PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

(in thousands)

	September 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	9,625		$	29,469
Accounts receivable, trade (net of allowance for doubtful accounts of $125 and $4,700)	511,746			371,938
Accounts receivable, related parties	18,271			3,143
Inventories	29,184			16,060
Other	35,063			32,208
Total current assets	603,889			452,818
Property, plant and equipment, at cost (net of accumulated
depreciation and amortization of $390,921 and $345,357)	1,668,997			1,619,163
Equity investments	375,188			365,286
Intangible assets	414,520			438,565
Goodwill	16,944			16,944
Other assets	53,425			48,216
Total assets	$	3,132,963		$	2,940,992
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	531,428		$	359,660
Accounts payable, related parties	18,150			16,269
Accrued interest	12,659			35,111
Other accrued taxes	12,795			9,941
Other	46,022			54,610
Total current liabilities	621,054			475,591
Senior Notes	1,128,620			1,129,650
Other long-term debt	325,500			210,000
Other liabilities and deferred credits	16,017			16,430
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive loss	—			(2,902		)
General partner’s interest	(27,143		)	(7,181		)
Limited partners’ interests	1,068,915			1,119,404
Total partners’ capital	1,041,772			1,109,321
Total liabilities and partners’ capital	$	3,132,963		$	2,940,992

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per Unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Operating revenues:
Sales of petroleum products	$	1,359,954		$	946,402		$	3,774,874		$	2,849,594
Transportation – Refined products	43,386			37,992			113,294			102,688
Transportation – LPGs	16,071			18,498			58,572			62,676
Transportation – Crude oil	9,288			6,813			28,164			20,777
Transportation – NGLs	10,430			9,996			31,022			29,335
Gathering – Natural gas	35,515			34,081			104,444			100,627
Other	15,366			13,107			52,265			41,231
Total operating revenues	1,490,010			1,066,889			4,162,635			3,206,928

Costs and expenses:
Purchases of petroleum products	1,345,677			932,546			3,730,330			2,807,734
Operating, general and administrative	61,235			52,199			167,095			141,224
Operating fuel and power	12,721			10,413			34,397			30,560
Depreciation and amortization	30,277			22,562			84,508			73,362
Taxes – other than income taxes	3,868			3,904			13,993			13,403
Gains on sales of assets	(849		)	—			(1,071		)	(3,948		)
Total costs and expenses	1,452,929			1,021,624			4,029,252			3,062,335

Operating income	37,081			45,265			133,383			144,593

Interest expense – net	(17,131		)	(20,537		)	(53,190		)	(64,398		)
Equity earnings	5,621			5,768			22,854			17,728
Other income (expense) – net	284			(5		)	1,000			437

Net income	$	25,855		$	30,491		$	104,047		$	98,360

Net Income Allocation:
Limited Partner Unitholders	$	18,396		$	21,620		$	74,032		$	69,361
Class B Unitholder	—			—			—			1,806
General Partner	7,459			8,871			30,015			27,193
Total net income allocated	$	25,855		$	30,491		$	104,047		$	98,360

Basic and diluted net income per Limited Partner and Class B Unit	$	0.29		$	0.36		$	1.18		$	1.21

Weighted average Limited Partner and Class B Units outstanding	62,999			60,517			62,999			58,675

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2004			2003
Cash flows from operating activities:
Net income	$	104,047		$	98,360
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	84,508			73,362
Earnings in equity investments, net of distributions	15,774			(6,988		)
Gains on sales of assets	(1,071		)	(3,948		)
Non-cash portion of interest expense	177			4,223
Increase in accounts receivable	(139,808		)	(83,343		)
Increase in inventories	(13,124		)	(380		)
Increase in other current assets	(2,855		)	(4,319		)
Increase in accounts payable and accrued expenses	135,446			85,661
Other	(10,056		)	14,031
Net cash provided by operating activities	173,038			176,659

Cash flows from investing activities:
Proceeds from the sales of assets	1,202			8,531
Acquisition of assets	(3,421		)	(5,459		)
Acquisition of additional interest in Centennial Pipeline LLC	—			(20,000		)
Investment in Centennial Pipeline LLC	(1,500		)	(3,000		)
Investment in Mont Belvieu Storage Partners, L.P.	(19,364		)	(250		)
Capital expenditures, net	(110,900		)	(103,903		)
Net cash used in investing activities	(133,983		)	(124,081		)

Cash flows from financing activities:
Proceeds from revolving credit facility	256,300			382,000
Repayments on revolving credit facility	(140,800		)	(589,000		)
Issuance of Senior Notes	—			198,570
Debt issuance costs	—			(3,079		)
Issuance of Limited Partner Units, net	—			287,554
Repurchase and retirement of Class B Units	—			(113,814		)
General Partner’s contribution	—			2
Distributions paid	(174,399		)	(145,415		)
Net cash provided by (used in) financing activities	(58,899		)	16,818

Net increase (decrease) in cash and cash equivalents	(19,844		)	69,396

Cash and cash equivalents at beginning of period	29,469			30,968
Cash and cash equivalents at end of period	$	9,625		$	100,364

Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.	$	—		$	61,042

Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	75,498		$	76,542

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

(in thousands, except Unit amounts)

	Outstanding Limited Partner Units	General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive Loss			Total

Partners’ capital at December 31, 2003	62,998,554	$	(7,181	)	$	1,119,404		$	(2,902	)	$	1,109,321
Adjustment to issuance of Limited Partner Units, net	—	—			(99		)	—			(99		)
Net income on cash flow hedges	—	—			—			2,902			2,902
Net income allocation	—	30,015			74,032			—			104,047
Cash distributions	—	(49,977		)	(124,422		)	—			(174,399		)

Partners’ capital at September 30, 2004	62,998,554	$	(27,143	)	$	1,068,915		$	—		$	1,041,772

See accompanying Notes to Consolidated Financial Statements.

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,

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

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):

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

Other Intangible Assets

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

	September 30, 2004					December 31, 2003
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortized intangible assets:
Gathering and transportation agreements	$	464,337	$	(84,929	)	$	464,337	$	(62,436	)
Fractionation agreement	38,000		(12,350		)	38,000		(10,925		)
Other	12,262		(2,800		)	11,270		(1,681		)
Total	$	514,599	$	(100,079	)	$	513,607	$	(75,042	)

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):

2004	$	34,915
2005	34,319
2006	34,305
2007	35,306
2008	32,982

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.

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.

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

Property, plant and equipment	$	12,811
Intangible assets	8,742
Other	144
Total assets	21,697

Total liabilities assumed	(687		)
Net assets acquired	$	21,010

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):

	September 30, 2004		December 31, 2003
Crude oil	$	13,832	$	1,303
Refined products	2,548		6,632
LPGs	3,240		517
Lubrication oils and specialty chemicals	3,925		3,080
Materials and supplies	5,524		4,528
Other	115		—
Total	$	29,184	$	16,060

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

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):

	Nine Months Ended September 30,
	2004		2003
Revenues	$	115,843	$	96,941
Net income	44,344		30,947

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):

	September 30, 2004		December 31, 2003
Current assets	$	64,580	$	56,243
Noncurrent assets	634,013		609,215
Current liabilities	44,966		43,177
Long-term debt	140,000		140,000
Noncurrent liabilities	19,862		13,182
Partners’ capital	493,765		469,099

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):

	Face Value		September 30, 2004		December 31, 2003
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	193.8	$	192.7
7.625% Senior Notes, due February 2012	500.0		577.0		559.0
6.125% Senior Notes, due February 2013	200.0		210.7		199.8
7.51% TE Products Senior Notes, due January 2028	210.0		218.2		217.4

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).

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

	September 30, 2004		December 31, 2003

Credit Facilities:
Revolving Credit Facility, due June 2006	$	325,500	$	210,000
6.45% TE Products Senior Notes, due January 2008	179,899		179,876
7.625% Senior Notes, due February 2012	498,382		498,216
6.125% Senior Notes, due February 2013	198,809		198,702
7.51% TE Products Senior Notes, due January 2028	210,000		210,000
Total borrowings	1,412,590		1,296,794
Adjustment to carrying value associated with hedges of fair value	41,530		42,856
Total Credit Facilities	$	1,454,120	$	1,339,650

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:

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

The following table reflects the allocation of total distributions paid during the nine months ended September 30, 2004 and 2003 (in thousands, except per Unit amounts):

	Nine Months Ended September 30,
	2004		2003
Limited Partner Units	$	124,422	$	104,478
General Partner Ownership Interest	2,539		2,180
General Partner Incentive	47,438		36,410
Total Partners’ Capital Cash Distributions	174,399		143,068
Class B Units	—		2,347
Total Cash Distributions Paid	$	174,399	$	145,415
Total Cash Distributions Paid Per Unit	$	1.975	$	1.85

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

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):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Service cost benefit earned during the period	$	936		$	795		$	2,808		$	2,385
Interest cost on projected benefit obligation	176			126			528			378
Expected return on plan assets	(224		)	(151		)	(672		)	(453		)
Amortization of prior service cost	2			2			6			6
Recognized net actuarial loss	4			6			12			18
Net pension benefits costs	$	894		$	778		$	2,682		$	2,334

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).

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):

	Three Months Ended September 30, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	1,358,220		$	1,734	$	1,359,954		$	—		$	1,359,954
Operating revenues	68,546			11,866			49,961		130,373			(317		)	130,056
Purchases of petroleum products	—			1,344,613			1,381		1,345,994			(317		)	1,345,677
Operating expenses, including power	43,419			17,804			16,601		77,824			—			77,824
Depreciation and amortization expense	12,818			3,268			14,191		30,277			—			30,277
Gains on sales of assets	(472		)	(377		)	—		(849		)	—			(849		)
Operating income	12,781			4,778			19,522		37,081			—			37,081
Equity earnings (losses)	(322		)	5,943			—		5,621			—			5,621
Other income, net	203			60			21		284			—			284
Earnings before interest	$	12,662		$	10,781		$	19,543	$	42,986		$	—		$	42,986

	Three Months Ended September 30, 2003
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	946,402		$	—	$	946,402		$	—		$	946,402
Operating revenues	65,009			9,575			46,045		120,629			(142		)	120,487
Purchases of petroleum products	—			932,688			—		932,688			(142		)	932,546
Operating expenses, including power	40,336			14,792			11,388		66,516			—			66,516
Depreciation and amortization expense	7,127			2,594			12,841		22,562			—			22,562
Operating income	17,546			5,903			21,816		45,265			—			45,265
Equity earnings (losses)	(1,437		)	7,205			—		5,768			—			5,768
Other income, net	70			(183		)	108		(5		)	—			(5		)
Earnings before interest	$	16,179		$	12,925		$	21,924	$	51,028		$	—		$	51,028

	Nine Months Ended September 30, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	3,770,006		$	4,868	$	3,774,874		$	—		$	3,774,874
Operating revenues	205,719			37,430			146,994		390,143			(2,382		)	387,761
Purchases of petroleum products	—			3,728,345			4,367		3,732,712			(2,382		)	3,730,330
Operating expenses, including power	122,118			46,880			46,487		215,485			—			215,485
Depreciation and amortization expense	31,106			9,381			44,021		84,508			—			84,508
Gains on sales of assets	(587		)	(484		)	—		(1,071		)	—			(1,071		)
Operating income	53,082			23,314			56,987		133,383			—			133,383
Equity earnings (losses)	(2,069		)	24,923			—		22,854			—			22,854
Other income, net	648			257			95		1,000			—			1,000
Earnings before interest	$	51,661		$	48,494		$	57,082	$	157,237		$	—		$	157,237

	Nine Months Ended September 30, 2003
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	2,849,594		$	—	$	2,849,594		$	—		$	2,849,594
Operating revenues	193,032			28,461			137,411		358,904			(1,570		)	357,334
Purchases of petroleum products	—			2,809,304			—		2,809,304			(1,570		)	2,807,734
Operating expenses, including power	108,153			43,384			33,650		185,187			—			185,187
Depreciation and amortization expense	21,341			8,125			43,896		73,362			—			73,362
Gain on sale of assets	—			(3,948		)	—		(3,948		)	—			(3,948		)
Operating income	63,538			21,190			59,865		144,593			—			144,593
Equity earnings (losses)	(2,632		)	20,360			—		17,728			—			17,728
Other income, net	119			219			172		510			(73		)	437
Earnings before interest	$	61,025		$	41,769		$	60,037	$	162,831		$	(73	)	$	162,758

The following table shows total assets, capital expenditures and significant non-cash investing activities for each of our reporting segments as of September 30, 2004, and December 31, 2003 (in thousands):

	Downstream Segment		Upstream Segment		Midstream Segment		Segments Total		Partnership and Other			Consolidated

September 30, 2004:
Total assets	$	952,050	$	1,025,832	$	1,176,289	$	3,154,171	$	(21,208	)	$	3,132,963
Capital expenditures	50,893		27,994		31,416		110,303		597			110,900

December 31, 2003:
Total assets	$	916,917	$	834,502	$	1,194,844	$	2,946,263	$	(5,271	)	$	2,940,992
Capital expenditures	59,061		13,427		67,882		140,370		147			140,517
Non-cash investing activities	61,042		—		—		61,042		—			61,042

The following table reconciles the segments’ total earnings before interest to consolidated net income for the three months and nine months ended September 30, 2004 and 2003 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Earnings before interest	$	42,986		$	51,028		$	157,237		$	162,758
Interest expense – net	(17,131		)	(20,537		)	(53,190		)	(64,398		)
Net income	$	25,855		$	30,491		$	104,047		$	98,360

NOTE 12. COMMITMENTS AND CONTINGENCIES

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery

and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. We have filed an answer to both complaints, denying the allegations, as well as various other motions. In April 2004, the court granted a partial motion for summary judgment in favor of the defendants, dismissing two of the plaintiffs’ personal injury claims in their entirety. It is anticipated that the plaintiffs will appeal this ruling. These cases are not covered by insurance. Discovery is ongoing, and we are defending ourselves vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suits. We cannot estimate the loss, if any, associated with these pending lawsuits.

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

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

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

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

In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

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

On March 26, 2004, an initial decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, et al. was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision lists factors that will be considered by the FERC, which include showing a substantial change in economic circumstances, the time factor that will be reviewed, what will be considered the basis of the rate and a pipeline’s documentary requirements. The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowed total return and total cost of service (including major cost elements of rate base such as tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rate and income tax allowances as standalone factors. The FERC further found that if a complainant can show that a pipeline’s volumes and overall cost of service collectively reflect a significant increase in net earnings between the establishment of the challenged rate pre-1992 and the time of the

complaint, based primarily on the combined impact of changes in volumes and changes in overall cost of service, the complainant has met its burden relative to establishing “changed circumstances.” It appears likely that the decision will be appealed. We have not yet determined the impact, if any, that the decision could have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit issued a decision in BP West Coast Products, LLC v. Federal Energy Regulatory Commission and United States of America, which reviewed the decisions that the FERC issued in Opinion Nos. 435, 435-A, 435-B and Clarification and Rehearing Order. In these opinions, the FERC considered the tariffs of SFPP, L.P. (“SFPP”) and complaints and other filings by shipper customers of SFPP. The Court determined, in part, that SFPP, a publicly traded limited partnership, is not allowed to include income tax allowance in its cost-of-service analysis in the determination of just and reasonable rates that were not grandfathered under the EP Act. With respect to SFPP’s grandfathered rates, the Court remanded to the FERC for further review, in light of the Court’s holding on income tax allowance, of the FERC’s determination that changes in the FERC’s tax allowance policy do not constitute “substantially changed circumstances” under the EP Act. The Court’s decision on income tax allowance does not affect our current rates and rate structure because our rates are not based on the cost-of-service methodology. However, the Court’s decision might become relevant to us should we (i) elect in the future to use cost-of-service to support our rates or (ii) be required to use such methodology to defend our indexed rates against a shipper complaint.

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. At September 30, 2004, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. Effective in March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. We are in the process of negotiating a final settlement with the State of Illinois, and we do not expect that compliance with the settlement will have a future material adverse effect on our financial position, results of operations or cash flows.

On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a stormwater retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” Such a violation, if proven, would be a misdemeanor criminal offense; however, we deny that any such criminal violation occurred, and we are vigorously defending our position in this matter. We do not expect the results of this notice will have a future material adverse effect on our financial position, results of operations or cash flows.

On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel

from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the United States Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter, and we do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.

At September 30, 2004, we have an accrued liability of $7.0 million, related to various TCTM and TE Products sites requiring environmental remediation activities. We do not expect that the completion of remediation programs associated with TCTM and TE Products activities will have a future material adverse effect on our financial position, results of operations or cash flows.

We regularly review our long-lived assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. At September 30, 2004, we have identified certain assets that we are assessing for recoverability resulting from recent operational changes. We are continuing to monitor these circumstances; however, we do not believe that the resolution of the matter will have a material effect on our financial condition, results of operations or cash flows.

Centennial has entered into credit facilities totaling $150.0 million and, as of September 30, 2004, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of Centennial’s pipeline system. TE Products and Marathon have each guaranteed one half of Centennial’s debt, up to a maximum amount of $75.0 million each.

NOTE 13. COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on certain investments to be reported in a financial statement. As of September 30, 2004, and for the nine months ended September 30, 2004 and 2003, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. This interest rate swap matured on April 6, 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in net income. As of September 30, 2004, all other comprehensive income has been recognized in net income.

The table below reconciles reported net income to total comprehensive income for the three months and nine months ended September 30, 2004 and 2003 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Net income	$	25,855	$	30,491	$	104,047	$	98,360
Net income on cash flow hedges	—		3,739		2,902		12,443
Total comprehensive income	$	25,855	$	34,230	$	106,949	$	110,803

	September 30, 2004
	TEPPCO Partners, L .P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	35,362	$	88,957	$	528,685	$	(49,115	)	$	603,889
Property, plant and equipment – net	—		1,181,242		487,755		—			1,668,997
Equity investments	1,041,799		430,003		205,051		(1,301,665		)	375,188
Intercompany notes receivable	1,057,192		—		—		(1,057,192		)	—
Intangible assets	—		378,944		35,576		—			414,520
Other assets	5,309		25,509		39,551		—			70,369
Total assets	$	2,139,662	$	2,104,655	$	1,296,618	$	(2,407,972	)	$	3,132,963
Liabilities and partners’ capital
Current liabilities	$	35,861	$	122,821	$	511,487	$	(49,115	)	$	621,054
Long-term debt	1,060,327		393,793		—		—			1,454,120
Intercompany notes payable	—		653,306		403,885		(1,057,191		)	—
Other long term liabilities	1,702		11,737		2,578		—			16,017
Total partners’ capital	1,041,772		922,998		378,668		(1,301,666		)	1,041,772
Total liabilities and partners’ capital	$	2,139,662	$	2,104,655	$	1,296,618	$	(2,407,972	)	$	3,132,963

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

	Three Months Ended September 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	106,776		$	1,383,551		$	(317	)	$	1,490,010
Costs and expenses	—		81,291			1,372,804			(317		)	1,453,778
Gains on sales of assets	—		(472		)	(377		)	—			(849		)
Operating income	—		25,957			11,124			—			37,081
Interest expense – net	—		(11,625		)	(5,506		)	—			(17,131		)
Equity earnings	25,855		11,304			5,943			(37,481		)	5,621
Other income – net	—		219			65			—			284
Net income	$	25,855	$	25,855		$	11,626		$	(37,481	)	$	25,855

	Three Months Ended September 30, 2003
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	98,013		$	969,018		$	(142	)	$	1,066,889
Costs and expenses	—		66,130			955,636			(142		)	1,021,624
Operating income	—		31,883			13,382			—			45,265
Interest expense – net	—		(12,493		)	(8,044		)	—			(20,537		)
Equity earnings	30,491		10,871			7,205			(42,799		)	5,768
Other income – net	—		230			(235		)	—			(5		)
Net income	$	30,491	$	30,491		$	12,308		$	(42,799	)	$	30,491

	Nine Months Ended September 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	317,477		$	3,847,540		$	(2,382	)	$	4,162,635
Costs and expenses	—		226,236			3,806,469			(2,382		)	4,030,323
Gains on sales of assets	—		(587		)	(484		)	—			(1,071		)
Operating income	—		91,828			41,555			—			133,383
Interest expense – net	—		(35,636		)	(17,554		)	—			(53,190		)
Equity earnings	104,047		47,144			24,923			(153,260		)	22,854
Other income – net	—		711			289			—			1,000
Net income	$	104,047	$	104,047		$	49,213		$	(153,260	)	$	104,047

	Nine Months Ended September 30, 2003
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	291,904		$	2,916,594		$	(1,570	)	$	3,206,928
Costs and expenses	—		189,370			2,878,483			(1,570		)	3,066,283
Gain on sale of assets	—		—			(3,948		)	—			(3,948		)
Operating income	—		102,534			42,059			—			144,593
Interest expense – net	—		(40,484		)	(23,987		)	73			(64,398		)
Equity earnings	98,360		36,042			20,360			(137,034		)	17,728
Other income – net	—		268			242			(73		)	437
Net income	$	98,360	$	98,360		$	38,674		$	(137,034	)	$	98,360

	Nine Months Ended September 30, 2004
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	104,047		$	104,047		$	49,213		$	(153,260	)	$	104,047
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			67,784			16,724			—			84,508
Earnings in equity investments, net of distributions	70,352			(4,236		)	5,977			(56,319		)	15,774
Gains on sales of assets	—			(587		)	(484		)	—			(1,071		)
Changes in assets and liabilities and other	(133,125		)	4,060			(27,902		)	126,747			(30,220		)
Net cash provided by operating activities	41,274			171,068			43,528			(82,832		)	173,038
Cash flows from investing activities	98			(17,830		)	(29,888		)	(86,363		)	(133,983		)
Cash flows from financing activities	(58,899		)	(165,268		)	(16,898		)	182,166			(58,899		)
Net decrease in cash and cash equivalents	(17,527		)	(12,030		)	(3,258		)	12,971			(19,844		)
Cash and cash equivalents at beginning of period	19,744			19,243			5,670			(15,188		)	29,469
Cash and cash equivalents at end of period	$	2,217		$	7,213		$	2,412		$	(2,217	)	$	9,625

	Nine Months Ended September 30, 2003
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	98,360		$	98,360		$	38,674		$	(137,034	)	$	98,360
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			58,274			15,088			—			73,362
Earnings in equity investments, net of distributions	47,055			(7,583		)	(9,620		)	(36,840		)	(6,988		)
Gain on sale of assets	—			—			(3,948		)	—			(3,948		)
Changes in assets and liabilities and other	103,806			(19,471		)	(45,929		)	(22,533		)	15,873
Net cash provided by (used in) operating activities	249,221			129,580			(5,735		)	(196,407		)	176,659
Cash flows from investing activities	(175,615		)	(164,221		)	(6,407		)	222,162			(124,081		)
Cash flows from financing activities	16,815			40,987			(6,949		)	(34,035		)	16,818
Net increase (decrease) in cash and cash equivalents	90,421			6,346			(19,091		)	(8,280		)	69,396
Cash and cash equivalents at beginning of period	—			8,247			22,721			—			30,968
Cash and cash equivalents at end of period	$	90,421		$	14,593		$	3,630		$	(8,280	)	$	100,364

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

You should read the following review of our financial position and results of operations in conjunction with our Consolidated Financial Statements and the notes thereto. Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes our cash flows and financial position. “Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect our future liquidity or earnings. The Consolidated Financial Statements should be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2003.

Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is detailed in our consolidated financial statements for the year ended December 31, 2003, included in our Annual Report on Form 10-K. Certain of these accounting policies require the use of estimates. The following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: revenue and expense accruals, including accruals for power costs, property taxes and crude oil margins; environmental costs; depreciation expense and asset impairment analysis related to property, plant and equipment; and amortization expense and asset impairment analysis related to goodwill and other intangible assets. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

Management Overview of the Three Months and Nine Months Ended September 30, 2004

We reported net income of $25.9 million, or $0.29 per Limited Partner and Class B Unit (collectively, “Unit” or “Units”), for the three months ended September 30, 2004, compared with net income of $30.5 million, or $0.36 per Unit, for the three months ended September 30, 2003. Net income for the nine months ended September 30, 2004, was $104.1 million, or $1.18 per Unit, compared with net income of $98.4 million, or $1.21 per Unit, for the nine months ended September 30, 2003. Our three month and nine month periods ended September 30, 2004, include a non-cash asset impairment charge of $4.4 million (see Note 3. Property, Plant and Equipment) and increased pipeline integrity costs of approximately $3.5 million and $14.2 million, respectively, for the three months and nine months ended September 30, 2004, on all of our business segments. These decreases in net income were partially offset by the recognition of $4.1 million of deferred revenue in our Downstream Segment. The weighted average number of Units outstanding was 63.0 million and 60.5 million for the three months ended September 30, 2004 and 2003, respectively, and 63.0 million and 58.7 million for the nine months ended September 30, 2004 and 2003, respectively.

Our Upstream Segment had a strong nine months, with increased transportation volumes on Seaway Crude Pipeline Company (“Seaway”) and on our South Texas system, which benefited from our November 2003 acquisition of assets from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”), partially offset by increased pipeline integrity expenses of $3.7 million. We anticipate that our 2004 pipeline integrity expenses for our Upstream Segment will be approximately $5.4 million higher than our 2003 costs as we continue to perform pipeline inspections and repairs under our integrity management program.

Our Downstream Segment results for the three months and nine months ended September 30, 2004, were impacted by higher pipeline integrity expenses of $1.1 million and $9.1 million, respectively, and an asset impairment charge of $4.4 million related to a marine facility in Beaumont, Texas. These decreases were partially offset by increased revenues from our refined products business and the recognition of $4.1 million of deferred

revenue. We anticipate that our pipeline integrity expenses for our Downstream Segment for 2004 will be approximately $3.0 million higher than our 2003 costs.

Our Midstream Segment benefited from increased volumes on Jonah Gas Gathering Company (“Jonah”), resulting from our recent Phase III expansion, offsetting the impact of reduced volumes on Val Verde Gas Gathering Company (“Val Verde”) primarily due to the natural decline of coal bed methane (“CBM”) production and slower than anticipated completion and connection of infill wells.

We increased our quarterly distribution from $0.65 per Unit to $0.6625 per Unit for the first quarter of 2004. Our third quarter distribution will remain at $0.6625 per Unit and will be paid on November 5, 2004.

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

We remain confident that our current strategy and focus will provide continued growth in earnings and cash distributions. These growth opportunities include:

• continued development of refined products and propane market opportunities, including pipeline and terminal expansions;

• continued development of the Jonah gas gathering system which serves the Jonah and Pinedale fields;

• integration of the Genesis crude oil assets and increased utilization of Seaway; and

• gathering of volumes from infill drilling of CBM by producers and new connections of conventional gas in the San Juan Basin, where our Val Verde system is located.

We have completed system changes to reverse the flow of the pipeline segment from Shreveport, Louisiana, to El Dorado, Arkansas. This segment is now configured to permit bi-directional flow of products. We have completed feasibility studies and are in discussions with potential customers regarding the transportation of volumes through the pipeline system in this area.

We are currently constructing a new refined products truck loading terminal in Bossier City, Louisiana. The facility will include six storage tanks and a fully automated two-bay truck loading rack. The terminal will expand delivery capacity of refined products to the Northwest Louisiana and East Texas markets by more than 20,000 barrels per day. The facility will increase the delivery of branded and unbranded premium and regular gasoline, as well as low-sulfur diesel fuels, which will meet the different product specifications of both market areas. The project is scheduled to be completed in the first quarter of 2005.

In 2003, we increased the delivery capability between Todhunter, Ohio, and Coshocton, Ohio, by 8,000 to 10,000 barrels per day and increased storage and improved loading capability at Oneonta, New York. We are nearing completion of a Phase II project to further expand our delivery capacity of liquefied petroleum gases (“LPGs”) to the Northeast by 8,000 to 10,000 barrels per day. The Phase II expansion includes the construction of three pump stations between Coshocton and Greensburg, Pennsylvania, and two stations from Greensburg to Watkins Glen, New York. Additional work on the pipeline segment between Greensburg and Philadelphia, Pennsylvania, to increase delivery rates to the Philadelphia area has been completed. Improvements are also underway at our Dubois, Pennsylvania, and Eagle, Pennsylvania, terminals. These projects will be completed by year-end 2004.

We have expanded both the pipeline capacity and processing capacity of the Jonah system. In 2003, the Phase III expansion was begun, which included an 80-mile expansion and 3,700 horsepower of new compression on the system and the building of a new 250 million cubic feet per day (“MMcf/day”) gas processing plant near Opal, Wyoming. Phase III was substantially completed during the fourth quarter of 2003, with system capacity increasing

to 1,180 MMcf/day at a cost of approximately $59.0 million. Additional capacity of 100 MMcf/day is expected to be completed in the fourth quarter of 2004, at a cost of approximately $13.0 million.

We completed an acquisition in 2003 and expanded systems that have improved our results of operations as discussed in this Report. 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. 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 (see Note 5. Acquisitions and Dispositions). The acquisition of Genesis was accounted for in accordance with the purchase method of accounting under Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations. Additionally, during 2004, the Basin system, which is a part of our Upstream Segment, was expanded between Midland, Texas, and Cushing, Oklahoma, resulting in an additional capacity of ten thousand barrels per day on the system.

Consistent with our business strategy, we continuously evaluate possible acquisitions of assets that would complement our current operations. Such acquisition efforts involve participation by us in processes that have been made public and involve a number of potential buyers, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial position, results of operations or cash flows.

Our Business

TEPPCO Partners, L.P., a Delaware limited partnership, is a publicly traded 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”), which are collectively 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. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, is the general partner of our Operating Partnerships. We hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.

We operate and report in three business segments:

• Downstream Segment – transportation and storage of refined products, LPGs and petrochemicals;

• Upstream Segment – gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and

• Midstream Segment – gathering of natural gas, transportation of natural gas liquids (“NGLs”) and fractionation of NGLs.

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

Results of Operations

The following table summarizes financial information by business segment for the three months and nine months ended September 30, 2004 and 2003 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Operating revenues:
Downstream Segment	$	68,546		$	65,009		$	205,719		$	193,032
Upstream Segment	1,370,086			955,977			3,807,436			2,878,055
Midstream Segment	51,695			46,045			151,862			137,411
Intersegment eliminations	(317		)	(142		)	(2,382		)	(1,570		)
Total operating revenues	1,490,010			1,066,889			4,162,635			3,206,928

Operating income:
Downstream Segment	12,781			17,546			53,082			63,538
Upstream Segment	4,778			5,903			23,314			21,190
Midstream Segment	19,522			21,816			56,987			59,865
Total operating income	37,081			45,265			133,383			144,593

Earnings before interest:
Downstream Segment	12,662			16,179			51,661			61,025
Upstream Segment	10,781			12,925			48,494			41,769
Midstream Segment	19,543			21,924			57,082			60,037
Intersegment eliminations	—			—			—			(73		)
Total earnings before interest	42,986			51,028			157,237			162,758

Interest expense	(18,495		)	(22,352		)	(57,002		)	(67,772		)
Interest capitalized	1,364			1,815			3,812			3,374
Net income	$	25,855		$	30,491		$	104,047		$	98,360

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

Downstream Segment

The following table presents volumes delivered in barrels and average tariff per barrel for the three months and nine months ended September 30, 2004 and 2003 (in thousands, except tariff information):

	Three Months Ended				Percentage		Nine Months Ended				Percentage
	September 30,				Increase		September 30,				Increase
	2004		2003		(Decrease)		2004		2003		(Decrease)
Volumes Delivered
Refined products	41,726		42,476		(2	)%	116,184		114,964		1	%
LPGs	9,107		9,146		—		31,109		29,678		5	%
Total	50,833		51,622		(2	)%	147,293		144,642		2	%

Average Tariff per Barrel
Refined products	$	1.04	$	0.89	17	%	$	0.98	$	0.89	10	%
LPGs	1.76		2.02		(13	)%	1.88		2.11		(11	)%
Average system tariff per barrel	$	1.17	$	1.09	7	%	$	1.17	$	1.14	3	%

Three Months Ended September 30, 2004 Compared with Three Months Ended September 30, 2003

Our Downstream Segment reported earnings before interest of $12.7 million for the three months ended September 30, 2004, compared with earnings before interest of $16.2 million for the three months ended September 30, 2003. Earnings before interest decreased $3.5 million primarily due to an increase of $8.3 million in costs and expenses, partially offset by an increase of $3.6 million in operating revenues, a decrease of $1.1 million in losses from equity investments and an increase of $0.1 million in other income – net. We discuss the factors influencing our operating performance below.

Revenues from refined products transportation increased $5.4 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to the recognition of $4.1 million of deferred revenue related to the expiration of two customer transportation agreements. Under some of our transportation agreements with customers, the contracts specify minimum monthly payments for transportation services. If the transportation services for the month are not used, the unused transportation service is recorded as deferred revenue. The contracts generally specify a subsequent period of time in which the customer can deliver excess products to us to recover the deferred revenue. During the third quarter of 2004, the time limit under two transportation agreements expired without the customers recovering the deferred revenue. As a result, we recognized the deferred revenue as refined products revenues in the current period. This additional revenue increased the refined products average tariff by $0.10 per barrel, or 11%.

The remaining refined products average tariff increased 6% primarily as a result of higher market-based tariff rates which went into effect in May 2004 and decreased short-haul deliveries of product received into our system from Centennial at Creal Springs, Illinois. Prior to the construction of Centennial, deliveries on our pipeline system were limited by our pipeline capacity, and transportation services for our customers were allocated in accordance with a proration policy. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. In February 2003, we entered into a lease agreement with Centennial that increased our flexibility to deliver refined products to our market areas. During the three months ended September 30, 2004, overall refined product volumes transported decreased 2% primarily due to lower short-haul volumes received into our system from Centennial, partially offset by increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets.

Revenues from LPGs transportation decreased $2.4 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to lower deliveries of propane in the upper Midwest and Northeast market areas due to less favorable price differentials between Mont Belvieu and other propane storage centers combined with pipeline downtime associated with the completion of the Northeast capacity expansion project, partially offset by higher deliveries of isobutane to Chicago area refineries and increased short-haul propane deliveries to Gulf Coast petrochemical customers. The higher propane prices in 2004 also reduced the fill of consumer storage of propane during 2004. The LPGs average rate per barrel decreased 13% from the prior year period primarily as a result of increased short-haul deliveries during the three months ended September 30, 2004.

Other operating revenues increased $0.6 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to higher refined products tender deduction and loading fees. These increases were partially offset by lower revenues from product exchanges, which are used to position product in the Midwest market area.

Costs and expenses increased $8.3 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. The increase was made up of a $5.7 million increase in depreciation and amortization expense, a $2.8 million increase in operating, general and administrative expenses and a $0.8 million increase in operating fuel and power, partially offset by a $0.5 million decrease in taxes – other than income taxes and $0.5 million of net gains on the sales of assets. Depreciation expense increased from the prior year period because of a $4.4 million charge in the third quarter of 2004, resulting from the impairment of marine assets in the Beaumont, Texas, area (see Note 3. Property, Plant and Equipment). Depreciation expense also increased primarily as a result of assets placed in service during 2003 and 2004. This increase was partially offset by

an increase in the estimated remaining life of a section of our pipeline system in the Northeast, resulting from pipeline capital improvements made as part of our integrity management program. Operating, general and administrative expenses increased primarily due to a $1.1 million increase in pipeline inspection and repair costs associated with our integrity management program, a $0.7 million increase in labor and benefits expense primarily related to incentive compensation plans, a $0.4 million increase in product losses relating to settlements with a shipper regarding jet fuel and an increase of $0.3 million in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002. Operating fuel and power expense increased $0.8 million primarily as a result of higher power rates during the 2004 period. Taxes – other than income taxes decreased $0.5 million as a result of revisions to estimated property tax accruals. In addition, we recognized net gains of $0.5 million for the three months ended September 30, 2004, from the sales of various assets in the Downstream Segment.

Net losses from equity investments decreased $1.1 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, as shown below (in thousands):

	Three Months Ended
	September 30,						Increase
	2004			2003			(Decrease)

Centennial	$	(1,839	)	$	(2,964	)	$	1,125
MB Storage	1,530			1,556			(26		)
Other	(13		)	(29		)	16
Total equity losses	$	(322	)	$	(1,437	)	$	1,115

Equity losses in Centennial for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, decreased $1.1 million primarily due to lower operating expenses, partially offset by a decrease in transportation revenues and volumes. Included in the equity loss for the three months ended September 30, 2004, is $1.7 million of equity income relating to the settlement of certain transmix matters recognized in previous periods.

Equity earnings from our 50% ownership interest in MB Storage remained virtually unchanged for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. In April 2004, MB Storage acquired storage assets and contracts for $33.5 million, of which TE Products contributed $16.5 million. Decreases in equity earnings were due to increased amortization and depreciation expense on the acquired storage assets and contracts, offset by increased storage revenue and rental revenue primarily from the acquired contracts and lower pipeline rehabilitation expenses on the MB Storage system.

Other income – net increased $0.1 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to higher interest income earned on cash investments and other investing activities.

Nine Months Ended September 30, 2004 Compared with Nine Months Ended September 30, 2003

Our Downstream Segment reported earnings before interest of $51.7 million for the nine months ended September 30, 2004, compared with earnings before interest of $61.0 million for the nine months ended September 30, 2003. Earnings before interest decreased $9.3 million primarily due to an increase of $23.2 million in costs and expense, partially offset by an increase of $12.7 million in operating revenues, a decrease of $0.6 million in losses from equity investments and an increase of $0.5 million in other income – net. We discuss the factors influencing our operating performance below.

Revenues from refined products transportation increased $10.6 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to the recognition of $4.1 million of deferred revenue related to the expiration of two customer transportation agreements, an overall increase of 1% in the refined products volumes delivered, primarily due to increases in motor fuel and distillate volumes transported as a result of a strong trucking market, and higher market-based tariff rates which went into effect in July

2003 and May 2004. These volume increases were primarily due to deliveries of products received into our pipeline from Centennial at Creal Springs, Illinois. Centennial has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. Prior to the construction of Centennial, deliveries on our pipeline system were limited by our pipeline capacity, and transportation services for our customers were allocated in accordance with a proration policy. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. In February 2003, we entered into a lease agreement with Centennial that increased our flexibility to deliver refined products to our market areas. Volume increases were due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. The refined products average rate per barrel increased 10% from the prior year period primarily due to higher market-based tariff rates which went into effect in July 2003 and May 2004, partially offset by the impact of the Midwest origin point for barrels received from Centennial, which resulted in decreased short-haul barrels transported on our system.

Revenues from LPGs transportation decreased $4.1 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to lower deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer weather during the first three months of 2004. Additionally, in late February 2004, the Mont Belvieu propane price spiked, which resulted in our sourced propane being less competitive than propane from other source points. Also contributing to the decrease were less favorable price differentials between Mont Belvieu and other supply centers during the second and third quarters of 2004. The higher propane prices in 2004 also reduced the fill of consumer storage of propane during 2004. These decreases were partially offset by increased deliveries of isobutane to Chicago area refineries and increased short-haul propane deliveries to Gulf Coast petrochemical customers. The LPGs average rate per barrel decreased 11% from the prior year period primarily as a result of increased short-haul deliveries during the nine months ended September 30, 2004.

Other operating revenues increased $6.2 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to higher propane inventory fees, higher refined products tender deduction and loading fees, higher revenues from product exchanges, which are used to position product in the Midwest market area, higher margins on product inventory sales and higher propane deliveries at our Providence, Rhode Island import facility.

Costs and expenses increased $23.2 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. The increase was made up of a $14.2 million increase in operating, general and administrative expenses, a $9.8 million increase in depreciation and amortization expense and a $0.1 million increase in operating fuel and power, partially offset by a $0.3 million decrease in taxes – other than income taxes and $0.6 million of net gains on the sales of assets. Operating, general and administrative expenses increased primarily due to a $9.1 million increase in pipeline inspection and repair costs associated with our integrity management program, a $1.4 million increase in consulting and contract services, of which $0.8 million was related to compliance with the Sarbanes-Oxley Act of 2002, a $1.1 million increase in potential acquisition evaluation activities, a $0.9 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, a $0.9 million increase in rental expense primarily related to a capacity lease on another pipeline and a $0.2 million increase in environmental assessment and remediation activities. These increases were partially offset by lower expenses in the 2004 period associated with the write-off of receivables related to customer bankruptcies and non-payments in 2003. Depreciation expense increased from the prior year period because of a $4.4 million charge resulting from the impairment of marine assets in the Beaumont area (see Note 3. Property, Plant and Equipment). Depreciation expense also increased as a result of assets placed in service during 2003, partially offset by an increase in the estimated remaining life of a section of our pipeline system in the Northeast, resulting from pipeline capital improvements made as part of our integrity management program. Taxes – other than income taxes decreased $0.3 million as a result of adjustments in the property tax accruals. In addition, we recognized net gains of $0.6 million for the nine months ended September 30, 2004, from the sales of various assets in the Downstream Segment.

Net losses from equity investments decreased $0.6 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, as shown below (in thousands):

	Nine Months Ended
	September 30,						Increase
	2004			2003			(Decrease)

Centennial	$	(7,982	)	$	(7,969	)	$	(13	)
MB Storage	5,944			5,400			544
Other	(31		)	(63		)	32
Total equity losses	$	(2,069	)	$	(2,632	)	$	563

Equity losses in Centennial for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, remained virtually unchanged, with increases primarily due to the acquisition of an additional 16.7% interest in Centennial on February 10, 2003, bringing TE Products’ ownership interest to 50%, and an increase in operating expenses, offset by increased transportation revenues and volumes. Included in the equity loss for the nine months ended September 30, 2004, is $1.7 million of equity income relating to the settlement of certain transmix matters recognized in previous periods.

Equity earnings from our 50% ownership interest in MB Storage increased $0.5 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. In April 2004, MB Storage acquired storage assets and contracts for $33.5 million, of which TE Products contributed $16.5 million. The increase in equity earnings is due to increased storage revenue, shuttle revenue and rental revenue primarily from the acquired contracts and lower pipeline rehabilitation expenses on the MB Storage system, partially offset by increased amortization and depreciation expense on storage assets and contracts acquired.

Other income – net increased $0.5 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to higher interest income earned on cash investments and other investing activities.

Upstream Segment

Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the Securities and Exchange Commission. We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil. We believe that margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed. Margin and volume information for the three months and nine months ended September 30, 2004 and 2003, is presented below (in thousands, except per barrel and per gallon amounts):

	Three Months Ended				Percentage		Nine Months Ended				Percentage
	September 30,				Increase		September 30,				Increase
	2004		2003		(Decrease)		2004		2003		(Decrease)

Margins:
Crude oil transportation	$	14,485	$	11,182	30	%	$	40,860	$	33,278	23	%
Crude oil marketing	4,327		5,732		(25	)%	16,920		16,936		—
Crude oil terminaling	2,426		2,294		6	%	7,392		6,843		8	%
Lubrication oil sales	1,657		1,319		26	%	4,653		4,010		16	%
Total margin	$	22,895	$	20,527	12	%	$	69,825	$	61,067	14	%

Total barrels:
Crude oil transportation	25,093		22,114		13	%	75,941		70,670		7	%
Crude oil marketing	43,284		43,694		(1	)%	131,208		118,269		11	%
Crude oil terminaling	28,889		28,004		3	%	89,777		83,566		7	%

Lubrication oil volume (total gallons)	3,346		2,420		38	%	9,765		7,573		29	%

Margin per barrel:
Crude oil transportation	$	0.577	$	0.506	14	%	$	0.538	$	0.471	14	%
Crude oil marketing	0.100		0.131		(24	)%	0.129		0.143		(10	)%
Crude oil terminaling	0.084		0.082		3	%	0.082		0.082		—
Lubrication oil margin (per gallon)	0.495		0.545		(9	)%	0.476		0.530		(10	)%

The following table reconciles the Upstream Segment margin to the consolidated statements of income using the information included in the consolidated statements of income and the statements of income in Note 11. Segment Information (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Sales of petroleum products	$	1,358,220		$	946,402		$	3,770,006		$	2,849,594
Transportation – Crude oil	9,288			6,813			28,164			20,777
Less: Purchases of petroleum products	(1,344,613		)	(932,688		)	(3,728,345		)	(2,809,304		)
Total margin	$	22,895		$	20,527		$	69,825		$	61,067

Three Months Ended September 30, 2004 Compared with Three Months Ended September 30, 2003

Our Upstream Segment reported earnings before interest of $10.8 million for the three months ended September 30, 2004, compared with earnings before interest of $12.9 million for the three months ended September 30, 2003. Earnings before interest decreased $2.1 million primarily due to an increase of $3.3 million in costs and

expenses (excluding purchases of crude oil and lubrication oil), a decrease of $1.3 million in equity earnings from Seaway and a decrease of $0.2 million in other operating revenues, partially offset by an increase of $2.4 million in margin and an increase of $0.3 million in other income – net. We discuss factors influencing our operating performance below.

Our margin increased $2.4 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. Crude oil transportation margin increased $3.3 million primarily due to an increase in transportation volumes and an increase in transportation revenues on our South Texas system, our Basin system and our Red River system. During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which are being integrated into our South Texas system (see Note 5. Acquisitions and Dispositions), resulting in an increase in transportation volumes and revenues. These increases were partially offset by lower transportation volumes on our West Texas and other gathering systems. Lubrication oil sales margin increased $0.4 million due to increased sales of chemical volumes and increased volumes related to the acquisitions of lubrication oil distributors in Abilene, Texas, in December 2003 and Casper, Wyoming, in August 2004. Crude oil terminaling margin increased $0.1 million as a result of higher pumpover volumes at Cushing, Oklahoma, partially offset by lower pumpover volumes at Midland, Texas. Crude oil marketing margin decreased $1.4 million primarily due to increased transportation costs and a $0.3 million pricing settlement with a customer.

Other operating revenue of the Upstream Segment decreased $0.2 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $3.3 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. The increase was comprised of a $2.1 million increase in operating, general and administrative expenses, a $0.7 million increase in depreciation and amortization expense, a $0.6 million increase in taxes – other than income taxes and a $0.3 million increase in operating fuel and power, partially offset by a $0.4 million gain on the sale of assets. Operating, general and administrative expenses increased $2.1 million from the prior year period primarily due to a $2.2 million increase in pipeline inspection and repair costs associated with our integrity management program, $0.5 million of additional expenses due to the acquisition of Genesis, including increased labor costs due to an increase in the number of employees between periods and increased operating costs and a $0.2 million increase in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002. These increases were partially offset by $0.9 million of lower environmental assessment and remediation costs in the 2004 period compared with the 2003 period. Depreciation and amortization expense increased $0.7 million primarily due to the assets acquired from Genesis. Taxes – other than income taxes increased $0.6 million due to increases in property tax accruals. Operating fuel and power increased $0.3 million primarily as a result of the acquisition of the Genesis assets and higher volumes in the 2004 period. In addition, we recognized a gain of $0.4 million for the three months ended September 30, 2004, from the sale of our remaining interest in the original Rancho Pipeline system (see Note 5. Acquisitions and Dispositions).

Equity earnings in Seaway decreased $1.3 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to higher operating and general and administrative expenses, partially offset by higher third-party transportation volumes and gains on crude oil inventory sales.

Other income – net increased $0.3 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to higher interest income earned on cash investments.

Nine Months Ended September 30, 2004 Compared with Nine Months Ended September 30, 2003

Our Upstream Segment reported earnings before interest of $48.5 million for the nine months ended September 30, 2004, compared with earnings before interest of $41.8 million for the nine months ended September 30, 2003. Earnings before interest increased $6.7 million primarily due to an increase of $8.8 million in margin, an increase of $4.6 million in equity earnings from Seaway and an increase of $1.6 million in other operating revenues,

partially offset by an increase of $4.8 million in costs and expenses (excluding purchases of crude oil and lubrication oil). Additionally, for the nine months ended September 30, 2004 and 2003, we recognized gains of $0.5 million and $3.9 million, respectively, on the sales of assets. We discuss factors influencing our operating performance below.

Our margin increased $8.8 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. Crude oil transportation margin increased $7.6 million primarily due to an increase in transportation volumes and increased transportation revenues on our South Texas system and increased revenues on our Basin system from movements of barrels on higher tariff segments. During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which are being integrated into our South Texas system (see Note 5. Acquisitions and Dispositions). These increases are partially offset by lower transportation volumes on our West Texas and other gathering systems. Crude oil terminaling margin increased $0.6 million as a result of higher pumpover volumes at Cushing, Oklahoma, partially offset by lower pumpover volumes at Midland, Texas. Lubrication oil sales margin increased $0.6 million due to increased sales of chemical volumes and increased volumes related to the acquisitions of lubrication oil distributors in Abilene, Texas, in December 2003 and in Casper, Wyoming, in August 2004. Crude oil marketing margin remained unchanged with increased volumes marketed, offset by an unfavorable invoicing settlement on a marketing contract in the first quarter of 2003, which reduced the marketing margin in 2003, and increased transportation costs.

Other operating revenue of the Upstream Segment increased $1.6 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to a $1.4 million favorable settlement with the former owner of some of our crude oil assets for inventory imbalances with customers on assets that were not acquired by us, and higher revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $4.8 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. The increase was made up of a $1.8 million increase in operating fuel and power, a $1.3 million increase in depreciation and amortization expense, a $1.0 million increase in operating, general and administrative expenses and a $0.7 million increase in taxes – other than income taxes. Operating fuel and power increased $1.8 million primarily as a result of the acquisition of the Genesis assets and higher volumes in the 2004 period. Depreciation and amortization expense increased $1.3 million primarily due to the assets acquired from Genesis. Operating, general and administrative expenses increased $1.0 million from the prior year period primarily due to a $3.7 million increase in pipeline inspection and repair costs associated with our integrity management program, a $1.9 million increase in labor and benefits expense related to incentive compensation plans and an increase in the number of employees between periods, a $1.7 million increase in expenses related to the Genesis acquisition, a $0.6 million increase in rental expense due to our pipeline lease at Freeport with Seaway and a $0.4 million increase in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002. These increases were partially offset by $4.1 million of higher environmental assessment and remediation costs in 2003, $1.7 million of expense in 2003 from the net settlement of crude oil imbalances with customers and $1.5 million of higher legal costs in 2003 related to the litigation and settlement with D.R.D. Environmental Services, Inc. Taxes – other than income taxes increased $0.7 million due to increases in property tax accruals.

In June 2003, we recorded a net gain of $3.9 million, included in the gain on sale of assets in our consolidated statements of income, on the sale of certain of the assets of the Rancho Pipeline. During the nine months ended September 30, 2004, we recorded net gains of $0.5 million, included in the gains on sales of assets in our consolidated statements of income, primarily related to the sale of our remaining interest in the original Rancho Pipeline system (see Note 5. Acquisitions and Dispositions).

Equity earnings in Seaway increased $4.6 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to higher transportation volumes, gains on crude oil inventory sales and a settlement with a former owner of Seaway’s crude oil assets regarding inventory imbalances with

customers on assets that were not acquired by us, partially offset by higher operating and general and administrative expenses.

Midstream Segment

The following table presents volume and average rate information for the three months and nine months ended September 30, 2004 and 2003 (in thousands, except average fee and average rate amounts):

	Three Months Ended				Percentage		Nine Months Ended				Percentage
	September 30,				Increase		September 30,				Increase
	2004		2003		(Decrease)		2004		2003		(Decrease)
Gathering – Natural Gas – Jonah :
Million cubic feet	90,005		75,807		19	%	257,402		220,600		17	%
Million British thermal units (“MMBtu”)	99,531		84,182		18	%	284,858		244,636		16	%
Average fee per MMBtu	$	0.191	$	0.193	(1	)%	$	0.195	$	0.192	2	%

Gathering – Natural Gas – Val Verde:
Million cubic feet	36,733		39,312		(7	)%	108,213		120,948		(11	)%
MMBtu	31,294		32,981		(5	)%	91,459		101,740		(10	)%
Average fee per MMBtu	$	0.527	$	0.540	(2	)%	$	0.533	$	0.528	1	%

Transportation – NGLs:
Thousand barrels	15,064		14,929		1	%	45,209		43,150		5	%
Average rate per barrel	$	0.692	$	0.670	3	%	$	0.686	$	0.680	1	%

Fractionation – NGLs:
Thousand barrels	994		956		4	%	3,064		3,034		1	%
Average rate per barrel	$	1.866	$	1.873	—		$	1.802	$	1.815	(1	)%

Sales – Condensate:
Thousand barrels	7.3		6.0		22	%	67.0		52.0		29	%
Average rate per barrel	$	43.54	$	23.89	82	%	$	35.58	$	30.22	18	%

Three Months Ended September 30, 2004 Compared with Three Months Ended September 30, 2003

Our Midstream Segment reported earnings before interest of $19.5 million for the three months ended September 30, 2004, compared with earnings before interest of $21.9 million for the three months ended September 30, 2003. Earnings before interest decreased $2.4 million due to an increase of $6.5 million in costs and expenses (excluding purchases of petroleum products) and a decrease of $0.1 million in other income – net, partially offset by an increase of $4.2 million in operating revenues and margin. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $1.4 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. Natural gas gathering revenues from the Jonah system increased $2.7 million and volumes delivered increased 14.2 Bcf for the three months ended September 30, 2004, due to the Phase III expansion of the Jonah system during 2003. The Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity from 880 MMcf/day to 1,180 MMcf/day. Natural gas gathering revenues from the Val Verde system decreased $1.3 million and volumes delivered decreased 2.6 Bcf for the three months ended September 30, 2004, primarily due to the natural decline of

CBM production and slower than anticipated completion and connection of infill wells, partially offset by increased volumes from new well connections to the Val Verde system in late May 2004. Val Verde’s average gas gathering rate decreased 2% for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to new well connections of conventional natural gas, which have a lower gathering rate than the existing Val Verde system average rates, made on the Val Verde system in late May 2004, partially offset by an increase in the average natural gas gathering rate due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas.

Jonah’s Pioneer gas processing plant was completed during the first quarter of 2004, as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming. Pioneer’s processing agreements allow the producers to elect annually whether to be charged under a fee-based arrangement or a fee plus keep-whole arrangement. Under the fee-based election, Jonah receives a fee for its processing services. Under the fee plus keep-whole election, Jonah receives a lower fee for its processing services, retains and sells the NGLs extracted during the process and delivers to the producers residue gas equivalent in energy to the natural gas received from the producers. Jonah purchases gas from a DEFS affiliate to replace the equivalent energy removed in the liquids. Jonah sells the NGLs it retains to a DEFS affiliate. These transactions resulted in a net sales and purchases margin in the three months ended September 30, 2004, of $0.3 million.

Revenues from the transportation of NGLs increased $0.4 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to increased volumes transported on the Chaparral and Panola pipelines, partially offset by decreased volumes transported on the Dean and Wilcox pipelines. The increase in the NGL transportation average rate per barrel resulted primarily from higher average rates per barrel on volumes transported on the Panola and Wilcox pipelines.

Other operating revenues increased $2.1 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003. Processing fee revenues increased $0.7 million as a result of Jonah’s Pioneer processing plant, which was constructed as part of the Phase III expansion and placed in service in January 2004. Jonah’s other operating revenues also increased $0.2 million due to higher condensate sales. Other operating revenues on Val Verde increased primarily due to $0.4 million in revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage for the three months ended September 30, 2004. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractually retained from producers. Value retained from producers or sales generated as a result of efficient fuel usage are recognized as other operating revenues. The remaining increase in other revenues was due to other miscellaneous revenue items.

Costs and expenses (excluding purchases of petroleum products) increased $6.5 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to a $4.1 million increase in operating, general and administrative expense, a $1.4 million increase in depreciation and amortization expense and a $1.2 million increase in operating fuel and power, partially offset by a $0.2 million decrease in taxes – other than income taxes. Operating, general and administrative expense increased due to a $1.6 million increase in pipeline maintenance and repair expenses, of which $0.2 million was associated with our integrity management program, a $0.9 million increase in general and administrative labor and benefits expense, a $0.9 million increase in gas settlement expenses, a $0.4 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $0.3 million increase in other expenses. Depreciation expense increased primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system. Amortization expense increased $0.2 million, due to a $0.5 million increase in amortization expense on Jonah as a result of higher volumes in the 2004 period, partially offset by a $0.3 million decrease on Val Verde as a result of lower volumes in the 2004 period. Operating fuel and power increased $1.2 million primarily due to increased NGL volumes transported on Chaparral, higher power costs and adjustments to fuel and power accruals. Taxes – other than income taxes decreased $0.1 million as a result of adjustments to property tax accruals.

Other income – net decreased $0.1 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to lower interest income earned on cash investments.

Nine Months Ended September 30, 2004 Compared with Nine Months Ended September 30, 2003

Our Midstream Segment reported earnings before interest of $57.1 million for the nine months ended September 30, 2004, compared with earnings before interest of $60.0 million for the nine months ended September 30, 2003. Earnings before interest decreased $2.9 million due to an increase of $12.9 million in costs and expenses (excluding purchases of petroleum products) and a decrease of $0.1 million in other income – net, partially offset by an increase of $10.1 million in operating revenues and margin. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $3.8 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. Natural gas gathering revenues from the Jonah system increased $8.7 million and volumes delivered increased 36.8 Bcf for the nine months ended September 30, 2004, due to the expansion of the Jonah system during 2003. The Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity from 880 MMcf/day to 1,180 MMcf/day. The increase in Jonah’s revenues was also partially due to higher gathering rates realized due to lower system pressures resulting from the increased capacity provided by the Phase III expansion. Natural gas gathering revenues from the Val Verde system decreased $4.9 million and volumes delivered decreased 12.7 Bcf for the nine months ended September 30, 2004, primarily due to the natural decline of CBM production and slower than anticipated completion and connection of infill wells, partially offset by increased volumes from new well connections made to the Val Verde system in late May 2004. Val Verde’s average natural gas gathering rate increased due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas, partially offset by a lower gathering rate on some of the new well connections.

Jonah’s Pioneer gas processing plant was completed during the first quarter of 2004, as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming. For the nine months ended September 30, 2004, the sales and purchases under the fee arrangements at the Pioneer plant resulted in a margin of $0.5 million.

Revenues from the transportation of NGLs increased $1.7 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to increases in volumes transported on the Chaparral and Panola pipelines, partially offset by decreased volumes on the Dean and Wilcox pipelines. Higher average rates per barrel on volumes transported on the Panola and Wilcox pipelines were offset by lower average rates per barrel on volumes transported on the Chaparral and Dean pipelines.

Other operating revenues increased $4.1 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003. Processing fee revenues increased $2.2 million as a result of Jonah’s Pioneer processing plant, which was constructed as part of the Phase III expansion and placed in service in January 2004. Jonah’s other operating revenues also increased $0.8 million due to higher condensate sales. Other operating revenues on Val Verde increased $1.1 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during the nine months ended September 30, 2004. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractually retained from producers. Value retained from producers or sales generated as a result of efficient fuel usage are recognized as other operating revenues.

Costs and expenses (excluding purchases of petroleum products) increased $12.9 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to a $10.7 million increase in operating, general and administrative expense, a $1.9 million increase in operating fuel and power, a $0.2 million increase in taxes – other than income taxes and a $0.1 million increase in depreciation and amortization expense. Operating, general and administrative expense increased due to a $4.3 million increase in gas settlement expenses, a $3.1 million increase in contract services for pipeline maintenance and repair costs, of which

$1.4 million was associated with our integrity management program and $0.8 million was related to accelerated maintenance expenditures at Val Verde to accommodate expected incremental volumes from an adjacent gathering system, a $2.4 million increase in general and administrative labor expense and an increase of $1.3 million in consulting and contract services, of which $0.8 million related to compliance with the Sarbanes-Oxley Act of 2002. These increases are partially offset by a $0.6 million decrease in expense related to the sale of our Enron Corp. receivable, which had been fully reserved in 2001. In December 2001, we expensed approximately $4.3 million of uncollected transportation deficiency revenues due to the bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001. Operating fuel and power increased $1.9 million primarily due to increased NGL volumes transported and higher power costs. Taxes – other than income taxes increased $0.2 million as a result of higher property balances. Amortization expense decreased $3.6 million primarily due to a $3.4 million decrease on Jonah’s intangible assets under the units-of-production method resulting from an extension of the expected amortization period from approximately 16 years to approximately 25 years (see Note 2. Goodwill and Other Intangible Assets), partially offset by a $1.3 million increase as a result of higher volumes in the 2004 period. Amortization expense on the Val Verde system decreased $1.5 million primarily due to lower volumes in the 2004 period, resulting from the natural decline in CBM production. These decreases were partially offset by increased depreciation expense of $3.6 million, primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system and additional well connections on the Val Verde system in 2004.

Other income – net decreased $0.1 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to lower interest income earned on cash investments.

Interest Expense and Capitalized Interest

Three Months Ended September 30, 2004 Compared with Three Months Ended September 30, 2003

Interest expense decreased $3.9 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, primarily due to a higher percentage of variable interest rate debt during the three months ended September 30, 2004, that carried a lower rate of interest as compared to fixed interest rate debt. The higher percentage of variable interest rate debt resulted from the expiration of an interest rate swap in April 2004 (see Note 4. Interest Rate Swaps).

Capitalized interest decreased $0.5 million for the three months ended September 30, 2004, compared with the three months ended September 30, 2003, due to interest capitalized on lower construction work-in-progress balances in 2004.

Nine Months Ended September 30, 2004 Compared with Nine Months Ended September 30, 2003

Interest expense decreased $10.8 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to a higher percentage of variable interest rate debt during the nine months ended September 30, 2004, that carried a lower rate of interest as compared to fixed interest rate debt. The higher percentage of variable interest rate debt resulted from the expiration of an interest rate swap in April 2004 (see Note 4. Interest Rate Swaps).

Capitalized interest increased $0.4 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, due to interest capitalized on higher construction work-in-progress balances in 2004.

Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings is our primary source of liquidity. At September 30, 2004, and December 31, 2003, we had working capital deficits of $17.2 million and

$22.8 million, respectively. At September 30, 2004, we had approximately $115.0 million in available borrowing capacity under our revolving credit facility to cover any working capital needs. Cash flows for the nine months ended September 30, 2004 and 2003 were as follows (in millions):

	Nine Months Ended September 30,
	2004			2003

Cash provided by (used in):
Operating activities	$	173.0		$	176.7
Investing activities	(134.0		)	(124.1		)
Financing activities	(58.9		)	16.8

Operating Activities

Net cash from operating activities for the nine months ended September 30, 2004 and 2003, was comprised of the following (in millions):

	Nine Months Ended September 30,
	2004			2003

Net income	$	104.1		$	98.4
Depreciation and amortization	84.5			73.4
Earnings in equity investments	(22.8		)	(17.8		)
Distributions from equity investments	38.6			10.8
Gains on sales of assets	(1.1		)	(3.9		)
Non-cash portion of interest expense	0.2			4.2
Cash provided by (used in) working capital and other	(30.5		)	11.6
Net cash from operating activities	$	173.0		$	176.7

Cash provided by operating activities decreased $3.7 million for the nine months ended September 30, 2004, compared with the nine months ended September 30, 2003, primarily due to the timing of payments for working capital components, partially offset by an increase of $27.8 million in distributions received from our equity investments in Seaway and MB Storage during the nine months ended September 30, 2004, and higher net income in the 2004 period.

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

Net cash from operating activities for the nine months ended September 30, 2004 and 2003, included interest payments, net of amounts capitalized, of $75.5 million and $76.5 million, respectively. Excluding the effects of hedging activities and interest capitalized, during the year ended December 31, 2004, we expect interest payments

on our fixed rate Senior Notes to be approximately $78.0 million. We expect to pay our interest payments with cash flows from operating activities.

Investing Activities

Cash flows used in investing activities totaled $134.0 million for the nine months ended September 30, 2004, and were comprised of $110.9 million of capital expenditures, $1.5 million of cash contributions for TE Products’ ownership interest in Centennial, $19.4 million of cash contributions for TE Products’ ownership interest in MB Storage and $3.4 million for the acquisition of assets acquired during the nine months ended September 30, 2004, partially offset by $1.2 million in net cash proceeds from the sales of various assets in our Upstream and Downstream Segments. Cash flows used in investing activities totaled $124.1 million for the nine months ended September 30, 2003, and were comprised of $103.9 million of capital expenditures, $20.0 million for TE Products’ acquisition of an additional 16.7% interest in Centennial, $3.0 million of cash contributions for TE Products’ ownership interest in Centennial and $0.2 million of cash contributions for TE Products’ ownership interest in MB Storage, partially offset by $3.0 million in net cash proceeds from the Rancho Pipeline transactions.

Financing Activities

Cash flows used in financing activities totaled $58.9 million for the nine months ended September 30, 2004, and were comprised of $174.4 million of distributions paid to unitholders, partially offset by $115.5 million in borrowings, net of repayments from our revolving credit facility. Cash flows provided by financing activities totaled $16.8 million for the nine months ended September 30, 2003, and were comprised of $382.0 million in proceeds from revolving credit facilities; $198.6 million from the issuance in January 2003 of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of $3.1 million; and $287.5 million from the issuance of 9.2 million Units in April and August 2003. These sources of cash for the nine months ended September 30, 2003, were partially offset by $589.0 million of repayments on our revolving credit facilities, $113.8 million to repurchase and retire all of the 3.9 million outstanding Class B Units and $145.4 million of distributions paid to unitholders.

Centennial has entered into credit facilities totaling $150.0 million and, as of September 30, 2004, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of Centennial’s pipeline system. TE Products and Marathon Ashland Petroleum LLC have each guaranteed one half of Centennial’s debt, up to a maximum of $75.0 million each.

Universal Shelf

We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof. At September 30, 2004, we have $2.0 billion available under this shelf registration.

Credit Facilities and Interest Rate Swap Agreements

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 in 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.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the net proceeds received was used for general partnership purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of September 30, 2004, we were in compliance with the covenants of these Senior Notes.

We have entered into interest rate swap agreements to hedge our exposure to cash flows and fair value changes. These agreements are more fully described in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The following table summarizes our credit facilities as of September 30, 2004 (in millions):

	As of September 30, 2004
			Available
	Outstanding		Borrowing		Maturity
Description:	Principal		Capacity		Date
Revolving Credit Facility (1)	$	325.5	$	224.5	June 2006
6.45% Senior Notes (2)	180.0		—		January 2008
7.625% Senior Notes (2)	500.0		—		February 2012
6.125% Senior Notes (2)	200.0		—		February 2013
7.51% Senior Notes (2)	210.0		—		January 2028
Total	$	1,415.5	$	224.5

(1) Our Revolving Credit Facility contains restrictive covenants that require us to maintain certain financial ratios. Under the most restrictive financial covenant, approximately $115.0 million was available to be borrowed at September 30, 2004. Certain of these restrictive covenants are adjusted in the event of an acquisition by us, which would permit additional borrowings under the facility. On October 21, 2004, the Revolving Credit Facility was amended. Total borrowing capacity was increased to $600.0 million, and the maturity date was extended to October 2009.

(2) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At September 30, 2004, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $3.9 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At September 30, 2004, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $37.6 million. At September 30, 2004, our 6.45% Senior Notes, our 7.625% Senior Notes

and our 6.125% Senior Notes include $2.9 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $174.4 million ($1.975 per Unit) and $145.4 million ($1.85 per Unit) during the nine months ended September 30, 2004 and 2003, respectively. Additionally, we declared a cash distribution of $0.6625 per Unit for the quarter ended September 30, 2004. We will pay the quarterly distribution of $58.7 million on November 5, 2004, to unitholders of record on October 29, 2004.

General Partner Interest

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2004 will be approximately $156.0 million (which includes $4.0 million of capitalized interest). We expect to spend approximately $116.3 million for revenue generating projects and facility improvements. Capital spending on revenue generating projects and facility improvements will include approximately $42.9 million for the expansion of our Downstream Segment facilities including pipelines extending from Seymour to Indianapolis, Indiana, further expansions of our Northeast pipeline system and construction of a new truck loading terminal in Bossier City, Louisiana. We expect to spend $25.9 million to expand our Upstream Segment pipelines and facilities in South Texas and Oklahoma and approximately $47.5 million to expand our Midstream Segment assets. We expect to spend approximately $35.7 million to sustain existing operations, including life-cycle replacements for equipment at various facilities and pipeline and tank replacements among all of our business segments. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Revolving Credit Facility due in June 2006 ($325.5 million outstanding at September 30, 2004), (ii) the TE Products $180.0 million 6.45% Senior Notes due January 15, 2008, (iii) our $500.0 million 7.625% Senior Notes due February 15, 2012, (iv) our $200.0 million 6.125% Senior Notes due February 1, 2013, and (v) the TE Products $210.0 million 7.51% Senior Notes due January 15, 2028.

TE Products is contingently liable as guarantor for the lesser of one half or $75.0 million principal amount (plus interest) of Centennial’s borrowings. In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the year ended December 31, 2003, and for the nine months ended September 30, 2004, TE Products exceeded the minimum throughput requirements on the lease agreement.

During the nine months ended September 30, 2004, TE Products contributed $1.5 million to Centennial to cover operating needs and capital expenditures. During the nine months ended September 30, 2004, TE Products contributed $19.4 million to MB Storage, of which $16.5 million was used for its acquisition of storage assets in April 2004. TE Products may be required to contribute cash to Centennial during the remainder of 2004, to cover capital expenditures, acquisitions or other operating needs and to MB Storage to cover significant capital expenditures or additional acquisitions.

Off-Balance Sheet Arrangements

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

Contractual Obligations

The following table summarizes our debt repayment obligations and material contractual commitments as of September 30, 2004 (in millions):

	Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years

Revolving Credit Facility (1)	$	325.5	$	—	$	325.5	$	—	$	—
6.45% Senior Notes due 2008 (2) (3)	180.0		—		—		180.0		—
7.625% Senior Notes due 2012 (3)	500.0		—		—		—		500.0
6.125% Senior Notes due 2013 (3)	200.0		—		—		—		200.0
7.51% Senior Notes due 2028 (2) (3)	210.0		—		—		—		210.0
Debt subtotal	1,415.5		—		325.5		180.0		910.0

Operating leases	84.2		18.0		28.3		14.4		23.5

Total	$	1,499.7	$	18.0	$	353.8	$	194.4	$	933.5

(1) On October 21, 2004, the Revolving Credit Facility was amended. Total borrowing capacity was increased to $600.0 million, subject to compliance with prescribed financial covenants, and the maturity date was extended to October 2009.

(2) Obligations of TE Products.

(3) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At September 30, 2004, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $3.9 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At September 30, 2004, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $37.6 million. At September 30, 2004, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.9 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustments and the unamortized debt discounts are excluded from this table.

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

Sources of Future Capital

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

As of September 30, 2004, we had $224.5 million in available borrowing capacity under the Revolving Credit Facility, subject to compliance with prescribed financial covenants. We expect that cash flows from operating activities will be adequate to fund cash distributions and

capital additions necessary to sustain existing operations. However, future expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity offerings.

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

Other Considerations

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

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 1. Organization and Basis of Presentation - New Accounting Pronouncements in the accompanying consolidated financial statements.

Forward-Looking Statements

The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline companies, changes in laws or regulations and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. For

additional discussion of such risks and uncertainties, see our Annual Report on Form 10-K for the year ended December 31, 2003, and other filings we have made with the Securities and Exchange Commission.

Our Corporate Governance Guidelines are available on our website at www.teppco.com.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

At September 30, 2004, we had $325.5 million outstanding under our variable interest rate revolving credit agreement. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of our variable interest rate debt outstanding at September 30, 2004, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be $3.3 million.

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

At September 30, 2004, TE Products had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008 and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively, the “TE Products Senior Notes”). At September 30, 2004, the estimated fair value of the TE Products Senior Notes was approximately $412.0 million. At September 30, 2004, we had outstanding $500.0 million principal amount of 7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013. At September 30, 2004, the estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0 million 6.125% Senior Notes was approximately $577.0 million and $210.7 million, respectively.

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, 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. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at September 30, 2004, and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

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.

Item 4. Controls and Procedures

The principal executive officer and principal financial officer of our General Partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2004, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

During the third quarter of 2004, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, those internal controls subsequent to the date of the evaluation. As a result, no corrective actions were required or undertaken.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows. See discussion of legal proceedings in Note 12. Commitments and Contingencies in the accompanying consolidated financial statements.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits:

Exhibit Number		Description

3.1		Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2		Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1		Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2		Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3		Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
4.4		Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.6		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P.

		(Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.7		Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.1		Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders dated as of October 21, 2004 ($600,000,000 Revolving Facility) (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of October 21, 2004 and incorporated herein by reference).
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

** Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TEPPCO Partners, L.P.
		(Registrant)
		(A Delaware Limited Partnership)

	By:	Texas Eastern Products Pipeline
	Company, LLC, as General Partner

	By:	/s/ BARRY R. PEARL
		Barry R. Pearl,
		President and Chief Executive Officer

	By:	/s/ CHARLES H. LEONARD
		Charles H. Leonard,
		Senior Vice President and Chief
		Financial Officer
Date: November 1, 2004

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

For the quarterly period ended September 30, 2004

OR

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

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2004 (unaudited) and December 31, 2003

Consolidated Statements of Income for the three months and nine months ended September 30, 2004 and 2003 (unaudited)

Consolidated Statements of Cash Flows for the nine months ended September 30, 2004 and 2003 (unaudited)

Consolidated Statement of Partners’ Capital for the nine months ended September 30, 2004 (unaudited)

Notes to the Consolidated Financial Statements (unaudited)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

Signatures

Balance at December 31, 2002	$	(20,055	)
Reclassification due to discontinued portion of cash flow hedge	989
Transferred to earnings	14,417
Change in fair value of cash flow hedge	1,747
Balance at December 31, 2003	$	(2,902	)
Transferred to earnings	2,939
Change in fair value of cash flow hedge	(37		)
Balance at September 30, 2004	$	—

Short Term Credit Facilities

Senior Notes

Other Long Term Debt and Credit Facilities

Quarterly Distributions of Available Cash

Retirement Plans

Other Postretirement Benefits

Estimated Future Benefit Contributions

Management Overview of the Three Months and Nine Months Ended September 30, 2004

revenue. We anticipate that our pipeline integrity expenses for our Downstream Segment for 2004 will be approximately $3.0 million higher than our 2003 costs.

We increased our quarterly distribution from $0.65 per Unit to $0.6625 per Unit for the first quarter of 2004. Our third quarter distribution will remain at $0.6625 per Unit and will be paid on November 5, 2004.

Our Business

Distributions and Issuance of Additional Limited Partner Units

Sources of Future Capital