           |                                                                                             |                                                      |         |                              |          |              | 4,593      |               |        |               | 896      |                 |        |   |           |          |         |   | 5,489    |        
|Cash and cash equivalents at beginning of
period    |                                                                                             |                                                      |         |                              |          |              | 3,654      |               |        |               | 21,825   |                 |        |   |           |          |         |   | 25,479   |        
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |        
|Cash and cash equivalents at end of period          |                                                                                             | $                                                    |         |                              |          | $            | 8,247      |               |        | $             | 22,721   |                 |        | $ |           |          |         | $ | 30,968   |        
|                                                    |                                                                                             |                                                      |          |                              |          |              |            |               |        |               |          |                 |        |   |            |          |         |   |          |        

F-48



---



##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)

|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |         |        |  
|---------------------------------------------------- | --------------------------------------------------------------------------------- | ---------------------------------------------------- | -------- | ---------------------------- | ------ | ------------ | -------- | ------------- | ------ | ------------- | ------- | --------------- | ------- | - | -------- | -------- | ------ | - | -------- | ------- | ------ | -
|                                                     |                                                                                   |                                                      |          | Year Ended December 31, 2001
|                                                     |                                                                                   |                                                      |          |                             
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          | TEPPCO 
|                                                     |                                                                                   |                                                      |          | TEPPCO                       |        | Guarantor    |          | Non-Guarantor |        | Consolidating |         | Partners, L .P.
|                                                     |                                                                                   |                                                      |          | Partners, L .P.              |        | Subsidiaries |          | Subsidiaries  |        | Adjustments   |         | Consolidated   
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                
|                                                     |                                                                                   |                                                      |          | (in thousands)              
|Cash flows from operating activities                 |                                                                                  
|                                                     | Net income                                                                        |                                                      | $        | 109,131                      |        |              | $        | 109,931       |        |               | $       | 19,327          |         |   | $        | (129,258 | )      |   | $        | 109,131 |       
|                                                     | Adjustments to reconcile net
income to net cash provided by
operating activities: |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |         |       
|                                                     |                                                                                   | Depreciation and amortization                        |          |                              |       |              |          |               | 31,226 |               |         |                 | 14,673  |   |          |          |       |   |          |         | 45,899 |  
|                                                     |                                                                                   | Earnings in equity investments,
net of distributions |          |                              | (5,219 | )            |          |               | 10,131 |               |         |                 | 13,417  |   |          |          | (3,952 | ) |          |         | 14,377 |  
|                                                     |                                                                                   | Changes in assets and
liabilities and other          |          |                              | 2,874  |              |          |               | 16,850 |               |         |                 | (20,783 | ) |          |          | 800    |   |          |         | (259   | )
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |        
|Net cash provided by operating activities            |                                                                                   |                                                      | 106,786  |                              |        |              | 168,138  |               |        |               | 26,634  |                 |         |   | (132,410 | )        |        |   | 169,148  |        
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |        
|Cash flows from investing activities                 |                                                                                   |                                                      | (498,711 | )                            |        |              | (514,178 | )             |        |               | (43,687 | )               |         |   | 498,711  |          |        |   | (557,865 | )      
|Cash flows from financing activities                 |                                                                                   |                                                      | 391,925  |                              |        |              | 340,529  |               |        |               | 20,947  |                 |         |   | (366,301 | )        |        |   | 387,100  |        
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |        
|Net increase (decrease) in cash and cash
equivalents |                                                                                   |                                                      |         |                              |        |              | (5,511   | )             |        |               | 3,894   |                 |         |   |         |          |        |   | (1,617   | )      
|Cash and cash equivalents at beginning of
period     |                                                                                   |                                                      |         |                              |        |              | 9,166    |               |        |               | 17,930  |                 |         |   |         |          |        |   | 27,096   |        
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |        
|Cash and cash equivalents at end of period           |                                                                                   | $                                                    |         |                              |        | $            | 3,655    |               |        | $             | 21,824  |                 |         | $ |         |          |        | $ | 25,479   |        
|                                                     |                                                                                   |                                                      |          |                              |        |              |          |               |        |               |         |                 |         |   |          |          |        |   |          |        

NOTE 21. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (1)

|                                                                      |  |                                         |           |         |  |         |           |         |  |   |           |  |  |   |           | 
|--------------------------------------------------------------------- |  | --------------------------------------- | --------- | ------- |  | ------- | --------- | ------- |  | - | --------- |  |  | - | --------- | 
|                                                                      |  | First                                   |           | Second  |  | Third   |           | Fourth 
|                                                                      |  | Quarter                                 |           | Quarter |  | Quarter |           | Quarter
|                                                                      |  |                                         |           |         |  |         |           |        
|                                                                      |  | (in thousands, except per Unit amounts)
|2003                                                                  |  |                                         |           |         |  |         |           |         |  |   |           |  |  |   |           | 
|Operating revenues                                                    |  | $                                       | 1,099,239 |         |  | $       | 1,040,800 |         |  | $ | 1,066,889 |  |  | $ | 1,048,904 | 
|Operating income                                                      |  |                                         | 51,342    |         |  |         | 47,986    |         |  |   | 45,265    |  |  |   | 47,815    | 
|Net income                                                            |  |                                         | 33,925    |         |  |         | 33,944    |         |  |   | 30,491    |  |  |   | 27,409    | 
|Basic and diluted income per Limited
Partner and Class B Unit (2) (3) |  | $                                       | 0.43      |         |  | $       | 0.43      |         |  | $ | 0.36      |  |  | $ | 0.31      | 
|2002                                                                  |  |                                         |           |         |  |         |           |         |  |   |           |  |  |   |           | 
|Operating revenues                                                    |  | $                                       | 631,137   |         |  | $       | 888,329   |         |  | $ | 880,804   |  |  | $ | 841,893   | 
|Operating income                                                      |  |                                         | 37,586    |         |  |         | 37,356    |         |  |   | 47,087    |  |  |   | 48,218    | 
|Net income                                                            |  |                                         | 26,808    |         |  |         | 24,377    |         |  |   | 32,093    |  |  |   | 34,584    | 
|Basic and diluted income per Limited
Partner and Class B Unit (4)     |  | $                                       | 0.46      |         |  | $       | 0.39      |         |  | $ | 0.48      |  |  | $ | 0.46      | 



---

|(1) |  | Certain reclassifications have been made to the quarterly
information to conform with the current presentation.                                                                                                                        
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Per Unit calculation includes 3,938,750 Units issued in April 2003,
3,916,547 Units repurchased and retired in April 2003, 5,162,900 Units
issued in August 2003, and 87,307 Units issued through the exercise of
Unit options in 2003.
|   
|(3) |  | The sum of the four quarters does not equal the total year due to
rounding.                                                                                                                                                            

F-49



---



##### Table of Contents



TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)



|(4) |  | Per Unit calculation includes 1,920,000 Units issued in March 2002,
3,175,000 Units issued in July and August 2002, 4,370,000 Units issued
in September 2002, 3,795,000 Units issued in November and December
2002, and 99,597 Units issued through the exercise of Unit options in
2002.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

F-50



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##### Table of Contents






INDEX TO EXHIBIT

|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1   |  | Certificate of Limited Partnership of TEPPCO Partners, L.P.
(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   |  | Third Amended and Restated Agreement of Limited Partnership of
TEPPCO Partners, L.P., dated September 21, 2001 (Filed as
Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the quarter ended September 30, 2001 and
incorporated herein by reference).                                                                                                                                                                                                                                                                                                                           
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.1   |  | Form of Certificate representing Limited Partner Units (Filed
as Exhibit 4.1 to the Registration Statement of TEPPCO
Partners, L.P. (Commission File No. 33-32203) and incorporated
herein by reference).                                                                                                                                                                                                                                                                                                                                                                                                          
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.2   |  | Form of Indenture between TE Products Pipeline Company,
Limited Partnership and The Bank of New York, as Trustee,
dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE
Products Pipeline Company, Limited Partnerships Registration
Statement on Form S-3 (Commission File No. 333-38473) and
incorporated herein by reference).                                                                                                                                                                                                                                                                              
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.3   |  | Form of Certificate representing Class B Units (Filed as
Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the year ended December 31, 1998 and
incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                                               
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.4   |  | Form of Indenture between TEPPCO Partners, L.P., as issuer, TE
Products Pipeline Company, Limited Partnership, TCTM, L.P.,
TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering
Company, as subsidiary guarantors, and First Union National
Bank, NA, as trustee, dated as of February 20, 2002 (Filed as
Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) dated as of February 20, 2002 and
incorporated herein by reference).                                                                                                                                                 
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.5   |  | First Supplemental Indenture between TEPPCO Partners, L.P., as
issuer, TE Products Pipeline Company, Limited Partnership,
TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas
Gathering Company, as subsidiary guarantors, and First Union
National Bank, NA, as trustee, dated as of February 20, 2002
(Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) dated as of February 20, 2002
and incorporated herein by reference).                                                                                                                                      
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.6   |  | Second Supplemental Indenture, dated as of June 27, 2002,
among TEPPCO Partners, L.P., as issuer, TE Products Pipeline
Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream
Companies, L.P., and Jonah Gas Gathering Company, as Initial
Subsidiary Guarantors, and Val Verde Gas Gathering Company,
L.P., as New Subsidiary Guarantor, and Wachovia Bank, National
Association, formerly known as First Union National Bank, as
trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended June
30, 2002 and incorporated herein by reference).
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|4.7   |  | Third Supplemental Indenture among TEPPCO Partners, L.P. as
issuer, TE Products Pipeline Company, Limited Partnership,
TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas
Gathering Company and Val Verde Gas Gathering Company, L.P. as
Subsidiary Guarantors, and Wachovia Bank, National
Association, as trustee, dated as of January 30, 2003 (Filed
as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
2002 and incorporated herein by reference).                                                                                       
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|10.1+ |  | Duke Energy Corporation Executive Savings Plan (Filed as
Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the year ended December 31, 1999 and
incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                                              
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|10.2+ |  | Duke Energy Corporation Executive Cash Balance Plan (Filed as
Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the year ended December 31, 1999 and
incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                                         
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|10.3+ |  | Duke Energy Corporation Retirement Benefit Equalization Plan
(Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
1999 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                               





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##### Table of Contents



|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.4+  |  | 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).                                                                                                                             
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.5+  |  | 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).                                                                                                              
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.6+  |  | Form of Employment Agreement between the Company and Thomas R.
Harper, Charles H. Leonard, James C. Ruth, John N.
Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E.
Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form
10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the year ended December 31, 1998 and incorporated herein
by reference).               
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.7   |  | 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).
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.8   |  | 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).                                                                                                                                                                              
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.9+  |  | 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).                                                                                                                   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.10+ |  | Form of Employment and Non-Compete Agreement between the
Company and J. Michael Cockrell effective January 1, 1999
(Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended September
30, 1999 and incorporated herein by reference).                                                                                                     
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.11+ |  | 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).                                                                                                         
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.12+ |  | 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).                                                                                                  
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.13+ |  | 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).                                                                                                                         
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.14+ |  | Texas Eastern Products Pipeline Company, LLC 2000 Long Term
Incentive Plan, Amendment and Restatement, effective January
1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 2000 and incorporated herein by reference).                                                                                           
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.15+ |  | TEPPCO Supplemental Benefit Plan, effective April 1, 2000
(Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
2000 and incorporated herein by reference).                                                                                                                                                                  
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.16+ |  | Employment Agreement with Barry R. Pearl (Filed as Exhibit
10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the quarter ended March 31, 2001 and
incorporated herein by reference).                                                                                                                                                                                   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                    
|10.17  |  | Amended and Restated Credit Agreement among TEPPCO Partners,
L.P. as Borrower, SunTrust Bank as Administrative Agent and LC
Issuing Bank, and Certain Lenders, dated as of April 6, 2001
($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended March 31, 2001 and incorporated
herein by reference). 





---



##### Table of Contents



|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|----- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.18 |  | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent, and Certain Lenders,
dated as of April 6, 2001 ($200,000,000 Revolving Facility)
(Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended March 31,
2001 and incorporated herein by reference).                                                                                                                 
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.19 |  | Amendment 1, dated as of September 28, 2001, to the Amended
and Restated Credit Agreement among TEPPCO Partners, L.P. as
Borrower, SunTrust Bank as Administrative Agent and LC Issuing
Bank, and Certain Lenders, dated as of April 6, 2001
($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 2001 and
incorporated herein by reference).                
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.20 |  | Amendment 1, dated as of September 28, 2001, to the Credit
Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust
Bank as Administrative Agent, and Certain Lenders, dated as of
April 6, 2001 ($200,000,000 Revolving Facility) (Filed as
Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended September
30, 2001 and incorporated herein by reference).                                                         
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.21 |  | Amendment and Restatement, dated as of November 13, 2001, to
the Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent, and Certain Lenders,
dated as of April 6, 2001 ($200,000,000 Revolving Facility)
(Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P
(Commission File No. 1-10403) for the year ended December 31,
2001 and incorporated herein by reference).                                                 
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.22 |  | Second Amendment and Restatement, dated as of November 13,
2001, to the Amended and Restated Credit Agreement amount
TEPPCO Partners, L.P. as Borrower, SunTrust Bank as
Administrative Agent and LC Issuing Bank, and Certain Lenders,
dated as of April 6, 2001 ($500,000,000 Revolving Facility)
(Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P
(Commission File No. 1-10403) for the year ended December 31,
2001 and incorporated herein by reference).
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.23 |  | Second Amended and Restated Agreement of Limited Partnership
of TE Products Pipeline Company, Limited Partnership, dated
September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of
TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
quarter ended September 30, 2001 and incorporated herein by
reference).                                                                                                                                                     
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.24 |  | Amended and Restated Agreement of Limited Partnership of TCTM,
L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the quarter ended September 30, 2001 and incorporated
herein by reference).                                                                                                                                                                                                   
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.25 |  | Contribution, Assignment and Amendment Agreement among TEPPCO
Partners, L.P., TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., Texas Eastern Products Pipeline
Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed
as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended June 30,
2001 and incorporated herein by reference).                                                                  
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.26 |  | 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).                                                                                                                                                                                                                                                    
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.27 |  | Agreement of Limited Partnership of TEPPCO Midstream
Companies, L.P., dated September 24, 2001 (Filed as Exhibit
3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the quarter ended September 30, 2001 and
incorporated herein by reference).                                                                                                                                                                                                 
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.28 |  | Agreement of Partnership of Jonah Gas Gathering Company dated
June 20, 1996 as amended by that certain Assignment of
Partnership Interests dated September 28, 2001 (Filed as
Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
2001 and incorporated herein by reference).                                                                                                                               
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.29 |  | Unanimous Written Consent of the Board of Directors of TEPPCO
GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to
Form 10-K of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the year ended December 31, 2001 and incorporated
herein by reference).                                                                                                                                                                                                    





---



##### Table of Contents



|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.30  |  | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent and Certain Lenders, as
Lenders dated as of March 28, 2002 ($200,000,000 Revolving
Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of
TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
three months ended March 31, 2002 and incorporated herein by
reference).                                      
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.31  |  | Amended and Restated Credit Agreement among TEPPCO Partners,
L.P. as Borrower, SunTrust Bank, as Administrative Agent and
LC Issuing Bank and Certain Lenders, as Lenders dated as of
March 28, 2002 ($500,000,000 Revolving Facility) (Filed as
Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the three months ended March
31, 2002 and incorporated herein by reference).   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.32  |  | Purchase and Sale Agreement between Burlington Resources
Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer,
dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of
TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as
of July 2, 2002 and incorporated herein by reference).                                                                                                                   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.33  |  | Credit Agreement among TEPPCO Partners, L.P., as Borrower,
SunTrust Bank, as Administrative Agent and Certain Lenders, as
Lenders dated as of June 27, 2002 ($200,000,000 Term Facility)
(Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) dated as of July 2, 2002 and
incorporated herein by reference).                                                                    
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.34  |  | Amendment, dated as of June 27, 2002 to the Amended and
Restated Credit Agreement among TEPPCO Partners, L.P., as
Borrower, SunTrust Bank, as Administrative Agent, and Certain
Lenders, dated as of March 28, 2002 ($500,000,000 Revolving
Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) dated as of July
2, 2002 and incorporated herein by reference).
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.35  |  | Amendment 1, dated as of June 27, 2002 to the Credit Agreement
among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as
Administrative Agent and Certain Lenders, dated as of March
28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as
Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission
File No. 1-10403) dated as of July 2, 2002 and incorporated
herein by reference).                    
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.36  |  | Agreement of Limited Partnership of Val Verde Gas Gathering
Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended June 30, 2002 and incorporated
herein by reference).                                                                                                                                                  
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.37+ |  | Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit
Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43
to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended June 30, 2002 and incorporated
herein by reference).                                                                                                                                          
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.38+ |  | Amended and Restated TEPPCO Supplemental Benefit Plan,
effective November 1, 2002 (Filed as Exhibit 10.44 to Form
10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the year ended December 31, 2002 and incorporated herein
by reference).                                                                                                                                                             
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.39+ |  | Texas Eastern Products Pipeline Company, LLC 2000 Long Term
Incentive Plan, Second Amendment and Restatement, effective
January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 2002 and incorporated herein by reference).                                                                                                       
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.40+ |  | Amended and Restated Texas Eastern Products Pipeline Company,
LLC Management Incentive Compensation Plan, effective January
1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 2002 and incorporated herein by reference).                                                                                                           
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.41+ |  | Amended and Restated TEPPCO Retirement Cash Balance Plan,
effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K
of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the
year ended December 31, 2002 and incorporated herein by
reference).                                                                                                                                                           
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                       
|10.42  |  | Formation Agreement between Panhandle Eastern Pipe Line
Company and Marathon Ashland Petroleum LLC and TE Products
Pipeline Company, Limited Partnership, dated as of August 10,
2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners,
L.P.                                                                                                                                                                   





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##### Table of Contents



|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|       |  | (Commission File No. 1-10403) for the year ended December
31, 2002 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.43  |  | Amended and Restated Limited Liability Company Agreement of
Centennial Pipeline LLC dated as of August 10, 2000 (Filed as
Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
2002 and incorporated herein by reference).                                                                                                                        
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.44  |  | Guaranty Agreement, dated as of September 27, 2002, between TE
Products Pipeline Company, Limited Partnership and Marathon
Ashland Petroleum LLC for Note Agreements of Centennial
Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 2002 and incorporated herein by reference).                                        
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.45  |  | LLC Membership Interest Purchase Agreement By and Between CMS
Panhandle Holdings, LLC, As Seller and Marathon Ashland
Petroleum LLC and TE Products Pipeline Company, Limited
Partnership, Severally as Buyers, dated February 10, 2003
(Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31,
2002 and incorporated herein by reference).
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.46  |  | Joint Development Agreement between TE Products Pipeline
Company, Limited Partnership and Louis Dreyfus Plastics
Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended March 31, 2003 and incorporated
herein by reference).                                                                                   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.47  |  | Credit Agreement among TEPPCO Partners, L.P. as Borrower,
SunTrust Bank as Administrative Agent and LC Issuing Bank and
The Lenders Party Hereto, as Lenders, dated as of June 27,
2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52
to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended June 30, 2003 and incorporated
herein by reference).               
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.48  |  | Agreement of Limited Partnership of Mont Belvieu Storage
Partners, L.P. dated effective January 21, 2003 (Filed as
Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended September
30, 2003 and incorporated herein by reference).                                                                                                                           
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|10.49  |  | Letter of Agreement Clarifying Rights and Obligations of the
Parties Under the Mont Belvieu Storage Partners, L.P.,
Partnership Agreement and the Mont Belvieu Venture, LLC, LLC
Agreement, dated October 13, 2003 (Filed as Exhibit 10.54 to
Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 2003 and
incorporated herein by reference).                 
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|12.1*  |  | Statement of Computation of Ratio of Earnings to Fixed
Charges.                                                                                                                                                                                                                                                                                                                                                
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|21     |  | Subsidiaries of the Partnership (Filed as Exhibit 21 to Form
10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the quarter ended June 30, 2002 and incorporated herein by
reference).                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|23*    |  | Consent of KPMG LLP.                                                                                                                                                                                                                                                                                                                                                                                           
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|24*    |  | Powers of Attorney.                                                                                                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|31.1*  |  | Certification of Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|31.2*  |  | Certification of Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|32.1** |  | Certification of Chief Executive Officer Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|32.2** |  | Certification of Chief Financial Officer Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                
|99.1*  |  | Charter of the Audit Committee of the Board of Directors of
the General Partner.                                                                                                                                                                                                                                                                                                                               



---

|*  |  | Filed herewith.                                                   
|-- |  | ------------------------------------------------------------------
|  
|** |  | Furnished herewith pursuant to Item 601(b)-(32) of
Regulation S-K.
|  
|+  |  | A management contract or compensation plan or arrangement.