TEPPCO PARTNERS LP - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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

Commission File No. 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)

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

2929 Allen Parkway

P.O. Box 2521

Houston, Texas 77252-2521

(Address of principal executive offices, including zip code)

(713) 759-3636

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Limited Partner Units outstanding as of August 2, 2004: 62,998,554.

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

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

Consolidated Statements of Income for the three months and six months ended June 30, 2004 and 2003 (unaudited)	2

Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2003 (unaudited)	3

Consolidated Statement of Partners’ Capital for the six months ended June 30, 2004 (unaudited)	4

Notes to the Consolidated Financial Statements (unaudited)	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Forward-Looking Statements	51

Item 3. Quantitative and Qualitative Disclosures About Market Risk	52

Item 4. Controls and Procedures	53

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	53

Item 6. Exhibits and Reports on Form 8-K	54

Signatures	59

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	13,854		$	29,469
Accounts receivable, trade (net of allowance for doubtful accounts of $443 and $4,700)	464,982			371,938
Accounts receivable, related parties	10,367			3,143
Inventories	16,273			16,060
Other	28,964			32,208
Total current assets	534,440			452,818
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $380,801 and $345,357)	1,636,748			1,619,163
Equity investments	383,756			365,286
Intangible assets	422,974			438,565
Goodwill	16,944			16,944
Other assets	50,416			48,216
Total assets	$	3,045,278		$	2,940,992

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	471,337		$	359,660
Accounts payable, related parties	12,324			16,269
Accrued interest	32,014			35,111
Other accrued taxes	11,468			9,941
Other	41,017			54,610
Total current liabilities	568,160			475,591
Senior Notes	1,122,723			1,129,650
Other long-term debt	260,000			210,000
Other liabilities and deferred credits	19,820			16,430
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive loss	—			(2,902		)
General partner’s interest	(17,680		)	(7,181		)
Limited partners’ interests	1,092,255			1,119,404
Total partners’ capital	1,074,575			1,109,321
Total liabilities and partners’ capital	$	3,045,278		$	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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Operating revenues:
Sales of petroleum products	$	1,232,807		$	927,232		$	2,414,920		$	1,903,192
Transportation – Refined products	38,937			37,802			69,908			64,696
Transportation – LPGs	13,721			13,357			42,501			44,178
Transportation – Crude oil	9,213			7,059			18,876			13,964
Transportation – NGLs	10,578			9,440			20,592			19,339
Gathering – Natural gas	34,427			32,264			68,929			66,546
Other	14,881			13,646			36,899			28,124
Total operating revenues	1,354,564			1,040,800			2,672,625			2,140,039

Costs and expenses:
Purchases of petroleum products	1,217,312			912,344			2,384,653			1,875,188
Operating, general and administrative	53,225			46,390			105,638			89,025
Operating fuel and power	10,384			9,970			21,676			20,147
Depreciation and amortization	26,411			23,487			54,231			50,800
Taxes – other than income taxes	4,831			4,571			10,125			9,499
Gain on sale of assets	—			(3,948		)	—			(3,948		)
Total costs and expenses	1,312,163			992,814			2,576,323			2,040,711

Operating income	42,401			47,986			96,302			99,328

Interest expense – net	(16,464		)	(22,550		)	(36,059		)	(43,861		)
Equity earnings	11,582			8,250			17,233			11,960
Other income – net	240			258			716			442

Net income	$	37,759		$	33,944		$	78,192		$	67,869

Net Income Allocation:
Limited Partner Unitholders	$	26,867		$	24,654		$	55,636		$	47,741
Class B Unitholder	—			126			—			1,806
General Partner	10,892			9,164			22,556			18,322
Total net income allocated	$	37,759		$	33,944		$	78,192		$	67,869

Basic and diluted net income per Limited Partner and Class B Unit	$	0.43		$	0.43		$	0.88		$	0.86

Weighted average Limited Partner and Class B Units outstanding	62,999			57,749			62,999			57,739

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2004			2003
Cash flows from operating activities:
Net income	$	78,192		$	67,869
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	54,231			50,800
Earnings in equity investments, net of distributions	3,617			(1,220		)
Gain on sale of assets	—			(3,948		)
Non-cash portion of interest expense	(219		)	3,075
Increase in accounts receivable	(93,044		)	(68,092		)
Increase in inventories	(213		)	(3,059		)
Decrease in other current assets	3,244			2,948
Increase in accounts payable and accrued expenses	93,583			80,174
Other	(7,219		)	3,994
Net cash provided by operating activities	132,172			132,541

Cash flows from investing activities:
Proceeds from the sale of assets	—			8,531
Acquisition of assets	(2,962		)	(5,459		)
Acquisition of additional interest in Centennial Pipeline LLC	—			(20,000		)
Investment in Centennial Pipeline LLC	(1,500		)	(1,000		)
Investment in Mont Belvieu Storage Partners, L.P.	(17,211		)	—
Capital expenditures, net	(60,373		)	(45,919		)
Net cash used in investing activities	(82,046		)	(63,847		)

Cash flows from financing activities:
Proceeds from revolving credit facility	149,800			335,000
Repayments on revolving credit facility	(99,800		)	(504,000		)
Issuance of Senior Notes	—			198,570
Debt issuance costs	—			(3,079		)
Issuance of Limited Partner Units, net	—			114,457
Repurchase and retirement of Class B Units	—			(113,814		)
General Partner’s contribution	—			2
Distributions paid	(115,741		)	(95,974		)
Net cash used in financing activities	(65,741		)	(68,838		)

Net decrease in cash and cash equivalents	(15,615		)	(144		)

Cash and cash equivalents at beginning of period	29,469			30,968
Cash and cash equivalents at end of period	$	13,854		$	30,824

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)	$	41,208		$	39,567

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	—	22,556			55,636			—			78,192
Cash distributions	—	(33,055		)	(82,686		)	—			(115,741		)

Partners’ capital at June 30, 2004	62,998,554	$	(17,680	)	$	1,092,255		$	—		$	1,074,575

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 June 30, 2004, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and six months ended June 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 for the three months and six months ended June 30, 2004 and 57.7 million Units for the three months and six months ended June 30, 2003). 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 8. Partners’ Capital and Distributions). The General Partner was allocated $22.6 million (representing 28.85%) and $18.3 million (representing 26.99%) of our net income for the six months ended June 30, 2004 and 2003, respectively, and $10.9 million (representing 28.85%) and $9.2 million (representing 26.99%) of our net income for the three months

ended June 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 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 six months ended June 30, 2003, the denominator was increased by 25,115 Units and 23,414 Units, respectively. For the three months and six months ended June 30, 2004, diluted net income per Unit equaled basic net income per Unit as the denominator was not changed since 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 6. 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 a law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact 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 will adopt the provisions of these FSPs in the quarter ended September 30, 2004; however, we do not believe that this regulation will 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.

At June 30, 2004, we had $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment in Seaway Crude Pipeline Company (equity method goodwill). The excess investment is included in our equity investments account at June 30, 2004. The following table presents the carrying amount of goodwill and equity method goodwill at June 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 June 30, 2004, and December 31, 2003 (in thousands):

	June 30, 2004					December 31, 2003
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortized intangible assets:
Gathering and transportation agreements	$	464,337	$	(77,198	)	$	464,337	$	(62,436	)
Fractionation agreement	38,000		(11,875		)	38,000		(10,925		)
Other	12,162		(2,452		)	11,270		(1,681		)
Total	$	514,499	$	(91,525	)	$	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 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 $8.3 million for each of the three month periods ended June 30, 2004 and 2003, and $16.5 million and $19.7 million for the six months ended June 30, 2004 and 2003, respectively.

At June 30, 2004, we had $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company (see Note 6. Equity Investments). The excess investment is included in our equity investments account at June 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	$	35,760
2005	36,692
2006	38,171
2007	35,286
2008	32,962

NOTE 3. 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 7. 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 six months ended June 30, 2004 and 2003, we recognized increases in interest expense of $2.9 million and $7.0 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 8. Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility. We reduced the outstanding balance of the revolving credit facility at December 31, 2003, to $210.0 million. During the year ended December 31, 2003, we recognized a loss of $1.0 million for the portion of the discontinued hedge. The total fair value of the interest rate swap was a loss of approximately $3.9 million at December 31, 2003. The remaining $2.9 million of other comprehensive income was transferred to earnings during the period from January 1, 2004, through the maturity of the interest rate swap on April 6, 2004.

On October 4, 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating 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 six months ended June 30, 2004 and 2003, we recognized reductions in interest expense of $5.1 million and $4.9 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 June 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 loss of approximately $2.9 million at June 30, 2004, and a gain of approximately $2.3 million at December 31, 2003.

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 June 30, 2004, the unamortized balance of the deferred gains was $38.6 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 4. 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 which 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, which is included in the gain on sale of assets in our consolidated statements of income.

Genesis Pipeline

On November 1, 2003, we completed the purchase of crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 8. 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 5. 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 June 30, 2004, and December 31, 2003. The major components of inventories were as follows (in thousands):

	June 30, 2004		December 31, 2003
Crude oil	$	2,434	$	1,303
Refined products	995		6,632
LPGs	4,203		517
Lubrication oils and specialty chemicals	3,372		3,080
Materials and supplies	5,113		4,528
Other	156		—
Total	$	16,273	$	16,060

NOTE 6. 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 six months ended June 30, 2004 and 2003, we received distributions from Seaway of $15.9 million and $10.7 million, respectively.

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 six months ended June 30, 2004, TE Products invested $1.5 million in Centennial, which is included in the equity investment balance at June 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 less mandatory capital expenditures, as defined in the operating agreement. Any amount of MB Storage’s annual income before depreciation expense less mandatory capital expenditures 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 six months ended June 30, 2004, TE Products’ sharing ratio in the earnings of MB Storage was approximately 70.2%. During the six months ended June 30, 2004, TE Products contributed $17.2 million to MB Storage, of which $16.5 million was used to acquire storage assets in April 2004. During the six months ended June 30, 2004, TE Products received distributions of $5.0 million from MB Storage.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the six months ended June 30, 2004 and 2003, is presented below (in thousands):

	Six Months Ended June 30,
	2004		2003
Revenues	$	79,890	$	59,759
Net income	33,524		18,301

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

	June 30, 2004		December 31, 2003
Current assets	$	71,149	$	56,243
Noncurrent assets	636,924		609,215
Current liabilities	48,348		43,177
Long-term debt	140,000		140,000
Noncurrent liabilities	13,309		13,182
Partners’ capital	506,416		469,099

Our investments in Seaway and Centennial include excess net investment amounts of $25.5 million and $33.4 million, respectively. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment.

NOTE 7. DEBT

Short Term Credit Facilities

On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained certain restrictive financial covenant ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. The Short-term Revolver expired on March 27, 2003.

Senior Notes

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

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of June 30, 2004, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of June 30, 2004, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on our $500.0 million revolving credit facility to $250.0 million. The balance of the net proceeds received was used for general partnership purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of 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 June 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 June 30, 2004, and December 31, 2003 (in millions):

	Face Value		June 30, 2004		December 31, 2003
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	185.5	$	192.7
7.625% Senior Notes, due February 2012	500.0		542.7		559.0
6.125% Senior Notes, due February 2013	200.0		197.4		199.8
7.51% TE Products Senior Notes, due January 2028	210.0		211.7		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 3. 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 June 30, 2004, $260.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 2.2%. At June 30, 2004, we were in compliance with the covenants of this credit agreement.

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 3. Interest Rate Swaps).

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

	June 30, 2004		December 31, 2003

Credit Facilities:
Revolving Credit Facility, due June 2006	$	260,000	$	210,000
6.45% TE Products Senior Notes, due January 2008	179,891		179,876
7.625% Senior Notes, due February 2012	498,327		498,216
6.125% Senior Notes, due February 2013	198,773		198,702
7.51% TE Products Senior Notes, due January 2028	210,000		210,000
Total borrowings	1,346,991		1,296,794
Adjustment to carrying value associated with hedges of fair value	35,732		42,856
Total Credit Facilities	$	1,382,723	$	1,339,650

NOTE 8. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offerings

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 4. 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 six months ended June 30, 2004 and 2003 (in thousands, except per Unit amounts):

	Six Months Ended June 30,
	2004		2003
Limited Partner Units	$	82,686	$	68,382
General Partner Ownership Interest	1,687		1,444
General Partner Incentive	31,368		23,801
Total Partners’ Capital Cash Distributions	115,741		93,627
Class B Units	—		2,347
Total Cash Distributions Paid	$	115,741	$	95,974
Total Cash Distributions Paid Per Unit	$	1.3125	$	1.225

On August 6, 2004, we will pay a cash distribution of $0.6625 per Unit for the quarter ended June 30, 2004. The second quarter 2004 cash distribution will total $58.7 million.

General Partner’s Interest

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 six months ended June 30, 2004, the General Partner was allocated $22.6 million (representing 28.85%) of our net income and received $33.1 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 June 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 six months ended June 30, 2004, resulted in a deficit in the General Partner’s equity account at June 30, 2004, and December 31, 2003. 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. After all allocations are made between the partners, if a deficit balance still remains in the General Partner’s equity account, the General Partner would not be required to make whole any such deficit.

NOTE 9. 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 six months ended June 30, 2004 and 2003, were as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Service cost benefit earned during the period	$	936		$	795		$	1,872		$	1,590
Interest cost on projected benefit obligation	176			126			352			252
Expected return on plan assets	(224		)	(151		)	(448		)	(302		)
Amortization of prior service cost	2			2			4			4
Recognized net actuarial loss	4			6			8			12
Net pension benefits costs	$	894		$	778		$	1,788		$	1,556

Estimated Future Benefit Contributions

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

NOTE 10. 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 (“RGP”) from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6. 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 six months ended June 30, 2004 and 2003 (in thousands):

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

Sales of petroleum products	$		—		$	1,231,019	$	1,788	$	1,232,807	$	—		$	1,232,807
Operating revenues	62,364				11,841		48,216		122,421		(664		)	121,757
Purchases of petroleum products	—				1,216,307		1,669		1,217,976		(664		)	1,217,312
Operating expenses, including power	38,534				15,001		14,905		68,440		—			68,440
Depreciation and amortization expense	9,211				3,045		14,155		26,411		—			26,411
Operating income	14,619				8,507		19,275		42,401		—			42,401
Equity earnings (losses)	(509			)	12,091		—		11,582		—			11,582
Other income, net	173				51		16		240		—			240
Earnings before interest	$	14,283			$	20,649	$	19,291	$	54,223	$	—		$	54,223

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

Sales of petroleum products	$		—	$	927,232		$	—	$	927,232		$	—		$	927,232
Operating revenues	60,058			9,466			44,462		113,986			(418		)	113,568
Purchases of petroleum products	—			912,762			—		912,762			(418		)	912,344
Operating expenses, including power	36,268			13,755			10,908		60,931			—			60,931
Depreciation and amortization expense	7,067			2,466			13,954		23,487			—			23,487
Gain on sale of assets	—			(3,948		)	—		(3,948		)	—			(3,948		)
Operating income	16,723			11,663			19,600		47,986			—			47,986
Equity earnings	64			8,186			—		8,250			—			8,250
Other income, net	55			213			27		295			(37		)	258
Earnings before interest	$	16,842		$	20,062		$	19,627	$	56,531		$	(37	)	$	56,494

	Six Months Ended June 30, 2004
	Downstream Segment				Upstream Segment		Midstream Segment		Segments Total		Partnership and Other			Consolidated

Sales of petroleum products	$		—		$	2,411,786	$	3,134	$	2,414,920	$	—		$	2,414,920
Operating revenues	137,173				25,564		97,033		259,770		(2,065		)	257,705
Purchases of petroleum products	—				2,383,732		2,986		2,386,718		(2,065		)	2,384,653
Operating expenses, including power	78,584				28,969		29,886		137,439		—			137,439
Depreciation and amortization expense	18,288				6,113		29,830		54,231		—			54,231
Operating income	40,301				18,536		37,465		96,302		—			96,302
Equity earnings (losses)	(1,747			)	18,980		—		17,233		—			17,233
Other income, net	445				197		74		716		—			716
Earnings before interest	$	38,999			$	37,713	$	37,539	$	114,251	$	—		$	114,251

	Six Months Ended June 30, 2003
	Downstream Segment				Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$		—		$	1,903,192		$	—	$	1,903,192		$	—		$	1,903,192
Operating revenues	128,023				18,886			91,366		238,275			(1,428		)	236,847
Purchases of petroleum products	—				1,876,616			—		1,876,616			(1,428		)	1,875,188
Operating expenses, including power	67,817				28,592			22,262		118,671			—			118,671
Depreciation and amortization expense	14,214				5,531			31,055		50,800			—			50,800
Gain on sale of assets	—				(3,948		)	—		(3,948		)	—			(3,948		)
Operating income	45,992				15,287			38,049		99,328			—			99,328
Equity earnings (losses)	(1,195			)	13,155			—		11,960			—			11,960
Other income, net	49				402			64		515			(73		)	442
Earnings before interest	$	44,846			$	28,844		$	38,113	$	111,803		$	(73	)	$	111,730

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

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

June 30, 2004:
Total assets	$	930,663	$	957,456	$	1,164,418	$	3,052,537	$	(7,259	)	$	3,045,278
Capital expenditures	24,277		19,500		16,300		60,077		296			60,373

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 six months ended June 30, 2004 and 2003 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Earnings before interest	$	54,223		$	56,494		$	114,251		$	111,730
Interest expense – net	(16,464		)	(22,550		)	(36,059		)	(43,861		)
Net income	$	37,759		$	33,944		$	78,192		$	67,869

NOTE 11. 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 June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. 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.

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 June 30, 2004, we have an accrued liability of $0.3 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. We are complying with the Agreed Order and are in the process of negotiating a final settlement with the State of Illinois. We do not expect that compliance with the Agreed Order or the settlement will have a future material adverse effect on our financial position, results of operations or cash flows.

At June 30, 2004, we have an accrued liability of $7.9 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 June 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 entered into credit facilities totaling $150.0 million and, as of June 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 12. 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 June 30, 2004, and for the six months ended June 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 June 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 six months ended June 30, 2004 and 2003 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Net income	$	37,759	$	33,944	$	78,192	$	67,869
Net income on cash flow hedges	220		3,235		2,902		8,704
Total comprehensive income	$	37,979	$	37,179	$	81,094	$	76,573

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

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 June 30, 2004	$	—

NOTE 13. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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

	June 30, 2004
	TEPPCO Partners, L .P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	42,548	$	84,583	$	452,074	$	(44,765	)	$	534,440
Property, plant and equipment – net	—		1,154,304		482,444		—			1,636,748
Equity investments	1,074,604		431,045		214,129		(1,336,022		)	383,756
Intercompany notes receivable	992,268		—		—		(992,268		)	—
Intangible assets	—		386,663		36,311		—			422,974
Other assets	5,608		23,463		38,289		—			67,360
Total assets	$	2,115,028	$	2,080,058	$	1,223,247	$	(2,373,055	)	$	3,045,278
Liabilities and partners’ capital
Current liabilities	$	43,098	$	103,406	$	466,422	$	(44,766	)	$	568,160
Long-term debt	995,728		386,995		—		—			1,382,723
Intercompany notes payable	—		614,930		377,339		(992,269		)	—
Other long term liabilities	1,627		17,577		616		—			19,820
Total partners’ capital	1,074,575		957,150		378,870		(1,336,020		)	1,074,575
Total liabilities and partners’ capital	$	2,115,028	$	2,080,058	$	1,223,247	$	(2,373,055	)	$	3,045,278

	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 June 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	98,813		$	1,256,415		$	(664	)	$	1,354,564
Costs and expenses	—		71,414			1,241,413			(664		)	1,312,163
Operating income	—		27,399			15,002			—			42,401
Interest expense – net	—		(11,219		)	(5,245		)	—			(16,464		)
Equity earnings	37,759		21,393			12,091			(59,661		)	11,582
Other income – net	—		186			54			—			240
Net income	$	37,759	$	37,759		$	21,902		$	(59,661	)	$	37,759

	Three Months Ended June 30, 2003
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	91,812		$	949,406		$	(418	)	$	1,040,800
Costs and expenses	—		62,363			934,817			(418		)	996,762
Gain on sale of assets	—		—			(3,948		)	—			(3,948		)
Operating income	—		29,449			18,537			—			47,986
Interest expense –net	—		(14,472		)	(8,115		)	37			(22,550		)
Equity earnings	33,944		18,918			8,186			(52,798		)	8,250
Other income – net	—		49			246			(37		)	258
Net income	$	33,944	$	33,944		$	18,854		$	(52,798	)	$	33,944

	Six Months Ended June 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	210,701		$	2,463,989		$	(2,065	)	$	2,672,625
Costs and expenses	—		144,830			2,433,558			(2,065		)	2,576,323
Operating income	—		65,871			30,431			—			96,302
Interest expense – net	—		(24,011		)	(12,048		)	—			(36,059		)
Equity earnings	78,192		35,840			18,980			(115,779		)	17,233
Other income – net	—		492			224			—			716
Net income	$	78,192	$	78,192		$	37,587		$	(115,779	)	$	78,192

	Six Months Ended June 30, 2003
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	193,891		$	1,947,576		$	(1,428	)	$	2,140,039
Costs and expenses	—		123,240			1,922,847			(1,428		)	2,044,659
Gain on sale of assets	—		—			(3,948		)	—			(3,948		)
Operating income	—		70,651			28,677			—			99,328
Interest expense – net	—		(27,991		)	(15,943		)	73			(43,861		)
Equity earnings	67,869		25,171			13,155			(94,235		)	11,960
Other income – net	—		38			477			(73		)	442
Net income	$	67,869	$	67,869		$	26,366		$	(94,235	)	$	67,869

	Six Months Ended June 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	$	78,192		$	78,192		$	37,587		$	(115,779	)	$	78,192
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			43,066			11,165			—			54,231
Earnings in equity investments, net of distributions	(21,109		)	(7,543		)	(3,080		)	35,349			3,617
Changes in assets and liabilities and other	(67,886		)	(1,978		)	2,248			63,748			(3,868		)
Net cash provided by (used in) operating activities	(10,803		)	111,737			47,920			(16,682		)	132,172

Cash flows from investing activities	98			(3,707		)	(21,035		)	(57,402		)	(82,046		)
Cash flows from financing activities	(7,083		)	(116,019		)	(31,612		)	88,973			(65,741		)
Net decrease in cash and cash equivalents	(17,788		)	(7,989		)	(4,727		)	14,889			(15,615		)
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	$	1,956		$	11,254		$	943		$	(299	)	$	13,854

	Six Months Ended June 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	$	67,869		$	67,869		$	26,366		$	(94,235	)	$	67,869
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			40,590			10,210			—			50,800
Equity earnings, net of distributions	28,105			(6,393		)	(2,415		)	(20,517		)	(1,220		)
Changes in assets and liabilities and other	(24,615		)	17,259			(1,154		)	23,602			15,092
Net cash provided by operating activities	71,359			119,325			33,007			(91,150		)	132,541

Cash flows from investing activities	(2,519		)	(59,883		)	(3,964		)	2,519			(63,847		)
Cash flows from financing activities	(68,840		)	(53,931		)	(34,698		)	88,631			(68,838		)
Net decrease in cash and cash equivalents	—			5,511			(5,655		)	—			(144		)
Cash and cash equivalents at beginning of period	—			8,247			22,721			—			30,968
Cash and cash equivalents at end of period	$	—		$	13,758		$	17,066		$	—		$	30,824

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, property, plant and equipment and goodwill and 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 Six Months Ended June 30, 2004

We reported net income of $78.2 million, or $0.88 per Limited Partner and Class B Unit (collectively, “Unit” or “Units”), for the six months ended June 30, 2004, compared with net income of $67.9 million, or $0.86 per Unit, for the six months ended June 30, 2003. Net income for the three months ended June 30, 2004, was $37.8 million, or $0.43 per Unit, compared with net income of $33.9 million, or $0.43 per Unit, for the three months ended June 30, 2003. The weighted average number of Units outstanding for the three months and six months ended June 30, 2004, was 63.0 million for both periods, compared with 57.7 million for the corresponding 2003 periods. Our Upstream Segment had a strong six months, with increased transportation volumes on Seaway Crude Pipeline Company (“Seaway”) and on our South Texas system, which benefited from our recent acquisition of the Genesis assets in November 2003. Our Downstream Segment results for the three months and six months ended June 30, 2004, were impacted by higher pipeline integrity costs of $2.6 million and $8.0 million, respectively, which essentially offset increased revenues from both our refined products and propane businesses. We anticipate that our pipeline integrity costs for our Downstream Segment for 2004 will be approximately $3.0 million to $5.0 million higher than our 2003 costs as we continue to perform pipeline maintenance under our integrity management program. 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 as a result of the natural decline of coal bed methane (“CBM”) production and slower than anticipated infill drilling. We increased our quarterly distribution from $0.65 per Unit to $0.6625 per Unit for the first quarter of 2004. Our second quarter distribution will remain at $0.6625 per Unit and will be paid on August 6, 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 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.

• 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 are continuing to pursue a plan to make system changes to allow for bi-directional flow and deliveries into the Shreveport market area. We have completed feasibility studies and are in discussions with potential customers regarding the transportation of volumes through the pipeline system in this area. Engineering design work is currently under way to reverse the flow of the pipeline segment from Shreveport to El Dorado, Arkansas. The project is scheduled to be completed by the end of 2004.

We are planning to build 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.

We have begun 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. 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. 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, will increase delivery rates to the Philadelphia area. Improvements will also be made at our Dubois, Pennsylvania, and Eagle, Pennsylvania, terminals. The project is scheduled to be completed in the fourth quarter of 2004.

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.

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, Texas, to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial Pipeline LLC (“Centennial”) and Mont Belvieu Storage Partners, L.P. (“MB Storage”) (see Note 6. Equity Investments).

Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado; transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (“Chaparral”) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah; and the gathering of CBM in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements.

We earn revenues and income and generate cash by charging our customers a fee for the transportation, storage, gathering, terminaling, fractionation and other services we provide. In our Upstream Segment, we seek to maintain a balanced marketing position until we make physical delivery of the crude oil, thereby minimizing or eliminating our exposure to price fluctuations occurring after the initial purchase. We are subject to economic and other factors that affect our industry. The demand for crude oil and petroleum products is dependent on the price of crude oil and the products produced from the refining of crude oil; the price of natural gas and locations in which natural gas is drilled; and the demand for petrochemicals, which is dependent on prices for products produced from petrochemicals. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems.

Acquisitions

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

Acquisition	Date of Acquisition	Purchase Price
Jonah (1)	September 30, 2001	$367.1 million
Chaparral (2)	March 1, 2002	$132.4 million
Val Verde (3)	June 30, 2002	$444.2 million
Genesis (4)	November 1, 2003	$21.0 million

(1) The acquisition of Jonah in 2001 served as our entry into the natural gas gathering industry.

(2) Chaparral extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to MB Storage’s existing storage facilities in Mont Belvieu.

(3) The Val Verde system gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States.

(4) 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 4. Acquisitions and Dispositions).

Since the acquisition of Jonah, we have expanded both the pipeline capacity and processing capacity of the Jonah system. In 2002, we completed the Phase I and Phase II expansions of Jonah, which nearly doubled the capacity of the Jonah system. The Phase I expansion was completed in May 2002 at a cost of approximately $25.0 million and increased system capacity by 62%, from approximately 450 million cubic feet per day (“MMcf/day”) to approximately 730 MMcf/day. In October 2002, the Phase II expansion was completed at a cost of approximately $45.0 million, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. In 2003, the Phase III expansion was begun, which included an 80-mile expansion on the system and the building of a new 250 MMcf/day gas processing plant near Opal, Wyoming. Phase III was substantially completed during the fourth quarter of 2003, with system capacity increasing to 1,180 MMcf/day at a cost of approximately $59.0 million.

In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners which previously held undivided interests in the pipeline. We acquired 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, which is included in the gain on sale of assets in our consolidated statements of income.

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.

Results of Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Operating revenues:
Downstream Segment	$	62,364		$	60,058		$	137,173		$	128,023
Upstream Segment	1,242,860			936,698			2,437,350			1,922,078
Midstream Segment	50,004			44,462			100,167			91,366
Intersegment eliminations	(664		)	(418		)	(2,065		)	(1,428		)
Total operating revenues	1,354,564			1,040,800			2,672,625			2,140,039

Operating income:
Downstream Segment	14,619			16,723			40,301			45,992
Upstream Segment	8,507			11,663			18,536			15,287
Midstream Segment	19,275			19,600			37,465			38,049
Total operating income	42,401			47,986			96,302			99,328

Earnings before interest:
Downstream Segment	14,283			16,842			38,999			44,846
Upstream Segment	20,649			20,062			37,713			28,844
Midstream Segment	19,291			19,627			37,539			38,113
Intersegment eliminations	—			(37		)	—			(73		)
Total earnings before interest	54,223			56,494			114,251			111,730

Interest expense	(18,048		)	(23,513		)	(38,507		)	(45,420		)
Interest capitalized	1,584			963			2,448			1,559
Net income	$	37,759		$	33,944		$	78,192		$	67,869

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 six months ended June 30, 2004 and 2003 (in thousands, except tariff information):

	Three Months Ended June 30,				Percentage Increase (Decrease)	Six Months Ended June 30,				Percentage Increase (Decrease)
	Three Months Ended June 30,					Six Months Ended June 30,
	2004		2003			2004		2003
Volumes Delivered
Refined products	41,936		42,256		(1)%	74,458		72,488		3%
LPGs	8,794		6,832		29%	22,002		20,532		7%
Total	50,730		49,088		3%	96,460		93,020		4%

Average Tariff per Barrel
Refined products	$	0.93	$	0.89	5%	$	0.94	$	0.89	6%
LPGs	1.56		1.96		(20)%	1.93		2.15		(10)%
Average system tariff per barrel	$	1.04	$	1.04	—	$	1.17	$	1.17	—

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

Our Downstream Segment reported earnings before interest of $14.3 million for the three months ended June 30, 2004, compared with earnings before interest of $16.9 million for the three months ended June 30, 2003. Earnings before interest decreased $2.6 million primarily due to an increase of $4.4 million in costs and expenses, increased losses of $0.6 million from equity investments, partially offset by an increase of $2.3 million in operating revenues 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 $1.1 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, primarily due to an increase in distillate volumes transported as a result of a strong trucking market. For the three months ended June 30, 2004, the refined products average tariff increased 5% from the prior year period primarily due to higher market-based tariff rates which went into effect in July 2003, 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 June 30, 2004, overall refined product volumes transported decreased 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 increased $0.4 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, primarily due to higher deliveries of isobutane to Chicago area refineries and increased short-haul propane deliveries to Gulf Coast petrochemical customers partially offset by lower deliveries of propane in the upper Midwest and Northeast market areas attributable to the impact of high propane prices and low inventories at Mont Belvieu during the second quarter of 2004. The LPGs average rate per barrel decreased 20% from the prior year period primarily as a result of increased short-haul deliveries during the three months ended June 30, 2004.

Other operating revenues increased $0.8 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, primarily due to higher margins on product inventory sales, higher refined products tender deduction fees and higher propane deliveries at our Providence, Rhode Island import facility. 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 $4.4 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003. The increase was made up of a $2.8 million increase in operating, general and administrative expenses and a $2.1 million increase in depreciation and amortization expense partially offset by a $0.5 million decrease in operating fuel and power. Operating, general and administrative expenses increased primarily due to a $2.6 million increase in pipeline integrity management expenses associated with our integrity management program, an $0.8 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, and an increase in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002. These increases were partially offset by lower expenses in the 2004 period associated with the write-off of receivables related to customer bankruptcies and other customer non-payments in 2003. Depreciation expense increased from the prior year period because 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, as a result of pipeline improvements made as part of our integrity management program. Operating fuel and power expense decreased as a result of a more efficient use of our transportation assets, partially offset by increased mainline throughput.

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

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

Centennial	$	(2,286	)	$	(1,827	)	$	(459	)
MB Storage	1,785			1,899			(114		)
Other	(8		)	(8		)	—
Total equity earnings (losses)	$	(509	)	$	64		$	(573	)

Equity losses in Centennial increased primarily due to higher operating expenses, partially offset by an increase in transportation volumes on Centennial. Equity earnings from our 50% ownership interest in MB Storage decreased $0.1 million for the three months ended June 30, 2004, compared with the three months ended June 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 decrease in equity earnings was due to increased amortization and depreciation expense on the acquired storage assets and contracts, partially offset by increased storage revenue, shuttle 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 June 30, 2004, compared with the three months ended June 30, 2003, primarily due to higher interest income earned on cash investments and other investing activities.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Our Downstream Segment reported earnings before interest of $39.0 million for the six months ended June 30, 2004, compared with earnings before interest of $44.9 million for the six months ended June 30, 2003. Earnings before interest decreased $5.9 million primarily due to an increase of $14.8 million in costs and expenses and increased losses of $0.6 million from equity investments partially offset by an increase of $9.1 million in operating revenues and an increase of $0.4 million in other income – net. We discuss the factors influencing our operating performance below.

Revenues from refined products transportation increased $5.2 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to an overall increase of 3% 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. These 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 6% from the prior year period primarily due to higher market-based tariff rates which went into effect in July 2003, partially offset by the impact of the Midwest origin point for barrels received from Centennial, which resulted in decreased short-haul barrels transported on our system.

Revenues from LPGs transportation decreased $1.7 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, primarily 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. This decrease was 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 10% from the prior year period primarily as a result of increased short-haul deliveries during the six months ended June 30, 2004.

Other operating revenues increased $5.6 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, primarily due to higher propane inventory fees, higher refined products tender deduction fees, higher margins on product inventory sales and higher propane deliveries at our Providence, Rhode Island import facility.

Costs and expenses increased $14.8 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003. The increase was made up of an $11.2 million increase in operating, general and administrative expenses, a $4.1 million increase in depreciation and amortization expense and a $0.2 million increase in taxes – other than income taxes. These increases were partially offset by a $0.7 million decrease in operating fuel and power. Operating, general and administrative expenses increased primarily due to an $8.0 million increase in pipeline integrity management expenses associated with our integrity management program, a $1.7 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, a $2.1 million increase in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002 and acquisition related activities and a $0.4 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 other customer non-payments in 2003. Depreciation expense increased from the prior year period because 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, as a result of pipeline improvements made as part of our integrity management program. Taxes – other than income taxes increased as a result of actual property taxes being slightly higher than previously estimated. Operating fuel and power expense decreased as a result of a more efficient use of our transportation assets, partially offset by increased mainline throughput.

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

	Six Months Ended June 30,						Increase (Decrease)
	2004			2003			Increase (Decrease)
Centennial	$	(6,143	)	$	(5,005	)	$	(1,138	)
MB Storage	4,414			3,844			570
Other	(18		)	(34		)	16
Total equity losses	$	(1,747	)	$	(1,195	)	$	(552	)

Equity losses in Centennial increased 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 higher operating expenses, partially offset by an increase in transportation volumes on Centennial. Equity earnings from our 50% ownership interest in MB Storage increased $0.6 million for the six months ended June 30, 2004, compared with the six months ended June 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 $0.4 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, primarily due to higher interest income earned on cash investments.

Upstream Segment

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

	Three Months Ended June 30,				Percentage Increase (Decrease)	Six Months Ended June 30,				Percentage Increase (Decrease)
	2004		2003		Percentage Increase (Decrease)	2004		2003		Percentage Increase (Decrease)

Margins:
Crude oil transportation	$	13,279	$	11,292	18%	$	26,375	$	22,096	19%
Crude oil marketing	6,901		6,469		7%	12,593		11,204		12%
Crude oil terminaling	2,241		2,429		(8)%	4,966		4,549		9%
Lubrication oil sales	1,504		1,339		12%	2,996		2,691		11%
Total margin	$	23,925	$	21,529	11%	$	46,930	$	40,540	16%

Total barrels:
Crude oil transportation	24,686		25,931		(5)%	50,848		48,556		5%
Crude oil marketing	42,270		36,903		15%	87,924		74,575		18%
Crude oil terminaling	27,800		28,193		(1)%	60,888		55,562		10%

Lubrication oil volume (total gallons)	2,949		2,310		28%	6,419		5,153		25%

Margin per barrel:
Crude oil transportation	$	0.538	$	0.435	24%	$	0.519	$	0.455	14%
Crude oil marketing	0.163		0.175		(7)%	0.143		0.150		(5)%
Crude oil terminaling	0.081		0.086		(6)%	0.082		0.082		—

Lubrication oil margin (per gallon)	0.510		0.580		(12)%	0.467		0.522		(11)%

The following table reconciles the Upstream Segment margin to the consolidated statements of income using the information presented in the consolidated statements of income and the statements of income in Note 10. Segment Information (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Sales of petroleum products	$	1,231,019		$	927,232		$	2,411,786		$	1,903,192
Transportation – Crude oil	9,213			7,059			18,876			13,964
Less: Purchases of petroleum products	(1,216,307		)	(912,762		)	(2,383,732		)	(1,876,616		)
Total margin	$	23,925		$	21,529		$	46,930		$	40,540

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

Our Upstream Segment reported earnings before interest of $20.6 million for the three months ended June 30, 2004, compared with earnings before interest of $20.0 million for the three months ended June 30, 2003. Earnings before interest increased $0.6 million primarily due to an increase of $2.4 million in margin, an increase of $3.9 million in equity earnings from Seaway and an increase of $0.2 million in other operating revenues, partially offset by an increase of $1.8 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and a decrease of $0.2 million in other income – net. Additionally, for the three months ended June 30, 2003, we recognized a gain of $3.9 million on the sale of assets. We discuss factors influencing our operating performance below.

Our margin increased $2.4 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003. Crude oil transportation margin increased $2.0 million primarily due to an increase in transportation revenues primarily on our South Texas system, as a result of the acquisition of the Genesis assets and increased revenues on our Basin system. These increases were partially offset by lower transportation volumes on our West Texas and other gathering systems. 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 4. Acquisitions and Dispositions). Crude oil marketing margin increased $0.4 million primarily due to increased volumes marketed and favorable crude oil price differentials. Lubrication oil sales margin increased $0.2 million due to increased sales of chemical volumes and increased volumes related to the acquisition of a lubrication oil distributor in Abilene, Texas, in December 2003. Crude oil terminaling margin decreased $0.2 million as a result of lower pumpover volumes at Midland, Texas, partially offset by higher pumpover volumes at Cushing, Oklahoma.

Other operating revenue of the Upstream Segment increased $0.2 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, primarily due to 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 $1.8 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003. The increase was made up of a $0.9 million increase in operating, general and administrative expenses, a $0.6 million increase in depreciation and amortization expense and a $0.5 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 expenses increased $0.9 million from the prior year period primarily due to an $0.8 million increase in pipeline integrity management expenses associated with our integrity management program, increases in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002 and increased labor costs primarily due to an increase in the number of employees between years as a result of the acquisition of Genesis. Depreciation and amortization expense increased $0.6 million due to the assets placed in service as a result of the Genesis acquisition. Operating fuel and power increased $0.5 million primarily as a result of the acquisition of the Genesis assets and higher volumes in 2004. Taxes – other than income taxes decreased $0.2 million due to decreases 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. In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the current owners of the Rancho Pipeline. We acquired 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.

Equity earnings in Seaway increased $3.9 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, due to higher third-party transportation volumes, gains on inventory sales and lower general and administrative expenses.

Other income – net decreased $0.2 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to lower interest income earned on cash investments.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Our Upstream Segment reported earnings before interest of $37.7 million for the six months ended June 30, 2004, compared with earnings before interest of $28.8 million for the six months ended June 30, 2003. Earnings before interest increased $8.9 million primarily due to an increase of $6.4 million in margin, an increase of $5.8 million in equity earnings from Seaway and an increase of $1.8 million in other operating revenues, partially offset by an increase of $1.0 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and a decrease of $0.2 million in other income – net. Additionally, for the six months ended June 30, 2003, we recognized a gain of $3.9 million on the sale of assets. We discuss factors influencing our operating performance below.

Our margin increased $6.4 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003. Crude oil transportation margin increased $4.3 million primarily due to an increase in transportation volumes and revenues on our South Texas system, as a result of the acquisition of the Genesis assets, and increased revenues on our Basin system. These increases were partially offset by lower transportation volumes on our West Texas and other gathering systems. 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 4. Acquisitions and Dispositions). Crude oil marketing margin increased $1.4 million due to increased volumes marketed and favorable crude oil price differentials, partially offset by an invoicing settlement on a marketing contract in the first quarter of 2003, which reduced the marketing margin in 2003. Crude oil terminaling margin increased $0.4 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 $0.3 million due to increased sales of chemical volumes and increased volumes related to the acquisition of a lubrication oil distributor in Abilene, Texas, in December 2003.

Other operating revenue of the Upstream Segment increased $1.8 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, primarily due to a $1.4 million 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 $1.0 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003. The increase was made up of a $1.5 million increase in operating fuel and power, a $0.6 million increase in depreciation and amortization expense and a $0.1 million increase in taxes – other than income taxes, partially offset by a decrease of $1.2 million in operating, general and administrative expenses. Operating fuel and power increased $1.5 million primarily as a result of the acquisition of the Genesis assets and higher volumes in 2004. Depreciation and amortization expense increased $0.6 million due to the assets placed in service as a result of the Genesis acquisition. Taxes – other than income taxes increased $0.1 million due to increases in property tax accruals. Operating, general and administrative expenses decreased $1.2 million from the prior year period primarily due to $3.1 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 higher legal costs in 2003 related to the litigation and settlement with D.R.D. Environmental Services, Inc. These decreases were partially offset by a $1.5 million increase in pipeline integrity management expenses associated with our integrity management program, increases in consulting and contract services primarily related to compliance with the Sarbanes-Oxley Act of 2002 and increased labor costs primarily due to an increase in the number of employees between years as a result of the acquisition of Genesis.

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.

Equity earnings in Seaway increased $5.8 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to higher third-party transportation volumes, gains on inventory sales, a settlement with the former owner of Seaway’s crude oil assets regarding inventory imbalances with customers on assets that were not acquired by us and lower general and administrative expenses.

Other income – net decreased $0.2 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to lower interest income earned on cash investments.

Midstream Segment

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

	Three Months Ended June 30,				Percentage Increase (Decrease)	Six Months Ended June 30,				Percentage Increase (Decrease)
	2004		2003		Percentage Increase (Decrease)	2004		2003		Percentage Increase (Decrease)
Gathering – Natural Gas – Jonah :
Million cubic feet	83,469		70,528		18%	167,397		144,793		16%
Million British thermal units (“MMBtu”)	92,430		78,509		18%	185,327		160,454		16%
Average fee per MMBtu	$	0.197	$	0.192	3%	$	0.198	$	0.191	4%

Gathering – Natural Gas – Val Verde:
Million cubic feet	35,989		39,927		(10)%	71,480		81,636		(12)%
Million British thermal units (“MMBtu”)	30,361		33,492		(9)%	60,165		68,759		(12)%
Average fee per MMBtu	$	0.533	$	0.514	4%	$	0.537	$	0.522	3%

Transportation – NGLs:
Thousand barrels	15,465		13,953		11%	30,145		28,221		7%
Average rate per barrel	$	0.684	$	0.677	1%	$	0.683	$	0.685	—

Fractionation – NGLs:
Thousand barrels	956		1,007		(5)%	2,070		2,078		—
Average rate per barrel	$	1.867	$	1.846	1%	$	1.771	$	1.788	(1)%

Sales – Condensate:
Thousand barrels	17.9		15.2		18%	59.7		46.0		30%
Average rate per barrel	$	37.17	$	27.43	36%	$	34.61	$	31.05	11%

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

Our Midstream Segment reported earnings before interest of $19.3 million for the three months ended June 30, 2004, compared with earnings before interest of $19.6 million for the three months ended June 30, 2003. Earnings before interest decreased $0.3 million due to an increase of $4.2 million in costs and expenses (excluding purchases of petroleum products) partially offset by an increase of $3.9 million in operating revenues and margin. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $2.2 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003. Natural gas gathering revenues from the Jonah system increased $3.2 million and volumes delivered increased 12.9 Bcf for the three months ended June 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 is also partially due to an increase in the average natural gas gathering rate due to certain pressure thresholds being achieved. Natural gas gathering revenues from the Val Verde system decreased $1.0 million and volumes delivered decreased 3.9 Bcf for the three months ended June 30, 2004, primarily due to the natural decline of CBM production and slower than anticipated infill drilling, which resulted in decreased revenues, partially offset by an increase in the average natural gas gathering rate due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas.

During the first quarter of 2004, Jonah’s Pioneer gas processing plant, which was constructed as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming, was completed. 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 sales and purchases in the second quarter of 2004 with a margin of $0.1 million. The margin from the sales and purchases related to the keep-whole election processing contracts is expected to remain very small.

Revenues from the transportation of NGLs increased $1.1 million for the three months ended June 30, 2004, compared with the three months ended June 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 $0.5 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, due to a $0.2 million increase in condensate sales on the Jonah system and a $0.7 million increase in processing fee revenues as a result of Jonah’s Pioneer processing plant, which was constructed as part of the Phase III expansion being placed in service in January 2004. These increases were partially offset by decreases of $0.4 million in other miscellaneous revenue.

Costs and expenses (excluding purchases of petroleum products) increased $4.2 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, due to a $3.1 million increase in operating, general and administrative expense, a $0.5 million increase in operating fuel and power, a $0.4 million increase in taxes – other than income taxes and a $0.2 million increase in depreciation and amortization expense. Operating, general and administrative expense increased due to a $1.6 million increase in gas settlement expenses, a $1.3 million increase in pipeline maintenance and repair expenses and a $0.6 million increase in general and administrative labor expense, 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. Operating fuel and power increased $0.5 million primarily due to increased NGL volumes and higher power costs. Taxes – other than income taxes increased $0.4 million as a result of higher property balances. Depreciation expense increased $0.5 million primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system. This increase was partially offset by decreased amortization expense of $0.3 million, due to a $0.7 million decrease on Val Verde as a result of lower volumes in 2004, partially offset by a $0.4 million increase in amortization expense on Jonah as a result of higher volumes in 2004.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Our Midstream Segment reported earnings before interest of $37.5 million for the six months ended June 30, 2004, compared with earnings before interest of $38.1 million for the six months ended June 30, 2003. Earnings before interest decreased $0.6 million due to an increase of $6.4 million in costs and expenses (excluding purchases

of petroleum products) partially offset by an increase of $5.8 million in operating revenues and margin. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $2.4 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003. Natural gas gathering revenues from the Jonah system increased $6.0 million and volumes delivered increased 22.6 Bcf for the six months ended June 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 is also partially due to an increase in the average natural gas gathering rate due to certain pressure thresholds being achieved. Natural gas gathering revenues from the Val Verde system decreased $3.6 million and volumes delivered decreased 10.2 Bcf for the six months ended June 30, 2004, primarily due to the natural decline of CBM production and slower than anticipated infill drilling, which resulted in decreased revenues, partially offset by an increase in the average natural gas gathering rate due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas.

During the first quarter of 2004, Jonah’s Pioneer gas processing plant, which was constructed as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming, was completed. For the six months ended June 30, 2004, the sales and purchases under the fee arrangements at the Pioneer plant resulted in a margin of $0.1 million.

Revenues from the transportation of NGLs increased $1.3 million for the six months ended June 30, 2004, compared with the six months ended June 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. Lower average rates per barrel on volumes transported on the Chaparral and Dean pipelines were offset by higher average rates per barrel on volumes transported on the Panola and Wilcox pipelines.

Other operating revenues increased $2.0 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to an increase of $1.4 million in processing fee revenues as a result of the Pioneer processing plant, constructed as part of the Phase III expansion, which was placed in service in January 2004 and an increase of $0.6 million in condensate sales on the Jonah system.

Costs and expenses (excluding purchases of petroleum products) increased $6.4 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to a $6.5 million increase in operating, general and administrative expense, a $0.7 million increase in operating fuel and power and a $0.4 million increase in taxes – other than income taxes, partially offset by a $1.2 million decrease in depreciation and amortization expense. Operating, general and administrative expense increased due to a $3.4 million increase in gas settlement expenses, a $1.8 million increase in pipeline maintenance repair expenses, a $1.4 million increase in general and administrative labor expense and an increase in consulting and contract services primarily 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. Operating fuel and power increased $0.7 million primarily due to increased NGL volumes and higher power costs. Taxes – other than income taxes increased $0.4 million as a result of higher property balances. Amortization expense decreased $3.7 million primarily due to a $3.2 million decrease on Jonah’s intangible assets under the units-of-production method resulting from an extension of the expected amortization period from 16 years to 25 years (see Note 2. Goodwill and Other Intangible Assets), partially offset by a $0.7 million increase as a result of higher volumes in 2004. Amortization expense on the Val Verde system decreased $1.2 million primarily due to lower volumes in 2004, as a result of the natural decline in CBM production. These decreases were partially offset by increased depreciation expense of $2.5 million, primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system.

Interest Expense and Capitalized Interest

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

Interest expense decreased $5.5 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, primarily due to a higher percentage of variable interest rate debt during the three months ended June 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 3. Interest Rate Swaps).

Capitalized interest increased $0.6 million for the three months ended June 30, 2004, compared with the three months ended June 30, 2003, due to interest capitalized on construction work-in-progress in 2004.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Interest expense decreased $6.9 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to lower outstanding debt balances and a higher percentage of variable interest rate debt during the six months ended June 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 3. Interest Rate Swaps).

Capitalized interest increased $0.9 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, due to interest capitalized on construction work-in-progress in 2004.

Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings is our primary source of liquidity. At June 30, 2004, and December 31, 2003, we had working capital deficits of $33.7 million and $22.8 million, respectively. At June 30, 2004, we had $290.0 million in available borrowing capacity under our revolving credit facility to cover any working capital needs. Cash flows for the six months ended June 30, 2004 and 2003 were as follows (in millions):

	Six Months Ended June 30,
	2004			2003

Cash provided by (used in):
Operating activities	$	132.2		$	132.5
Investing activities	(82.1		)	(63.9		)
Financing activities	(65.7		)	(68.8		)

Operating Activities

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

	Six Months Ended June 30,
	2004			2003

Net income	$	78.2		$	67.9
Depreciation and amortization	54.2			50.8
Earnings in equity investments	(17.2		)	(12.0		)
Distributions from equity investments	20.8			10.8
Gain on sale of assets	—			(3.9		)
Non-cash portion of interest expense	(0.2		)	3.1
Cash provided by (used in) working capital and other	(3.6		)	15.8

Net cash from operating activities	$	132.2		$	132.5

Cash provided by operating activities decreased $0.3 million for the six months ended June 30, 2004, compared with the six months ended June 30, 2003, primarily due to the timing of payments for working capital components, partially offset by higher net income in the 2004 period and an increase of $10.0 million in distributions received from our equity investments in Seaway and MB Storage during the six months ended June 30, 2004.

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 six months ended June 30, 2004 and 2003, included interest payments, net of amounts capitalized, of $41.2 million and $39.6 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 $82.1 million for the six months ended June 30, 2004, and were comprised of $60.4 million of capital expenditures, $1.5 million of cash contributions for TE Products’ ownership interest in Centennial, $17.2 million of cash contributions for TE Products’ ownership interest in MB Storage and $3.0 million for the acquisition of assets acquired during the six months ended June 30, 2004. Cash flows used in investing activities totaled $63.9 million for the six months ended June 30, 2003, and were comprised of $45.9 million of capital expenditures, $20.0 million for TE Products’ acquisition of an additional 16.7% interest in Centennial and $1.0 million of cash contributions for TE Products’ ownership interest in Centennial, partially offset by $3.0 million in net cash proceeds from the Rancho Pipeline transactions.

Financing Activities

Cash flows used in financing activities totaled $65.7 million for the six months ended June 30, 2004, and were comprised of $115.7 million of distributions paid to unitholders, partially offset by $50.0 million in borrowings, net of repayments from our revolving credit facility. Cash flows used in financing activities totaled $68.8 million for the six months ended June 30, 2003, and were comprised of $504.0 million of repayments on our revolving credit facility; $113.8 million to repurchase and retire the outstanding Class B Units and $96.0 million of distributions paid to unitholders. These uses of cash for the six months ended June 30, 2003, were partially offset by $335.0 million in proceeds from our revolving credit facility; $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 $114.5 million from the issuance of 3.9 million Units in April 2003.

Centennial entered into credit facilities totaling $150.0 million and, as of June 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 (“Marathon”) 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 effectiveness, 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 June 30, 2004, we have $2.0 billion remaining under this shelf registration.

Credit Facilities and Interest Rate Swap Agreements

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 June 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 June 30, 2004 (in millions):

	As of June 30, 2004
Description:	Outstanding Principal		Available Borrowing Capacity		Maturity Date
Revolving Credit Facility	$	260.0	$	290.0	June 2006
6.45% Senior Notes (1)	180.0		—		January 2008
7.625% Senior Notes (1)	500.0		—		February 2012
6.125% Senior Notes (1)	200.0		—		February 2013
7.51% Senior Notes (1)	210.0		—		January 2028
Total	$	1,350.0	$	290.0

(1) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2004, the 7.51% Senior Notes include an adjustment to decrease the fair value of the debt by $2.9 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 June 30, 2004, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $38.6 million. At June 30, 2004, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.0 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 $115.7 million ($1.3125 per Unit) and $96.0 million ($1.225 per Unit) during the six months ended June 30, 2004 and 2003, respectively. Additionally, we declared a cash distribution of $0.6625 per Unit for the quarter ended June 30, 2004. We will pay the distribution of $58.7 million on August 6, 2004, to unitholders of record on July 30, 2004.

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.

General Partner Interest

As of June 30, 2004, and December 31, 2003, we had a deficit balance of $17.7 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 six months ended June 30, 2004, the General Partner was allocated $22.6 million (representing 28.85%) of our net income and received $33.1 million in cash distributions.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2004 will be approximately $162.7 million (which includes $4.0 million of capitalized interest). We expect to spend approximately $124.2 million for revenue generating projects and facility improvements. Capital spending on revenue generating projects and facility improvements will include approximately $54.4 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 $22.2 million to expand our Upstream Segment pipelines and facilities in South Texas and Oklahoma and approximately $47.6 million to expand our Midstream Segment assets. We expect to spend approximately $34.5 million of capital costs 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 ($260.0 million outstanding at June 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 six months ended June 30, 2004, TE Products exceeded the minimum throughput requirements on the lease agreement.

During the six months ended June 30, 2004, TE Products contributed $1.5 million to Centennial to cover operating needs and capital expenditures. During the six months ended June 30, 2004, TE Products contributed $17.2 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 June 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	$	260.0	$	—	$	260.0	$	—	$	—
6.45% Senior Notes due 2008 (1) (2)	180.0		—		—		180.0		—
7.625% Senior Notes due 2012 (2)	210.0		—		—		—		210.0
6.125% Senior Notes due 2013 (2)	500.0		—		—		—		500.0
7.51% Senior Notes due 2028 (1) (2)	200.0		—		—		—		200.0
Debt subtotal	1,350.0		—		260.0		180.0		910.0

Operating leases	65.4		17.3		27.3		10.4		10.4

Total	$	1,415.4	$	17.3	$	287.3	$	190.4	$	920.4

(1) Obligations of TE Products.

(2) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2004, the 7.51% Senior Notes include an adjustment to decrease the fair value of the debt by $2.9 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 June 30, 2004, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $38.6 million. At June 30, 2004, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.0 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 June 30, 2004, we had $290.0 million in available borrowing capacity under the Revolving Credit Facility. We expect that cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, future expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity offerings.

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

Other Considerations

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.

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 June 30, 2004, we had $260.0 million outstanding under our variable interest rate revolving credit agreement. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of our variable interest rate debt outstanding at June 30, 2004, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be $2.6 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 June 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 June 30, 2004, the estimated fair value of the TE Products Senior Notes was approximately $397.2 million. At June 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 June 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 $542.7 million and $197.4 million, respectively.

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 7. 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 six months ended June 30, 2004 and 2003, we recognized increases in interest expense of $2.9 million and $7.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

On February 20, 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap agreements were terminated resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the floating rate of interest was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into on July 16, 2002, were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At June 30, 2004, the unamortized balance of the deferred gains was $38.6 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

Item 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 June 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 second 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 11. 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+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

10.2+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

10.3+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

10.4+		Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).

10.5+		Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).

10.6+		Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

10.7		Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

10.8		Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

10.9+		Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.10+		Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.11+		Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.12+		Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.13+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

10.14+		TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

10.15+		Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

10.16		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

10.17		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

10.18		Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.19		Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.20		Amendment and Restatement, dated as of November 13, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.21		Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.22		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.23		Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.24		Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).

10.25		Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).

10.26		Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.27		Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.28		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.29		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

10.30		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

10.31		Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.32		Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.33		Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.34		Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.35		Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

10.36+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

10.37+		Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.38+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.39+		Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.40+		Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.41		Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.42		Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.43		Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.44		LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.45		Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).

10.46		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and incorporated herein by reference).

10.47		Agreement of Limited Partnership of Mont Belvieu Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

10.48		Letter of Agreement Clarifying Rights and Obligations of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 13, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.

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.

+ A management contract or compensation plan or arrangement.

(b) Reports on Form 8-K filed with or furnished to the Securities and Exchange Commission during the quarter ended June 30, 2004:

A current report on Form 8-K was furnished on April 27, 2004, reporting first quarter financial results.

A current report on Form 8-K was filed on June 7, 2004, including as an exhibit the audited balance sheet of Texas Eastern Products Pipeline Company, LLC, as of December 31, 2003.

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: August 3, 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

Distributions and Issuance of Additional Limited Partner Units

Sources of Future Capital