UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

Commission File No. 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)

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  ý  No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes  ý 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 28, 2004:   62,998,554.

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS,  L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

See accompanying Notes to Consolidated Financial Statements.

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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.

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TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

(in thousands, except Unit amounts)

See accompanying Notes to Consolidated Financial Statements.

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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 interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%.  The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of our 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” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.

The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of September 30, 2004, 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, 2004, are not necessarily indicative of results of our operations for the full year 2004.  You should read these 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, 2003.  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 a different business strategy.

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, “Unit” or “Units”) is computed by dividing our net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 63.0 million and 60.5 million Units for the three months ended September 30, 2004 and 2003, respectively, and 63.0 million and 58.7 million Units for the nine months ended September 30, 2004 and 2003, 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 9. Partners’ Capital and Distributions).  The General Partner was allocated $7.5 million (representing 28.85%) and $8.9 million (representing 29.09%) of our net income for the three months ended September 30, 2004 and 2003, respectively, and $30.0 million (representing 28.85%) and $27.2 million (representing 27.65%) of our net income for the nine months ended September 30, 2004 and 2003,

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

Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, 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 and nine months ended September 30, 2003, the denominator was increased by 12,677 Units and 10,813 Units, respectively.  For the three months and nine months ended September 30, 2004, diluted net income per Unit equaled basic net income per Unit as the denominator was not changed because all remaining outstanding Unit options were exercised during the third quarter of 2003.

New Accounting Pronouncements

In December 2003, the Financial Accounting Standards Board (“FASB”) revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”).  FIN 46, issued by the FASB in January 2003, 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.  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 adopted the new requirements detailed in FIN 46(R) as of March 31, 2004.  In connection with our adoption of FIN 46(R), 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 materially affected by our adoption of FIN 46(R), and thus we have accounted for them as equity method investments (see Note 7. Equity Investments).  Our adoption of FIN 46(R) did not have an effect on our financial position, results of operations or cash flows.

On December 8, 2003, President Bush signed into 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 was permitted by FASB Staff Position (“FSP”) Nos. 106-1 and 106-2, 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 adopted the provisions of these FSPs in the quarter ended September 30, 2004.  This regulation did not have a material adverse effect on our financial position, results of operations or cash flows.

In December 2003, the FASB issued a revision to Statement of Financial Accounting Standards (“SFAS”) No. 132, Employers’ Disclosures about Pensions and Other Post-Retirement Benefits.  This revision required that companies provide more details about their plan assets, benefit obligations, cash flows, benefit costs and other relevant information.  A description of investment policies and strategies and target allocation percentages, or target ranges, for these asset categories also is required in financial statements.  Cash flows will include projections of future benefit payments and an estimate of contributions to be made in the next year to fund pension and other postretirement benefit plans.  In addition to expanded annual disclosures, the FASB is requiring companies to report the various elements of pension and other postretirement benefit costs on a quarterly basis.  The guidance is effective for fiscal years ending after December 15, 2003, and for quarters beginning after December 15, 2003.  We adopted

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the provisions of the revised SFAS 132 effective December 31, 2003, and certain provisions regarding disclosure of information about estimated future benefit payments in the first quarter of 2004.

In April 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128, to clarify what is meant by a participating security as described in SFAS No. 128, Earnings Per Share.  The consensus also provides guidance on applying the two-class method for computing earnings per share.  The two-class method is an earnings allocation formula for computing earnings per share and is the required method prescribed by SFAS 128 for companies with participating securities or more than one class of common stock.  The consensus primarily affects companies that issue securities that are entitled to participate in dividends with common shares and would cause affected companies to report lower earnings per share amounts.  The consensus is to be applied retroactively for periods beginning after March 31, 2004.  The adoption of EITF 03-06 did not have an effect on our financial position, results of operations or cash flows.

NOTE 2.  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, and 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.  There have been no goodwill impairment losses recorded since the adoption of SFAS 142.

At September 30, 2004, we have $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, 2004.  The following table presents the carrying amount of goodwill and equity method goodwill at September 30, 2004, by business segment (in thousands):

Other Intangible Assets

The following table reflects the components of amortized intangible assets at September 30, 2004, and December 31, 2003 (in thousands):

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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.

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.  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. Due to 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, 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 extended the amortization period of Jonah’s natural gas gathering contracts by an estimated 9 years, increasing from approximately 16 years to approximately 25 years.  The amortization of the contracts related to the Val Verde Gas Gathering Company (“Val Verde”) assets, also amortized on a unit-of-production basis, is expected to average approximately 20 years.  Revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis.  Our fractionation agreement with DEFS is being amortized over its contract period of 20 years.  The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years.

Amortization expense on intangible assets was $8.6 million and $8.1 million for the three months ended September 30, 2004 and 2003, respectively, and $25.0 million and $27.9 million for the nine months ended September 30, 2004 and 2003, respectively.

At September 30, 2004, we have $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, 2004.  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.

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

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NOTE 3. PROPERTY, PLANT AND EQUIPMENT

We evaluate impairment of long-lived assets 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 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.

During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area.  The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment.  The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational.  As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the fair value of the facility.

NOTE 4. INTEREST RATE SWAPS

We 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 matured on April 6, 2004.  We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million.  Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings.  On June 27, 2003, we repaid the amounts outstanding under our revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 8.  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, 2004 and 2003, we recognized increases in interest expense of $2.9 million and $10.7 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

During 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 9.  Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility.  We reduced the outstanding balance of the revolving credit facility at December 31, 2003, to $210.0 million.  During the year ended December 31, 2003, we recognized a loss of $1.0 million for the portion of the discontinued hedge.  The total fair value of the interest rate swap was a loss of approximately $3.9 million at December 31, 2003.  The remaining $2.9 million of other comprehensive income was transferred to earnings during the period from January 1, 2004, through the maturity of the interest rate swap on April 6, 2004.

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

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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, 2004 and 2003, we recognized reductions in interest expense of $7.5 million and $7.4 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, 2004, 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 $3.9 million at September 30, 2004, and a gain of approximately $2.3 million at December 31, 2003.

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, 2004, the unamortized balance of the deferred gains was $37.6 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.

NOTE 5.  ACQUISITIONS AND DISPOSITIONS

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 that previously held undivided interests in the pipeline.  We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline.  We sold 183 miles 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 in the second quarter of 2003.  During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million.  These gains are included in the gains on sales of assets in our consolidated statements of income.

Genesis Pipeline

On November 1, 2003, we purchased 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 9.  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 are integrating these assets into our South Texas pipeline system which will allow 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.

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

NOTE 6.  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 September 30, 2004, and December 31, 2003.  The major components of inventories were as follows (in thousands):

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 June 2002 through May 2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenue and expense of Seaway.  During the nine months ended September 30, 2004 and 2003, we received distributions from Seaway of $30.9 million and $10.7 million, respectively.  During the three months ended September 30, 2004, we received a distribution from Seaway of $15.0 million.  No distributions were received in the corresponding quarter of 2003.

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 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial

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to 50% each.  During the nine months ended September 30, 2004, TE Products invested an additional $1.5 million in Centennial, which is included in the equity investment balance at September 30, 2004.

On 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 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 operates the facilities for MB Storage.  Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 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 credited 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 income before depreciation expense, as defined in the operating agreement.  Any amount of MB Storage’s annual income before depreciation expense in excess of $7.15 million is allocated evenly between TE Products and Louis Dreyfus.  Depreciation expense on assets each originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed.  Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the nine months ended September 30, 2004, TE Products’ sharing ratio in the earnings of MB Storage was approximately 72.3%.  During the nine months ended September 30, 2004, TE Products contributed $19.4 million to MB Storage, of which $16.5 million was used to acquire storage assets in April 2004.  During the three months and nine months ended September 30, 2004, TE Products received distributions of $2.8 million and $7.7 million, respectively, from MB Storage.  No distributions were received during the three months and nine months ended September 30, 2003.

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, 2004 and 2003, is presented below (in thousands): 

Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of September 30, 2004, and December 31, 2003, is presented below (in thousands):

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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.

NOTE 8.  DEBT

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.  The Short-term Revolver expired on March 27, 2003.

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, 2004, 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.  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 additional indebtedness.  As of September 30, 2004, 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

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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, 2004, 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 September 30, 2004, and December 31, 2003 (in millions):

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 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, 2004, $325.5 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 2.5%.  At September 30, 2004, we were in compliance with the covenants of this credit agreement.  On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing.

We 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, which matured on April 6, 2004 (see Note 4.  Interest Rate Swaps).

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The following table summarizes the principal amounts outstanding under our credit facilities as of September 30, 2004, and December 31, 2003 (in thousands):

NOTE 9.  PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offerings

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 Duke Energy Transport and Trading Company, LLC.  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 was 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 5.  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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The following table reflects the allocation of total distributions paid during the nine months ended September 30, 2004 and 2003 (in thousands, except per Unit amounts):

On November 5, 2004, we will pay a cash distribution of $0.6625 per Unit for the quarter ended September 30, 2004.  The third quarter 2004 cash distribution will total $58.7 million.

General Partner’s Interest

As of September 30, 2004, and December 31, 2003, we had a deficit balance of $27.1 million and $7.2 million, respectively, 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 generally consists of its cumulative share of our net income less cash distributions made to the General Partner plus capital contributions that it has made to us.  For the nine months ended September 30, 2004, the General Partner was allocated $30.0 million (representing 28.85%) of our net income and received $50.0 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 Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners.  At September 30, 2004, and 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

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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.  Cash distributions in excess of net income allocations and capital contributions during the year ended December 31, 2003, and the nine months ended September 30, 2004, resulted in a deficit in the General Partner’s equity account at December 31, 2003, and September 30, 2004.  Future cash distributions that 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.  If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.

NOTE 10. EMPLOYEE BENEFIT PLANS

Retirement Plans

We have adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”), which is a non-contributory, trustee-administered pension plan.  In addition, certain executive officers participate in the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”), which is a non-contributory, 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 three months and nine months ended September 30, 2004 and 2003, were as follows (in thousands):

Other Postretirement Benefits

Effective January 1, 2001, we provide 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

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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 costs for the TEPPCO OPB for the three months and nine months ended September 30, 2004 and 2003, were as follows (in thousands):

Estimated Future Benefit Contributions

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

NOTE 11. 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, sales 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 as 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, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 7.  Equity Investments).

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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 along 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 coal bed methane (“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 following tables include financial information by reporting segment for the three months and nine months ended September 30, 2004 and 2003 (in thousands):

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