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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

For the quarterly period ended September 30, 2003

OR

Commission File No. 1-10403

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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Limited Partner Units outstanding as of October 29, 2003:   62,998,554

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

i

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)

See accompanying Notes to Consolidated Financial Statements.

1

TEPPCO PARTNERS, L.P.

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

See accompanying Notes to Consolidated Financial Statements.

2

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

See accompanying Notes to Consolidated Financial Statements.

3

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)
(in thousands, except Unit amounts)

See accompanying Notes to Consolidated Financial Statements.

4

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION

     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 approximate 70% interest 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.

     The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of the management of the Company, of a normal and recurring nature and necessary for a fair statement of our financial position as of September 30, 2003, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and nine months ended September 30, 2003, are not necessarily indicative of results of our operations for the full year 2003. You should read the interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2002. We have reclassified certain amounts from prior periods to conform with the current presentation.

     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.

     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.”

Net Income Per Unit

     Basic net income per Limited Partner and Class B Unit (collectively, “Units”) is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 60.5 million and 50.0 million Units for the three months ended September 30, 2003, and 2002, respectively, and 58.7 million and 47.0 million Units for the nine months ended September 30, 2003, and 2002, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each period (see Note 10. Quarterly Distributions of Available Cash). The General Partner was allocated $8.9 million (representing 29.09%) and $8.1 million (representing 25.18%) of net income for the three months ended September 30, 2003, and 2002, respectively, and $27.2 million (representing 27.65%) and $21.0 million (representing 25.18%) of net income for the nine months ended September 30, 2003, and 2002, respectively.

5

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, according to our limited partnership agreement.

     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 three months ended September 30, 2003, and 2002, the denominator was increased by 12,677 Units and 20,645 Units, respectively. For the nine months ended September 30, 2003, and 2002, the denominator was increased by 10,813 Units and 34,931 Units, respectively. During the third quarter of 2003, all remaining outstanding Unit options were exercised.

New Accounting Pronouncements

     In December 2002, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide 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 the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. We have not granted options for any periods presented. For options outstanding under our 1994 Long Term Incentive Plan, 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. Assuming we had used the fair value method of accounting for our unit option plan, pro forma net income for the nine months ended September 30, 2002, would be lower than reported net income by an immaterial amount. Pro forma net income would equal reported net income for the three months ended September 30, 2003, and 2002, and for the nine months ended September 30, 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.

     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 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 Others and amends certain other existing pronouncements. SFAS 149 is effective for contracts

6

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

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 a material 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 a material effect on our financial position, results of operations or cash flows.

     In May 2003, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-04, Accounting for “Cash Balance” Pension Plans, to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in the consensus, the consensus also requires the use of the traditional unit credit method for purposes of measuring benefit obligations and annual cost of benefits earned as opposed to the projected unit credit method. We have historically accounted for our cash balance plans as defined benefit plans; however, we are required to adopt the measurement provisions of EITF 03-04 in our cash balance plans’ next measurement date of December 31, 2003. Any differences in the measurement of the obligation as a result of applying the consensus will be reported as a component of actuarial gain or loss. We do not believe that the adoption of EITF 03-04 will have a material 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. Upon application of EITF 01-08, the accounting requirements under the consensus could 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. 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.

7

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

NOTE 2. 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 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

8

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually.

     To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred.

     At September 30, 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). The excess investment is included in our equity investments account at September 30, 2003. The following table presents the carrying amount of goodwill and equity method goodwill at September 30, 2003, by business segment (in thousands):

Other Intangible Assets

     The following table reflects the components of amortized intangible assets at September 30, 2003, and December 31, 2002 (in thousands):

     At September 30, 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 September 30, 2003. This excess investment is accounted for as an intangible asset with an indefinite life. We will assess the intangible asset for impairment 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 expected useful life of the contract assets on a quarterly basis based on the best available information. Amortization expense on intangible assets was $8.1 million and $10.1 million for the three months ended September 30, 2003 and 2002,

9

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

respectively, and $27.9 million and $19.4 million for the nine months ended September 30, 2003 and 2002, 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 Gas Gathering Company (“Jonah”) and because of certain limited production forecasts obtained from producers on the Jonah system related to the expansions, we increased, in the second quarter of 2003, 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):

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

     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 9. 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 nine months ended September 30, 2003, and 2002, we recognized increases in interest expense of $10.7 million and $9.6 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 September 30, 2003, we determined that we would repay a portion of the amount outstanding under the revolving credit facility with proceeds from our Unit offering in August 2003 (see Note 8. Partners’ Capital) 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 $0.8 million, which has been included in interest expense. The total fair value of the interest rate swap was a loss of approximately $7.6 million and $20.1 million at September 30, 2003, and December 31, 2002, respectively. Losses recognized in other comprehensive income of approximately $6.8 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

10

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

value of the portion of the interest rate swap related to the discontinued hedge will be recorded in earnings currently 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 nine months ended September 30, 2003, and 2002, we recognized reductions in interest expense of $7.4 million and $5.4 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 September 30, 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 $7.3 million and $13.6 million at September 30, 2003, and December 31, 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 September 30, 2003, the unamortized balance of the deferred gains was $41.5 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.

NOTE 5. 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. This purchase served as our entry into the natural gas gathering industry. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. Under a contractual agreement, DEFS manages and operates Jonah on our behalf.

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. We funded the purchase by a borrowing under our $500.0 million revolving credit facility (see Note 9. Debt). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu, Texas. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. Under a contractual agreement, DEFS manages and operates Chaparral on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting, and we allocated the purchase price to property,

11

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

plant and equipment. Accordingly, the results of the acquisition are included in the consolidated financial statements from March 1, 2002.

Val Verde Gas Gathering Company

     On June 30, 2002, we completed the purchase of Val Verde Gas Gathering Company (“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 by 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 9. Debt). The remaining purchase price was funded through working capital sources of cash. The Val Verde system gathers coal bed methane (“CBM”) from 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. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from June 30, 2002.

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

     The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets on a units-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 acquisition of Val Verde occurred at the beginning of 2002 (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.

12

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

     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 acquisition been consummated at the beginning of 2002, or the results which may be attained in the future.

Rancho Pipeline

     We owned an approximate 25% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas, acquired in connection with our acquisition of crude oil assets in 2000. 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.

NOTE 6. INVENTORIES

     Inventories are carried at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows (in thousands):

     The costs of inventories did not exceed market values at September 30, 2003, and December 31, 2002.

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 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 Illinois. Through February 9, 2003, each participant owned a one-

13

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

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 nine months ended September 30, 2003, excluding the amount paid for the acquisition of the additional ownership interest, TE Products contributed approximately $3.0 million to Centennial, which is included in the equity investment balance at September 30, 2003.

     As of January 1, 2003, TE Products and Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”) effectively formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership 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 $7.2 million on an annual basis) of MB Storage’s earnings before interest, taxes, depreciation and amortization, as defined in the operating agreement. Any amount of MB Storage’s earnings before interest, taxes, depreciation and amortization in excess of the $7.2 million is allocated evenly between TE Products and Louis Dreyfus. For the nine months ended September 30, 2003, TE Products’ sharing ratio in the earnings of MB Storage was approximately 74%.

     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 nine months ended September 30, 2003, and for Seaway and Centennial for the nine months ended September 30, 2002, is presented below (in thousands):

     Summarized combined balance sheet data for Seaway, Centennial and MB Storage as of September 30, 2003, and for Seaway and Centennial as of December 31, 2002, is presented below (in thousands):

     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)
(Unaudited)

NOTE 8. PARTNERS’ CAPITAL

     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 3,916,547 previously outstanding Class B Units held by Duke Energy Transport and Trading Company, LLC (“DETTCO”), an affiliate of Duke Energy. 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 $38.0 million of the proceeds were used to repay indebtedness under our revolving credit facility. The remaining proceeds will be used to fund revenue-generating and system upgrade capital expenditures during the remainder of 2003, and $21.0 million will be used to fund the acquisition of additional crude oil facilities (see Note 15. Subsequent Event). The remaining amount will be used for general partnership purposes.

NOTE 9. 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 September 30, 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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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

additional indebtedness. As of September 30, 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 September 30, 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 changes in the fair value on a portion of the Senior Notes discussed above. See Note 4. Derivative Financial Instruments.

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. Derivative Financial Instruments). 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 September 30, 2003, $225.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate, before the effects of hedging activities, of 1.9%. At September 30, 2003, we were in compliance with the covenants in this credit agreement.

     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. Derivative Financial Instruments.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

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 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 5. 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 outstanding under our credit facilities as of September 30, 2003, and December 31, 2002 (in thousands):

NOTE 10. 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)
(Unaudited)

     The following table reflects the allocation of total distributions paid during the nine months ended September 30, 2003, and 2002 (in thousands, except per Unit amounts).

     On November 7, 2003, we will pay a cash distribution of $0.65 per Unit for the quarter ended September 30, 2003. The third quarter 2003 cash distribution will total approximately $57.1 million.

NOTE 11. SEGMENT DATA

     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).

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

     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 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 the equity earnings from our 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 5. Acquisitions and Dispositions).

     The table below includes interim financial information by reporting segment for the interim periods ended September 30, 2003 and 2002 (in thousands):